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EX-32.2 - EX-32.2 - Antero Midstream Partners LPam-20171231ex322a60597.htm
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EX-31.2 - EX-31.2 - Antero Midstream Partners LPam-20171231ex3121193c6.htm
EX-31.1 - EX-31.1 - Antero Midstream Partners LPam-20171231ex311347357.htm
EX-23.1 - EX-23.1 - Antero Midstream Partners LPam-20171231ex2318f4195.htm
EX-21.1 - EX-21.1 - Antero Midstream Partners LPam-20171231ex2113e9383.htm
EX-12.1 - EX-12.1 - Antero Midstream Partners LPam-20171231ex121f40e14.htm

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10‑K


ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017

or

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission File No. 001‑36719


ANTERO MIDSTREAM PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)

46-4109058
(IRS Employer
Identification No.)

1615 Wynkoop Street
Denver Colorado
(Address of principal executive offices)

80202
(Zip Code)

 

(303) 357‑7310

(Registrant’s telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act:

Title of Each Class

Name of Each Exchange on which Registered

Common Units Representing Limited Partner Interests

New York Stock Exchange

 

Securities Registered Pursuant to Section 12(g) of the Act: None.


Indicate by check mark if the registrant is a well‑known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes  ☐ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes  ☒ No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes  ☐ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted 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 and post such files). ☒ Yes  ☐ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10‑K. 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non‑accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,”  “smaller reporting company,” and “emerging growth company” in Rule 12b‑2 of the Exchange Act.

Large accelerated filer 

 

Emerging growth company ☐

Accelerated filer ☐

Non‑accelerated filer ☐
(Do not check if a
smaller reporting company)

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). ☐ Yes  ☒ No

The aggregate market value of the registrant’s common units  representing limited partner interests held by non-affiliates of the registrant as of June 30, 2017, the last business day of the registrant’s most recently completed second fiscal quarter was approximately $2.6 billion based on the closing price of Antero Midstream Partners LP’s common units representing limited partner interests as reported on the New York Stock Exchange of $33.18.

As of February 8, 2018, there were 186,934,568 common units representing limited partner interests outstanding.

Documents incorporated by reference: None.

 

 

 


 

TABLE OF CONTENTS

 

 

 

Page

CAUTIONARY STATEMENT REGARDING FORWARD‑LOOKING STATEMENTS 

 

PART I 

6

Items 1 and 2. 

Business and Properties

6

Item 1A. 

Risk Factors

21

Item 1B. 

Unresolved Staff Comments

49

Item 3. 

Legal Proceedings

49

Item 4. 

Mine Safety Disclosures

49

PART II 

50

Item 5. 

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

50

Item 6. 

Selected Financial Data

52

Item 7. 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

56

Item 7A. 

Quantitative and Qualitative Disclosures About Market Risk

75

Item 8. 

Financial Statements and Supplementary Data

75

Item 9. 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

75

Item 9A. 

Controls and Procedures

76

Item 9B. 

Other Information

77

PART III 

78

Item 10. 

Directors, Executive Officers, and Corporate Governance

78

Item 11. 

Executive Compensation

85

Item 12. 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

112

Item 13. 

Certain Relationships and Related Transactions and Director Independence

116

Item 14. 

Principal Accountant Fees and Services

125

PART IV 

126

Item 15. 

Exhibits and Financial Statement Schedules

126

 

 

 

 

 

 

 

 

2


 

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. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Annual Report on Form 10-K. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

 

Antero Resources Corporation’s expected production and ability to meet its drilling and development plan;

 

our ability to execute our business strategy;

 

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

 

natural gas, natural gas liquids (“NGLs”) and oil prices;

 

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

 

plans, objectives, expectations and intentions contained in this report that are not historical.

 

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to our business. These risks include, but are not limited to, commodity price volatility, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, conflicts of interest among holders of our common units, and the other risks described under “Risk Factors” in this Annual Report on Form 10-K.

 

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

 

All forward-looking statements, expressed or implied, included in this report 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, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report on Form 10-K.

3


 

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.

 

“Btu.”  British thermal units.

 

“C3+.” Natural gas liquids excluding ethane, consisting primarily of propane, isobutane, normal butane and natural gasoline.

 

“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 expenditures.”  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. 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 expenditures.”  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.

4


 

 

“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.

 

“MMcfe.” One million cubic feet of natural gas equivalent with one barrel of oil, condensate or NGLs converted to six thousand cubic feet of natural gas.

 

“MMcf/d.”  One million cubic feet per day.

 

“MMcfe/d.”  One million cubic feet equivalent 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 which may be extracted as purity products such as ethane, propane, isobutene and normal butane, and natural gasoline.

 

“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.

 

“WTI.” West Texas Intermediate light sweet crude oil.

 

5


 

PART I

 

References in this Annual Report on Form 10-K to “Predecessor,” “we,” “our,” “us” or like terms, when referring to period prior to November 10, 2014, refer to Antero Resources Corporation’s gathering, compression and water assets, our predecessor for accounting purposes. References to “the Partnership,” “we,” “our,” “us” or like terms, when referring to periods between November 10, 2014 and September 23, 2015 refer to the Partnership’s gathering and compression assets and Antero Resources Corporation’s water handling and treatment assets. References to “the Partnership,” “we,” “our,” “us” or like terms, when referring to periods since September 23, 2015 or when used in the present tense or prospectively, refer to Antero Midstream Partners LP.

 

Items 1 and 2.  Business and Properties 

 

Our Partnership

 

We are a growth-oriented limited partnership formed by Antero Resources Corporation (“Antero Resources”) to own, operate and develop midstream energy assets to service Antero Resources’ rapidly increasing production. Our assets consist of gathering pipelines, compressor stations, processing and fractionation plants and water handling and treatment assets, through which we provide midstream services to Antero Resources under long-term, fixed-fee contracts. Our assets are located in the rapidly developing liquids-rich Marcellus Shale and Utica Shale located in West Virginia and Ohio, two of the premier North American shale plays. We believe that our strategically located assets and our relationship with Antero Resources position us to become a leading midstream energy company serving the Marcellus and Utica Shales.

 

Since our initial public offering, we have grown our quarterly distribution 115% from our minimum quarterly distribution of $0.17 per unit ($0.68 per unit on an annualized basis) for the quarter ended December 31, 2014 (the initial quarter for which we paid a quarterly cash distribution) to $0.365 per unit ($1.46 per unit on an annualized basis) for the quarter ended December 31, 2017. Our ability to consistently grow our cash distributions is driven by a combination of Antero Resources’ production growth and our accretive build‑out of additional midstream infrastructure to service that production growth.

Antero Midstream Partners LP’s (the “Partnership” or “Antero Midstream”) assets consist of gathering pipelines, compressor stations, interests in processing and fractionation plants, and water handling and treatment infrastructure, through which Antero Midstream and its affiliates provide gathering, compression, processing, fractionation and integrated water services, including fresh water delivery services and other fluid handling services. These services are provided to Antero Resources under long-term, fixed-fee contracts, limiting Antero Midstream’s direct exposure to commodity price risk.  As of December 31, 2017, all of Antero Resources’ approximate 705,000 gross acres (620,000 net acres) are dedicated to Antero Midstream for gathering, compression and water services, except for approximately 156,000 gross acres subject to third‑party gathering and compression commitments. Antero Midstream also owns 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, a wholly owned subsidiary of MPLX. In connection with Antero Midstream’s entry into the Joint Venture with MarkWest, Antero Midstream released to the Joint Venture its 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 Antero Midstream, and subject to any pre‑existing dedications or other third‑party commitments, Antero Resources has dedicated to Antero Midstream 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 services areas in West Virginia and Ohio for water services. Antero Midstream also has certain rights of first offer with respect to gathering, compression, processing, and fractionation services, and water services for acreage located outside of the existing dedicated areas. The gathering and compression and water services agreements each have a 20‑year initial term and are subject to automatic annual renewal after the initial term.

 

On September 23, 2015, Antero Resources contributed (the “Water Acquisition”) (i) all of the outstanding limited liability company interests of Antero Water LLC (“Antero Water”) to the Partnership and (ii) all of the assets, contracts, rights, permits and properties owned or leased by Antero Resources and used primarily in connection with the construction, ownership, operation, use or maintenance of Antero Resources’ advanced wastewater treatment complex undergoing testing and commissioning in Doddridge County, West Virginia, to Antero Treatment LLC (“Antero

6


 

Treatment”) (collectively, (i) and (ii) are referred to herein as the “Contributed Assets”). Our results for the year ended December 31, 2015 has been recast to include the historical results of Antero Water because the transaction was between entities under common control. Antero Water’s operations prior to the Water Acquisition consisted entirely of fresh water delivery operations.

 

The agreement includes certain minimum fresh water delivery commitments that require Antero Resources to take delivery or pay a fee on a minimum volume of fresh water deliveries in calendar years 2016 through 2019. Minimum volume commitments are 90,000 barrels per day in 2016, 100,000 barrels per day in 2017 and 120,000 barrels per day in 2018 and 2019.  We have a secondment agreement whereby Antero Resources provides seconded employees to perform certain operational services with respect to our assets for a 20-year period that commenced at the Water Acquisition date. Additionally, we have a services agreement whereby Antero Resources provides certain administrative services to us for a 20-year period, that commenced at the Initial Public Offering (“IPO”) date.

 

In connection with the Water Acquisition, we have agreed to pay Antero Resources (a) $125 million in cash if we deliver 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.

 

Our gathering and compression assets consist of 8-, 12-, 16-, 20-, 24-, and 30-inch high and low pressure gathering pipelines, compressor stations, and processing and fractionation plants that collect and process natural gas, NGLs and oil from Antero Resources’ wells in West Virginia and Ohio. The Partnership’s water handling and treatment assets include two independent systems that deliver fresh water from sources including the Ohio River, local reservoirs as well as several regional waterways. The water handling and treatment assets also consist of flowback and produced water assets used to provide services for well completion and production operations in Antero Resources’ operating areas. 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. The flowback and produced water services assets consist of wastewater transportation, disposal, and a wastewater treatment facility that is currently undergoing testing and commissioning. As of December 31, 2017, we had the ability to store 5.4 million barrels of fresh water in 38 impoundments.

 

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

 

As of December 31, 2017, in West Virginia, we owned and operated 122 miles of buried fresh water pipelines and 68 miles of surface fresh water pipelines that service Antero Resources’ drilling activities in the Marcellus Shale, as well as 25 centralized water storage facilities equipped with transfer pumps.  As of December 31, 2017, in Ohio, we owned and operated 55 miles of buried fresh water pipelines and 28 miles of surface fresh water pipelines that service Antero Resources’ drilling activities in the Utica Shale, as well as 13 centralized water storage facilities equipped with transfer pumps. The water handling and treatment services include hauling, treatment and disposal or recycling of flow back and produced water.

 

Our operations are located in the United States and are organized into two reporting segments: (1) gathering and processing and (2) water handling and treatment. Financial information for our reporting segments is located under “Note 12. Reporting Segments” to our consolidated financial statements.

 

Developments and Highlights

 

Financial Results

For the year ended December 31, 2017, we generated cash flows from operations of $476 million, net income of $307 million, Adjusted EBITDA of $529 million, and Distributable Cash Flow of $421 million. This compares to cash flows from operations of $379 million, net income of $237 million, Adjusted EBITDA of $404 million, and Distributable Cash Flow of $353 million for the year ended December 31, 2016. See “—Non-GAAP Financial

7


 

Measures” for a definition of Adjusted EBITDA and Distributable Cash Flow (non-GAAP measures) and a reconciliation of Adjusted EBITDA and Distributable Cash Flow to net income.

Cash Distributions

The board of directors of our general partner has declared a cash distribution of $0.365 per unit for the quarter ended December 31, 2017. The distribution was paid on February 13, 2018 to unitholders of record as of February 1, 2018.

 

2018 Capital Budget

 

During 2018, 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’ 2018 drilling and completion capital budget is $1.3 billion. Antero Resources plans to operate an average of five drilling rigs and complete between 120 and 125 horizontal wells in the Marcellus, all of which are located on acreage dedicated to us. In the Utica, Antero plans to operate one drilling rig and complete between 20 and 25 horizontal wells in 2018, all of which are located on acreage dedicated to us.  

 

Our 2018 capital budget is approximately $650 million, which includes $585 million of expansion capital and $65 million of maintenance capital. The capital budget includes $385 million of capital for gathering and compression infrastructure, approximately 90% of which will be invested in the Marcellus Shale and the remaining 10% will be invested in the Utica Shale. The gathering and compression budget is expected to fund construction of over 51 miles of gathering pipelines in the Marcellus and Utica Shales combined. We also expect to invest $35 million for water infrastructure capital to construct 25 miles of additional buried fresh water pipelines and surface pipelines to support Antero Resources’ completion activities. Approximately 85% of the water infrastructure budget will be allocated to the Marcellus Shale and the remaining 15% will be allocated to the Utica Shale. Our 2018 budget also includes $15 million of capital for the final completion of our advanced wastewater treatment facility, which is expected to be placed into full commercial service during the first quarter of 2018, and $215 million for our investment in the Joint Venture.

 

Joint Venture

 

On February 6, 2017, we formed the Joint Venture to develop processing and fractionation assets in Appalachia with MarkWest. We and MarkWest each own a 50% interest in the Joint Venture and MarkWest operates the Joint Venture assets. The Joint Venture assets consist of processing plants in West Virginia, and a one-third interest in a MarkWest fractionator in Ohio.

 

In conjunction with the Joint Venture, on February 10, 2017 we issued 6,900,000 common units, including common units issued pursuant to the underwriters’ option to purchase additional common units, resulting in net proceeds of approximately $223 million (the “Offering”). We used the proceeds from the Offering to repay outstanding borrowings under our Credit Facility incurred to fund the investment in the Joint Venture, and for general partnership purposes.

Subordinated Unit Conversion

 

On January 11, 2017, the board of directors of our general partner declared a cash distribution of $0.28 per unit for the quarter ended December 31, 2016. The distribution was paid on February 8, 2017 to unitholders of record as of February 1, 2017. Upon payment of this distribution, the requirements for the conversion of all subordinated units were satisfied under our partnership agreement. As a result, effective February 9, 2017, the 75,940,957 subordinated units owned by Antero Resources were converted into common units on a one-for-one basis and thereafter will participate on terms equal with all other common units in distributions of available cash. The conversion did not impact the amount of the cash distributions paid by the Partnership or the total units outstanding. 

Credit Facility

On October 26, 2017, we entered into a restated and amended senior revolving credit facility. The facility was amended to include fall away covenants and lower interest rates that are triggered if and when we are assigned an investment grade credit rating by either Standard and Poor’s or Moody’s.

Lender commitments under our new facility remained at $1.5 billion. The maturity date of the facility was extended from November 2019 to October 26, 2022. At December 31, 2017, we had borrowings of $555 million and no

8


 

letters of credit outstanding under the Credit Facility. See “—Debt Agreements—Revolving Credit Facility” for a description of our revolving Credit Facility.

Antero Midstream GP LP Initial Public Offering

Antero Midstream GP LP (“AMGP”) was originally formed as Antero Resources Midstream Management LLC (“ARMM”) in 2013, to become our general partner.  In April 2017, in connection with its proposed IPO, ARMM formed Antero Midstream Partners GP LLC (“AMP GP”), a Delaware limited liability company, as a wholly owned subsidiary, and assigned it the general partner interest in us.  Concurrent with the assignment, AMP GP was admitted as our sole general partner and ARMM ceased to be Antero Midstream’s general partner.  On May 4, 2017, ARMM converted from a Delaware limited liability company to a Delaware limited partnership and changed its name to Antero Midstream GP LP in connection with its IPO.  Subsequent to its IPO, AMGP indirectly controls the general partnership interest in us, through its ownership of AMP GP, as well as Antero IDR Holdings LLC (“IDR LLC”), which owns the incentive distribution rights in us. We received no proceeds from the sale of common shares in AMGP’s IPO.

Our Assets

 

The following table provides information regarding our gathering and processing systems as of December 31, 2016 and 2017:

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering and Processing System

 

Low-Pressure Pipeline (miles)

 

High-Pressure Pipeline (miles)

 

Compression Capacity (MMcf/d)

 

As of December 31,

 

2016

 

2017

 

2016

 

2017

 

2016

 

2017

Marcellus

115   

 

126   

 

98   

 

116   

 

1,015   

 

1,590   

Utica

58   

 

68   

 

36   

 

36   

 

120   

 

120   

Total

173   

 

194   

 

134   

 

152   

 

1,135   

 

1,710   

 

The following table provides information regarding our water handling and treatment systems as of December 31, 2016 and 2017:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Water Handling and Treatment System

 

Buried Fresh Water Pipeline (miles)

 

Surface Fresh Water Pipeline (miles)

 

Wells Serviced by Water Distribution

 

Fresh Water Impoundments

 

As of December 31,

 

2016

 

2017

 

2016

 

2017

 

2016

 

2017

 

2016

 

2017

Marcellus

116   

 

122   

 

87   

 

68   

 

99   

 

115   

 

22   

 

25   

Utica

49   

 

55   

 

34   

 

28   

 

32   

 

27   

 

14   

 

13   

Total

165   

 

177   

 

121   

 

96   

 

131   

 

142   

 

36   

 

38   

 

As of December 31, 2017, our Marcellus and Utica Shale gathering systems included 242 miles and 123 miles of pipelines, respectively, and our water handling and treatment systems included 190 miles and 83 miles of pipelines, respectively.

 

In addition, our assets include a wastewater treatment facility that is currently undergoing testing and commissioning. We expect it to go into full commercial service in the first quarter of 2018.

 

Our Relationship with Antero Resources

 

Antero Resources is our most significant customer and is one of the largest producers of natural gas and NGLs in the Appalachian Basin, where it produced, on average, 2.3 Bcfe/d net (28% liquids) during 2017, an increase of 22% as compared to 2016. As of December 31, 2017, Antero Resources’ estimated net proved reserves were 17.3 Tcfe, which were comprised of 64% natural gas, 34% NGLs, and 2% oil. As of December 31, 2017, Antero Resources’ drilling inventory consisted of 4,133 identified potential horizontal well locations (approximately 3,200 of which were located on acreage dedicated to us) for gathering and compression and water handling and treatment services, which provides us with significant opportunities for growth as Antero Resources’ active drilling program continues and its production increases. Antero Resources’ 2018 drilling and completion budget is $1.3 billion, and includes plans to operate an

9


 

average of six drilling rigs, including five rigs in the Marcellus Shale, and one rig in the Utica 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 are highly dependent on Antero Resources as our most significant customer, and we expect to derive most of our revenues from Antero Resources for the foreseeable future. Accordingly, we are indirectly subject to the business risks of Antero Resources. For additional information, please read “Risk Factors—Risks Related to Our Business.” Because a substantial majority 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 adverse impact on us.

 

Contractual Arrangements

 

Gathering and Compression

 

In connection with our IPO, Antero Resources dedicated all of its current and future acreage in West Virginia, Ohio and Pennsylvania to us for gathering and compression except for acreage attributable to third-party commitments in effect prior to the Antero Midstream IPO, or acreage we have acquired that contained pre-existing dedications. For a discussion of Antero Resources’ existing third‑party commitments, 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 of $0.30 per Mcf, a high pressure gathering fee of $0.18 per Mcf, and a compression fee of $0.18 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. For additional information, please read “Item 13. Certain Relationships and Related Transactions.”

 

Water Handling and Treatment Services

 

In connection with the Water Acquisition on September 23, 2015, we entered in a Water Services Agreement with Antero Resources whereby we have agreed to provide certain water handling and treatment services to Antero Resources within an area of dedication in defined service areas in Ohio and West Virginia. Antero Resources agreed to pay us for all water handling and treatment services provided by us in accordance with the terms of the Water Services Agreement. The initial term of the Water Services Agreement is 20 years from September 23, 2015 and from year to year thereafter until terminated by either party. Under the agreement, Antero Resources will pay a fixed fee of $3.685 per barrel in West Virginia and $3.635 per barrel in Ohio and all other locations for fresh water deliveries by pipeline directly to the well site, subject to annual CPI adjustments. Antero Resources has committed to pay a fee on a minimum volume of fresh water deliveries in calendar years 2016 through 2019. Antero Resources is obligated to pay a minimum volume fee to us in the event the aggregate volume of fresh water delivered to Antero Resources under the Water Services Agreement is less than 90,000 barrels per day in 2016, 100,000 barrels per day in 2017 and 120,000 barrels per day in 2018 and 2019. Antero Resources also agreed to pay us a fixed fee of $4.00 per barrel for wastewater treatment at the advanced wastewater treatment complex and a fee per barrel for wastewater collected in trucks owned by us, in each case subject to annual CPI-based adjustments.  In addition, we contract with third party service providers to provide Antero Resources flow back and produced water services and Antero Resources will reimburse us third party out-of-pocket costs plus 3%.

 

Gas Processing and NGL Fractionation

 

Prior to the formation of the Joint Venture, we did not have any gas processing or NGL fractionation infrastructure; however, we have a right‑of‑first‑offer agreement with Antero Resources for the provision of such 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

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first offering us the right to provide such services. For additional information, please read “—Antero Resources’ Existing Third‑Party Commitments” and “Item 13. Certain Relationships and Related Transactions.”

 

In connection with the formation of the Joint Venture, we and Antero Resources amended and restated our right of first offer agreement in order to, among other things, amend the list of conflicting dedications set forth in such agreement to include the gas processing and NGL fractionation arrangement between Antero Resources and MarkWest. Pursuant to such gas processing and NGL fractionation agreements, Antero has dedicated 195,000 gross acres of processing and fractionation to MarkWest for processing and fractionation, which has separately agreed to use the Joint Venture for a portion of processing and fractionation services. 

 

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, 2017, the excluded acreage consisted of approximately 156,000 of Antero Resources’ existing net leasehold acreage. At that same date, approximately 950 of Antero Resources’ 4,133 potential horizontal well locations were located within the excluded acreage.

 

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 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 our gathering and compression agreement and water handling and treatment services agreement with Antero Resources. 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 and treatment systems. In addition, these third parties may develop their own gathering and compression and water handling and treatment 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 Federal Energy Regulatory Commission, or 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,

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increase operating costs, and, depending on the facility in question, could adversely affect Antero Midstream’s results of operations and cash flows. In addition, if any of Antero Midstream’s facilities were found to have provided services or otherwise operated in violation of the ICA, this could result in the imposition of administrative and civil remedies and criminal penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC.

 

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint‑based rate regulation. States in which we operate may adopt ratable take and common purchaser statutes, which would require our gathering pipelines to take natural gas without undue discrimination in favor of one producer over another producer or one source of supply over another similarly situated source of supply. The regulations under these statutes may have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. States in which we operate may also adopt a complaint‑based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such regulation will be adopted and whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our system due to state regulations.

 

Our gathering operations could be adversely affected should they be subject in the future to more stringent application of state regulation of rates and services. Our gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

 

The Energy Policy Act of 2005, 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 $1,000,000 per day per violation. On January 9, 2017, FERC issued an order (Order No. 834) 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 $1,213,503 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 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;

 

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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 strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. 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. Effective April 27, 2017, those maximum civil penalties were increased to $209,002 per violation per day, with a maximum of $2,090,022 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.

 

On June 22, 2016, the President signed into law new legislation entitled Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, or the PIPES Act. The PIPES Act reauthorizes 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 the 2011 Pipeline Safety Act, of which approximately twelve remain to be completed. The mandates yet to be acted upon include requiring certain shut-off valves on transmission lines, mapping all high consequence areas, and shortening the deadline for accident and incident notifications.

 

PHMSA regularly revises its pipeline safety regulations. For example, in March of 2015, PHMSA finalized new rules applicable to gas and hazardous liquid pipelines that, among other changes, impose new post-construction inspections, welding, gas component pressure testing requirements, as well as requirements for calculating pressure reductions for immediate repairs on liquid pipelines. In addition, in May 2016, PHMSA proposed rules that would, if adopted, impose more stringent requirements for certain gas lines. Among other things, the proposed rulemaking would extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond ‘‘high consequence areas’’ to cover gas pipelines found in newly defined ‘‘moderate consequence areas’’ that contain as few as five dwellings within the potential impact area and would also require gas pipelines installed before 1970 that are currently exempted from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures, or MAOP. Other new requirements proposed by PHMSA under rulemaking would require pipeline operators to: report to PHMSA in the event of certain MAOP exceedances; strengthen PHMSA integrity management requirements; consider seismicity in evaluating threats to a pipeline; conduct hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and use more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. The proposed rulemaking also seeks to impose a number of requirements on natural gas gathering lines. More recently, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a high consequence area. The final rule would also impose new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, implementation of this rule has been delayed as a result of the change in U.S. Presidential Administrations, and the final rule is not expected to be published by the Federal Register until the second quarter of 2018. Separately, in March 2017, new PHMSA rules related to gas and hazardous liquid pipeline accident reporting, control room personnel training requirements, personnel drug and alcohol testing, and incorporating consensus standards by reference for integrity management issues such as in-line inspection and stress corrosion cracking direct assessment became effective.

 

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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. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

 

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. In addition to regulatory changes, costs may be incurred when there is an accidental release of a commodity transported by our system, or a regulatory inspection identifies a deficiency in our required programs.

 

Regulation of Environmental and Occupational Safety and Health Matters

 

General

 

Our natural gas gathering and compression and water handling and treatment activities are subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

 

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

 

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

 

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

 

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

 

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

 

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and natural resource damages. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or solid wastes have been disposed or otherwise released. Moreover, neighboring landowners and other third parties may file common law claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or solid waste into the environment.

 

The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. As with the midstream industry in general, complying with current and anticipated environmental laws and regulations can increase our capital costs to construct, maintain and operate equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we do not believe they will have a material adverse effect on our business, financial position, results of operations or cash flows, nor do we believe that they will affect our competitive position since the operations of our competitors are generally similarly affected. In addition, we believe that the various activities in which we are presently engaged that are subject to environmental laws and regulations are not expected to materially interrupt or diminish our operational ability to gather natural gas and provide water handling and treatment services. We cannot assure you, however, that future events, such as changes in existing

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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 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. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of Congress to provide for such regulation. 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 or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of water and natural gas that move through our systems, which in turn could materially adversely affect our revenues and results of operations.

 

Hazardous Waste

 

Antero Midstream and Antero Resources’ operations generate solid wastes, including some 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. 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. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. Any revisions to Subtitle D would have to be finalized by 2021. 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.

 

Our Clearwater Facility and adjacent Antero Landfill operate pursuant to West Virginia Department of Environmental Protection (“DEP”) permits for the management of stormwater and waste water 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, 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 Antero 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

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or criminal penalties and/or remedial obligations to remove previously disposed radioactive wastes and remediate contaminated property.

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 liability for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment and for damages to natural resources.

 

We currently own or lease, and may have in the past owned or leased, properties that have been used for the gathering and compression of natural gas and the gathering and transportation of oil. Although we typically used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by it or on or under other locations where such substances have been taken for disposal. Such petroleum hydrocarbons or wastes may have migrated to property adjacent to our owned and leased sites or the disposal sites. In addition, some of the properties may have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes, including waste disposed of by prior owners or operators; remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform remedial operations to prevent future contamination. We are not currently a potentially responsible party in any federal or state Superfund site remediation and there are no current, pending or anticipated Superfund response or remedial activities at or implicating our facilities or operations.

 

Air Emissions

 

The federal Clean Air Act, and comparable state laws, regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and also impose various emission limits, operational limits and monitoring, reporting and recordkeeping requirements on air emission sources. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. These laws are frequently subject to change. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard, or NAAQS, for ozone from 75 to 70 parts per billion. In November 2017, the EPA published a partial list of attainment designations for the 2015 ozone standard. The EPA issued preliminary non-attainment designations in December 2017, and has announced that they plan to issue final attainment status designations during the first half of 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”

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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. The rule, which was supposed to have become effective in August 2015, has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs, and implementation of the rule has been stayed pending resolution of the court challenge. In January 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction to review the rule. Now that the Supreme Court has established the proper jurisdiction for the litigation, several district court cases that had been put on hold could be restarted, and it unclear how the Trump Administration will defend the rule. Following the issuance of a presidential executive order to review the rule, the EPA and the Corps proposed a rulemaking to repeal the rule in June 2017; the EPA and Corps also announced their intent to issue a new rule defining the CWA’s jurisdiction. In November 2017, the EPA and the Corps proposed postponing by two years the effective date of the rule until at least 2020, which would provide the agencies more time to potentially repeal and replace the rule. As a result, future implementation of the rule is uncertain at this time. To the extent the 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.

 

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 we maintain all material discharge permits necessary to conduct our operations, and further 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 compliance with worker health and safety requirements will have a material adverse effect on our business or operations.

 

Endangered Species

 

The Endangered Species Act, or ESA, and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our operating activities that could have an adverse impact on our results of operations.

 

Climate Change

 

The EPA has determined that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s

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atmosphere and other climatic changes. Based on these findings, EPA has adopted regulations under existing provisions of the federal Clean Air Act, that establish Prevention of Significant Deterioration, or PSD, pre‑construction permits, and Title V operating permits for GHG emissions from certain large stationary sources. 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, on a case‑by‑case basis. 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 that set emissions standards for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. In June 2017, the EPA proposed to stay these requirements for two years and revisit the entirety of the 2016 standards. Comments to the EPA’s proposal were due in August 2017.  The EPA has not yet published a final rule staying the methane NSPS.  As a result of these developments, future implementation of the 2016 standards is uncertain at this time. These rules (and any additional regulations) could impose new compliance costs and permitting burdens on natural gas operations. In addition, the United States (along with numerous other nations) agreed to the Paris Agreement on climate change in December 2015, which agreement entered into force in November 2016. However, in June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and in August 2017, the U.S. State Department officially informed the United Nations of the United States’ intent to withdraw from the Paris Agreement to seek negotiations either to re-enter the Paris Agreement on different terms or to establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time. Additionally, while Congress has from time to time considered legislation to reduce emissions of GHGs, the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. Although it is not possible at this time to predict how any new legislation or regulations (including any such matters relating to the Paris Agreement) that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit or otherwise address emissions of GHGs could adversely affect demand for the oil and natural gas that exploration and production operators produce, some of whom are our customers, which could thereby reduce demand for our midstream services. Finally, it should be noted that some 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.

 

Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for energy infrastructure projects, such as pipelines and terminal facilities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time.

 

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 2017, nor do we anticipate that such expenditures will be material in 2018.

 

Employees

 

We do not have any employees. The officers of AMP GP and its subsidiaries and affiliates (our “general partner”), who are also officers of Antero Resources, manage our operations and activities. As of December 31, 2017, Antero Resources employed approximately 593 people who provide support to our operations. All of the employees required to conduct and support our operations are employed by Antero Resources. Antero Resources considers its relations with its employees to be satisfactory. Additionally, we have a secondment agreement whereby Antero Resources provides seconded employees to perform certain operational services with respect to our assets for a 20-year period that commenced on the Water Acquisition date.

 

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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. 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.

 

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 make available free of charge our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, and our Current Reports on Form 8-K 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 Relations” link.

 

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

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Item 1A.  Risk Factors 

 

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” in evaluating an investment in our common units.

 

If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected.

 

Risks Related to Our Business

 

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 for the foreseeable future. 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 revenues and cash available for distribution. 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 and treatment services;

 

a reduction in or slowing of Antero Resources’ well completions, which would directly and adversely impact demand for our water handling and treatment services;

 

the volatility of natural gas, NGLs and oil prices, which could have a negative effect on the value of Antero Resources’ properties, its drilling programs or its ability to finance its operations;

 

the availability of capital on an economic basis to fund Antero Resources’ exploration and development activities as well as to fund our capital expenditure programs;

 

Antero Resources’ ability to replace reserves;

 

Antero Resources’ drilling and operating risks, including potential environmental liabilities;

 

transportation and processing capacity constraints and interruptions;

 

adverse effects of governmental and environmental regulation; and

 

losses from pending or future litigation.

 

In late 2014, global energy commodity prices declined precipitously as a result of several factors, including an increase in worldwide commodity supplies, a stronger U.S. dollar, relatively mild weather in large portions of the U.S., and strong competition among some oil producing countries for market share.  Commodity prices remained depressed prices in 2015 and 2016, although a modest recovery began in late 2016, and has continued intermittently in 2017 and 2018.

 

Changes in commodity prices can significantly affect Antero Resources’ operations and financial condition, and therefore our capital resources, liquidity, and expected operating results. 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 and

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treatment services are directly associated with Antero Resources’ well completion activities and water needs, which are partially driven by horizontal lateral lengths and the number of completion stages per well. Any decrease in volumes of natural gas and produced water that Antero Resources produces or any decrease in the number of wells that Antero Resources completes could adversely affect our business 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 and treatment services agreements. We cannot predict the extent to which Antero Resources’ business would be impacted if conditions in the energy industry deteriorate, nor can we estimate the impact such conditions would have on Antero Resources’ ability to execute its drilling and development program or perform under our gathering and compression and water handling and treatment services agreements. Any material non-payment or non-performance by Antero Resources could reduce our ability to make distributions to our unitholders.

 

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 on our ability to access capital as a result of such adverse changes at Antero Resources 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 unit 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 could also 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, 2017 (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.

 

We may not generate sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to our unitholders.

 

In order to make our minimum quarterly distribution of $0.17 per common unit per quarter, or $0.68 per unit per year, we will require available cash of approximately $32 million per quarter, or approximately $127 million per year based on the common units outstanding at December 31, 2017, as well as grants made under the Antero Midstream Partners LP Long-term Incentive Plan. We may not generate sufficient cash flows each quarter to support the payment of the minimum quarterly distribution or to increase our quarterly distributions in the future from the fourth quarter of 2017 level of $0.365 per unit.

 

The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

the volume of natural gas we gather and compress and the volume of water we handle and treat in connection with well completion operations;

the rates we charge third parties, if any, for our water handling and treatment and gathering and compression services;

 

market prices of natural gas, NGLs and oil and their effect on Antero Resources’ drilling schedule as well as produced volumes;

 

Antero Resources’ ability to fund its drilling program;

 

adverse weather conditions;

 

the level of our operating, maintenance and general and administrative costs;

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regulatory action affecting the supply of, or demand for, natural gas, the rates we can charge for our services, how we contract for services, our existing contract, our operating costs or our operating flexibility; and

 

prevailing economic conditions.

 

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

 

the level and timing of maintenance and expansion capital expenditures we make;

 

our debt service requirements and other liabilities;

 

our ability to borrow under our debt agreements to pay distributions;

 

fluctuations in our working capital needs;

 

restrictions on distributions contained in any of our debt agreements;

 

the cost of acquisitions, if any;

 

fees and expenses of our general partner and its affiliates (including Antero Resources) we are required to reimburse;

 

the amount of cash reserves established by our general partner; and

 

other business risks affecting our cash levels.

 

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 and treatment services are directly associated with Antero Resources’ well completion activities and water needs, which are partially driven by horizontal lateral lengths and the number of completion stages per 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 natural gas 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 wells, revenues for our gathering and compression and water handling and treatment services will be directly and adversely affected. Our ability to maintain water handling and treatment services revenues is substantially dependent on continued completion activity by Antero Resources or third parties over time, as well as the volumes of produced water 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 and (iii) our ability to obtain dedications of acreage from third parties. Our fresh water delivery services, which make up a substantial portion of our water handling and treatment services revenues, will be in greatest demand in connection with completion activities. To the extent that Antero Resources or other fresh water delivery customers complete wells with shorter lateral lengths, the demand for our fresh water delivery services would be reduced.

 

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We have no control over Antero Resources’ or other producers’ levels of development and completion activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, our water handling and treatment business is dependent upon active development in our areas of operation. In order to maintain or increase throughput levels on our water handling and treatment systems, we must service new wells. We have no control over Antero Resources or other producers or their development plan decisions, which are affected by, among other things:

 

the availability and cost of capital;

 

prevailing and projected natural gas, NGLs and oil prices;

 

demand for natural gas, NGLs and oil;

 

quantities of reserves;

 

geologic considerations;

 

environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

 

the costs of producing the gas and the availability and costs of drilling rigs and other equipment.

 

Fluctuations in energy prices can also greatly affect the development of reserves. In late 2014, global energy commodity prices declined precipitously as a result of several factors, including an increase in worldwide commodity supplies, a stronger U.S. dollar, relatively mild weather in large portions of the U.S., and strong competition among some oil producing countries for market share.  Commodity prices remained depressed prices in 2015 and 2016, although a modest recovery began in late 2016, and has continued intermittently in 2017 and 2018.

 

These lower prices have compelled most natural gas and oil producers, including Antero Resources, to reduce the level of exploration, drilling and production activity. 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 would reduce our revenues and ability to pay distributions. Sustained reductions in development or production activity in our areas of operation could lead to reduced utilization of our services.

 

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. If reductions in development activity result in our inability to maintain the current levels of throughput on our systems, or our water handling and treatment services, or if reductions in lateral lengths result in a decrease in demand for our water handling and treatment services on a per well basis, those reductions could reduce our revenue and cash flows and adversely affect our ability to make cash distributions to our unitholders.

 

Finally, each of the gathering and compression agreement, water services agreement and right of first offer agreement permit between us and Antero Resources 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. Any such dispositions could adversely affect our business and operating results.

 

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 that we construct subsequent to our initial public offering in November 2014 at Antero

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Resources’ request. The high pressure pipelines and compressor stations that existed prior to our initial public offering are not supported by minimum volume commitments from Antero Resources. Any decrease in the current levels of throughput on our gathering and compression systems could reduce our revenue and cash flows and adversely affect our ability to make cash distributions to our unitholders.

 

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, our ability to make cash distributions may be diminished 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 will be unable to expand our business operations and, as a result, we will be unable to raise the level of our future cash distributions. To fund our expansion capital expenditures and investment capital expenditures, we will be required to use cash from our operations or incur borrowings. Alternatively, we may sell additional common units or other securities to fund our capital expenditures. Such uses of cash from our operations will reduce cash available for distribution to our unitholders. 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. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the then current distribution rate, which could materially decrease our ability to pay distributions at the prevailing distribution rate. Neither Antero Resources, our general partner or any of their respective Affiliates is committed to providing any direct or indirect support to fund our growth.

 

Our gathering and compression and water handling and treatment 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 gathering and compression and water handling and treatment systems that we own, which are 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 governmental regulation, market limitations or interruption of the compression or transportation of natural gas, NGLs or oil.

 

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flows and not solely on profitability, which may prevent us from making distributions, even during periods in which we record net income.

 

You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flows and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record a net loss for financial accounting purposes, and conversely, we might fail to make cash distributions during periods when we record net income for financial accounting purposes.

 

Our construction or purchase of new gathering and compression, processing, water handling and treatment or other assets, including the water treatment facility currently undergoing testing and commissioning, may not be completed on schedule, at the budgeted cost or at all, and they may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our cash flows, results of operations and financial condition and, as a result, our ability to distribute cash to our unitholders.

 

The construction of additions or modifications to our existing systems and the construction or purchase of new assets, including the water treatment facility currently undergoing testing and commissioning, 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. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, the

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construction of the water treatment facility will occur over an extended period of time, and we will not receive any material increases in revenues until the project is completed. Moreover, 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 and treatment or other assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions 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 make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

 

The success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our business, results of operations and financial condition and, as a result, our ability to make cash distributions to our unitholders.

 

In addition, our revolving credit facility and the indenture governing our senior notes impose certain limitations on our ability to enter into mergers or combination transactions. Our revolving credit facility and the indenture 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 its 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. Accordingly, 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, which could reduce our cash available for distribution to our unitholders. In addition, differences in views among the owners of the Joint Venture could result in delayed decisions or in failures to agree on significant matters, potentially adversely affecting the business and results of operations or prospects of the Joint Venture and, in turn, the amount of cash from the Joint Venture operations distributed to us.

 

If the Joint Venture is not successful or if the Joint Venture does not perform as expected, our future financial performance may be negatively impacted.

 

We may be exposed to certain risks in connection with our ownership interest in the Joint Venture, including regulatory, environmental and litigation risks. If such risks or other anticipated or unanticipated liabilities were to materialize, any desired benefits of our entry into the Joint Venture may not be fully realized, if at all, and its future financial performance may be negatively impacted.

 

In addition, the Joint Venture may result in other difficulties including, among other things:

 

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diversion of our management’s attention from other business concerns;

 

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.

 

The Joint Venture assets consist of processing plants in West Virginia and a one third interest in a fractionator in Ohio (the “MarkWest fractionator”). Any significant interruption at these facilities would adversely affect the Joint Venture’s operations.

 

We do not operate the MarkWest fractionator, and the operations of the Joint Venture’s processing facilities and the MarkWest fractionator could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within its control, such as:

 

unscheduled turnarounds or catastrophic events, including damages to facilities, related equipment and surrounding properties caused by earthquakes, tornadoes, hurricanes, floods, fires, severe weather, explosions and other natural disasters;

 

restrictions imposed by governmental authorities or court proceedings;

 

labor difficulties that result in a work stoppage or slowdown;

 

a disruption in the supply of NGL’s to the Joint Venture’s processing and fractionation plants and associated facilities;

 

disruption in the supply of power, water and other resources necessary to operate the Joint Venture’s facilities

 

damage to the Joint Venture’s facilities resulting from NGLs that do not comply with applicable specifications; and

 

inadequate fractionation capacity or market access to support production volumes, including lack of availability of rail cars, barges, trucks and pipeline capacity, or market constraints, including reduced demand or limited markets for certain NGL products.

 

In addition, MarkWest’s NGL 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 under construction or other pipeline projects are not completed, Antero Resources’, and correspondingly the Partnership’s, future growth may be limited.

 

Antero Resources has secured sufficient long term firm takeaway capacity on major pipelines that are in existence or currently under construction in each of its core operating areas to accommodate its current development plans; however, any failure of any pipeline under construction to be completed, or any unavailability of existing takeaway pipelines, 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 utilization of our, which could adversely affect our operating margin, cash flows and ability to make cash distributions to our unitholders.

 

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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 and equipment costs, which could have a material adverse effect on our business and results of operations.

 

Gathering and compression and water handling and treatment services require special equipment and laborers skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. The employees supporting our operations are employees of Antero Resources. If Antero Resources experiences shortages of necessary equipment or skilled labor in the future, our allocation of labor and equipment costs and overall productivity could be materially and adversely affected. If our allocation of equipment or labor prices increase or if Antero Resources experiences materially increased health and benefit costs for employees, our 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, cash flows and ability to make cash distributions to our unitholders 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. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. 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, cash flows and ability to make cash distributions to our unitholders 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 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, results of operations and financial condition and, as a result, our ability to make cash distributions to our unitholders.

 

Restrictions in our existing and future debt agreements could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

 

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

 

incur or guarantee additional debt;

 

redeem or repurchase units or make distributions under certain circumstances;

 

make certain investments and acquisitions;

 

incur certain liens or permit them to exist;

 

enter into certain types of transactions with affiliates;

 

merge or consolidate with another company; and

 

transfer, sell or otherwise dispose of assets.

 

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The indenture 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 ratios and tests. 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 not meet a financial covenant.

 

The provisions of our revolving credit facility and the indenture 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 indenture 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 the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

 

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, results of operations and cash flows could be materially and adversely affected.

 

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

 

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 results of operations and cash flows. The FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations of up to $1,213,503 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.”

 

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Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas, NGLs and oil production by our customers, which could reduce the throughput on our gathering and compression systems and the number of wells for which we provide water handling and treatment services, which could adversely impact our revenues.

 

All of Antero Resources’ natural gas, NGLs and oil production is being 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. 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. In addition, 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 some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts:  water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.  Since 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. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of Congress from time to time to provide for such regulation. Antero Midstream 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 or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of liquids and natural gas that move through our gathering systems or reduce the number of wells drilled and completed that require fresh water for hydraulic fracturing activities, which in turn could materially adversely affect our revenues and results of operations.

 

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 depend on Antero Resources to source the fresh water we deliver. The availability of Antero Resources’ water supply may be limited due to reasons such as prolonged drought. Some state and local governmental authorities have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to ensure adequate local water supply. Any such decrease in the demand for water handling and treatment services would adversely affect our business and results of operations.

 

Antero Resources 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

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obligations for pollution or contamination resulting from our and our customer’s operations. Failure to comply with these laws, regulations and permits may result in joint and several, strict liability and the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our gathering systems pass and facilities where wastes resulting from our operations are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenues, which in turn could affect our profitability. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability. For example, 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 a 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.

 

Our operations also pose risks of environmental liability due to 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 our 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 some 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. 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. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business.

Our Clearwater Facility and adjacent Antero Landfill operate pursuant to West Virginia DEP permits for the management of stormwater and waste water 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

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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, or if we otherwise fails 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.

 

Climate change laws and regulations restricting emissions of “greenhouse gases” (“GHG”) could result in increased operating costs and reduced demand for the natural gas that we gather while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

 

The EPA has determined that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, EPA has adopted regulations under existing provisions of the federal Clean Air Act, that establish Prevention of Significant Deterioration, or PSD, pre‑construction permits, and Title V operating permits for GHG emissions from certain large stationary sources. 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, on a case‑by‑case basis. 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. As noted above, in June 2016, the EPA finalized new regulations 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. However, in June 2017, the EPA proposed to stay implementation of the new regulations for two years and revisit the entirety of the 2016 standards. Comments to the EPA’s proposal were due in August 2017. The EPA has not yet published a final rule. As a result of these developments, future implementation of the 2016 standards is uncertain at this time. These rules (and any additional regulations) could impose new compliance costs and permitting burdens on natural gas and midstream operations.

 

In addition, the United States (along with numerous other nations) agreed to the Paris Agreement on climate change in December 2015, which agreement entered into force in November 2016. However, in June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and in August 2017, the U.S. State Department officially informed the United Nations of the United States’ intent to withdraw from the Paris Agreement to seek negotiations either to re-enter the Paris Agreement on different terms or to establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time. While Congress has from time to time considered legislation to reduce emissions of GHGs, the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. 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 that limit emissions of GHGs could adversely affect demand for the oil and natural gas that exploration and production operators produce, some of whom are our customers, which could thereby reduce demand for our midstream services.

 

Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for energy infrastructure projects, such as pipelines and terminal facilities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time.

 

Finally, it should be noted that some 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, 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 our financial condition and operations.

 

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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, or 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 “high consequence areas.” The regulations require operators to:

 

perform ongoing assessments of pipeline integrity;

 

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

 

improve data collection, integration and analysis;

 

repair and remediate the pipeline as necessary; and

 

implement preventive and mitigating actions.

 

The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, or 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 high consequence areas. Consistent with the 2011 Pipeline Safety Act,, the Pipelines and Hazardous Materials Safety Administration, or 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 April 2017, those maximum civil penalties were increased to $209,002 and $2,090,022, 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 signed into law important new legislation entitled Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, or the PIPES Act. The PIPES Act reauthorizes 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 twelve remain to be completed. The mandates yet to be acted upon include requiring certain shut-off valves on transmission lines, mapping all high consequence areas, and shortening the deadline for accident and incident notifications.

 

PHMSA regularly revises its pipeline safety regulations. For example, in March of 2015, PHMSA finalized new rules applicable to gas and hazardous liquid pipelines that, among other changes, impose new post-construction inspections, welding, gas component pressure testing requirements, as well as requirements for calculating pressure reductions for immediate repairs on liquid pipelines. More recently, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a high consequence area. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, implementation of this rule has been delayed as a result of the change in U.S. Presidential Administrations, and the final rule is not expected to be published in the Federal Register until the second quarter of 2018. Separately, in March 2017, new PHMSA rules related to gas and hazardous liquid pipeline accident reporting, control room personnel training requirements, personnel drug and alcohol testing, and incorporating consensus standards by reference for integrity management issues such as in-line inspection and stress corrosion cracking direct

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assessment became effective. Additional future regulatory action expanding PHMSA jurisdiction and imposing stricter integrity management requirements is likely. For example, in May 2016, PHMSA proposed rules that would, if adopted, impose more stringent requirements for certain gas lines. Among other things, the proposed rulemaking would extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond “high consequence areas” to cover gas pipelines found in newly defined “moderate consequence areas” that contain as few as 5 dwellings within the potential impact area and would also require gas pipelines installed before 1970 that are currently exempted from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures, or MAOP.  Other new requirements proposed by PHMSA under the rulemaking would require pipeline operators to: report to PHMSA in the event of certain MAOP exceedances; strengthen PHMSA integrity management requirements; consider seismicity in evaluating threats to a pipeline; conduct hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and use more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. The proposed rulemaking also seeks to impose a number of requirements on gathering lines. 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. 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 ability to distribute cash and, accordingly, the market price for our common units.

 

Our operations are subject to all of the hazards inherent in the provision of the gathering and compression and water handling and treatment 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 and suspension of operations; and

 

hazards experienced by other operators that may affect our operations by instigating increased regulations and oversight.

 

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

 

injury or loss of life;

 

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

 

pollution and other environmental damage;

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regulatory investigations and penalties;

 

suspension of our operations; and

 

repair and remediation costs.

 

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable under policies we are covered under, and neither we nor AMP GP on our behalf 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, results of operations, financial condition and ability to make cash distributions to you.

 

We are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

 

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

 

In addition, new or additional regulations, new interpretations of existing requirements or changes in our operations could also trigger the need for Environmental Assessments or more detailed Environmental Impact Statements under the National Environmental Policy Act and analogous state laws, or that impose new permitting requirements on our operations could result in increased costs or delays of, or denial of rights to conduct, our development programs. For example, in 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. To the extent the 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. The rule has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs, and implementation of the rule has been stayed pending resolution of the court challenge. 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.

 

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The loss of key personnel could adversely affect our ability to operate.

 

We depend on the services of a relatively small group of our general partner’s 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 general partner’s 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.

 

We do not have any officers or employees and rely solely on officers of our general partner and employees of Antero Resources.

 

We are managed and operated by the board of directors of our general partner. Affiliates of Antero Resources conduct businesses and activities of their own in which we have no economic interest. As a result, there could be material competition for the time and effort of the officers and employees who provide services to our general partner and Antero Resources. If our general partner and the officers and employees of Antero Resources do not devote sufficient attention to the management and operation of our business, our financial results may suffer, and our ability to make distributions to our unitholders may be reduced.

 

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, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flows required to make interest payments on our debt;

 

we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

 

our flexibility in responding to changing business and economic conditions may be limited.

 

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, 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.

 

If we cease to be eligible to utilize the equity distribution agreement, our financial flexibility and liquidity could be adversely affected.

 

We have historically used sales of common units pursuant to the equity distribution agreement to partially fund capital expenditures. As of December 31, 2017, we had approximately $157 million of available capacity under the equity distribution agreement. If we cease to be eligible to utilize the equity distribution agreement, we may be required to find alternate sources to fund capital expenditures, which could reduce our financial flexibility and adversely affect our liquidity.

 

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Terrorist or cyber‑attacks and threats could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.

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 and treatment 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, 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, results of operations, financial condition and ability to make cash distributions.

Risks Inherent in an Investment in Us

 

Antero Resources, our general partner and their respective affiliates, including AMGP, which owns our general partner, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.

 

AMGP owns and controls our general partner and appoints all of the officers and directors of our general partner. All of the officers and a majority of the directors of our general partner are officers or directors of AMGP GP LLC, the general partner of AMGP (“AMGP GP”). Similarly, all of the officers and a majority of the directors of our general partner are also officers or directors of Antero Resources. Although our general partner has a duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owner, AMGP. Further, our general partner’s 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, AMGP, and our general partner, on the one hand, and us and our common unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of AMGP or Antero Resources over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

 

actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders;

 

the directors and officers of AMGP have a fiduciary duty to make decisions in the best interests of AMGP and its owners, which may be contrary to our interests;

 

the directors and officers of Antero Resources have a fiduciary duty to make decisions in the best interests of the owners of Antero Resources, which may be contrary to our interests;

 

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our general partner is allowed to take into account the interests of parties other than us, such as AMGP, in exercising certain rights under our partnership agreement;

 

except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

 

our general partner may cause us to borrow funds in order to permit the payment of cash distributions,

 

our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

 

our general partner determines the amount and timing of any capital expenditure and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus, and this determination can affect the amount of cash from operating surplus that is distributed to our unitholders;

 

our partnership agreement limits the liability of, and replaces the duties owed by, our general partner and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

 

common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us;

 

contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not and will not be the result of arm’s length negotiations;

 

our partnership agreement permits us to distribute up to $75.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus, which may be used to fund distributions on the incentive distribution rights;

 

our general partner determines which costs incurred by it and its affiliates (including Antero Resources) are reimbursable by us;

 

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf;

 

our general partner intends to limit its liability regarding our contractual and other obligations;

 

our general partner may exercise its right to call and purchase common units if it and its affiliates (including Antero Resources) own more than 80% of the common units;

 

our general partner controls the enforcement of obligations that it and its affiliates (including Antero Resources) owe to us;

 

we may not choose to retain separate counsel for ourselves or for the holders of common units;

 

our general partner’s affiliates may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us; and

 

the holder or holders of our incentive distribution rights may elect to cause us to issue common units to it in connection with a resetting of incentive distribution levels without the approval of our unitholders, which may result in lower distributions to our common unitholders in certain situations.

 

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Certain of our common unitholders have investments in our affiliates that may conflict with the interests of other holders of our common units.

 

Certain funds affiliated with Warburg Pincus LLC (“Warburg”), certain funds affiliated with Yorktown Partners LLC (“Yorktown”), Paul M. Rady and Glen C. Warren, Jr. (collectively, the “Sponsors”) own a significant interest in us.  Affiliates of Warburg and Yorktown, Mr. Rady and Mr. Warren serve as members of the board of directors of our general partner and the board of directors of Antero Resources and AMGP GP, and each of  Warburg and Yorktown are controlled in part by individuals who serve as members of the board of directors of AMGP and the board of directors of Antero Resources.  The Sponsors also own the membership interests in AMGP GP, a majority of the common shares in AMGP, a majority of the Series B Units in IDR LLC, the holder of our IDRs, and a significant portion of the shares of common stock of Antero Resources. Please see “Item 11. Executive Compensation—Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table—Series B Units in IDR LLC” for more information regarding the Series B Units in IDR LLC. As a result of their investments in AMGP, AMGP GP and Antero Resources, the Sponsors may have conflicting interests with other holders of our common units. 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 expenditure and growth plans, decisions to modify or limit the IDRs in the future, the terms of our agreements with Antero Resources and AMGP and their respective subsidiaries, and the pursuit of potentially competitive business activities or business opportunities.

 

Ongoing cost reimbursements due to our general partner and its affiliates for services provided, which are determined by our general partner, will be substantial and will reduce our cash available for distribution to our unitholders.

 

Prior to making distributions on our common units, we reimburse our general partner and its affiliates for all expenses they incur on our behalf. These expenses include all costs incurred by our general partner and its affiliates in managing and operating us, including costs for rendering administrative staff and support services to us and reimbursements paid by our general partner to Antero Resources for customary management and general administrative services. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed under the services agreement. Our partnership agreement provides that our general partner determines the expenses that are allocable to us in good faith. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

 

We expect to distribute a significant portion of our cash available for distribution to our partners, which could limit our ability to grow and make acquisitions.

 

We plan to distribute most of our cash available for distribution, 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 units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. 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 distribute to our unitholders.

 

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our units with contractual standards governing its duties.

 

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions, in its individual capacity, as opposed to in its capacity as our general partner, or otherwise, free of fiduciary duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the parties where the

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language in our partnership agreement does not provide for a clear course of action. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

 

how to allocate business opportunities among us and its other affiliates;

 

whether to exercise its limited call right;

 

how to exercise its voting rights with respect to the units it owns;

 

whether to exercise its registration rights;

 

whether to elect to reset target distribution levels; and

 

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

 

Unitholders are treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.

 

Our partnership agreement limits the liability of, and replaces the duties owed by, our general partner and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

 

Our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

 

our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decision was not adverse to the interest of the partnership, and, with respect to criminal conduct, did not act with the knowledge that its conduct was unlawful;

 

our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged in by it in bad faith or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful; and

 

in resolving conflicts of interest, it will be presumed that in making its decision our general partner, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith.

 

Our partnership agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which limits our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees. Our partnership agreement also provides that any unitholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful action.

 

Our partnership agreement provides that, with certain limited exceptions, the Court of Chancery of the State of Delaware will be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of

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our partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners, (4) asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) or (5) asserting a claim against us governed by the internal affairs doctrine. In addition, if any unitholder brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. Limited partners who own common units irrevocably consent to these limitations, provisions and potential reimbursement obligations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers.

 

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

 

Compared to the holders of common stock in a corporation, unitholders have limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by AMGP, as a result of it owning our general partner, and not by our unitholders. Please read “Item 10. Directors, Executive Officers, and Corporate Governance—Management of Antero Midstream Partners LP” and “Certain Relationships and Related Transactions.” Unlike publicly-traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

Our general partner intends to limit its liability regarding our obligations.

 

Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

 

The holder or holders of our incentive distribution rights may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of our general partner’s board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

 

The holder or holders of a majority of our incentive distribution rights have the right, at any time they have received incentive distributions at the highest level to which they are entitled (50%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election, a baseline distribution amount will be calculated equal to an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (such amount is referred to as the ‘‘reset minimum quarterly distribution’’), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

 

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We anticipate that the holder of our incentive distribution rights would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per unit without such conversion. However, the holder of our incentive distribution rights may transfer the incentive distribution rights at any time. It is possible that the holder of our incentive distribution rights or a transferee could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when the holders of the incentive distribution rights expect that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, the holders of the incentive distribution rights may be experiencing, or may expect to experience, declines in the cash distributions it receives related to the incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for them to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to the holders of the incentive distribution rights in connection with resetting the target distribution levels.

 

The incentive distribution rights may be transferred to a third party without unitholder consent.

 

The holder of our incentive distribution rights may transfer the incentive distribution rights to a third party at any time without the consent of our unitholders. If the incentive distribution rights are transferred to a third party but our general partner retains its general partner interest, our general partner (and its owner, AMGP) may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained indirect ownership of the incentive distribution rights.

 

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity, to incur debt to capture growth opportunities or for other purposes, or to make cash distributions at our intended levels.

 

If interest rates rise, the interest rates on our revolving credit facility, future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, to incur debt to expand or for other purposes, or to make cash distributions at our intended levels.

 

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

 

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates (including Antero Resources), their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

 

Control of our general partner may be transferred to a third party without unitholder consent.

 

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner from transferring all or a portion of their respective ownership interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby exert significant control over the decisions made by the board of directors and officers. This effectively permits a “change of control” without the vote or consent of the unitholders.

 

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We may issue additional units, including units that are senior to the common units, without unitholder approval, which would dilute our unitholders’ existing ownership interests.

 

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

each unitholder’s proportionate ownership interest in us will decrease;

 

the amount of cash available for distribution on each unit may decrease;

 

the ratio of taxable income to distributions may increase;

 

the relative voting strength of each previously outstanding unit may be diminished; and

 

the market price of the common units may decline.

 

Future sales of common units in the public markets or otherwise, which sales could have an adverse impact on the trading price of the common units.

 

As of February 13, 2018, Antero Resources holds 98,870,335 common units. Additionally, we have agreed to provide Antero Resources with certain registration rights, pursuant to which we may be required to register the common units they hold under the Securities Act and applicable state securities laws. Pursuant to the registration rights agreement and our partnership agreement, we may be required to undertake a future public or private offering of common units and use the net proceeds from such offering to redeem an equal number of common units held by Antero Resources.

 

In November 2014, we filed a registration statement on Form S-8 under the Securities Act to register common units issuable under the Antero Midstream Partners Long-Term Incentive Plan (the “Midstream LTIP”).  Subject to applicable vesting requirements, Rule 144 limitations applicable to affiliates and the expiration of lock-up agreements, common units registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

 

Future sales of common units in public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

 

Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

 

If at any time our general partner and its affiliates (including Antero Resources) own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (i) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, or the Exchange Act. Our general partner and its affiliates (including Antero Resources) own an aggregate of 52.9% of our common units.

 

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Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

 

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we own assets and conduct business in West Virginia and Ohio. You could be liable for any and all of our obligations as if you were a general partner if:

 

a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

 

your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

 

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

 

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

The New York Stock Exchange does not require a publicly-traded partnership like us to comply with certain of its corporate governance requirements.

 

Our common units are listed on the NYSE under the symbol “AM.” Because we are a publicly-traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Item 10. Directors, Executive Officers, and Corporate Governance—Management of Antero Midstream Partners LP.”

 

Tax Risks to Common Unitholders

 

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to a material amount of entity-level taxation. If the IRS were to treat us as a corporation for federal income tax purposes, or if we were to become subject to entity-level taxation for state tax purposes, our cash available for distribution to our unitholders would be substantially reduced.

 

The anticipated after tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

 

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. We have requested and obtained a favorable private letter ruling from the IRS to the effect that, based on the facts presented in the private letter ruling request, income from fresh water delivery services is qualifying income for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

 

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If we were treated as a corporation for federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flows and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

 

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us. We own assets and conduct business in West Virginia and Ohio. Several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, Ohio imposes a commercial activity tax of 0.26% on taxable gross receipts with a “substantial nexus” with Ohio. Imposition of a similar tax on us in other jurisdictions that we may expand to could substantially reduce our cash available for distribution to our unitholders.

 

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly applied on a retroactive basis.

 

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

 

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017.  We do not believe the Final Regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.

 

However, any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or ultimately will be enacted. Any similar or future legislative changes could negatively impact the value of an investment in our common units. Our unitholders are urged to consult with their own tax advisors with respect to the status of regulatory or administrative developments and proposals and their potential effect on their investment in our common units.

 

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders.

 

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the conclusions of our counsel or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in our cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

 

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any

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taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders behalf.

 

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

 

Even if unitholders do not receive any cash distributions from us, unitholders will be required to pay taxes on their share of our taxable income.

 

Unitholders are required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from them with respect to that income.

 

In response to current market conditions, we may engage in transactions to deliver and manage our liquidity that may result in income and gain to our unitholders without a corresponding cash distribution.   For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, unitholders may be allocated taxable income and gain resulting from the sale without receiving a cash distribution.  Further, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect of any such allocations will depend on the unitholder's individual tax position with respect to its units. Unitholders are encouraged to consult their tax advisors with respect to the consequences to them of COD income.

 

Tax gain or loss on disposition of our common units could be more or less than expected.

 

If a unitholder sells common units, such unitholder will recognize a gain or loss equal to the difference between the amount realized and that unitholder’s  tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease such unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the units that unitholder sells will, in effect, become taxable income to such unitholder if  the units are sold at a price greater than the unitholder’s tax basis in those units, even if the price the unitholder receives is less than its original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its common units, the unitholder may incur a tax liability in excess of the amount of cash it receives from the sale.

 

A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income to such unitholder due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to

46


 

such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

 

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

 

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.

 

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.

 

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit. 1 Note to Draft: To be discussed with Antero.

 

The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interest in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our common units.

 

Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

 

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.

 

We treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

 

Because we cannot match transferors and transferees of our common units and because of other reasons, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury regulations. Our counsel is unable to opine as to the validity of this approach. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns.

47


 

 

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

 

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date.  Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 

A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and could recognize gain or loss from the disposition.

 

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

 

We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.

 

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

 

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain recognized from the sale of our common units, have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

 

Unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of investing in our common units.

 

In addition to U.S. federal income taxes, our unitholders may be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements.

 

48


 

We own assets and conduct business in West Virginia and Ohio, each of which imposes a personal income tax on individuals. If we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is each unitholder’s responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

 

Item 1B.  Unresolved Staff Comments

 

Not applicable.

 

Item 3.  Legal Proceedings 

 

Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. 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.

 

49


 

PART II

 

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

 

Common Units

 

Our common units are listed on the New York Stock Exchange and traded under the symbol “AM.” On February 9, 2018, our common units were held by 8 holders of record.  The number of holders does not include the holders for whom units are held in a “nominee” or “street” name. In addition, as of February 13, 2018, Antero Resources and its affiliates owned 98,870,335 of our common units, which represents a 52.9% limited partner interest in us.

 

The table below reflects the high and low intraday sales prices per share of our common units on the New York Stock Exchange for each period presented:

 

 

 

 

 

 

 

 

 

 

 

 

 

Common Unit

 

Distributions per

 

    

High

    

Low

    

Common Unit

2017:

 

 

 

 

 

 

 

 

 

Quarter ended December 31, 2017

 

$

32.20

 

 

25.71

 

$

0.3650

Quarter ended September 30, 2017

 

 

35.10

 

 

30.48

 

 

0.3400

Quarter ended June 30, 2017

 

 

35.55

 

 

29.62

 

 

0.3200

Quarter ended March 31, 2017

 

 

35.74

 

 

30.45

 

 

0.3000

2016:

 

 

 

 

 

 

 

 

 

Quarter ended December 31, 2016

 

$

31.39

 

 

25.93

 

$

0.2800

Quarter ended September 30, 2016

 

 

28.72

 

 

24.61

 

 

0.2650

Quarter ended June 30, 2016

 

 

27.96

 

 

20.52

 

 

0.2500

Quarter ended March 31, 2016

 

 

27.01

 

 

17.00

 

 

0.2350

 

Issuer Purchases of Equity Securities

 

The issuer purchases of equity securities during the fourth quarter of 2017 primarily relates to shares purchased to cover the tax resulting from units that vested in November 2017 under the Midstream LTIP.

 

 

 

 

 

 

 

 

 

 

 

 

Period

    

Number of Shares Purchased

    

 

Average Price Paid per Share

    

 

Total Number of Shares Purchased as Part of Publicly Announced Plans

    

Maximum Number of Shares that May Yet be Purchased Under the Plan

October 1, 2017 - October 31, 2017

  

601

 

$

31.11

 

 

 —

 

N/A

November 1, 2017 - November 30, 2017

  

182,302

 

$

27.40

 

 

 —

 

N/A

December 1, 2017 - December 31, 2017

  

 —

 

$

 —

 

 

 —

 

N/A

 

Securities Authorized for Issuance Under Equity Compensation Plans

 

In connection with the completion of our IPO, our general partner adopted the Midstream LTIP, which permits the issuance of up to 10,000,000 common units.  Restricted unit grants have been made to each of the independent directors of our general partner and phantom unit grants have been made to each of the executive officers of our general partner under the Midstream LTIP.  Please read the information under “Item 11.  Executive Compensation – Compensation Discussion and Analysis – Equity Compensation Plan Information.”

 

Our Minimum Quarterly Distribution

 

Our partnership agreement provides for a minimum quarterly distribution of $0.17 per unit for each whole quarter, or $0.68 per unit on an annualized basis.

 

50


 

The board of directors of our general partner has adopted a policy pursuant to which distributions for each quarter will be paid to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates.  Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors.

 

If cash distributions to our unitholders exceed $0.1955 per common unit in any quarter, our unitholders and the holders of our IDRs will receive distributions according to the following percentage allocations:

 

 

 

 

 

 

 

 

 

Marginal Percentage

 

 

 

Interest in

 

 

 

Distributions

 

Total Quarterly Distribution

 

 

 

 

 

Target Amount

    

Unitholders

    

IDR Holders

 

above $0.1955 up to $0.2125

    

85

%  

15

%

above $0.2125 up to $0.2550

 

75

%  

25

%

above $0.2550

 

50

%  

50

%

 

There is no guarantee that we will make cash distributions to our unitholders.  We do not have a legal or contractual obligation to pay distributions quarterly or on any other basis or at our minimum quarterly distribution rate or at any other rate.  Our cash distribution policy may be changed at any time and is subject to certain restrictions, including our partnership agreement, our credit facility and applicable partnership law.

 

General Partner Interest

 

Our general partner owns a non‑economic general partner interest in us, which does not entitle it to receive cash distributions. However, the owner of our general partner controls the owner of our IDRs and is entitled to receive a portion of the distributions on our IDRs due to its indirect ownership of our IDRs.

 

Cash Distributions and Conversion of Subordinated Units

 

Antero Resources was issued all of our subordinated units in connection with our IPO. The principal difference between our common units and subordinated units was that, for any quarter during the subordination period, holders of the subordinated units were not entitled to receive any distribution from operating surplus until the common units had received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units did not accrue arrearages. Under the terms of our partnership agreement, the subordination period was to end on the first business day after distributions from operating surplus equaled or exceeded $1.02 per unit (150% of the annualized minimum quarterly distribution) on all outstanding common units and subordinated units for a four-quarter period immediately preceding that date.

 

Upon payment of the February 8, 2017 distribution to unitholders, the requirements for the conversion of all subordinated units were satisfied under our partnership agreement. As a result, effective February 9, 2017, the 75,940,957 subordinated units owned by Antero Resources were converted into common units on a one-for-one basis and now participate on terms equal with all other common units in distributions of available cash. The conversion did not impact the amount of the cash distributions paid by the Partnership or the total units outstanding.

 

On January 16, 2018, the board of directors of our general partner declared a cash distribution of $0.365 per unit for the quarter ended December 31, 2017. The distribution was paid on February 13, 2018 to unitholders of record as of February 1, 2018.

 

51


 

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 Partnership and our Predecessor. Our Predecessor for accounting purposes consisted of Antero Resources’ gathering and compression assets and related operations on a carve-out basis. The Partnership was originally formed as Antero Resources Midstream LLC and converted into a limited partnership in connection with the completion of the Partnership’s IPO on November 10, 2014. The information in this report includes periods prior to the Water Acquisition, which occurred on September 23, 2015. Consequently, the Partnership’s consolidated financial statements have been retrospectively recast for all periods presented to include the historical results of Antero Water, because the Water Acquisition was between entities under common control. Antero Water’s operations through September 23, 2015 consist entirely of fresh water delivery.

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31,

 

 

2013

 

2014

 

2015

 

2016

 

2017

 

 

($ in thousands, except per unit amounts)

Revenue:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenue - Antero Resources

 

$

58,234

 

 

258,029

 

 

386,164

 

 

585,517

 

 

772,233

Revenue - third-party

 

 

 —

 

 

8,245

 

 

1,160

 

 

835

 

 

264

Gain on sale of assets

 

 

 —

 

 

 —

 

 

 —

 

 

3,859

 

 

 —

Total revenue

 

 

58,234

 

 

266,274

 

 

387,324

 

 

590,211

 

 

772,497

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Direct operating

 

 

7,871

 

 

48,821

 

 

78,852

 

 

161,587

 

 

232,538

General and administrative (before equity-based compensation)

 

 

9,716

 

 

18,748

 

 

28,736

 

 

28,114

 

 

31,529

Equity-based compensation

 

 

24,349

 

 

11,618

 

 

22,470

 

 

26,049

 

 

27,283

Impairment of property and equipment

 

 

 —

 

 

 —

 

 

 —

 

 

 —

 

 

23,431

Depreciation

 

 

14,119

 

 

53,029

 

 

86,670

 

 

99,861

 

 

119,562

Accretion of contingent acquisition consideration

 

 

 —

 

 

 —

 

 

3,333

 

 

16,489

 

 

13,476

Total operating expenses

 

 

56,055

 

 

132,216

 

 

220,061

 

 

332,100

 

 

447,819

Operating income

 

 

2,179

 

 

134,058

 

 

167,263

 

 

258,111

 

 

324,678

Interest expense, net

 

 

(164)

 

 

(6,183)

 

 

(8,158)

 

 

(21,893)

 

 

(37,557)

Equity in earnings of unconsolidated affiliates

 

 

 —

 

 

 —

 

 

 —

 

 

485

 

 

20,194

Net income and comprehensive income

 

$

2,015

 

 

127,875

 

 

159,105

 

 

236,703

 

 

307,315

Pre-IPO net income attributed to parent

 

 

(2,015)

 

 

(98,219)

 

 

 —

 

 

 —

 

 

 —

Pre-Water Acquisition net income attributed to parent

 

 

 —

 

 

(22,234)

 

 

(40,193)

 

 

 —

 

 

 —

Net income attributable to incentive distribution rights

 

 

 —

 

 

 —

 

 

(1,264)

 

 

(16,944)

 

 

(69,720)

Limited partners' interest in net income

 

$

 —

 

 

7,422

 

 

117,648

 

 

219,759

 

 

237,595

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income per limited partner unit - basic and diluted

 

$

 —

 

 

0.05

 

 

0.74

 

 

1.24

 

 

1.28

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average limited partner units outstanding - basic

 

 

 —

 

 

151,882

 

 

158,479

 

 

176,647

 

 

185,630

Weighted average limited partner units outstanding - diluted

 

 

 —

 

 

151,882

 

 

158,527

 

 

176,801

 

 

186,083

 

52


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

    

 

 

2013

 

2014

 

2015

 

2016

 

2017

 

  

 

(in thousands)

Balance sheet data (at period end):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

  

$

 —

 

 

230,192

 

 

6,883

  

 

14,042

 

 

8,363

  

 

Property and equipment, net

 

 

793,330

 

 

1,531,595

 

 

1,893,826

 

 

2,195,879

 

 

2,605,602

 

 

Total assets

 

 

808,337

 

 

1,816,610

 

 

1,980,032

 

 

2,349,895

 

 

3,042,209

 

 

Long-term indebtedness

 

 

 —

 

 

115,000

 

 

620,000

 

 

849,914

 

 

1,196,000

 

 

Total capital

 

 

732,061

 

 

1,620,903

 

 

1,082,745

 

 

1,222,810

 

 

1,516,469

 

 

Cash flows data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

38,245

 

 

169,433

 

 

259,678

 

 

378,607

 

 

475,796

 

 

Net cash used in investing activities

 

 

(598,177)

 

 

(797,505)

 

 

(445,455)

 

 

(478,163)

 

 

(779,818)

 

 

Net cash provided by (used in) financing activities

 

 

559,932

 

 

858,264

 

 

(37,532)

 

 

106,715

 

 

298,343

 

 

Other financial data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA(1)

 

 

40,647

 

 

198,705

 

 

279,736

 

 

404,353

 

 

528,625

 

 


(1)For a discussion of the non‑GAAP financial measure 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 Measures” below.

 

Non‑GAAP Financial Measures

 

We view Adjusted EBITDA as an important indicator of our performance. We define Adjusted EBITDA as net income before interest expense, impairment expense, depreciation expense, accretion of contingent acquisition consideration, equity-based compensation expense, gain on asset sale, excluding equity in earnings of unconsolidated affiliates, and including cash distributions from unconsolidated affiliates. 

We use Adjusted EBITDA to assess:

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

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

the viability of acquisitions and other capital expenditure projects.

We define Distributable Cash Flow as Adjusted EBITDA less interest paid, income tax withholding payments and cash reserved for payments of income tax withholding upon vesting of equity-based compensation awards, cash reserved for bond interest, and ongoing maintenance capital expenditures paid, excluding pre-acquisition amounts attributable to the parent.  We use Distributable Cash Flow as a performance metric to compare the cash generating performance of the Partnership from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to unitholders.  Distributable Cash Flow does not reflect changes in working capital balances.

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

“Segment Adjusted EBITDA” is also used by our management team for various purposes, including as a measure of operating performance and as a basis for strategic planning and forecasting. Segment Adjusted EBITDA is a non-GAAP financial measure that we define as operating income before equity-based compensation expense, interest expense, impairment expense, depreciation expense, accretion of contingent acquisition consideration, gain on asset sale,

53


 

excluding pre-acquisition income and expenses attributable to the parent and equity in earnings of unconsolidated affiliates, and including cash distributions from unconsolidated affiliates. Operating income represents net income before interest expense and equity in earnings of unconsolidated affiliates, and is the most directly comparable GAAP financial measure to Segment Adjusted EBITDA because we do not account for interest expense on a segment basis. The following tables represent a reconciliation of our operating income to Segment Adjusted EBITDA for the periods presented (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering and Processing

 

Water Handling and Treatment

 

Consolidated Total

Year ended December 31, 2013

 

 

 

 

 

 

 

 

 

Operating income (loss)

  

$

(14,186)

  

 

16,365

  

 

2,179

Depreciation expense

 

 

11,346

 

 

2,773

 

 

14,119

Equity-based compensation

 

 

15,931

 

 

8,418

 

 

24,349

Segment and consolidated Adjusted EBITDA

 

$

13,091

 

 

27,556

 

 

40,647

 

 

 

 

 

 

 

 

 

 

Year ended December 31, 2014

 

 

 

 

 

 

 

 

 

Operating income

  

$

21,452

  

 

112,606

  

 

134,058

Depreciation expense

 

 

36,789

 

 

16,240

 

 

53,029

Equity-based compensation

 

 

8,619

 

 

2,999

 

 

11,618

Segment and consolidated Adjusted EBITDA

 

$

66,860

 

 

131,845

 

 

198,705

 

 

 

 

 

 

 

 

 

 

Year ended December 31, 2015

 

 

 

 

 

 

 

 

 

Operating income

  

$

103,523

  

 

63,740

  

 

167,263

Depreciation expense

 

 

60,838

 

 

25,832

 

 

86,670

Accretion of contingent acquisition consideration

 

 

 —

 

 

3,333

 

 

3,333

Equity-based compensation

 

 

17,840

 

 

4,630

 

 

22,470

Segment and consolidated Adjusted EBITDA

 

$

182,201

 

 

97,535

 

 

279,736

 

 

 

 

 

 

 

 

 

 

Year ended December 31, 2016

 

 

 

 

 

 

 

 

 

Operating income

  

$

170,861

  

 

87,250

  

 

258,111