Antero Midstream
Annual Report 2015

Plain-text annual report

VALUE CHAIN OPPORTUNITY ANTERO MIDSTREAM OWNED ASSETS F R E S H W T N E M T A E R T R E T A W E T S A W A T E R D E LIV E R Y S E V I C R E R S E T A D W E C U D O R P LOW PRESSURE GATHERING 161 Miles at Year-End 2015 WELL PAD COMPRESSION 820 MMcf/d of Capacity at Year-End 2015 CONDENSATE GATHERING 19 Miles at Year-End 2015 HIGH PRESSURE GATHERING 112 Miles at Year-End 2015 A N T E R O M I D S T R E A M / / 2 0 1 5 A N N U A L R E P O R T ANTERO MIDSTREAM OPTION ASSETS STABILIZATION REGIONAL GAS PIPELINE(1) GAS PROCESSING ANTERO MIDSTREAM HAS THE OPTION TO PARTICIPATE IN PROCESSING, FRACTIONATION, TERMINALING AND STORAGE PROJECTS OFFERED TO ANTERO RESOURCES. STONEWALL GATHERING PIPELINE(1) Miles 50 Capacity In-Service 1.4 Bcf/d YES Y-GRADE PIPELINE FRACTIONATION INTERCONNECT NGL PRODUCT PIPELINES (Ethane, Propane, Butane, etc.) LONG-HAUL INTERSTATE PIPELINE TERMINALS & STORAGE (1) AM holds option to purchase 15% of Stonewall Pipeline at cost plus cost of carry. END USERS 2015 ANNUAL REPORT // PG 01 MAINTAINING OUR GROWTH & MOMENTUM TO BECOME A FULL VALUE CHAIN MIDSTREAM PROVIDER VALUE CHAIN OPPORTUNITY ANTERO MIDSTREAM OWNED ASSETS F R E S H W T N E M T A E R T R E T A W E T S A W A T E R D E LIV E R Y S E V I C R E R S E T A D W E C U D O R P LOW PRESSURE GATHERING 161 Miles at Year-End 2015 WELL PAD COMPRESSION 820 MMcf/d of Capacity at Year-End 2015 CONDENSATE GATHERING 19 Miles at Year-End 2015 HIGH PRESSURE GATHERING 112 Miles at Year-End 2015 A N T E R O M I D S T R E A M / / 2 0 1 5 A N N U A L R E P O R T ANTERO MIDSTREAM OPTION ASSETS STABILIZATION REGIONAL GAS PIPELINE(1) GAS PROCESSING ANTERO MIDSTREAM HAS THE OPTION TO PARTICIPATE IN PROCESSING, FRACTIONATION, TERMINALING AND STORAGE PROJECTS OFFERED TO ANTERO RESOURCES. STONEWALL GATHERING PIPELINE(1) Miles 50 Capacity In-Service 1.4 Bcf/d YES Y-GRADE PIPELINE FRACTIONATION INTERCONNECT NGL PRODUCT PIPELINES (Ethane, Propane, Butane, etc.) LONG-HAUL INTERSTATE PIPELINE TERMINALS & STORAGE (1) AM holds option to purchase 15% of Stonewall Pipeline at cost plus cost of carry. END USERS 2015 ANNUAL REPORT // PG 01 GATHERING & COMPRESSION ANTERO ACREAGE MARCELLUS CORE UTICA CORE BUILT HIGH PRESSURE GATHERING THIRD PARTY DEDICATION AREA PLANNED HIGH PRESSURE GATHERING BUILT COMPRESSOR STATION BUILT LOW PRESSURE GATHERING PLANNED COMPRESSOR STATION PITTSBURGH METRO AREA PLANNED LOW PRESSURE GATHERING WATER HANDLING & TREATMENT ANTERO ACREAGE MARCELLUS CORE UTICA CORE BUILT PERMANENT FRESH WATER LINE BUILT FRESH WATER IMPOUNDMENT PLANNED PERMANENT FRESH WATER LINE PLANNED FRESH WATER IMPOUNDMENT BUILT SURFACE FRESH WATER LINE ANTERO CLEARWATER FACILITY PITTSBURGH METRO AREA PRIMARY WATER TAKE POINT  CONTINUED GROWTH & MOMENTUM, driven by our sponsor, Antero Resources, the most active operator in the largest shale gas and liquids play in North America 478 MMcf/d 6% 94% 454 435 186 VOLUME THROUGHPUT SINCE ANTERO MIDSTREAM IPO MARCELLUS UTICA 1,124 MMcf/d 42% 1,038 965 935 1,197 1,216 1,195 MMcf/d 1,134 38% 358 738 908 58% 62% 222 2015 CAPITAL EXPENDITURES ($MM) 2015 EBITDA(1) ($MM) CUMUL ATIVE CAPITAL QUARTERLY CAPITAL $445 MM $313 $83 MM $55 $41 $36 120 Bbl/d 38% 105 93 67 62% $193 $114 Q4‘14 Q1‘15 Q2‘15 Q3‘15 Q4‘15 Q4‘14 Q1‘15 Q2‘15 Q3‘15 Q4‘15 Q4‘14 Q1‘15 Q2‘15 Q3‘15 Q4‘15 Q4‘14 Q1‘15 Q2‘15 Q3‘15 Q4‘15 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 LOW PRESSURE GATHERING (MMcf/d) HIGH PRESSURE GATHERING (MMcf/d) COMPRESSION (MMcf/d) FRESH WATER DELIVERY (MBbl/d) (1) EBITDA attributable to the Partnership.  DRIVING VALUE CREATION for the AM unit holder = Build Organically at 4x to 7x EBITDA vs. Typical Drop Down/Buy at 8x to 12x EBITDA TOP TIER DISTRIBUTION GROWTH SINCE IPO QUARTERLY DISTRIBUTION PER UNIT DISTRIBUTABLE CASH FLOW COVERAGE $0.250 2.0x 28%–30% TARGET ANNUAL DISTRIBUTION GROWTH THROUGH 2017 $0.170 1.1x $0.190 1.3x $0.180 1.2x $0.220 1.8x $0.205 1.4x 0 0 Q4‘14 Q1‘15 Q2‘15 Q3‘15 Q4‘15 PG 02 // ANTERO MIDSTREAM DEAR FELLOW UNITHOLDERS, This past year brought continued momentum and success for Antero Midstream Partners (NYSE: AM), our first full year as a publically-traded partnership. One of our most important accomplishments during 2015 was the transaction in which Antero Midstream acquired the water business of Antero Resources for $1.05 billion in September 2015. This acquisition allowed Antero Midstream to significantly enhance its service mix by providing water handling services in addition to gathering and compression services. The acquisition further provided the opportunity to develop an advanced wastewater treatment facility for future fluid handling and water recycling services. Our position as the primary service provider to Antero Resources, who continues to successfully develop its leading liquids-rich acreage position in Appalachia, enabled us to generate peer-leading volumetric, revenue, and cash flow growth in 2015. Low-pressure gathering volumes grew by 104%, compression volumes grew by 313% and high-pressure gathering volumes grew by 158% over 2014 volumes. In the months between our IPO in the fourth quarter of 2014 and the corresponding quarter in 2015, revenues grew by 45%, EBITDA grew by 41% and distributions per unit grew by 29%. We remain confident in our plans for 2016, despite the difficult commodity price environment currently impacting the industry. The operational and financial strength of our sponsor and its proposed 2016 development plan bodes well for Antero Midstream. We intend to maintain our momentum and success in 2016 for the continued benefit of Antero Midstream unitholders. WORLD CLASS SPONSOR In 2008, Antero Resources (NYSE: AR) identified the Appalachian Basin as having the potential to be one of the lowest cost unconventional resource plays in North America. Antero’s strategy was driven by its focus to become the lowest cost producer in the lowest cost shale gas play in the U.S. whereby it could maintain sustainable growth through the commodity price cycle. Despite the challenging price environment over the last twelve months, in which oil prices declined by 48% and natural gas prices by 40%, Antero continued to successfully and efficiently develop its market-leading liquids-rich core acreage position. In 2015, Antero’s net proved reserves grew by 4% to 13.2 Tcfe, net production grew by 48% to 1,493 MMcfe/d and EBITDAX grew by 4% to $1.2 billion. Also in 2015, Antero added 27,000 net acres in the Marcellus Shale, virtually all dedicated to Antero Midstream, and completed 74 horizontal wells supporting net production growth of 33% to 1,160 MMcfe/d. In the Utica Shale, the Company completed 57 horizontal wells supporting net production growth of 150% to 333 MMcfe/d. Antero Resources remains committed to maintaining its growth strategy in 2016, a strategy supported by $3.5 billion of total liquidity, access to premium markets through an industry- leading firm transportation portfolio, and a leading acreage position in the lowest cost U.S. shale plays. This will provide ongoing growth opportunities for Antero Midstream in 2016 and beyond. ORGANIC GROWTH OPPORTUNITIES During the past year Antero Midstream continued to build its gathering and compression infrastructure by investing more than $300 million. Unlike many midstream MLPs, we grow “organically” by directly investing capital into midstream assets rather than buying those same assets at a stepped-up price through a drop down or acquisition. By investing in our assets at 4 to 7 times EBITDA rather than spending 8 to 12 times EBITDA on an acquisition, we generate higher returns for Antero Midstream unitholders. Reflecting our organic growth focus, we added 40 miles of combined low-pressure, high-pressure and condensate gathering lines in 2016. We also successfully placed into service two compressor stations in the Marcellus Shale and one in the Utica Shale, adding incremental compression capacity of 325 MMcf/d and 120 MMcf/d, respectively. As of year-end 2015, we have invested a total of $1.3 billion in gathering and compression infrastructure in the Appalachian Basin, which is now the largest U.S. producing basin. We have built 2,200 MMcf/d of gathering throughput and 432 MMcf/d of compression throughput in the Marcellus and Utica shales, respectively. Our capital program remains underpinned by our mutually interdependent relationship with Antero Resources, which allows us to prudently spend capital in a timely and cost-effective manner. This eliminates the risk of spending speculative capital and instead allows for the investment of “just-in- time” capital, which results in lower-risk project economics. This is an important yet under-appreciated benefit of working directly with our sponsor, especially in the low-commodity price cycle we are facing in 2016. 2015 ANNUAL REPORT // PG 03 WITH ITS SIGNIFICANT LIQUIDITY POSITION, ACCESS TO PREMIUM MARKETS THROUGH ITS INDUSTRY- LEADING FIRM TRANSPORTATION PORTFOLIO AND A LEADING ACREAGE POSITION IN THE LOWEST-COST U.S. SHALE PLAYS, ANTERO IS POISED TO MAINTAIN ITS GROWTH PROFILE WHICH WILL REMAIN TO THE LONG-TERM BENEFIT OF ANTERO MIDSTREAM. WATER BUSINESS ACQUISITON As described above, Antero Midstream completed a transforming transaction in 2015 by acquiring the integrated water business owned and built by Antero Resources for $1.05 billion. The business represented a sizeable water infrastructure position unique to the Appalachian Basin and allowed for the creation of an additional business line for Antero Midstream. Built from the ground up by Antero Resources the acquisition included 150 miles of permanently buried pipelines, 80 miles of surface pipelines, 35 fresh water impoundments and 15,000 horsepower of water pump capacity. In addition to the water infrastructure assets acquired from Antero Resources, the acquisition included the exclusive right to provide water handling services for all of Antero’s well completion operations in West Virginia and Ohio. Furthermore, the acquisition included the rights to an advanced wastewater treatment facility called the Antero Clearwater Facility, currently under construction in West Virginia. Reflecting the importance of this business, this innovative water handling facility places Antero Midstream at the forefront of water management and conservation among U.S. shale producers. The $1.05 billion acquisition price was funded through a cash payment of $794 million and the issuance of 11.0 million partnership units to Antero Resources. This cash payment was funded from Antero Midstream’s credit facility, cash on hand and a private placement of 12.9 million partnership units in September 2015. Pro forma for the transaction, Antero Resources’ ownership of Antero Midstream is 66%. 2016 POTENTIAL Following the acquisition of the water handling business in 2015 and the 2016 development plan for Antero Resources, Antero Midstream expects to maintain growth and momentum in the coming year. Our sponsor, Antero Resources, remains the most active operator in the Appalachian Basin and expects to report peer- leading production growth of 17% by targeting high rate-of-return core liquids-rich drilling exclusively on Antero Midstream dedicated acreage. In order to accommodate Antero Resources’ growth, Antero Midstream expects to invest $435 million in associated gathering, compression and water-related infrastructure in 2016. Additionally, Antero Midstream has the option to participate in as much as a 15% non-operated equity interest in the 67-mile Stonewall gathering system in which Antero is the anchor shipper. In support of our 2016 development plans, Antero Midstream has approximately $1.0 billion in liquidity to provide the necessary financial support to pursue these attractive organic growth opportunities. We remain committed to supporting the growth profile of our industry-leading sponsor, Antero Resources, which will enable us to continue to achieve top-tier, consistent distribution growth in 2016 and beyond. THE PEOPLE OF ANTERO MIDSTREAM We want to express our appreciation for the dedication and hard work of our talented employees. They continue to generate the momentum and value creation exhibited by the partnership since our IPO. The skills and expertise of our people in assembling and executing world-class midstream projects represent Antero Midstream’s true strength and competitive advantage. We also appreciated the guidance and support of our Board of Directors. We thank you, the unitholders, for investing in our partnership and look forward to further value creation in 2016 and for years to come. PAUL M. R ADY Chairman & CEO GLEN C. WARREN, JR. President PG 04 // ANTERO MIDSTREAM FORM 10-K 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, 2015 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) 1615 Wynkoop Street Denver Colorado (Address of principal executive offices) 46-4109058 (IRS Employer Identification No.) 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 Common Units Representing Limited Partner Interests Name of Each Exchange on which Registered 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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer  Accelerated filer  Smaller reporting company  Non-accelerated filer  (Do not check if a smaller reporting company) 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 voting common stock held by non-affiliates of the registrant as of June 30, 2015, the last business day of the registrant’s most recently completed second fiscal quarter was approximately $1.3 billion. As of February 19, 2016, there were 100,222,309 common units representing limited partner interests and 75,940,957 subordinated units representing limited partner interests outstanding. Documents incorporated by reference: None. TABLE OF CONTENTS Page CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS 6 PART I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Business and Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 45 PART II . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Items 1 and 2. Item 1A. Item 1B. Item 3. Item 4. Item 5. Item 6. Item 7. Item 7A. Item 8. Item 9. Item 9A. Item 9B. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . 51 Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70 Changes in and Disagreements With Accountants on Accounting and Financial Disclosure . . . . 70 Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70 Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 PART III . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 Directors, Executive Officers, and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99 Certain Relationships and Related Transactions and Director Independence . . . . . . . . . . . . . . . . . 102 Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108 PART IV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Item 10. Item 11. Item 12. Item 13. Item 14. Item 15. 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 drilling and development plan; • • • • • • • • • • • our ability to execute our business strategy; natural gas, natural gas liquids (“NGLs”) and oil prices; competition and government regulations; actions taken by third-party producers, operators, processors and transporters; pending legal or environmental matters; costs of conducting our gathering and compression 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 the gathering and compression and water handling and treatment 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 flow and access to capital, the timing of development expenditures, 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 TERMS The following are abbreviations and definitions of certain terms used in this document, which are commonly used in our industry: Bbl or barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs or other liquid hydrocarbons. Bbl/d: Bbl per day. 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. 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: The general area encompassed by one or more oil or gas reservoirs or pools that are located on a single geologic feature, that are otherwise closely related to the same geologic feature (either structural or stratigraphic). 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. 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. 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. 4 MMcfe: One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbls of crude oil, condensate or natural gas liquids. 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, which consist primarily of ethane, propane, isobutane, normal butane and natural gasoline. oil: Crude oil and condensate. SEC: United States Securities and Exchange Commission. Tcfe: One Tcf equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. throughput: The volume of product transported or passing through a pipeline, plant, terminal or other facility. WTI: West Texas Intermediate 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 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 (the “Partnership). Items 1 and 2. Business and Properties Our Partnership We are a growth-oriented limited partnership formed by Antero Resources Corporation (“Antero”) to own, operate and develop midstream energy assets to service Antero’s rapidly increasing production. Our assets consist of gathering pipelines, compressor stations and water handling and treatment assets, through which we provide midstream services to Antero under long-term, fixed-fee contracts. Our assets are located in the rapidly developing liquids-rich southwestern core of the Marcellus Shale in northwest West Virginia and the liquids-rich core of the Utica Shale in southern Ohio, two of the premier North American shale plays. We believe that our strategically located assets and our relationship with Antero position us to become a leading midstream energy company serving the Marcellus and Utica Shales. Pursuant to our long-term contract with Antero, we have secured a 20-year dedication, that commenced at IPO date, covering substantially all of Antero’s current and future acreage for gathering and compression services. All of Antero’s 569,000 net acre leasehold is dedicated to us for gathering and compression services except for the third-party commitments in place prior to our formation, or at the time the applicable properties were acquired, which includes approximately 136,000 Marcellus Shale net leasehold acres characterized by dry gas and liquids-rich production that have been previously dedicated to third-party gatherers. Please read “—Antero’s Existing Third-Party Commitments.” Net of the excluded acreage, our contract covers approximately 435,000 net leasehold acres held by Antero as of December 31, 2015 for gathering and compression services. In addition to Antero’s existing acreage dedication, our agreement provides that any acreage Antero acquires in the future will be dedicated to us for gathering and compression services, unless such acreage is subject to a pre-existing dedication for such services. We also provide condensate gathering services to Antero under the gathering and compression agreement. The Partnership’s gathering and compression assets consist of 8-, 12-, 16-, and 20-inch high and low pressure gathering pipelines and compressor stations that collect natural gas, NGLs and oil from Antero’s wells in the Marcellus Shale in West Virginia and the Utica Shale in Ohio. The Partnership’s assets also include two independent fresh water distribution systems that deliver water used by Antero for hydraulic fracturing activities in Antero’s operating areas. The fresh water distribution systems consist of permanent buried pipelines, surface pipelines and fresh water storage facilitates, as well as pumping stations and impoundments to transport the fresh water throughout the pipeline system. To the extent necessary, we move surface pipelines to well pads to service completion operations in concert with Antero’s drilling program. As of December 31, 2015, we had the ability to store a total of 4.9 million barrels of fresh water in 35 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 oil and gas producers operating within and adjacent to Antero’s operating area, and we are able to provide water delivery services to other oil and gas producers in the area, subject to commercial arrangements, in an effort to further leverage our existing system to reduce water truck traffic. As of December 31, 2015, in West Virginia, we owned and operated 104 miles of buried fresh water pipelines and 80 miles of surface fresh water pipelines that service Antero’s drilling activities in the Marcellus Shale, as well as 22 centralized water storage facilities equipped with transfer pumps. As of December 31, 2015, in Ohio, we owned and operated 49 miles of buried fresh water pipelines and 26 miles of surface fresh water pipelines that service Antero’s 6 drilling activities in the Utica Shale, as well as 13 centralized water storage facilities equipped with transfer pumps. The waste water handling services include hauling, treatment and disposal of flow back and produced water. Our operations are located in the United States and are organized into two reporting segments: (1) gathering and compression and (2) water handling and treatment. Financial information for our reporting segments is located under “Note 9. Reporting Segments” to our combined consolidated financial statements. Developments and Highlights Energy Industry Environment 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. during winter months, and strong competition among oil producing countries for market share. These events continued into 2015 and early 2016 and, along with slower economic growth in China, have led to the further suppression of commodity prices. Spot prices for WTI declined from approximately $106.00 per Bbl in June 2014 to less than $50.00 per Bbl in January 2015, and declined further to less than $30.00 per Bbl in January 2016. Spot prices for Henry Hub natural gas declined from approximately $4.40 per MMBtu in January 2014 to $3.00 per MMBtu in January 2015, and declined further to less than $1.80 per MMBtu for a brief period in December 2015. Spot prices for propane declined from approximately $1.55 per gallon in January 2014 to less than $0.50 per gallon in January 2015, and declined further to less than $0.35 per gallon in January 2016. During 2016, we plan to expand our existing Marcellus and Utica Shale gathering, compression, and fresh water delivery infrastructure to accommodate Antero’s development plans. Antero’s 2016 drilling and completion capital budget is $1.3 billion, which is forecasted to generate production growth of 15%. Antero plans to operate an average of 5 drilling rigs and complete approximately 80 horizontal wells in the Marcellus, and 2 drilling rigs and complete 30 horizontal wells in the Utica in 2016, all located on acreage dedicated to us. Water Acquisition and Private Placement On September 23, 2015, pursuant to the terms of the Contribution, Conveyance and Assumption Agreement (the “Contribution Agreement”) between us , Antero Treatment LLC (“Antero Treatment”) and Antero, Antero contributed (the “Water Acquisition”) (i) all of the outstanding limited liability company interests of Antero Water LLC (“Antero Water”) to us and (ii) all of the assets, contracts, rights, permits and properties owned or leased by Antero and used primarily in connection with the construction, ownership, operation, use or maintenance of Antero’s advanced waste water treatment complex to be constructed in Doddridge County, West Virginia, to Antero Treatment (collectively, (i) and (ii) are referred to herein as the “Contributed Assets”). In consideration for the contribution of the Contributed Assets, we (i) paid Antero a cash distribution equal to $553 million, less $171 million of assumed debt, (ii) issued 10,988,421 common units valued at $230 million representing limited partner interests in the Partnership to Antero, (iii) distributed proceeds of approximately $241 million from the Partnership’s private placement of 12,898,000 common units at $18.84 per common unit to a group of institutional investors (the “Private Placement”) and (iv) agreed to pay Antero (a) $125 million in cash if we deliver 176,295,000 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 219,200,000 barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. We borrowed $525 million on our bank credit facility in connection with this transaction. We have agreements with Antero pursuant to which we will provide gathering and compression services and certain fluid handling services to Antero for a 20-year period. The agreement includes certain minimum fresh water delivery commitments that require Antero 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 provides seconded employees to perform certain operational services with respect to our gathering and 7 compression assets and water handling and treatment assets for a 20-year period. Additionally, we have a services agreement whereby Antero provides certain administrative services to us for a 20-year period, that commenced at IPO date. 2016 Capital Budget Our 2016 capital budget is approximately $435 million, which includes $410 million of expansion capital and $25 million of maintenance capital. The capital budget includes $240 million of expansion capital on 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 will result in 9 miles and 22 miles of additional low pressure and high pressure gathering pipelines, respectively, and 240 MMcf/d of incremental compression capacity in 2016. We also expect to invest $40 million of expansion capital in fresh water delivery infrastructure, approximately 75% of which will be invested in the Marcellus Shale and the remaining 25% will be invested in the Utica Shale. In addition, we plan to construct one fresh water storage impoundment as well as 11 miles and 19 miles of fresh water trunklines and surface pipelines, respectively. Our 2016 budget also includes $130 million of construction capital for the advanced waste water treatment facility, which is expected to be placed into service in late 2017. Our Assets The following table provides information regarding our gathering and compression systems as of December 31, 2014 and 2015: Gathering and Compression System 91 106 Marcellus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Utica . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 55 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136 161 Low- Pressure Pipeline (miles) High- Condensate Pressure Pipeline Pipeline (miles) (miles) As of December 31, 2014 2015 2014 2015 2014 2015 2014 2015 — 375 700 — 120 19 19 375 820 62 76 35 36 97 112 Compression Capacity (MMcf/d) — 16 16 Average Daily Throughput for the Year Ended December 31, 2015 (Mmcfe/d) 822 357 1,179 The following table provides information regarding our water handling and treatment systems as of December 31, 2014 and 2015: 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, Marcellus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Utica . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103 49 152 2014 2015 104 49 153 53 6 59 80 26 106 151 41 192 2014 2015 2014 2015 2014 2015 22 13 35 22 8 30 62 62 124 Our gathering and compression assets consist of 8-, 12-, 16-, and 20-inch high and low pressure gathering pipelines and compressor stations that collect natural gas, NGLs and oil from Antero’s wells in the Marcellus Shale in West Virginia and the Utica Shale in Ohio. Our assets also include two independent fresh water distribution systems that deliver water used primarily by Antero for hydraulic fracturing activities. The fresh water distribution systems consist of permanent buried pipelines, surface pipelines and fresh water storage facilitates, as well as pumping stations and impoundments to transport the fresh water throughout the pipeline system. 8 We have the right to participate in up to a 15% non-operating equity interest in the 67-mile Stonewall gathering pipeline for which Antero is an anchor shipper (the “Regional Gathering System”). The Regional Gathering System was placed into service on November 30, 2015 and Antero has a firm commitment of 900 MMcf/d through the system. Our option expires six months following the date on which the Regional Gathering System was placed into service, or May 30, 2016. In addition, we have entered into a right-of-first-offer agreement with Antero to allow for us to provide Antero with gas processing or NGLs fractionation, transportation or marketing services in the future. As of December 31, 2015, our Marcellus and Utica Shale water handling systems include 184 miles and 75 miles of pipelines, respectively, our gathering systems include 182 miles and 110 miles of pipelines, respectively, and our year-end daily compression capacity is 700 MMcf/d and 120 MMcf/d, respectively. Our Relationship with Antero Antero 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, 1.5 Bcfe/d net (19% liquids) during 2015, an increase of 48% as compared to 2014. As of December 31, 2015, Antero’s estimated net proved reserves were 13.2 Tcfe, which were comprised of 72% natural gas, 27% NGLs, and 1% oil. As of December 31, 2015, Antero’s drilling inventory consisted of 3,719 identified potential horizontal well locations (2,940 of which were located on acreage dedicated to us) for gathering and compression services, which provides us with significant opportunities for growth as Antero’s active drilling program continues and its production increases. Antero’s 2016 drilling and completion budget is $1.3 billion, and includes plans to operate an average of seven drilling rigs, including five operated rigs in the Marcellus Shale, and two operated rigs in the Utica Shale. Antero’s guidance for 2016 includes projected net daily production of 1.7 Bcfe/d, a 15% increase over 2015. Antero relies substantially on us to deliver the midstream infrastructure necessary to accommodate its continuing production growth. For additional information regarding our contracts with Antero, please read “—Contractual Arrangements with Antero.” We are highly dependent on Antero as our most significant customer, and we expect to derive most of our revenues from Antero for the foreseeable future. Accordingly, we are indirectly subject to the business risks of Antero. For additional information, please read “Risk Factors—Risks Related to Our Business.” Because a substantial majority of our revenue is derived from Antero, any development that materially and adversely affects Antero’s operations, financial condition or market reputation could have a material adverse impact on us. Contractual Arrangements Gathering and Compression Pursuant to our 20-year gathering and compression agreement that commenced at IPO date, Antero has agreed to dedicate all of its current and future acreage in West Virginia, Ohio and Pennsylvania to us for gathering and compression (other than the third-party commitments in place prior to our formation, unless acreage is subject to a pre- existing dedication for such services). For a discussion of Antero’s existing third-party commitments, please read “— Antero’s Existing Third-Party Commitments.” We also have an option to gather and compress natural gas produced by Antero 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, a compression fee of $0.18 per Mcf, and a condensate gathering fee of $4.00 per Bbl, in each case subject to CPI-based adjustments. If and to the extent Antero requests that we construct new high pressure lines and compressor stations, the gathering and compression agreement contains minimum volume commitments that require Antero 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.” 9 Water Services In connection with the Water Acquisition on September 23, 2015, we entered in a 20-year Water Services Agreement with Antero whereby we have agreed to provide certain fluid handling services to Antero within an area of dedication in defined service areas in Ohio and West Virginia and Antero agreed to pay monthly fees to us for all fluid handling 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 the date thereof and from year to year thereafter until terminated by either party. Under the agreement, Antero 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 has committed to pay a fee on a minimum volume of fresh water deliveries in calendar years 2016 through 2019. Antero is obligated to pay a minimum volume fee to us in the event the aggregate volume of fresh water delivered to Antero 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 also agreed to pay us a fixed fee of $4.00 per barrel for waste water treatment at the advanced waste water treatment complex and a fee per barrel for waste water collected in trucks owned by us, in each case subject to annual CPI-based adjustments. Until such time as the advanced waste water treatment complex is placed into service or we operate our own fleet of trucks for transporting waste water, we will continue to contract with third parties to provide Antero flow back and produced water services and Antero will reimburse us third party out-of-pocket costs plus 3%. Gas Processing and NGL Fractionation Although we do not currently have any gas processing, NGL fractionation, transportation or marketing infrastructure, we have entered into a right-of-first-offer agreement with Antero for such services, pursuant to which Antero has agreed, subject to certain exceptions, not to procure any gas processing, NGL fractionation, transportation or marketing services with respect to its production (other than production subject to a pre-existing dedication) without first offering us the right to provide such services. For additional information, please read “—Antero’s Existing Third-Party Commitments” and “Item 13. Certain Relationships and Related Transactions.” Option to Participate in Regional Gathering System We have the right to participate in up to a 15% non-operating equity interest in the 67-mile Stonewall gathering pipeline for which Antero is an anchor shipper. The Regional Gathering System was placed into service on November 30, 2015 and Antero has a firm commitment of 900 MMcf/d through the system. Our option expires six months following the date on which the Regional Gathering System was placed into service, or May 30, 2016. In addition, we have entered into a right-of-first-offer agreement with Antero to allow for us to provide Antero with gas processing or NGLs fractionation, transportation or marketing services in the future. Antero’s Existing Third-Party Commitments Excluded Acreage Antero 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, 2015, the excluded acreage consisted of approximately 136,000 of Antero’s existing net leasehold acreage. At that same date, 779 of Antero’s 3,719 potential horizontal well locations were located within the excluded acreage. Other Commitments In addition to the excluded acreage, Antero 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. 10 Title to Properties Our real property is classified into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our pipelines and major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our pipelines and major facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We have leased or owned these lands without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership of such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses. Seasonality Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas end users, utilities and marketers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the spring, summer and fall, thereby smoothing demand for natural gas. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase demand for our services during the summer and winter months and decrease demand for our services during the spring and fall months. Competition As a result of our relationship with Antero, we do not compete for the portion of Antero’s existing operations for which we currently provide midstream services and will not compete for future portions of Antero’s operations that will be dedicated to us pursuant to our gathering and compression agreement with Antero. For a description of this contract, please read “—Our Relationship with Antero—Contractual Arrangements with Antero.” 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 11 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. 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. 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, and 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. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil 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; 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 12 • 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. The PHMSA has also issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. 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 October 2015, PHMSA proposed new regulations for hazardous liquid pipelines that would 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 proposal also requires new reporting requirements for certain unregulated pipelines, including all gathering lines. Additional future regulatory action expanding PHMSA jurisdiction and imposing stricter integrity management requirements is likely. For example, in December 2015, the Senate Commerce Committee approved legislation that, among other things, requires PHMSA to conduct an assessment of its inspections process and integrity management programs for natural gas and hazardous liquid pipelines. The legislation would also require PHMSA to prioritize various rulemakings required by the 2011 Pipeline Safety Act and propose and finalize the rules mandated by the act. If enacted, this legislation could result in PHMSA proposing additional integrity management requirements for our regulated pipelines. At this time, we cannot predict the cost of such requirements, but they could be significant. 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 have incorporated all existing requirements into our programs by the required regulatory deadlines, and are continually incorporating 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; 13 • • • • 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 is 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 or 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 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. We believe that we are in substantial compliance with all of these environmental laws and regulations. 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 only customer, Antero, 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. In addition, various studies are currently underway by the EPA and other federal agencies concerning the potential environmental impacts of hydraulic fracturing activities. 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 liquids and natural gas that 14 move through our gathering systems, which in turn could materially adversely affect our revenues and results of operations. Hazardous Waste Antero’s 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. 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 non-hazardous could be classified as hazardous waste in the future. In addition, from time to time various environmental groups have petitioned for the EPA to regulate currently excluded wastes under RCRA’s hazardous waste provisions. 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 and adversely affect our business. 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 record keeping requirements on air emission sources. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, 15 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. 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. Several EPA new source performance standards, or NSPS, and national emission standards for hazardous air pollutants, or NESHAP, also apply to our facilities and operations. These NSPS and NESHAP standards impose emission limits and operational limits as well as detailed testing, recordkeeping and reporting requirements on the “affected facilities” covered by these regulations. Several of our facilities are “major” facilities requiring Title V operating permits which impose semi-annual reporting requirements. At the state level, in January 2016, Pennsylvania announced new rules that will require the Pennsylvania Department of Environmental Protection, or PADEP, to develop a new general permit for oil and gas exploration, development, and production facilities and liquids loading activities, requiring best available technology for equipment and processes, enhanced record-keeping, and quarterly monitoring inspections for the control of methane emissions. The PADEP also intends to issue similar methane rules for existing sources. In addition, the department has also proposed to establish Best Management Practices, including leak detection and repair programs, to reduce fugitive methane emissions from production, gathering, processing, and transmission facilities. We may incur capital expenditures in the future for air pollution control equipment in connection with complying with existing and recently proposed rules, or with obtaining or maintaining operating permits and complying with federal, state and local regulations related to air emissions. However, we do not believe that such requirements will have a material adverse effect on our operations. 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. In September 2015, new EPA and U.S. Army Corps of Engineers rules defining the scope of the EPA’s and the Corps’ jurisdiction became effective. 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. The requirement to obtain permits before commencing a regulated activity has the potential to delay the development of natural gas and oil projects. 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. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of waste water 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. We believe that we maintain all required discharge permits necessary to conduct our operations, and further believe we are in substantial compliance with the terms thereof. 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 16 local government authorities and citizens. We believe that our operations are in substantial compliance with the applicable worker health and safety requirements. 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 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. More recently, in August 2015, the EPA proposed 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 as part of the Administration’s efforts to reduce methane emissions from the oil and natural gas sector by up to 45% from 2012 levels by 2025. The regulations are expected to be finalized in 2016. If the rules are adopted as proposed, these rules could impose new compliance costs and permitting burdens on natural gas operations. 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. Nevertheless, the Obama administration has announced it intends to adopt additional regulations to reduce emissions of GHGs and to encourage greater use of low carbon technologies. 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. 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. 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 2015, nor do we anticipate that such expenditures will be material in 2016. Employees We do not have any employees. The officers of our general partner, who are also officers of Antero manage our operations and activities. As of December 31, 2015, Antero employed approximately 480 people who provided direct, full-time support to our operations. All of the employees required to conduct and support our operations are employed by Antero and all of our direct, full-time personnel are subject to the services agreement with our general partner and Antero. Antero considers its relations with its employees to be satisfactory. Additionally, we have a secondment agreement whereby Antero provides seconded employees to perform certain operational services with respect to our gathering and compression assets and water handling and treatment assets for a 20-year period. 17 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. 18 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, any development that materially and adversely affects Antero’s operations, financial condition or market reputation could have a material and adverse impact on us. We are substantially dependent on Antero as a significant customer, and we expect to derive a substantial majority of our revenues from Antero for the foreseeable future. As a result, any event, whether in our area of operations or otherwise, that adversely affects Antero’s 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, including, among others: • • • • • • • • • a reduction in or slowing of Antero’s development program, which would directly and adversely impact demand for our gathering and compression services and our water services; a reduction in or slowing of Antero’s completions of wells, which would directly and adversely impact demand for our water services; the volatility of natural gas, NGLs and oil prices, which could have a negative effect on the value of Antero’s properties, its drilling programs or its ability to finance its operations; the availability of capital on an economic basis to fund Antero’s exploration and development activities as well as to fund our capital expenditure programs; Antero’s ability to replace reserves; Antero’s drilling and operating risks, including potential environmental liabilities; transportation 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. during winter months, and strong competition among oil producing countries for market share. These events continued into 2015 and early 2016 and, along with slower economic growth in China, have led to the further suppression of commodity prices. Spot prices for WTI declined from approximately $106.00 per Bbl in June 2014 to less than $50.00 per Bbl in January 2015, and declined further to less than $30.00 per Bbl in January 2016. Spot prices for Henry Hub natural gas declined from approximately $4.40 per MMBtu in January 2014 to $3.00 per MMBtu in January 2015, and declined further to less than $1.80 per MMBtu for a brief period in December 2015. Spot prices for propane declined from approximately $1.55 per gallon in January 2014 to less than $0.50 per gallon in January 2015, and declined further to less than $0.35 per gallon in January 2016. 19 Changes in commodity prices can significantly affect our capital resources, liquidity and expected operating results. Please see “—Because of the natural decline in production from existing wells, our success depends, in part, on Antero’s ability to replace declining production and our ability to secure new sources of natural gas from Antero or third parties. Any decrease in volumes of natural gas and produced water that Antero produces or any decrease in the number of wells that Antero completes, could adversely affect our business and operating results.” Further, we are subject to the risk of non-payment or non-performance by Antero, including with respect to our gathering and compression and water services agreements. We cannot predict the extent to which Antero’s business would be impacted if conditions in the energy industry continue to deteriorate, nor can we estimate the impact such conditions would have on Antero’s ability to execute its drilling and development program or perform under our gathering and compression and water services agreements. Any material non-payment or non-performance by Antero could reduce our ability to make distributions to our unitholders. Also, due to our relationship with Antero, 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’s 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 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 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. 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 and subordinated unit per quarter, or $0.68 per unit per year, we will require available cash of approximately $30 million per quarter, or approximately $120 million per year based on the common units and subordinated units outstanding at December 31, 2015, as well as grants made under the Antero Midstream Partners LP Long-term Incentive Plan. We may not generate sufficient cash flow each quarter to support the payment of the minimum quarterly distribution or to increase our quarterly distributions in the future. 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 water we provide to Antero for well completion operations and the volume of natural gas we gather and compress; the volume of condensate we gather; 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’s drilling schedule as well as produced volumes; Antero’s ability to fund its drilling program; adverse weather conditions; 20 • • • the level of our operating, maintenance and general and administrative costs; 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) 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’s ability to replace declining production and our ability to secure new sources of natural gas from Antero or third parties. Additionally, our water services are directly associated with Antero’s 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 that Antero produces or any decrease in the number of wells that Antero completes, 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 reduces its development activity or otherwise ceases to drill and complete wells, revenues for our gathering and compression and water services will be directly and adversely affected. Our ability to maintain water services revenues is substantially dependent on continued completion activity by Antero 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 or third parties. The primary factors affecting our ability to obtain additional sources of natural gas include (i) the success of Antero’s drilling activity in our areas of operation, (ii) Antero’s acquisition of additional acreage and (iii) our ability to obtain dedications of acreage from third parties. Our fresh water distribution services, which make up a substantial portion of our water services revenues, will be in greatest demand in connection with completion activities. To the extent that Antero or other fresh water distribution customers complete wells with shorter lateral lengths, the demand for our fresh water distribution services would be reduced. We have no control over Antero’s 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 fresh water distribution business is dependent upon active development in our areas of operation. In order to maintain or increase throughput levels on our fresh water distribution systems, we must 21 service new wells. We have no control over Antero 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; levels 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. during winter months, and strong competition among oil producing countries for market share. These events continued into 2015 and early 2016 and, along with slower economic growth in China, have led to the further suppression of commodity prices. Spot prices for WTI declined from approximately $106.00 per Bbl in June 2014 to less than $50.00 per Bbl in January 2015, and declined further to less than $30.00 per Bbl in January 2016. Spot prices for Henry Hub natural gas declined from approximately $4.40 per MMBtu in January 2014 to $3.00 per MMBtu in January 2015, and declined further to less than $1.80 per MMBtu for a brief period in December 2015. Spot prices for propane declined from approximately $1.55 per gallon in January 2014 to less than $0.50 per gallon in January 2015, and declined further to less than $0.35 per gallon in January 2016. These lower prices have compelled most natural gas and oil producers, including Antero, 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’s production. If prices remain at current levels or 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 services, or if reductions in lateral lengths result in a decrease in demand for our water services on a per well basis, those reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders. 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 at Antero’s request. Our existing compressor stations and gathering pipelines are not supported by minimum volume commitments from Antero. Any decrease in the current levels of throughput on our gathering and compression systems could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders. We may not be able to attract third-party gathering and compression volumes or opportunities to provide water services, which could limit our ability to grow and increase our dependence on Antero. Part of our long-term growth strategy includes diversifying our customer base by identifying opportunities to offer services to third parties. To date, substantially all of our revenues were earned from Antero. Our ability to increase 22 throughput on our gathering and compression systems and water services systems and any related revenue from third parties is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when requested by third parties. To the extent that we lack available capacity on our systems for third-party volumes, we may not be able to compete effectively with third-party systems for additional oil and natural gas production in our areas of operation. In addition, some of our natural gas and NGLs marketing competitors for third-party volumes have greater financial resources and access to larger supplies of natural gas than those available to us, which could allow those competitors to price their services more aggressively than we do. Our efforts to attract new unaffiliated customers may be adversely affected by (i) our relationship with Antero and the fact that a substantial majority of the capacity of our gathering and compression systems and water systems will be necessary to service Antero’s production and development and completion schedule and (ii) our desire to provide services pursuant to fee-based contracts. As a result, we may not have the capacity to provide services to third parties and/or potential third-party customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure. 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’s 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, 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 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 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 processing 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 flow 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 flow 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. 23 Our construction or purchase of new gathering and compression, processing, water handling and treatment or other assets, including the water treatment facility currently under construction, 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 under construction, 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 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, processing, 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. 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 services require special equipment and laborers skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. If we experience shortages of necessary equipment or skilled labor in the future, our labor and equipment costs and overall productivity could be materially and adversely affected. If our equipment or labor prices increase or if we experience 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 flow 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 flow 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 that we gather and compress, 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 24 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 revolving credit facility 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. 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 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 could result in a default or an event of default that could enable our lenders 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. 25 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 $1,000,000 per day for each violation and disgorgement of profits associated with any violation. For more information regarding federal and state regulation of our operations, please read “Business— Regulation of Operations.” Increased regulation of hydraulic fracturing could result in reductions or delays in 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 services, which could adversely impact our revenues. All of Antero’s 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, the U.S. Environmental Protection Agency (the “EPA”) recently issued a study on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not led to widespread systemic impacts on drinking water resources in the United States, although there may be above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board. More recently, in August 2015, the EPA proposed rules that would establish new air emission controls for methane emissions from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storage activities. The EPA’s proposed rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions, fugitive emissions from well sites and compressors, equipment leaks at natural gas processing plants, and pneumatic pumps. These proposed rules also extend existing requirements for the emission of volatile organic compounds to the same equipment and processes. 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 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. 26 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 distribution services. Our business includes fresh water distribution 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 to source the fresh water we distribute. The availability of Antero’s 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 services would adversely affect our business and results of operations. Antero or any third-party customers may incur significant liability under, or costs and expenditures to comply with, environmental and worker health and safety regulations, which are complex and subject to frequent change. As an owner, lessee or operator of gathering pipelines and compressor stations, we are subject to various stringent federal, state, provincial and local laws and regulations relating to the discharge of materials into, and protection of, the environment. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly response actions. These laws and regulations may impose various obligations that are applicable to our and our customer’s operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customer’s operations. Failure to comply with these laws, regulations and permits may result in joint and several, strict liability and the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our gathering systems pass and facilities where wastes resulting from our operations are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause it to lose potential and current customers, interrupt its operations and limit its growth and revenues, which in turn could affect our profitability. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability. Our operations also pose risks of environmental liability due to 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. 27 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. More recently, in August 2015, the EPA proposed 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 as part of the Administration’s efforts to reduce methane emissions from the oil and natural gas sector by up to 45% from 2012 levels by 2025. The regulations are expected to be finalized in 2016. If the rules are adopted as proposed, these rules could impose new compliance costs and permitting burdens on natural gas operations. 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. Nevertheless, the Obama administration has announced it intends to adopt additional regulations to reduce emissions of GHGs and to encourage greater use of low carbon technologies. 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. 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. 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 28 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. 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. 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 October 2015, PHMSA proposed new regulations for hazardous liquid pipelines that would 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 proposal also requires new reporting requirements for certain unregulated pipelines, including all gathering lines. Additional future regulatory action expanding PHMSA jurisdiction and imposing stricter integrity management requirements is likely. For example, in December 2015, the Senate Commerce Committee approved legislation that, among other things, requires PHMSA to conduct an assessment of its inspections process and integrity management programs for natural gas and hazardous liquid pipelines. The legislation would also require PHMSA to prioritize various rulemakings required by the 2011 Pipeline Safety Act and propose and finalize the rules mandated by the act. 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 gathering and compression of natural gas, 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. 29 Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for: • • • • • • injury or loss of life; damage to and destruction of property, natural resources and equipment; pollution and other environmental damage; regulatory investigations and penalties; suspension of our operations; and repair and remediation costs. We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable under policies we are covered under, and neither we nor Antero Resources Investment LLC (“Antero Investment”) 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 or permitting requirements, 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, as well as litigation over the adequacy of those reviews, which could result in increased costs or delays of, or denial of rights to conduct, our development programs. 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 oil, 30 natural gas, NGLs and other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties. Please read “Item 1. Business—Regulation of Environmental and Occupational Safety and Health Matters” for a further description of laws and regulations that affect us. The loss of key personnel could adversely affect our ability to operate. We depend on the services of a relatively small group of 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 and Chief Financial Officer, 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. We are managed and operated by the board of directors of our general partner. Affiliates of Antero 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. If our general partner and the officers and employees of Antero 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 flow 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. Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations. Terrorist attacks or cyber-attacks may significantly affect the energy industry, including our operations and those of our 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. Consequently, it is possible that any of these 31 occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Risks Inherent in an Investment in Us Antero, our general partner and their respective affiliates, including Antero Resources Investment LLC (“Antero Investment”), 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. Antero Investment owns and controls our general partner and appoints all of the officers and directors of our general partner. A majority of the officers and directors of our general partner are officers or directors of Antero Investment. Similarly, a majority of the officers and directors of our general partner are also officers or directors of Antero. 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, Antero Investment. Further, our general partner’s directors and officers who are also directors and officers of Antero have a fiduciary duty to manage Antero in a manner that is beneficial to Antero. Conflicts of interest will arise between Antero, Antero Investment 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 Antero Investment or Antero 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 or accelerate the right to convert subordinated units; the directors and officers of Antero Investment have a fiduciary duty to make decisions in the best interests of the owners of Antero Investment, which may be contrary to our interests; the directors and officers of Antero have a fiduciary duty to make decisions in the best interests of the owners of Antero, which may be contrary to our interests; our general partner is allowed to take into account the interests of parties other than us, such as Antero Investment, 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 which, in turn, may affect the ability of the subordinated units owned by Antero to convert; 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; 32 • • • • • • • • • • • 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; except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval; 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 our subordinated units or the incentive distribution rights; our general partner determines which costs incurred by it and its affiliates (including Antero) 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) own more than 80% of the common units; our general partner controls the enforcement of obligations that it and its affiliates (including Antero) 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. 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 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. 33 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 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; 34 • • 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 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 Antero Investment, 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 35 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. Our general partner 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. Our general partner has the right, as the initial holder of our incentive distribution rights, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (50%) for the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal 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. If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to our general partner will equal the number of common units that would have entitled our general partner to an aggregate quarterly cash distribution in the quarter prior to the reset election equal to the distribution to our general partner on the incentive distribution rights in the quarter prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels. Our general partner may transfer all or a portion of the incentive distribution rights in the future. After any such transfer, the holder or holders of a majority of our incentive distribution rights will be entitled to exercise the right to reset the target distribution levels. The incentive distribution rights held by our general partner may be transferred to a third party without unitholder consent. Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner (and its owner, Antero Investment) 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 ownership of its 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 36 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 affiliaites (including Antero), 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. 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; because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase; 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 19, 2016, Antero holds 40,929,378 common units and all 75,940,957 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier. Additionally, we have agreed to provide Antero 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. 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, 37 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) 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 affilites 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) own an aggregate of 40.8% of our common and all of our subordinated units. At the end of the subordination period, assuming no additional issuances of units, as of February 19, 2016, (other than upon the conversion of the subordinated units), our general partner and its affiliates will own 66.3% of our common units. 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 Pennsylvania, 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. 38 The price of our common units may fluctuate significantly, which could cause you to lose all or part of your investment. The market price of our common units is influenced by many factors, some of which are beyond our control, including: • • • • • • • • • our quarterly distributions; our quarterly or annual earnings or those of other companies in our industry; events affecting Antero; announcements by us or our competitors of significant contracts or acquisitions; changes in accounting standards, policies, guidance, interpretations or principles; general economic conditions; the failure of securities analysts to cover our common units or changes in financial estimates by analysts; future sales of our common units; and other factors described in these “Risk Factors.” If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units. 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.” We incur increased costs as a result of being a publicly-traded partnership. We had no history operating as a publicly-traded partnership prior to our initial public offering (“IPO”). As a publicly-traded partnership, we incur significant legal, accounting and other expenses that we did not incur prior to our IPO. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly-traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay or reserve cash for our expenses, including the costs 39 of being a publicly-traded partnership. As a result, the amount of cash we have available for distribution to our unitholders is affected by the costs associated with being a publicly-traded partnership. As a result of our IPO, we became subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly-traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we incur additional costs associated with our SEC reporting requirements. We also incur significant expense in order to maintain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on our board or as executive officers. 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 become subject to entity-level taxation for state tax purposes, our cash available for distribution to you 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 distribution 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. 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, which is currently a maximum of 35%. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the 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 on us. We own assets and conduct business in West Virginia, Ohio and Pennsylvania. 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 you. 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 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 40 time. For example, 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. One such 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, the Internal Revenue Service, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement. 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. Recently enacted legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that could substantially reduce cash available for distribution to you. The IRS may adopt positions that differ from the positions we take in the future. 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 cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders. Recently enacted legislation applicable to us for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Unless we are eligible to (and choose to) elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to you may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year. Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income. You are required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you 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, you 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. 41 Tax gain or loss on disposition of our common units could be more or less than expected. If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them. Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Allocations and/or distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non -U.S. person, you should consult your 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 depreciation and amortization positions 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 those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. We 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 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, instead of on the basis of the date a particular unit is transferred. The U.S. Department of the Treasury recently adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such final regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. 42 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 modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. We have adopted certain valuation methodologies in determining unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods 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 respective 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 respective 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 amount, character, and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes. We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. As of December 31, 2015, Antero owned 66.3% of the total interests in our capital and profits. Therefore, a transfer by Antero of all or a portion of its interests in us could, in conjunction with the trading of common units held by the public, result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that includes our termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS recently announced a relief procedure whereby if a publicly-traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs. 43 You will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where you do not live as a result of investing in our common units. In addition to U.S. federal income taxes, you 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 you do not live in any of those jurisdictions. You 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, you may be subject to penalties for failure to comply with those requirements. We own assets and conduct business in West Virginia, Ohio and Pennsylvania, each of which imposes a personal income tax on individuals. As 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 your 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. During the third quarter of 2015, the West Virginia Department of Environmental Protection (“WVDEP”) issued us a notice of violation (“NOV”) for improper installation of an engine catalyst at the startup of our North Canton Compressor Station. We continue to negotiate with WVDEP to resolve this matter, but believe that it could result in monetary sanctions exceeding $100,000; however, we do not expect that any ultimate sanction will have a material impact on our financial position, results of operations, or liquidity. 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. 44 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 19, 2016, our common units were held by 22 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 19, 2016, Antero and its affiliates owned 40,929,378 of our common units and 75,940,957 of our subordinated units, which together represent a 66.3% 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: 2015: Quarter ended December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Quarter ended September 30, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Quarter ended June 30, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Quarter ended March 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 26.00 29.36 29.76 27.75 $ $ $ $ 17.65 16.47 24.10 20.50 $ $ $ $ 0.2200 0.2050 0.1900 0.1800 2014: For the period from November 5, 2014 through December 31, 2014 . . . . . $ 30.77 $ 22.80 $ 0.0943 Common Unit High Low Distributions per Common Unit Prior to November 5, 2014, there was no public market for our common units. Issuer Purchases of Equity Securities Period October 1, 2015 - October 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . — November 1, 2015 - November 30, 2015 . . . . . . . . . . . . . . . . . . 211,198 $ 22.76 — December 1, 2015 - December 31, 2015 . . . . . . . . . . . . . . . . . . . Purchased — — $ Number of Shares 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 N/A N/A N/A Unregistered Sales of Equity Securities On September 23, 2015, we completed the previously announced sale of 12,898,000 common units at $18.84 per common unit for net proceeds of approximately $241 million. We used the net proceeds of the Private Placement to fund the Water Acquisition. The common units were offered and sold in the Private Placement pursuant to an exemption from registration under Section 4(a)(2) of the Securities Act. Other exemptions from registration may have applied. Also on September 23, 2015, in consideration for the Water Acquisition, we issued 10,988,421 common units valued at $230 million representing limited partner interests in the Partnership to Antero. The common units were offered and sold pursuant to an exemption from registration under Section 4(a)(2) of the Securities Act. Other exemptions from registration may have applied. 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 45 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. 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. Our partnership agreement generally provides that we distribute cash each quarter during the subordination period in the following manner: • • • first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $0.1700 plus any arrearages from prior quarters; second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $0.1700; and third, to the holders of common units and subordinated units pro rata until each has received a distribution of $0.1955. If cash distributions to our unitholders exceed $0.1955 per common unit and subordinated unit in any quarter, our unitholders and our general partner, as the holder of our incentive distribution rights (“IDRs”), will receive distributions according to the following percentage allocations: Marginal Percentage Interest in Distributions General Partner Total Quarterly Distribution Target Amount above $0.1955 up to $0.2125 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . above $0.2125 up to $0.2550 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . above $0.2550 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unitholders (as holder of IDRs) 85 % 75 % 50 % 15 % 25 % 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, our general partner owns the IDRs and may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests. Subordinated Units Antero owns all of our subordinated units. The principal difference between our common units and subordinated units is that, for any quarter during the subordination period, holders of the subordinated units are not 46 entitled to receive any distribution from operating surplus until the common units have 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 will not accrue arrearages. When the subordination period ends, all of the subordinated units will convert into an equal number of common units. The subordination period will end on the first business day after we have earned and paid at least $0.68 (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and subordinated unit for each of three consecutive, non-overlapping four- quarter periods ending on or after September 30, 2017 and there are no outstanding arrearages on our common units. To the extent we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such arrearage payments in the future except during the subordination period. To the extent we have cash available for distribution from operating surplus in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any distribution arrearages on common units related to prior quarters before any cash distribution is made to holders of subordinated units. Cash Distributions On January 13, 2016, we announced that the board of directors of our general partner declared a cash distribution of $0.22 per unit for the quarter ended December 31, 2015. The distribution will be payable on February 29, 2016 to unitholders of record as of February 15, 2016. 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’s 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 combined 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 water distribution. 47 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 combined consolidated financial statements and related notes included elsewhere in this report: Year ended December 31, Revenue: Revenue - Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revenue - third-party . . . . . . . . . . . . . . . . . . . . . . . . . . Total revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating expenses: Direct operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative (before equity-based compensation) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity-based compensation expense . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Contingent acquisition consideration accretion . . . . . Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pre-IPO net (income) loss attributed to parent . . . . . . Pre-Water Acquisition net income attributed to 2011 $ 441 $ — 441 802 647 698 397 — 997 — 2,196 (1,755) 2 2,977 — 1,679 — 5,354 (4,707) 8 $ (1,757) $ (4,715) 4,715 1,757 2012 (in thousands, except per unit amounts) 2013 2014 2015 647 — $ 58,234 — 58,234 $ 258,029 8,245 266,274 $ 386,164 1,160 387,324 7,871 48,821 78,852 9,716 24,349 14,119 — 56,055 2,179 164 2,015 (2,015) 18,748 11,618 53,029 — 132,216 134,058 6,183 $ 127,875 (98,219) 28,736 22,470 86,670 3,333 220,061 167,263 8,158 $ 159,105 — parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General partner interest in net income attributable to incentive distribution rights . . . . . . . . . . . . . . . . . . . . Limited partners' interest in net income . . . . . . . . . . . . $ — — — (22,234) (40,193) — — $ — — $ — — $ — (1,264) 7,422 $ 117,648 Net income allocable to common units - basic and diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ — $ — $ 3,711 $ 62,421 Net income allocable to subordinated units - basic and diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Limited partner interest in net income - basic and — — — 3,711 55,227 diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ — $ — $ 7,422 $ 117,648 Net income per limited partner unit: Basic: Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ Diluted: Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Weighted average limited partner units outstanding: Basic: — $ — $ — $ — $ — $ — $ — $ — $ — — $ $ 0.05 0.05 $ $ — $ $ — 0.05 $ $ 0.05 0.76 0.73 0.76 0.73 Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — Diluted: Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — — — — 75,941 75,941 75,941 75,941 82,538 75,941 82,586 75,941 48 December 31, 2012 2013 2014 2015 (in thousands) — $ Balance sheet data (at period end): Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Property and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term indebtedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash flow data: Net cash provided by (used in) operating activities . . . . . . . . $ (3,236) $ 38,245 $ 169,433 $ 259,678 (445,455) Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . Net cash provided by (used in) financing activities . . . . . . . . (37,532) Other financial data: Adjusted EBITDA(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,883 1,893,826 1,980,032 620,000 1,082,745 1,531,595 1,816,610 115,000 1,620,903 180,249 180,408 — 144,897 793,330 808,337 — 732,061 (797,505) 858,264 (598,177) 559,932 (117,347) 120,583 — $ 230,192 $ 198,705 40,647 279,736 (3,028) (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 Measure” below. Non-GAAP Financial Measure We use Adjusted EBITDA and Distributable Cash Flow as performance measures to assess the ability of our assets to generate cash sufficient to pay interest costs, support indebtedness and make cash distributions. Adjusted EBITDA is a financial measure reported to our lenders and used as a gauge for compliance with some of the financial covenants included in our revolving credit facility. We define Adjusted EBITDA as net income before equity-based compensation expense, interest expense, interest income, income taxes and depreciation and amortization expense, excluding pre-acquisition income and expenses attributable to the parent. We define Distributable Cash Flow as Adjusted EBITDA less cash interest paid, income tax withholding payments upon vesting of equity-based compensation awards, and ongoing maintenance capital expenditures paid, excluding pre-acquisition amounts attributable to the parent. Distributable Cash Flow should not be viewed as indicative of the actual amount of cash we have available for distributions from operating surplus or that we plan to distribute. We use Adjusted EBITDA and Distributable Cash Flow to assess: • • • • the financial performance of our assets, without regard to financing methods in the case of adjusted EDITDA, capital structure or historical cost basis; the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions; 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. Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. The GAAP measures most directly comparable to Adjusted EBITDA and Distributable Cash Flow are net income and net cash provided by operating activities. The non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow should not be considered as an alternative 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. 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. 49 The following table represents a reconciliation of our Adjusted EBITDA and Distributable Cash Flow to the most directly comparable GAAP financial measures for the periods presented: 2011 2012 2013 2014 2015 Year ended December 31, (in thousands) Reconciliation of Net Income (Loss) to Adjusted EBITDA and Distributable Cash Flow: Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (1,757) $ (4,715) $ Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . Contingent acquisition consideration accretion . . . . . . Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pre-IPO net (income) loss attributed to parent . . . . . . . Pre-IPO depreciation expense attributed to parent . . . . Pre-IPO equity-based compensation expense attributed to parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pre-IPO interest expense attributed to parent . . . . . . . . Pre-Water Acquisition net income attributed to parent . Pre-Water Acquisition depreciation expense attributed to parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pre-Water Acquisition equity-based compensation 2 997 — — 8 1,679 — — (758) 1,757 (997) (3,028) 4,715 (1,679) 2,015 $ 127,875 $ 159,105 8,158 6,183 86,670 53,029 3,333 — 22,470 11,618 279,736 198,705 — (98,219) — (43,419) 164 14,119 — 24,349 40,647 (2,015) (14,119) — (2) — — (8) — (24,349) (164) — (8,697) (5,358) (22,234) — — (40,193) — — expense attributed to parent . . . . . . . . . . . . . . . . . . . . — — Pre-Water Acquisition interest expense attributed to parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Adjusted EBITDA attributable to the Partnership . . . . . Cash interest paid, net - attributable to the Partnership . Income tax witholding upon vesting of Antero Midstream LP equity-based compensation awards . . Maintenance capital expenditures (1) . . . . . . . . . . . . . . . Distributable cash flow . . . . . . . . . . . . . . . . . . . . . . . . . . $ — — — — — — $ — — — — — — $ — — — — — — — — (3,086) (18,767) (654) (3,445) (359) 16,679 (331) (2,326) 215,005 (5,149) — (1,157) (4,806) (13,097) 15,191 $ 191,953 $ Reconciliation of Adjusted EBITDA to Cash Provided (Used in) by Operating Activities: Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Amortization of deferred financing costs . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Changes in operating assets and liabilities . . . . . . . . . . Net cash provided by (used in) operating activities . . . . $ (758) $ (3,028) $ 40,647 $ 198,705 $ 279,736 1,144 — — (8,158) (164) (2) 142 (13,044) (2,238) (618) $ (3,236) $ 38,245 $ 169,433 $ 259,678 135 (6,183) (23,224) — (8) (200) (1) Maintenance capital expenditures represent that portion of our estimated capital expenditures associated with (i) the connection of new wells to our gathering and compression systems that we believe will be necessary to offset the natural production declines Antero will experience on all of its wells over time, and (ii) water distribution to new wells necessary to maintain the average throughput volume on our systems. 50 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our combined consolidated financial statements and related notes included elsewhere in this report. The information provided below supplements, but does not form part of, our financial statements. This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact our future operating performance or financial condition, please read see “Item 1A. Risk Factors.” and the section entitled “Cautionary Statement Regarding Forward-Looking Statements.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. References in this report to “Predecessor,” “we,” “our,” “us” or like terms, when referring to periods prior to November 10, 2014, refer to Antero’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’s water 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. Overview We are a growth-oriented limited partnership formed by Antero to own, operate and develop midstream energy assets to service Antero’s increasing production. Our assets consist of gathering pipelines and compressor stations that collect natural gas, NGLs and oil from Antero’s wells in the Marcellus Shale in West Virginia and the Utica Shale in Ohio. Our assets also include two independent fresh water distribution systems that deliver fresh water from the Ohio River, several regional waterways, and waste water services for well completion operations in Antero’s operating areas. These fresh water systems consist of permanent buried pipelines, surface pipelines and fresh water storage facilitates, as well as pumping stations and impoundments to transport the fresh water throughout the pipelines. The waste water services consist of waste water transportation, disposal, and treatment, including a water treatment facility, currently under construction. We believe that our strategically located assets and our relationship with Antero position us to become a leading midstream energy company serving the Marcellus and Utica shale plays. Water Acquisition and Private Placement On September 23, 2015, Antero contributed (i) all of the outstanding limited liability company interests of Antero Water to us and (ii) all of the assets, contracts, rights, permits and properties owned or leased by Antero and used primarily in connection with the construction, ownership, operation, use or maintenance of Antero’s advanced waste water treatment complex to be constructed in Doddridge County, West Virginia, to Antero Treatment, a wholly owned subsidiary. In consideration for the contribution of the Contributed Assets, the Partnership (i) paid Antero a cash distribution equal to $553 million, less $171 million of assumed debt, (ii) issued 10,988,421 common units valued at $230 million representing limited partner interests in the Partnership to Antero, (iii) distributed proceeds of approximately $241 million from the Partnership’s private placement of 12,898,000 common units at $18.84 per common unit to a group of institutional investors and (iv) agreed to pay Antero (a) $125 million in cash if the Partnership delivers 176,295,000 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 the Partnership delivers 219,200,000 barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020, representing a discounted net present value of $175 million at the time of the Water Acquisition. The Partnership borrowed $525 million on its bank credit facility in connection with this transaction. We have agreements with Antero pursuant to which we will provide gathering and compression services and certain fluid handling services to Antero for a 20-year period. The agreement includes certain minimum fresh water 51 delivery commitments that require Antero 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 provides seconded employees to perform certain operational services with respect to our gathering and compression assets and water handling and treatment assets for a 20-year period. Additionally, we have a services agreement whereby Antero provides certain administrative services to us for a 20-year period, that commenced at IPO date. Credit Facility As of December 31, 2015, lender commitments under our revolving credit facility were $1.5 billion, with a letter of credit sublimit of $150 million. At December 31, 2015, we had borrowings of $620 million and no letters of credit outstanding under the revolving credit facility. Our revolving credit facility matures in November 2019. See “— Capital Resources and Liquidity.” Recent Trends and Uncertainties The gathering and compression agreement with Antero provides for fixed fee structures, and we intend to continue to pursue additional fixed fee opportunities with Antero and third parties in order to avoid direct commodity price exposure. However, to the extent that our future contractual arrangements with Antero or third parties do not provide for fixed fee structures, we may become subject to commodity price risk. We are subject to commodity price risks to the extent that they impact Antero’s development plan and therefore our gathering volumes. 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. during winter months, and strong competition among oil producing countries for market share. These events continued into 2015 and early 2016 and, along with slower economic growth in China, have led to the further suppression of commodity prices. Spot prices for WTI declined from approximately $106.00 per Bbl in June 2014 to less than $50.00 per Bbl in January 2015, and declined further to less than $30.00 per Bbl in January 2016. Spot prices for Henry Hub natural gas declined from approximately $4.40 per MMBtu in January 2014 to $3.00 per MMBtu in January 2015, and declined further to less than $1.80 per MMBtu for a brief period in December 2015. Spot prices for propane declined from approximately $1.55 per gallon in January 2014 to less than $0.50 per gallon in January 2015, and declined further to less than $0.35 per gallon in January 2016. During 2016, we plan to expand our existing Marcellus and Utica Shale gathering, compression, and fresh water delivery infrastructure to accommodate Antero’s development plans. Antero’s 2016 drilling and completion capital budget is $1.3 billion, which is forecasted to generate production growth of 15%. Antero plans to operate an average of 5 drilling rigs and complete approximately 80 horizontal wells in the Marcellus, and 2 drilling rigs and complete 30 horizontal wells in the Utica in 2016, all located on acreage dedicated to us. A further or extended decline in commodity prices could cause some of the development and production projects of Antero or third parties to be uneconomic or less profitable, which could reduce gathering and water handling and treatment volumes in our current and future potential areas of operation. Those reductions in gathering and water handling and treatment volumes could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders. 52 Sources of Our Revenues Our gathering and compression revenues are driven by the volumes of natural gas and condensate we gather and compress, and our water handling and treatment revenues are driven by waste water services and quantities of fresh water delivered to our customers to support their well completion operations. Pursuant to our long-term contracts with Antero, we have secured 20-year dedications covering a significant portion of Antero’s current and future acreage for gathering and compression services. We have also entered into a 20-year water services agreement covering Antero’s 569,000 net acres in West Virginia and Ohio, with a right of first offer on all future areas of operation. Under the agreement, we will receive a fixed fee for all fresh water deliveries by pipeline directly to the well site, subject to annual CPI adjustments. In addition, Antero has agreed to 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. All of Antero’s existing acreage is dedicated to us for gathering and compression services except for the existing third-party commitments, which includes approximately 136,000 Marcellus Shale net leasehold acres characterized by dry gas and liquids-rich production that have been previously dedicated to third-party gatherers. Our gathering and compression operations are substantially dependent upon natural gas and oil and condensate production from Antero’s upstream activity in its areas of operation. In addition, there is a natural decline in production from existing wells that are connected to our gathering systems. Although we expect that Antero will continue to devote substantial resources to the development of oil and gas reserves, we have no control over this activity and Antero has the ability to reduce or curtail such development at its discretion. Our water handling and treatment operations are substantially dependent upon the number of wells drilled and completed by Antero. As of December 31, 2015, Antero’s estimated net proved reserves were 13.2 Tcfe, of which 72% was natural gas. As of December 31, 2015, Antero’s drilling inventory consisted of 3,719 identified potential horizontal well locations, of which 2,940 were dedicated to us, providing us with significant opportunity for growth as Antero’s robust drilling program continues and its production increases. Under the terms of the Water Services Agreement, Antero 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 also agreed to pay us a fixed fee of $4.00 per barrel for waste water treatment at the advanced waste water treatment complex and a fee per barrel for waste water collected in trucks owned by us, in each case subject to annual CPI-based adjustments. Until such time as the advanced waste water treatment complex is placed into service or we operate our own fleet of trucks for transporting waste water, we will continue to contract with third parties to provide Antero flow back and produced water services and Antero will reimburse us third party out-of-pocket costs plus 3%. How We Evaluate Our Operations We use a variety of financial and operational metrics to evaluate our performance. These metrics help us identify factors and trends that impact our operating results, profitability and financial condition. The key metrics we use to evaluate our business are provided below. Adjusted EBITDA and Distributable Cash Flow We use Adjusted EBITDA and Distributable Cash Flow as performance measures to assess the ability of our assets to generate cash sufficient to pay interest costs, support indebtedness and make cash distributions. Adjusted EBITDA and Distributable Cash flow are non-GAAP financial measures. See “Item 6. Selected Financial Data—Non- GAAP Financial Measure,” for more information regarding these financial measures, including a reconciliation of Adjusted EBITDA and Distributable Cash Flow to the most directly comparable GAAP measures. 53 Natural Gas and Oil and Condensate Throughput We must continually obtain additional supplies of natural gas and oil and condensate to maintain or increase throughput on our systems. Our ability to maintain existing supplies of natural gas and oil and condensate and obtain additional supplies is primarily impacted by our acreage dedication and the level of successful drilling activity by Antero and, to a lesser extent in the future, the potential for acreage dedications with and successful drilling by third party producers. Any increase in our throughput volumes over the near term will likely be driven by Antero continuing its robust drilling and development activities in its Marcellus and Utica Shale acreage. In the short term, we expect increases in high pressure gathering and compression throughput volumes to be less than that for low pressure gathering revenues, in part because a percentage of Antero’s high pressure gathering and compression needs will be met by existing third-party providers. Fresh Water Throughput Because the necessity for fresh water is primarily driven by hydraulic fracturing activities conducted as part of well completions, our fresh water throughput volumes are not directly impacted by ongoing production volumes. Antero’s consolidated acreage positions allow us to distribute fresh water for Antero’s completion activities in a more efficient manner. However, to the extent that Antero’s drilling and completion schedule is not met, or Antero uses less fresh water in its well completion operations than expected (for example, as a result of drilling shorter laterals), our fresh water throughput volumes may decline. Principal Components of Our Cost Structure The primary components of our operating expenses that we evaluate include direct operating expense, general and administrative expenses, depreciation expense and interest expense. Direct Operating Expense We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Labor costs, water disposal, pigging, fuel, monitoring costs, repair and non-capitalized maintenance costs, utilities and contract services comprise the most significant portion of our direct operating expense. We schedule maintenance over time to avoid significant variability in our direct operating expense and minimize the impact on our cash flow. The primary drivers of our direct operating expense include: • gathering and compression throughput in the Marcellus and Utica Shales; • well completions in the Marcellus and Utica Shales for which we deliver fresh water and provide water handling, treatment and disposal services; • maintenance and contract service costs; • • regulatory and compliance costs; operating costs associated with our internal growth projects, including: • • increases in miles of pipeline; additional compressor stations; and • ad valorem taxes. 54 General and Administrative Expenses Our general and administrative expenses include direct charges for operations of our assets and costs allocated by Antero. These costs relate to: (i) various business services, including payroll processing, accounts payable processing and facilities management, (ii) various corporate services, including legal, accounting, treasury, information technology and human resources and (iii) compensation, including equity-based compensation. These expenses are charged or allocated to us based on the nature of the expenses and are allocated based on a combination of our proportionate share of Antero’s gross property and equipment, capital expenditures and labor costs, as applicable. Management believes these allocation methodologies are reasonable. Our general and administrative expenses include equity-based compensation costs allocated by Antero to us for grants made pursuant to: (i) Antero’s Long-Term Incentive Plan (the “Antero LTIP”), (ii) profits interests awards valued in connection with the Antero reorganization pursuant to its initial public offering of common stock, which closed on October 16, 2013, and (iii) grants made to Antero employees under our own plan. In connection with the IPO, our general partner adopted the Midstream LTIP, and on November 12, 2014, we granted 20,000 restricted units and 2,361,440 phantom units under the plan. For accounting purposes, these units are treated as if they are distributed from us to Antero. During the year ended December 31, 2015, Antero recognized approximately $17.1 million in equity-based compensation related to these awards, $5.3 million of which was allocated to us and included in our general and administrative expenses. We will be allocated a portion of approximately $46.1 million of unrecognized equity-based compensation expense related to the Midstream LTIP over the remaining service period of the awards. Depreciation Expense Depreciation expense consists of our estimate of the decrease in value of the assets capitalized in property and equipment as a result of using the assets throughout the applicable year. Depreciation is computed over the asset’s estimated useful life using the straight-line basis. Gathering pipelines and compressor stations are depreciated over a 20 year useful life. Fresh water distribution systems are depreciated over a 5 to 20 year useful life. Specifically, we use a useful life of 5 years for our surface pipelines and equipment, 10 years for our above ground storage tanks, and 20 years for our permanent buried pipeline systems. Interest Expense In 2015, interest expense represents interest related to: (i) borrowings under our revolving credit facility, (ii) borrowings under a credit facility agreement between Antero Water, and the lenders under Antero’s credit facility that were incurred for the Water Acquisition (the “water facility”), (iii) capital leases and (iv) commitment fees and amortization of deferred financing costs incurred under our revolving credit facility that we entered into in connection with the closing of the IPO. In 2014, interest expense represents interest related to: (i) borrowings under Antero’s credit facility that were incurred for the acquisition of our gathering and compression assets (the “midstream credit facility”), (ii) borrowings under the water facility, (iii) capital leases and (iv) commitment fees and amortization of deferred financing costs incurred under our revolving credit facility that we entered into in connection with the closing of the IPO. Items Affecting Comparability of Our Financial Results The historical financial results of our Predecessor discussed below may not be comparable to our future financial results primarily as a result of the significant increase in the scope of our operations over the last several years. Our gathering and compression and water handling and treatment systems are relatively new, having been substantially built within the last three years. Accordingly, our revenues and expenses over that time reflect the significant ramp up in our operations. Similarly, Antero has experienced significant growth in its production and drilling and completion schedule over that same period. Accordingly, it may be difficult to project trends from our historical financial data going forward. 55 Results of Operations Year Ended December 31, 2014 Compared to Year Ended December 31, 2015 We have two operating segments: (1) gathering and compression, and (2) water handling and treatment. The operating results and assets of our reportable segments were as follows for the year ended December 31, 2014 and 2015 (in thousands): Gathering and Compression Handling Water Consolidated Total Year Ended December 31, 2014 Revenues: Revenue - Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revenue - third-party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 95,746 $ - 95,746 162,283 $ 258,029 8,245 266,274 8,245 170,528 Operating expenses: Direct operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative (before equity-based compensation). . . . . Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,470 13,416 8,619 36,789 74,294 33,351 5,332 2,999 16,240 57,922 48,821 18,748 11,618 53,029 132,216 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 21,452 $ 112,606 $ 134,058 Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 553,582 $ 200,116 $ 753,698 Year Ended December 31, 2015 Revenues: Revenue - Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revenue - third-party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 230,210 $ 382 230,592 155,954 $ 386,164 1,160 387,324 778 156,732 Operating expenses: Direct operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative (before equity-based compensation). . . . . Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Contingent acquisition consideration accretion . . . . . . . . . . . . . . . . . . . Total expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,783 22,608 17,840 60,838 - 127,069 53,069 6,128 4,630 25,832 3,333 92,992 78,852 28,736 22,470 86,670 3,333 220,061 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 103,523 $ 63,740 $ 167,263 Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 320,002 $ 132,633 $ 452,635 56 The following sets forth selected operating data for the year ended December 31, 2014 compared to the year ended December 31, 2015: Year ended December 31, 2014 2015 Amount of Increase (Decrease) Percentage Change (in thousands, except average realized fees) Revenue: Revenue - Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revenue - third-party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 258,029 8,245 266,274 $ 386,164 $ 128,135 (7,085) 121,050 1,160 387,324 50 % (86)% 45 % Operating expenses: Direct operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative (before equity-based compensation) . Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Contingent acquisition consideration accretion . . . . . . . . . . . . . . Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78,852 28,736 22,470 86,670 3,333 220,061 167,263 8,158 $ 159,105 $ Adjusted EBITDA(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 198,705 $ 279,736 $ Operating Data: 48,821 18,748 11,618 53,029 — 132,216 134,058 6,183 $ 127,875 30,031 9,988 10,852 33,641 3,333 87,845 33,205 1,975 31,230 81,031 Gathering—low pressure (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . Gathering—high pressure (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . Compression (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Condensate gathering (MBbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fresh water distribution (MBbl) . . . . . . . . . . . . . . . . . . . . . . . . . . Wells serviced by water distribution . . . . . . . . . . . . . . . . . . . . . . . Gathering—low pressure (MMcf/d) . . . . . . . . . . . . . . . . . . . . . . . Gathering—high pressure (MMcf/d) . . . . . . . . . . . . . . . . . . . . . . Compression (MMcf/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Condensate gathering (MBbl/d) . . . . . . . . . . . . . . . . . . . . . . . . . . Fresh water distribution (MBbl/d) . . . . . . . . . . . . . . . . . . . . . . . . . 181,727 167,935 38,104 621 48,333 192 498 460 104 2 132 370,830 432,861 157,515 1,117 35,044 124 1,016 1,186 432 3 96 189,103 264,926 119,411 496 (13,289) (68) 518 726 328 1 (36) Average realized fees: $ Average gathering—low pressure fee ($/Mcf) . . . . . . . . . . . . . . $ Average gathering—high pressure fee ($/Mcf) . . . . . . . . . . . . . . $ Average compression fee ($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . Average gathering—condensate fee ($/Bbl) . . . . . . . . . . . . . . . . $ Average fresh water distribution fee - Antero ($/Bbl) . . . . . . . . . $ Average fresh water distribution fee - third party ($/Bbl) . . . . . . $ $ 0.31 $ 0.18 $ 0.18 4.08 $ 3.56 $ 3.00 $ 0.31 $ 0.19 $ 0.19 $ 4.16 $ 3.64 $ 4.75 $ 0.00 0.01 0.01 0.08 0.08 1.75 62 % 53 % 93 % 63 % * 66 % 25 % 32 % 24 % 41 % 104 % 158 % 313 % 80 % (27)% (35)% 104 % 158 % 313 % 80 % (27)% 2 % 2 % 2 % 2 % 2 % 58 % * Not meaningful or applicable. (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 “Item 6. Selected Financial Data—Non-GAAP Financial Measure”. Revenue - Antero. Revenues from gathering and compression of natural gas and condensate, and water handling and treatment increased from $258.0 million for the year ended December 31, 2014 to $386.2 million for the year ended December 31, 2015. Revenues from our gathering and compression segment increased from $95.7 million for the year ended December 31, 2014 to $230.2 million for the year ended December 31, 2015. Revenues from our water 57 handling and treatment segment decreased from $162.3 million for the year ended December 31, 2014 to $156.0 million for the year ended December 31, 2015. These fluctuations are primarily the result of: • • • low pressure gathering revenue increased $60.1 million period over period due to an increase of throughput volumes of 189 Bcf, or 518 MMcf/d, which was primarily due to 119 new wells added in 2015 and, the expansion of our low pressure gathering system by 25 miles in 2015; high pressure gathering revenue increased $49.8 million due to an increase of throughput volumes of 263 Bcf, or 720 MMcf/d, primarily as a result of the addition of five new high pressure gathering lines placed in service in 2015 and the expansion of our high pressure gathering system by 15 miles in 2015; compressor revenue increased $22.5 million due to an increase of throughput volumes of 119 Bcf, or 328 MMcf/d, primarily due to the addition of four new compressor stations that were placed in service during 2015; • waste water handling revenue increased $28.9 million due to the acquisition of Antero’s waste water handling assets as part of the Water Acquisition in September 2015; and • fresh water handling revenue decreased $35.3 million, due to a decrease in fresh water distribution of 13,289 MBbl, or 36 MBbl/d, primarily due to fresh water distribution to fewer wells completed by Antero. Revenue — third-party. Third –party revenue decreased from $8.2 million for the year ended December 31, 2014 to $1.2 million for the year ended December 31, 2015. The decrease was due to lower third party fresh water distribution volumes. Direct operating expenses. Total direct operating expenses increased from $48.8 million for the year ended December 31, 2014 to $78.9 million for the year ended December 31, 2015. Direct operating expenses related to our gathering and compression segment increased from $15.5 million for the year ended December 31, 2014 to $25.8 million for the year ended December 31, 2015. The increase was primarily due to an increase in the number of gathering pipelines and compressor stations in 2015. Direct operating expenses related to our water handling and treatment segment increased from $33.3 million for the year ended December 31, 2014 to $53.1 million for the year ended December 31, 2015. The increase was primarily due to an increase in water handling and treatment assets in 2015. General and administrative expenses. General and administrative expenses (before equity-based compensation expense) increased from $18.7 million for the year ended December 31, 2014 to $28.7 million for the year ended December 31, 2015. The increase was primarily a result of increased staffing levels and related salary and benefits expenses and increased legal and other general corporate expenses to support our growth, as well as additional expenditures attributable to our operation as a publicly traded master limited partnership. Equity-based compensation expenses. Equity-based compensation expense increased from $11.6 million for the year ended December 31, 2014 to $22.5 million for the year ended December 31, 2015. This increase was due to an increase in the allocation of Antero’s equity-based compensation expense to us related to related to (i) awards made under Antero Resources Corporation’s equity-based compensation plans after December 31, 2014 and (ii) awards made to Antero employees and officers, and to non-employee directors of our general partner under the Antero Midstream Partners LP Long-Term Incentive Plan after December 31, 2014. Equity-based compensation expense allocated to us from Antero has no effect on our cash flows. Contingent acquisition consideration accretion expense. Total contingent acquisition consideration accretion expense increased from zero for the year ended December 31, 2014 to $3.3 million for the year ended December 31, 2015. In connection with the Water Acquisition, we have agreed to pay Antero (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. At the time of the Water Acquisition, we recorded a liability for the discounted 58 net present value of the contingent acquisition consideration, and as time passes, we recognize accretion expense. The increase was due to one quarter of contingent acquisition consideration accretion incurred in the fourth quarter of 2015. Depreciation expense. Total depreciation expense increased from $53.0 million for the year ended December 31, 2014 to $86.7 million for the year ended December 31, 2015. Depreciation expense related to our gathering and compression segment increased from $36.8 million for the year ended December 31, 2014 to $60.8 million for the year ended December 31, 2015. The increase was primarily due to gathering and compression placed in service and depreciated in 2015, as well as a full period of depreciation for the assets placed in service during 2014. Depreciation expense related to our water handling and treatment segment increased from $16.2 million for the year ended December 31, 2014 to $25.9 million for the year ended December 31, 2015. The increase was primarily due to water assets placed in service and depreciated in 2015, as well as a full period of depreciation for the assets placed in service during 2014. Interest expense. Interest expense increased from $6.2 million for the year ended December 31, 2014 to $8.2 million for the year ended December 31, 2015. The increase was primarily due to interest, commitment fees and amortization of deferred financing fees incurred during 2015 in relation to our revolving credit and Water facilities, compared to interest and commitment fees incurred during 2014 under the Midstream credit and Water facilities. The Midstream credit facility was repaid in connection with the completion of the IPO, and the Water facility was terminated on September 23, 2015, in connection with the Water Acquisition. Operating income. Total operating income increased from $134.1 million for the year ended December 31, 2014 to $167.3 million for the year ended December 31, 2015. Operating income related to our gathering and compression segment increased from $21.5 million for the year ended December 31, 2014 to $103.5 million for the year ended December 31, 2015. The increase was primarily due to an increase in gathering compression throughput volumes in 2015. Operating income related to our water handling and treatment segment decreased from $112.6 million for the year ended December 31, 2014 to $63.8 million for the year ended December 31, 2015. This decrease was primarily due to a decrease in fresh water throughput volumes in 2015. Adjusted EBITDA. Adjusted EBITDA increased from $198.7 million for the year ended December 31, 2014 to $279.7 million for the year ended December 31, 2015. The increase was primarily due to an increase in gathering compression throughput volumes, partially offset by a decrease in fresh water throughput volumes in 2015. 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 “Item 6. Selected Financial Data—Non-GAAP Financial Measure.” 59 Year Ended December 31, 2013 Compared to Year Ended December 31, 2014 The operating results and assets of our reportable segments were as follows for the year ended December 31, 2013 and 2014 (in thousands): Gathering and Water Consolidated Compression Handling Total Year Ended December 31, 2013 Revenues: Revenue - Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 22,363 $ 35,871 $ 58,234 Operating expenses: Direct operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative (before equity-based compensation). . . . . . Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,079 7,193 15,931 11,346 36,549 5,792 2,523 8,418 2,773 19,506 7,871 9,716 24,349 14,119 56,055 Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (14,186) $ 16,365 $ 2,179 Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 389,340 $ 200,256 $ 589,596 Year Ended December 31, 2014 Revenues: Revenue - Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revenue - third-party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 95,746 $ 162,283 $ 258,029 8,245 266,274 8,245 170,528 - 95,746 Operating expenses: Direct operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative (before equity-based compensation). . . . . . Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,470 13,416 8,619 36,789 74,294 33,351 5,332 2,999 16,240 57,922 48,821 18,748 11,618 53,029 132,216 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 21,452 $ 112,606 $ 134,058 Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 553,582 $ 200,116 $ 753,698 60 The following table sets forth selected operating data for the year ended December 31, 2013 compared to the year ended December 31, 2014: Revenue: Year ended December 31, 2013 2014 Amount of Percentage Increase (Decrease) Change (in thousands, except average realized fees) Revenue - Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 58,234 Revenue - third-party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58,234 — $ 258,029 $ 199,795 8,245 208,040 8,245 266,274 Operating expenses: Direct operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative (before equity-based compensation) Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40,950 9,032 (12,731) 38,910 76,161 131,879 6,019 $ 127,875 $ 125,860 Adjusted EBITDA(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 40,647 $ 198,705 $ 158,058 Operating Data: 48,821 18,748 11,618 53,029 132,216 134,058 6,183 7,871 9,716 24,349 14,119 56,055 2,179 164 2,015 Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Gathering—low pressure (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . Gathering—high pressure (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . Compression (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Condensate gathering (MBbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fresh water distribution (MBbl) . . . . . . . . . . . . . . . . . . . . . . . . . . Wells serviced by water distribution . . . . . . . . . . . . . . . . . . . . . . . Gathering—low pressure (MMcf/d) . . . . . . . . . . . . . . . . . . . . . . . Gathering—high pressure (MMcf/d) . . . . . . . . . . . . . . . . . . . . . . Compression (MMcf/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Condensate gathering (MBbl/d) . . . . . . . . . . . . . . . . . . . . . . . . . . Fresh water distribution (MBbl/d) . . . . . . . . . . . . . . . . . . . . . . . . . Average realized fees: 61,406 11,736 9,900 — 10,481 67 168 32 27 — 29 181,727 167,935 38,104 621 48,333 192 498 460 104 2 132 120,321 156,199 28,204 621 37,852 125 330 428 77 2 103 Average gathering—low pressure fee ($/Mcf) . . . . . . . . . . . . . . $ Average gathering—high pressure fee ($/Mcf) . . . . . . . . . . . . . . $ Average compression fee ($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . $ Average gathering—condensate fee ($/Bbl) . . . . . . . . . . . . . . . . $ Average fresh water distribution fee - Antero ($/Bbl) . . . . . . . . . $ Average fresh water distribution fee - third party ($/Bbl) . . . . . . $ 0.30 0.18 0.18 $ $ $ — $ 3.42 $ — $ 0.31 $ 0.18 $ 0.18 $ 4.08 $ 3.56 $ 3.00 $ 0.01 0.00 0.00 * 0.14 3.00 343 % * 357 % 520 % 93 % (52)% 276 % 136 % 6,052 % 3,670 % 6,246 % 389 % 196 % 1,331 % 285 % * 361 % 187 % 196 % 1,331 % 285 % * 361 % 3 % 2 % 2 % * % 4 % * % * Not meaningful or applicable. (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 “Item 6. Selected Financial Data—Non-GAAP Financial Measure”. Revenue - Antero. Revenues from gathering and compression of natural gas and condensate, and water handling and treatment increased from $58.2 million for the year ended December 31, 2013 to $258.0 million for the year ended December 31, 2014. Revenues from our gathering and compression segment increased from $22.3 million for the year ended December 31, 2013 to $95.7 million for the year ended December 31, 2014. Revenues from our water handling and treatment segment increased from $35.9 million for the year ended December 31, 2013 to $162.3 million for the year ended December 31, 2014. These fluctuations are primarily the result of: • low pressure gathering revenue increased $37.0 million period over period primarily due to an increase of throughput volumes of 120 Bcf, or 330 MMcf/d, which was primarily due to 126 new wells added in 61 2014, the expansion of our low pressure gathering system by 56 miles in 2014, and an increase in the average realized fees of $0.01 per Mcf resulting from a consumer price index-based rate adjustment; • high pressure gathering revenue increased $28.6 million due to an increase of throughput volumes of 156 Bcf, or 428 MMcf/d, primarily as a result of the addition of twelve new high pressure gathering lines placed in service in 2014 and the expansion of our high pressure gathering system by 35 miles in 2014; and • water handling revenue increased $126.4 million, primarily due to an increase of fresh water volumes distributed of 35,104 MBbl, or 96 MBbl/d, which was primarily due to distributing fresh water to 125 additional wells during 2014, and an increase in the average realized fees of $0.14 per Bbl resulting from a higher proportion delivered to wellhead than impoundments and a consumer price index based rate adjustment. Revenue — third-party. Third-party water handling revenue increased $8.3 million period over period primarily due to an increase of volumes provided to third party producers of 2,748 MBbl, or 8 MBbl/d in 2014. Direct operating expenses. Direct operating expenses increased from $7.9 million for the year ended December 31, 2013 to $48.8 million for the year ended December 31, 2014. Direct operating expenses related to our gathering and compression segment increased from $2.1 million for the year ended December 31, 2013 to $15.5 million for the year ended December 31, 2014. The increase was primarily due to an increase in the number of gathering pipelines and compressor stations in 2014, as well as an increase in ad valorem tax expense related to the gathering and compression assets in West Virginia. Direct operating expenses related to our water handling and treatment segment increased from $5.8 million for the year ended December 31, 2013 to $33.3 million for the year ended December 31, 2014. The increase was primarily due to an increase in water handling activities due to overall increases in operations. General and administrative expenses. General and administrative expenses (before equity-based compensation) increased from $9.7 million for the year ended December 31, 2013 to $18.7 million for the year ended December 31, 2014. The increase was primarily a result of increased staffing levels and related salary and benefits expenses, and increases in legal and other general corporate expenses and the related allocation of direct and indirect costs to us by Antero. The increase was also attributable to an increase in staff required to support our additional capital projects. Equity-based compensation expenses. Equity-based compensation expense decreased from $24.3 million for the year ended December 31, 2013 to $11.6 million for the year ended December 31, 2014. This decrease was due to a decrease in the allocation of Antero’s equity-based compensation expense to us related to Antero’s profits interests awards. This decrease is offset by an increase in equity-based compensation expense allocated to us by Antero related to (i) awards made under the Antero LTIP and (ii) awards made to Antero employees under the Midstream LTIP. Depreciation expense. Depreciation expense increased from $14.1 million for the year ended December 31, 2013 to $53.0 million for the year ended December 31, 2014. Depreciation expense related to our gathering and compression segment increased from $11.3 million for the year ended December 31, 2013 to $36.8 million for the year ended December 31, 2014. The increase was primarily due to gathering and compression assets placed in service and depreciated in 2014, as well as a full period of depreciation for the assets places in service during 2013. Depreciation expense related to our water handling and treatment segment increased from $2.8 million for the year ended December 31, 2013 to $16.2 million for the year ended December 31, 2014. The increase was primarily due to water assets placed in service and depreciated in 2014, as well as a full period of depreciation for the assets places in service during 2013. Interest expense. Interest expense increased from $0.2 million for the year ended December 31, 2013 to $6.2 million for the year ended December 31, 2014. The increase was primarily due to interest incurred on $510 million in borrowings under the midstream credit facility and $115 million in borrowings under the water facility, as well as commitment fees incurred on our revolving credit facility. Upon completion of the IPO on November 10, 2014, we repaid $510 million of the midstream credit facility and had an outstanding balance of $115 million under the water 62 facility. We had no outstanding balance under our revolving credit facility at December 31, 2014. Operating income. Total operating income increased from $2.2 million for the year ended December 31, 2013 to $134.1 million for the year ended December 31, 2014. We had an operating loss related to our gathering and compression segment of $14.2 million for the year ended December 31, 2013 and operating income of $21.5 million for the year ended December 31, 2014. The increase was primarily due to an increase in gathering compression throughput volumes in 2015. Operating income related to our water handling segment increased from $16.4 million for the year ended December 31, 2013 to $112.6 million for the year ended December 31, 2014. This increase was primarily due to an increase in fresh water throughput volumes in 2015. Adjusted EBITDA. Adjusted EBITDA increased from $40.6 million for the year ended December 31, 2013 to $198.7 million for the year ended December 31, 2014. The increase was primarily due to an increase in gathering, compression and fresh water throughput volumes in 2014. 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 “Item 6. Selected Financial Data—Non-GAAP Financial Measure.” Capital Resources and Liquidity Sources and Uses of Cash Historically, our sources of liquidity have included cash generated from operations and funding from Antero. Prior to the IPO, we participated in Antero’s centralized cash management program, whereby excess cash from most of its subsidiaries was swept into a centralized account. Sales and purchases related to our Predecessor third-party transactions were received or paid in cash by Antero within the centralized cash management system. Subsequent to the closing of the IPO, we began maintaining our own bank accounts and sources of liquidity for gathering and compression operations, and after September 23, 2015, we began maintaining our own bank accounts and sources of liquidity for water handling and treatment operations. Also on September 23, 2015, the Partnership completed the previously announced sale of 12,898,000 common units at $18.84 per common unit for net proceeds of approximately $241 million (the “Private Placement”). The Partnership used the net proceeds of the Private Placement to fund the Water Acquisition. Capital and liquidity is provided by operating cash flow, cash on our balance sheet, and borrowings under our revolving credit facility, further discussed below. We expect cash flow from operations to continue to contribute to our liquidity in the future. Sources of liquidity include borrowing capacity under our revolving credit facility. We expect the combination of these capital resources, as well as future capital market transactions, will be adequate to meet our working capital requirements, capital expenditures program and expected quarterly cash distributions for at least the next 12 months. The board of directors of our general partner has adopted a cash distribution policy pursuant to which we intend to distribute at least the minimum quarterly distribution of $0.17 per unit ($0.68 per unit on an annualized basis) on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. On January 13, 2016, we announced that the board of directors of our general partner declared a cash distribution of $0.22 per unit for the quarter ended December 31, 2015. The distribution will be payable on February 29, 2016 to unitholders of record as of February 15, 2016. We expect our future cash requirements relating to working capital, maintenance capital expenditures and quarterly cash distributions to our partners will be funded from cash flows internally generated from our operations. Our expansion capital expenditures will be funded by borrowings under our revolving credit facility or from potential capital markets transactions. The following table and discussion presents a summary of our combined net cash provided by or used in 63 operating activities, investing activities and financing activities for the periods indicated: Year ended December 31, 2014 2015 2013 (in thousands) Operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net increase in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (598,177) 559,932 38,245 $ 169,433 $ 259,678 (445,455) (797,505) (37,532) 858,264 — $ 230,192 $ (223,309) Cash Flow Provided by Operating Activities Net cash provided by operating activities was $38.2 million, $169.4 million, and $259.7 million for the years ended December 31, 2013, 2014 and 2015, respectively. The increase in cash flows from operations from 2014 to 2015 was primarily the result of increased throughput volumes and revenues as a result of new gathering and compression systems placed in service in 2015. The increase in cash flows from operations from 2013 to 2014 was primarily the result of increased throughput volumes and revenues as a result of new gathering, compression and water handling systems placed in service in 2014. Cash Flow Used in Investing Activities Prior to the IPO on November 10, 2014, all of our gathering and compression capital expenditures were funded by Antero, and prior to September 23, 2015 all of our water handling and treatment capital expenditures were funded by Antero. During the years ended December 31, 2013, 2014, and 2015, we used cash flows in investing activities of $598.2 million, $797.5 million, and $445.5 million, respectively, as a result of our capital expenditures for gathering systems, compressor stations, and water handling and treatment systems. The decrease in cash flows used in investing activities from 2014 to 2015, and the increase in cash flows used in investing activities from 2013 to 2014, is primarily due to buried water line capital projects completed in 2014. The board of directors of our general partner has approved a gathering and compression capital budget of $435 million for 2016 to expand our existing gathering and compression systems and water handling and treatment systems to accommodate Antero’s development plans. Our capital budgets may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If natural gas, NGLs, and oil prices decline to levels below acceptable levels or costs increase to levels above acceptable levels, Antero could choose to defer a significant portion of its budgeted capital expenditures until later periods. As a result, we may also defer a significant portion of our budgeted capital expenditures to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in Antero’s development plans, changes in prices, availability of financing, acquisition costs, industry conditions, the timing of regulatory approvals, success or lack of success in Antero’s drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside our control. Cash Flow Provided by (Used in) Financing Activities Net cash used in financing activities for the year ended December 31, 2015 of $37.5 million is the result of the following: (i) $240.7 million in proceeds from the private placement of common units, (ii) $380.3 million in net cash distributions to Antero, primarily in connection with the Water Acquisition, (iii) $107.2 million in quarterly cash distributions to our unitholders, and (iv) $52.7 million in deemed cash distributions to Antero. The following cash provided by financing activities partially offset net cash used in financing activities (described above): (i) $505.0 million in net borrowings under the revolving credit facility and water facility in connection with the Water Acquisition, and (ii) $240.7 million in net proceeds paid to Antero for the private placement of common units in connection with the Water Acquisition. 64 Net cash provided by financing activities for the year ended December 31, 2014 of (i) $858.3 million is the result of $1.1 billion in net proceeds from our IPO and (ii) $625.0 million in borrowings under the predecessor credit facilities, partially offset by (i) $510.0 million in repayments on the midstream credit facility, (ii) $337.9 million net distributions to Antero, (iii) $4.9 million payments of deferred financing costs, and (iv) $1.2 million principal payments on capital leases. Net cash provided by financing activities for the year ended December 31, 2013 of $559.9 million is the result of $560.8 million in deemed contributions from Antero, slightly offset by $0.9 million for principal payments on capital leases. Debt Agreements Revolving Credit Facility On November 10, 2014, in connection with the closing of the IPO, we entered into a revolving credit facility with a syndicate of lenders. As of December 31, 2015, the revolving credit facility provided for lender commitments of $1.5 billion and for a letter of credit sublimit of $150 million. At December 31, 2015, we had $620 million of borrowings and no letters of credit outstanding under the revolving credit facility. The revolving credit facility will mature on November 10, 2019. Principal amounts borrowed are payable on the maturity date with such borrowings bearing interest that is payable quarterly. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the LIBOR Rate administered by the ICE Benchmark Administration for one, two, three, six or twelve months plus an applicable margin ranging from 150 to 225 basis points, depending on the leverage ratio then in effect. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 50 to 125 basis points, depending on the leverage ratio then in effect. The revolving credit facility is guaranteed by our subsidiaries and is secured by mortgages on substantially all of our and our subsidiaries’ properties. The revolving credit facility contains restrictive covenants that may limit our ability to, among other things: • • incur additional indebtedness; sell assets; • make loans to others; • make investments; • enter into mergers; • make certain restricted payments; • • • incur liens; and engage in certain other transactions without the prior consent of the lenders. Borrowings under the revolving credit facility also require us to maintain the following financial ratios: an interest coverage ratio, which is the ratio of our consolidated EBITDA to its consolidated current interest charges of at least 2.5 to 1.0 at the end of each fiscal quarter; provided that upon obtaining an investment grade rating, the borrower may elect not to be subject to such ratio; 65 • • a consolidated total leverage ratio, which is the ratio of consolidated debt to consolidated EBITDA (annualized until the fiscal quarter ending September 30, 2016), of not more than 5.50 to 1.00 for the fiscal quarter ending December 31, 2015, of not more than 5.25 to 1.00 for the fiscal quarter ending March 31, 2016, and of not more than 5.00 to 1.00 for the fiscal quarter ending June 30, 2016 and each fiscal quarter thereafter; provided that after electing to issue unsecured high yield notes, the consolidated total leverage ratio will not be more than 5.25 to 1.0, or, following the election of the borrower for two fiscal quarters after a material acquisition, 5.50 to 1.0; and if we elect to issue unsecured high yield notes, a consolidated senior secured leverage ratio, which is the ratio of consolidated senior secured debt to consolidated EBITDA, of not more than 3.75 to 1.0. We were in compliance with such covenants and ratios as of December 31, 2014 and 2015. The actual borrowing capacity available to us may be limited by the interest coverage ratio, consolidated total leverage ratio, and consolidated senior secured leverage ratio covenants. Contractual Obligations At December 31, 2015, we had $620 million of borrowings and no letters of credit outstanding under the revolving credit facility. Under the terms of our revolving credit facility, we are required to pay a commitment fee of 0.250% on any unused portion of the credit facility. A summary of our contractual obligations as of December 31, 2015 is provided in the following table: Year ended December 31, (in millions) Revolving credit facility (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — 98 Water treatment (2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Contingent acquisition consideration (3) . . . . . . . . . . . . . . . . . . — Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 98 60 2016 2017 2018 2019 2020 Thereafter Total 620 620 — 163 — — — 250 125 — 1,033 5 745 125 — — 125 — 60 — — 5 — (1) Includes outstanding principal amounts on our revolving credit facility at December 31, 2015. This table does not include future commitment fees, interest expense or other fees on our revolving credit facility because they are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments, or future interest rates to be charged. (2) Includes obligations related to our water treatment facility. (3) In connection with the Water Acquisition, we have agreed to pay Antero (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. Critical Accounting Policies and Estimates The following discussion relates to the critical accounting policies and estimates for both the Partnership and our Predecessor. The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with GAAP. The preparation of our combined consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. We provide 66 expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 2—Summary of Significant Accounting Policies to the financial statements for a discussion of additional accounting policies and estimates made by management. Revenue Recognition We provide gathering and compression and water handling and treatment services under fee-based contracts primarily based on throughput or cost plus margin. Under these arrangements, we receive fees for gathering oil and gas products, compression services, and water handling and treatment services. The revenue we earn from these arrangements is directly related to (1) in the case of natural gas gathering and compression, the volumes of metered natural gas that we gather, compress and deliver to natural gas compression sites or other transmission delivery points, (2) in the case of oil and condensate gathering, the volumes of metered oil and condensate that we gather and deliver to other transmission delivery points, (3) in the case of fresh water handling and treatment services, the quantities of fresh water delivered to our customers for use in their well completion operations, or (4) in the case of waste water handling and treatment, the third party out-of-pocket costs plus 3%. We recognize revenue when all of the following criteria are met: (1) persuasive evidence of an agreement exists, (2) services have been rendered, (3) prices are fixed or determinable and (4) collectability is reasonable assured. Our gathering and compression and water services agreements with Antero include Minimum Volume Commitments (“MVCs”) creating a take or pay arrangement. Furthermore, under the terms of both agreements, we charge interest to Antero for capital costs we incur that are not placed into service, beginning 30 days after the agreed upon in service date, due to completions that Antero elects to defer. We classify this revenue as interest income on our statement of operations. Property and Equipment Property and equipment primarily consists of gathering pipelines, compressor stations and water handling and treatment systems and are stated at the lower of historical cost less accumulated depreciation, or fair value, if impaired. We capitalize construction-related direct labor and material costs. Maintenance and repair costs are expensed as incurred. Depreciation expense consists of our estimate of the decrease in value of the assets capitalized in property and equipment as a result of using the assets throughout the applicable year. Depreciation is computed over the asset’s estimated useful life using the straight-line basis. Surface pipelines are depreciated over a 5 year life, above ground storage tanks are depreciated over a 10 year life, and permanent pipeline systems, gathering pipelines and compressor stations are depreciated over a 20 year useful life. The depreciation of fixed assets recorded under capital lease agreements is included in depreciation expense. Uncertainties that may impact these estimates include, among others, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are placed into service, management makes estimates with respect to useful lives and salvage values that management believes are reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts. General and Administrative and Equity-Based Compensation Costs General and administrative costs are charged or allocated to us based on the nature of the expenses and are allocated based on our proportionate share of Antero’s gross property and equipment, capital expenditures and labor costs, as applicable. These allocations are based on estimates and assumptions that management believes are reasonable. Equity-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. Estimating the fair value of each award, the number of awards that will ultimately vest, and the forfeiture rate requires 67 management to apply judgment to estimate the tenure of our employees. Equity-based compensation expenses are allocated to us based on our proportionate share of Antero’s labor costs. These allocations are based on estimates and assumptions that management believes are reasonable. Fair Value Measurement The Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long-lived assets). The fair value is the price that we estimate would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly. In connection with the Water Acquisition, we have agreed to pay Antero (a) $125 million in cash if we deliver 176,295,000 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 219,200,000 barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. This contingent consideration liability is valued based on Level 3 inputs. We account for contingent consideration in accordance with applicable accounting guidance pertaining to business combinations. We are contractually obligated to pay Antero contingent consideration in connection with the Water Acquisition, and therefore recorded this contingent consideration liability at the time of the Water Acquisition. We update our assumptions each reporting period based on new developments and adjust such amounts to fair value based on revised assumptions, if applicable, until such consideration is satisfied through payment upon achievement of the specified objectives or it is eliminated upon failure to achieve the specified objectives. New Accounting Pronouncements On May 28, 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard is effective for us on January 1, 2018. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. We are evaluating the effect that ASU 2014-09 will have on our financial statements and related disclosures. We have not yet selected a transition method nor have we determined the effect of the standard on our ongoing financial reporting. On April 7, 2015, the FASB issued ASU No. 2015-03, Interest—Imputation of Interest, which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the associated debt liability. The new standard became effective for us on January 1, 2016. We do not believe that this standard will have a material impact on our ongoing financial reporting. 68 In April 2015, the FASB issued ASU 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions, which requires a master limited partnership (MLP) to allocate earnings (losses) of a transferred business entirely to the general partner when computing earnings per unit (EPU) for periods before the dropdown transaction occurred. The EPU for limited partners that was previously reported would not change as a result of the dropdown transaction. The ASU also requires an MLP to disclose the effects of the dropdown transaction on EPU for the periods before and after the dropdown transaction occurred. The new standard became effective for us on January 1, 2016. The ASU requires retrospective application and early adoption was permitted. We elected to early adopt ASU 2015-06, and our combined consolidated financial statements and related disclosures reflect the application of this guidance. Off-Balance Sheet Arrangements As of December 31, 2015, we did not have any off-balance sheet arrangements. Item 7A. Quantitative and Qualitative Disclosures About Market Risk The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. Commodity Price Risk Our gathering and compression and water services agreements with Antero provide for fixed-fee structures, and we intend to continue to pursue additional fixed-fee opportunities with Antero and third parties in order to avoid direct commodity price exposure. However, to the extent that our future contractual arrangements with Antero or third parties do not provide for fixed-fee structures, we may become subject to commodity price risk. We are subject to commodity price risks to the extent that they impact Antero’s development program and production and therefore our gathering volumes. Interest Rate Risk Our primary exposure to interest rate risk results from outstanding borrowings under our revolving credit facility, which has a floating interest rate. We do not currently, but may in the future, hedge the interest on portions of our borrowings under our revolving credit facility from time-to-time in order to manage risks associated with floating interest rates. At December 31, 2015, we had $620 million of borrowings and no letters of credit outstanding under the revolving credit facility. A 1.0% increase in our revolving credit facility interest rate for the year ended December 31, 2015 would have resulted in an estimated $1.9 million increase in interest expense. Credit Risk We are dependent on Antero as our primary customer, and we expect to derive a substantial majority of our revenues from Antero for the foreseeable future. As a result, any event, whether in our area of operations or otherwise, that adversely affects Antero’s production, drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect our revenues and cash available for distribution. Further, we are subject to the risk of non-payment or non-performance by Antero, including with respect to our gathering and compression and water services agreements. We cannot predict the extent to which Antero’s business would be impacted if conditions in the energy industry were to deteriorate further, nor can we estimate the impact such conditions would have on Antero’s ability to execute its drilling and development program or to perform under our agreement. Any material non-payment or non-performance by Antero could reduce our ability to make distributions to our unitholders. 69 Item 8. Financial Statements and Supplementary Data The Report of Independent Registered Public Accounting Firm, Combined Consolidated Financial Statements and supplementary financial data required for this Item are set forth beginning on page F-1 of this report and are incorporated herein by reference. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Not applicable. Item 9A. Controls and Procedures Evaluation of Disclosure Controls and Procedures As required by Rule 13a-15(b) under the Exchange Act we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this annual report. Our disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2015. Management’s Annual Report on Internal Control Over Financial Reporting The management of our general partner is responsible for establishing and maintaining adequate internal control over financial reporting for us as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Our internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of the assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements. Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect all misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time. Under the supervision of, and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework and criteria established in Internal Control—Integrated Framework in 2013, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management of our general partner concluded that our internal control over financial reporting was effective as of December 31, 2015. The effectiveness of our internal control over financial reporting as of December 31, 2015 has been audited by KPMG LLP, an independent registered public accounting firm which also audited our consolidated financial statements 70 as of and for the year ended December 31, 2015, as stated in their reports which appear beginning on page F-2 in this report. Changes in Internal Control Over Financial Reporting There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter of 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Item 9B. Other Information Amendment to Partnership Agreement On February 23, 2016, our general partner amended our partnership agreement to address a typographical error contained therein and effect the intent expressed in our Registration Statement (the “Registration Statement”) on Form S-1 (Registration No. 333-193798). Prior to the effectiveness of the amendment, our partnership agreement provided that the “Third Target Distribution” (as defined in the partnership agreement) would be $0.2250 per unit per quarter. The amendment clarifies that the third target distribution shall be $0.2550 per unit per quarter, as expressly stated in the Registration Statement. Disclosure pursuant to Section 13(r) of the Securities Exchange Act of 1934 Pursuant to Section 13(r) of the Exchange Act, we may be required to disclose in our annual and quarterly reports to the SEC, whether we or any of our “affiliates” knowingly engaged in certain activities, transactions or dealings relating to Iran or with certain individuals or entities targeted by US economic sanctions. Disclosure is generally required even where the activities, transactions or dealings were conducted in compliance with applicable law. Because the SEC defines the term “affiliate” broadly, it includes any entity under common “control” with us (and the term “control” is also construed broadly by the SEC). The description of the activities below has been provided to us by Warburg Pincus LLC (“WP”), affiliates of which: (i) beneficially own more than 10% of Antero’s outstanding common stock and/or are members of our general partner’s board of directors and (ii) beneficially own more than 10% of the equity interests of, and have the right to designate members of the board of directors of Santander Asset Management Investment Holdings Limited (“SAMIH”) and Endurance International Group Holdings, Inc. (“Endurance”). Each of SAMIH and Endurance may therefore be deemed to be under common “control” with Antero Midstream Partner LP; however, this statement is not meant to be an admission that common control exists. The disclosure below relates solely to activities conducted by SAMIH, Endurance and their respective affiliates. The disclosure does not relate to any activities conducted by us or by WP and does not involve our or WP’s management. Neither we nor WP has had any involvement in or control over the disclosed activities, and neither we nor WP has independently verified or participated in the preparation of the disclosure. Neither we nor WP is representing as to the accuracy or completeness of the disclosure nor do we or WP undertake any obligation to correct or update it. We understand that each of SAMIH’s SEC-reporting affiliates intends to disclose in its next annual or quarterly SEC report that: (a) Santander UK plc (“Santander UK”) holds frozen savings accounts and one current account for two customers resident in the United Kingdom (“U.K.”) who are currently designated by the United States (“U.S.”) for terrorism. The accounts held by each customer were blocked after the customer’s designation and have remained blocked and dormant throughout 2015. Revenue generated by Santander UK on these accounts is negligible. (b) An Iranian national, resident in the U.K., who is currently designated by the U.S. under the Iranian Financial Sanctions Regulations and the Weapons of Mass Destruction Proliferators Sanctions Regulations (“NPWMD”), holds a mortgage with Santander UK that was issued prior to any such designation. No further drawdown has been made (or 71 would be allowed) under this mortgage although Santander UK continues to receive repayment installments. In 2015, total revenue in connection with the mortgage was approximately £3,876 while net profits were negligible relative to the overall profits of Santander UK. Santander UK does not intend to enter into any new relationships with this customer, and any disbursements will only be made in accordance with applicable sanctions. The same Iranian national also holds two investment accounts with Santander ISA Managers Limited. The funds within both accounts are invested in the same portfolio fund. The accounts have remained frozen during 2015. The investment returns are being automatically reinvested, and no disbursements have been made to the customer. Total revenue for the Santander group in connection with the investment accounts was approximately £188 while net profits in 2015 were negligible relative to the overall profits of Banco Santander, S.A. (c) During the third quarter of 2015 two additional Santander UK customers were designated. First, a UK national designated by the U.S. under the Specially Designated Global Terrorist (“SDGT”) sanctions program who is on the U.S. Specially Designated National (“SDN”) list. This customer holds a bank account which generated revenue of approximately £180 during the third and fourth quarter of 2015. The account is blocked. Net profits in the third and fourth quarter of 2015 were negligible relative to the overall profits of Santander. Second, a UK national also designated by the U.S. under the SDGT sanctions program who is on the U.S. SDN list, held a bank account. No transactions were made in the third and fourth quarter of 2015 and the account is blocked and in arrears. (d) In addition, during the fourth quarter of 2015, Santander UK has identified one additional customer. A UK national designated by the U.S. under the SDGT sanctions program who is on the U.S. SDN list, held a bank account which generated negligible revenue during the fourth quarter of 2015. The account was closed during the fourth quarter of 2015. Net profits in the fourth quarter of 2015 were negligible relative to the overall profits of Banco Santander, S.A. We understand that Endurance intends to disclose in its next annual or quarterly SEC report that: On December 2, 2015, Endurance terminated a subscriber account (the “Subscriber Account”) that Endurance believes to be associated with Issam Shammout and Sky Blue Bird Aviation (“Shammout”) identified by the Office of Foreign Assets Control (“OFAC”), as a Specially Designated National (“SDN”), on May 21, 2015, pursuant to 31 C.F.R. Part 594. The Subscriber Account was inadvertently migrated to Endurance’s servers following its acquisition of the assets of Arvixe LLC (“Arvixe”) on October 31, 2014. Pursuant to the terms of the asset purchase agreement between Endurance and Arvixe, any customer accounts prohibited by OFAC were expressly excluded from the acquisition. Accordingly, Endurance does not believe it took legal ownership of the Subscriber Account, and no revenue was collected by Endurance in connection with the Subscriber Account since the date on which Shammout was added to the SDN list. Nonetheless, upon identifying that the Subscriber Account had been migrated to its servers, Endurance promptly suspended all services and terminated the Subscriber Account. Endurance reported the Subscriber Account to OFAC as potentially the property of a SDN subject to blocking pursuant to Executive Order 13224. As of January 25, 2016, Endurance has not received any correspondence from OFAC regarding this matter. 72 PART III Item 10. Directors, Executive Officers, and Corporate Governance Management of Antero Midstream Partners LP We are managed and operated by the board of directors and executive officers of our general partner, Antero Midstream Management LLC (“Midstream Management”). Our general partner is controlled by Antero Investment. All of the officers and certain of the directors of our general partner are also officers and directors of Antero. Neither our general partner nor its board of directors is elected by our unitholders. Antero Investment is the sole member of our general partner and has the right to appoint our general partner’s entire board of directors, including at least three independent directors meeting the independence standards established by the NYSE. Our unitholders are not entitled to directly participate in our management or operations. Our general partner owes certain contractual duties to our unitholders as well as a fiduciary duty to its owners. Our general partner has 8 directors. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act. All of the executive officers of our general partner listed below allocate their time between managing our business and affairs and the business and affairs of Antero. The amount of time that our general partner’s executive officers devote to our business and the business of Antero will vary in any given year based on a variety of factors. Our general partner’s executive officers intend, however, to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs. Antero provides customary management and general administrative services to us pursuant to a services agreement. Our general partner reimburses Antero at cost for its direct expenses incurred on behalf of us and a proportionate amount of its indirect expenses incurred on behalf of us, including, but not limited to, compensation expenses. Neither our general partner nor Antero receives any management fee or other compensation. Under a services agreement, Antero charges us a general and administrative fee for services it provides us. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Please read “Item 13. Certain Relationships and Related Transactions and Director Independence.” Board Leadership Structure The Board does not have a formal policy addressing whether or not the roles of Chairman and Chief Executive Officer should be separate or combined. The directors serving on the Board possess considerable professional and industry experience, significant experience as directors of both public and private companies and a unique knowledge of the challenges and opportunities that we face. As such, the Board believes that it is in the best position to evaluate our needs and to determine how best to organize Midstream Management’s leadership structure to meet those needs. At present, Midstream Management’s Board has chosen to combine the positions of Chairman and Chief Executive Officer. While the Board believes it is important to retain the flexibility to determine whether the roles of Chairman and Chief Executive Officer should be separated or combined in one individual, the Board believes that the current Chief Executive Officer is an individual with the necessary experience, commitment and support of the other members of the Board to effectively carry out the role of Chairman. The Board believes this structure promotes better alignment of strategic development and execution, more effective implementation of strategic initiatives and clearer accountability for our success or failure. Moreover, the 73 Board believes that combining the Chairman and Chief Executive Officer positions does not impede independent oversight of the Partnership. Six of the eight members of the Board are independent under NYSE rules. Board’s Role in Risk Oversight In the normal course of our business, we are exposed to a variety of risks, including market risks relating to changes in commodity prices, interest rates, technical risks affecting our facilities, political risks and credit and investment risk. The Board oversees our strategic direction, and in doing so considers the potential rewards and risks of our business opportunities and challenges, and monitors the development and management of risks that impact our strategic goals. Executive Sessions To facilitate candid discussion among our directors, the non-management directors meet in regularly scheduled executive sessions. The director who presides at these meetings is chosen by the Board prior to such meetings. Interested Party Communications Unitholders and other interested parties may communicate by writing to: Antero Midstream Partners LP, 1615 Wynkoop Street, Denver, Colorado 80202. Unitholders may submit their communications to the Board, any committee of the Board or individual directors on a confidential or anonymous basis by sending the communication in a sealed envelope marked "Unitholder Communication with Directors" and clearly identify the intended recipient(s) of the communication. Our Chief Administrative Officer will review each communication and other interested parties and will forward the communication, as expeditiously as reasonably practicable, to the addressees if: (1) the communication complies with the requirements of any applicable policy adopted by the Board relating to the subject matter of the communication; and (2) the communication falls within the scope of matters generally considered by the Board. To the extent the subject matter of a communication relates to matters that have been delegated by the Board to a committee or to an executive officer of the general partner, then the general partner’s Chief Administrative Officer may forward the communication to the executive officer or chairman of the committee to which the matter has been delegated. The acceptance and forwarding of communications to the members of the Board or an executive officer does not imply or create any fiduciary duty of the Board members or executive officer to the person submitting the communications. Information may be submitted confidentially and anonymously, although we may be obligated by law to disclose the information or identity of the person providing the information in connection with government or private legal actions and in other circumstances. Our policy is not to take any adverse action, and not to tolerate any retaliation, against any person for asking questions or making good faith reports of possible violations of law, our policies or our Corporate Code of Business Conduct and Ethics. Available Governance Materials The Board has adopted the following materials, which are available on our website at www.anteromidstream.com: • Charter of the Audit Committee of the Board; • Corporate Code of Business Conduct and Ethics; • Financial Code of Ethics; and • Corporate Governance Guidelines. 74 Unitholders may obtain a copy, free of charge, of each of these documents by sending a written request to Antero Midstream Partners LP, 1615 Wynkoop Street, Denver, Colorado, 80202. We intend to disclose any amendments to, or waivers from, our Code of Business Conduct and Ethics on our website. Directors and Executive Officers The following table shows information for our general partner’s executive officers and directors. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. There are no family relationships among any of the directors or executive officers. Some of the directors and all of the executive officers also serve as executive officers of Antero. Name Paul M. Rady . . . . . . . . . . . . . . . . . . . . . . . . . Glen C. Warren, Jr. . . . . . . . . . . . . . . . . . . . . Michael N. Kennedy . . . . . . . . . . . . . . . . . . . Kevin J. Kilstrom . . . . . . . . . . . . . . . . . . . . . Alvyn A. Schopp . . . . . . . . . . . . . . . . . . . . . . Age Position With Our General Partner 62 Chairman and Chief Executive Officer 60 Director, President and Secretary 41 Chief Financial Officer and Senior Vice President 61 Senior Vice President—Production 57 Chief Administrative Officer, Senior Regional Vice President and Treasurer Ward D. McNeilly . . . . . . . . . . . . . . . . . . . . . Richard W. Connor . . . . . . . . . . . . . . . . . . . . Peter R. Kagan . . . . . . . . . . . . . . . . . . . . . . . . W. Howard Keenan, Jr. . . . . . . . . . . . . . . . . . Brooks J. Klimley . . . . . . . . . . . . . . . . . . . . . Christopher R. Manning . . . . . . . . . . . . . . . . David A. Peters . . . . . . . . . . . . . . . . . . . . . . . 65 Senior Vice President—Reserves, Planning and Midstream 66 Director 47 Director 65 Director 58 Director 48 Director 57 Director Paul M. Rady has served as Chief Executive Officer and Chairman of the Board of Directors of Midstream Management since February 2014. Mr. Rady has also served as Chief Executive Officer and Chairman of the Board of Directors of Antero since May 2004 and of its predecessor company from its founding in 2002 to its ultimate sale to XTO Energy, Inc. in April 2005. Prior to Antero, Mr. Rady served as President, CEO and Chairman of Pennaco Energy from 1998 until its sale to Marathon in early 2001. Prior to Pennaco, Mr. Rady was with Barrett Resources from 1990 until 1998 where he initially was recruited as Chief Geologist in 1990, then served as Exploration Manager, EVP Exploration, President, COO and Director and ultimately CEO. Mr. Rady began his career with Amoco where he served 10 years as a geologist focused on the Rockies and Mid-Continent. Mr. Rady holds a B.A. in Geology from Western State College of Colorado and M.Sc. in Geology from Western Washington University. Mr. Rady’s significant experience as a chief executive of oil and gas companies, together with his training as a geologist and broad industry knowledge, enable Mr. Rady to provide the board with executive counsel on a full range of business, strategic and professional matters. Glen C. Warren, Jr. has served as President and Secretary and as a director of Midstream Management since January 2016, prior to which he served as President, Chief Financial Officer and Secretary and as a director of Midstream Management beginning in February 2014. Mr. Warren has also served as President, Chief Financial Officer and Secretary and as a director of Antero since May 2004 and of its predecessor company from its founding in 2002 to its ultimate sale to XTO Energy, Inc. in April 2005. Prior to Antero, Mr. Warren served as EVP, CFO and Director of Pennaco Energy from 1998 until its sale to Marathon in early 2001. Mr. Warren spent 10 years as a natural resources investment banker focused on equity and debt financing and M&A advisory with Lehman Brothers, Dillons Read & Co. Inc. and Kidder, Peabody & Co. Mr. Warren began his career as a landman in the Gulf Coast region with Amoco, where he spent six years. Mr. Warren holds a B.A. from the University of Mississippi, a J.D. from the University of Mississippi School of Law and an M.B.A. from the Anderson School of Management at U.C.L.A. 75 Mr. Warren’s significant experience as a chief financial officer of oil and gas companies, together with his experience as an investment banker and broad industry knowledge, enable Mr. Warren to provide the board with executive counsel on a full range of business, strategic, financial and professional matters. Michael N. Kennedy has served as Chief Financial Officer of Midstream Management and Senior Vice President of Finance since January 2016, prior to which he served as Vice President of Finance of Midstream Management beginning in February 2014. Mr. Kennedy has also served as Senior Vice President of Finance of Antero since January 2016, prior to which he served as Vice President of Finance of Antero beginning in August 2013. Mr. Kennedy was Executive Vice President and Chief Financial Officer of Forest Oil Corporation (“Forest”) from 2009 to 2013. From 2001 until 2009, Mr. Kennedy held various financial positions of increasing responsibility within Forest. From 1996 to 2001, Mr. Kennedy was an auditor with Arthur Andersen LLP focusing on the Natural Resources industry. Mr. Kennedy holds a B.S. in Accounting from the University of Colorado at Boulder. Kevin J. Kilstrom has served as Senior Vice President of Production of Midstream Management since January 2016, prior to which he served as Vice President of Production of Midstream Management beginning in February 2014. Mr. Kilstrom also has served as Senior Vice President of Production of Antero since January 2016, prior to which he served as Vice President of Production of Antero beginning in June 2007. Mr. Kilstrom was a Manager of Petroleum Engineering with AGL Energy of Sydney, Australia from 2006 to 2007. Prior to AGL, Mr. Kilstrom was with Marathon Oil as an Engineering Consultant and Asset Manager from 2003 to 2006 and as a Business Unit Manager for Marathon’s Powder River coal bed methane assets from 2001 to 2003. Mr. Kilstrom also served as a member of the board of directors of three Marathon subsidiaries from October 2003 through May 2005. Mr. Kilstrom was an Operations Manager and reserve engineer at Pennaco Energy from 1999 to 2001. Mr. Kilstrom was at Amoco for more than 22 years prior to 1999. Mr. Kilstrom holds a B.S. in Engineering from Iowa State University and an M.B.A. from DePaul University. Alvyn A. Schopp has served as Chief Administrative Officer, Senior Regional Vice President, and Treasurer of Midstream Management since January 2016, prior to which he served as Chief Administrative Officer, Regional Vice President and Treasurer of Midstream Management beginning in February 2014. Mr. Schopp has also served as Chief Administrative Officer, Senior Regional Vice President, and Treasurer of Antero since January 2016, as Chief Administrative Officer, Regional Vice President and Treasurer from September 2013 to January 2016, as Vice President of Accounting and Administration and Treasurer from January 2005 to September 2013, as Controller and Treasurer from 2003 to 2005 and as Vice President of Accounting and Administration and Treasurer of Antero’s predecessor company, Antero Resources Corporation, from January 2005 until its ultimate sale to XTO Energy, Inc. in April 2005. From 1993 to 2000, Mr. Schopp was CFO, Director and ultimately CEO of T-Netix. From 1980 to 1993 Mr. Schopp was with KPMG LLP, most recently as a Senior Manager. Mr. Schopp holds a B.B.A. from Drake University. Ward D. McNeilly has served as Senior Vice President of Reserves, Planning and Midstream of Midstream Management since January 2016, prior to which he served as Vice President of Reserves, Planning and Midstream of Midstream Management beginning in February 2014. Mr. McNeilly also has served as Senior Vice President of Reserves, Planning & Midstream of Antero since January 2016, prior to which he served as Vice President of Reserves, Planning & Midstream of Antero beginning in October 2010. Mr. McNeilly has 34 years of experience in oil and gas asset management, operations, and reservoir management. From 2007 to October 2010, Mr. McNeilly was BHP Billiton’s Gulf of Mexico Operations Manager. From 1996 through 2007, Mr. McNeilly served in various North Sea and Gulf of Mexico Deepwater operations and asset management positions with Amoco and then BP. Mr. McNeilly served in a number of different domestic and international positions with Amoco from 1979 to 1996. Mr. McNeilly holds a B.S. in Geological Engineering from the Mackay School of Mines at the University of Nevada. Richard W. Connor joined the board of Midstream Management in connection with our listing on the NYSE, and serves as the Chairman of the audit committee. Mr. Connor has served as a director and Chairman of the audit committee of Antero since September 1, 2013. Prior to his retirement in September 2009, Mr. Connor was an audit partner with KPMG LLP, or KPMG, where he principally served publicly traded clients in the energy, mining, telecommunications, and media industries for 38 years. Mr. Connor was elected to the partnership in 1980 and was appointed to KPMG’s SEC Reviewing Partners Committee in 1987 where he served until his retirement. From 1996 to September 2008, he served as the Managing Partner of KPMG’s Denver office. Mr. Connor earned his B.S. degree in 76 accounting from the University of Colorado. Mr. Connor is a member of the board of directors of Zayo Group Holdings, Inc. (NYSE: ZAYO), a provider of bandwidth infrastructure and colocation services, and the chairman of its audit committee. Mr. Connor is also a director of Centerra Gold, Inc. (TSX: CG.T), a Toronto-based gold mining company listed on the Toronto Stock Exchange. Mr. Connor has experience in technical accounting and auditing matters, knowledge of SEC filing requirements and experience with a variety of energy clients. We believe his background and skill set make Mr. Connor well-suited to serve as a member of our board of directors and as Chairman of the audit committee. Peter R. Kagan has served as a director of Midstream Management since February 2014. Mr. Kagan also has served as a director of Antero since 2004. Mr. Kagan has been with Warburg Pincus since 1997 where he leads the firm’s investment activities in energy and natural resources. He is a Partner of Warburg Pincus & Co. and a Managing Director of Warburg Pincus LLC. He is also a member of Warburg Pincus LLC’s Executive Management Group. Mr. Kagan received a B.A. degree cum laude from Harvard College and J.D. and M.B.A. degrees with honors from the University of Chicago. Prior to joining Warburg Pincus, he worked in investment banking at Salomon Brothers in both New York and Hong Kong. Mr. Kagan currently also serves on the boards of directors of the following public companies: Laredo Petroleum Holdings, Inc., MEG Energy Corp. and Targa Resources Corp., as well as the boards of several private companies. In addition, he is a director of Resources for the Future and a trustee of Milton Academy. Mr. Kagan has significant experience with energy companies and investments and broad knowledge of the oil and gas industry. We believe his background and skill set make Mr. Kagan well-suited to serve as a member of our board of directors. W. Howard Keenan, Jr. has served as a director of Midstream Management since February 2014. Mr. Keenan also has served as a director of Antero since 2004. Mr. Keenan has over thirty-five years of experience in the financial and energy businesses. Since 1997, he has been a Member of Yorktown Partners LLC, a private investment manager focused on the energy industry. From 1975 to 1997, he was in the Corporate Finance Department of Dillon, Read & Co. Inc. and active in the private equity and energy areas, including the founding of the first Yorktown Partners fund in 1991. He is serving or has served as a director of multiple Yorktown Partners portfolio companies. Mr. Keenan holds an B.A. degree cum laude from Harvard College and an M.B.A. degree from Harvard University. Mr. Keenan has significant experience with energy companies and investments and broad knowledge of the oil and gas industry. We believe his background and skill set make Mr. Keenan well-suited to serve as a member of our board of directors. Brooks J. Klimley has served as a director of Midstream Management since March 2015, and serves as a member of the audit committee. In 2013, Mr. Klimley joined The Silverfern Group, which is focused on private equity co-investments, after a nearly 25 year career leading investment banking practices covering the energy and mining sectors. In addition, he has served as an Adjunct Professor at Columbia University’s graduate schools of business and international affairs since 2010. Previously, Mr. Klimley acted as President of Brooks J. Klimley & Associates, an energy advisory services firm focused on strategy and capital raising for energy and natural resources companies. Prior to founding his own firm in 2009, Mr. Klimley acted as the President of CIT Energy and held senior leadership positions at a number of financial institutions, including Citicorp, Bear Stearns, UBS and Kidder, Peabody. Mr. Klimley holds a dual B.A./M.A. in Jurisprudence (Law) from Oxford University and a joint degree in Economics and History from Columbia University. Mr. Klimley has significant experience with energy companies and investments and broad knowledge of the oil and gas industry. We believe his background and skill set make Mr. Klimley well-suited to serve as a member of our board of directors. Christopher R. Manning has served as a director of Midstream Management since February 2014. Mr. Manning also has served as a director of Antero since 2005. Mr. Manning has been a Partner with Trilantic Capital Partners since its formation and spin out from Lehman Brothers Merchant Banking in April 2009, and is currently a member of its Executive Committee and Chairman of Trilantic Energy Partners. His primary focus is on investments in the energy 77 sector. Mr. Manning joined Lehman Brothers Merchant Banking in 2000 and was concurrently the Head of Lehman Brothers’ Investment Management Division, including both the Asset Management and Private Equity businesses, in Asia-Pacific from 2006 to 2008. He was also a member of the Global Investment Management Division Executive Committee and the Private Equity Division Operating Committee. Prior to Lehman Brothers, Mr. Manning was the chief financial officer of The Wing Group, a developer of international power projects. Prior to The Wing Group, he was in the investment banking department of Kidder, Peabody & Co., where he worked on M&A and corporate finance transactions in the energy sector. Mr. Manning currently serves on the boards of The Cross Group, Enduring Resources, LLC, Fluid Delivery Systems, Templar Energy LLC, and Trail Ridge Energy Partners II LLC, Velvet Energy, Ltd., and Ward Energy Partners. Mr. Manning was previously Chairman of the Board of LB Pacific and TLP Energy and a director of Mediterranean Resources and VantaCore Partners. Mr. Manning holds an M.B.A. from The Wharton School of the University of Pennsylvania and a B.B.A. from the University of Texas at Austin. Mr. Manning has significant experience with energy companies and investments and broad knowledge of the oil and gas industry. We believe his background and skill set make Mr. Manning well-suited to serve as a member of our board of directors. David A. Peters joined the board of Midstream Management in connection with our listing on the NYSE, and serves as a member of the audit committee. Mr. Peters served as a director of TransMontaigne GP L.L.C., the general partner of TransMontaigne Partners L.P. (NYSE: TLP), from May 2005 to August 2014, and served as a member of the audit and compensation committees and as the chair of the conflicts committee. Since 1999, Mr. Peters has been a business consultant with a primary client focus in the energy sector. In addition, Mr. Peters also served as a member of the board of directors of QDOBA Restaurant Corporation from 1998 to 2003. From 1997 to 1999, Mr. Peters was a managing director of a private investment fund, and from 1995 to 1997 he served as an executive vice president at Duke Energy Field Services/PanEnergy Field Services Inc., responsible for natural gas gathering, processing and storage operations. Prior to joining Duke Energy Field Services/PanEnergy Field Services Inc., Mr. Peters held various positions with Associated Natural Gas Corporation, and from 1980 to 1984, he worked in the audit department of Peat Marwick Mitchell & Co. Mr. Peters holds a B.B.A. from the University of Michigan. Mr. Peters has extensive knowledge of the energy industry as a business consultant and a former director of the general partner of a master limited partnership and significant financial and accounting knowledge. We believe his background and skill set make Mr. Peters well-suited to serve as a member of our board of directors and of the audit committee. Committees of the Board of Directors The board of directors of our general partner has an audit committee. We do not have a compensation committee, but rather the board of directors of our general partner approves equity grants to directors and Antero employees. The board of directors of our general partner may establish a conflicts committee to review specific matters that the board believes may involve conflicts of interest. Audit Committee Rules implemented by the NYSE and SEC require us to have an audit committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act. Messrs. Connor, Klimley and Peters serve on our audit committee, and Mr. Connor serves as the Chairman of the committee. As required by the rules of the SEC and listing standards of the NYSE, the audit committee consists solely of independent directors. SEC rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member. An “audit committee financial expert” is defined as a person who, based on his or her experience, possesses the attributes outlined in such rules. Our board of directors believes that Mr. Connor possesses substantial financial experience based on his extensive experience in technical accounting and auditing matters as a former audit partner of KPMG, LLP. As a result of these qualifications, we believe Mr. Connor satisfies the definition of “audit committee financial expert.” 78 This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee oversees our compliance programs relating to legal and regulatory requirements. We adopted an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE. Conflicts Committee Our general partner may, from time to time, have a conflicts committee to which the board will appoint at least two independent directors and which may be asked to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee will determine if the resolution of the conflict of interest is adverse to the interest of the partnership. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Antero Investment and Antero, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Exchange Act requires executive officers and managing board members of our general partner and persons who beneficially own more than 10% of a registered class of our equity securities to file reports of ownership and changes in ownership with the SEC and to furnish us with copies of all such reports. Based solely upon our review of reports received by us, or representations from certain reporting persons that no filings were required, we believe that all of the officers and managing board members of our general partner and persons who beneficially owned more than 10% of our common units complied with all applicable filing requirements during fiscal year 2015. Item 11. Executive Compensation COMPENSATION DISCUSSION AND ANALYSIS Overview Neither we nor our general partner have any employees. All of the executive officers of our general partner and other personnel who provide services to our business are employed by Antero. The named executive officers of our general partner (which we refer to below as our “Named Executive Officers”) are listed below along with their respective principal positions with our general partner and Antero: Name Paul M. Rady . . . . . . . . Chairman of the Board and Chief Executive Officer Glen C. Warren, Jr. . . . Director, President, Chief Financial Officer and Secretary Alvyn A. Schopp . . . . . Chief Administrative Officer, Regional Senior Vice President and Treasurer Kevin J. Kilstrom . . . . Senior Vice President—Production Ward D. McNeilly . . . . Senior Vice President—Reserves, Planning and Midstream Principal Position Aside from certain equity awards granted to our Named Executive Officers under the Antero Midstream Partners LP Long-Term Incentive Plan (the “Midstream LTIP”), our Named Executive Officers currently receive all of their compensation and benefits for services provided to our business from Antero. Although we bear an allocated portion of Antero’s costs of providing such compensation and benefits to the employees who serve as our Named Executive Officers, we have no control over such costs and do not establish or direct the compensation policies or practices of Antero. All decisions regarding compensation are made by the compensation committee of Antero’s board of directors (the “Compensation Committee”), except that long-term equity incentive awards under the Midstream LTIP are 79 approved by the board of directors of our general partner (the “Board”). Our Named Executive Officers devote their time as needed to the conduct of our business and affairs and the conduct of Antero and our general partner’s business and affairs. Pursuant to the services agreement that we have entered into with Antero and our general partner, we are required to reimburse Antero for a proportionate amount of compensation expenses incurred on our behalf. The following Compensation Discussion and Analysis (1) provides an overview of compensation policies and programs applicable to our Named Executive Officers; (2) explains compensation objectives, policies and practices with respect to our Named Executive Officers; and (3) identifies the elements of compensation for each of our Named Executive Officers. The elements of compensation and the Compensation Committee’s decisions with respect to determination on payments are not subject to approval by the Board. Certain members of the Board are members of the board of directors of Antero. Messrs. Kagan, Keenan, Manning and Connor, each a director of our Board, were also members of the board of directors of Antero in 2015. As used in this Compensation Discussion and Analysis (other than in this “Overview” and “Compensation of Directors” below), references to “our,” “we,” “us,” the “Company,” and similar terms refer to Antero, references to the “Board” or “Board of Directors” refers to the board of directors of Antero, and references to the Partnership refer to us, Antero Midstream Partners LP. Executive Summary Compensation Philosophy and Objectives of Our Compensation Program Since our inception, we have sought to profitably grow our company and our compensation philosophy has been primarily focused on recruiting individuals who are motivated to help us achieve that goal. Accordingly, we have structured our compensation program to attract highly qualified and experienced individuals capable of contributing to the continued growth of our Company, in terms of net production, oil and gas reserves and enterprise value. To achieve these objectives, we provide what we believe is a competitive total compensation package to our Named Executive Officers through a combination of base salary, annual cash incentive payments, and long-term equity-based incentive awards, as discussed in more detail below. Compensation Best Practices The following table highlights the compensation best practices utilized by the Company: What We Do  Use a representative and relevant peer group What We Don’t Do x No tax gross ups for executive officers  Apply robust minimum stock ownership guidelines x No “single-trigger” change-of-control cash payments  Link annual incentive compensation to the x No excessive perquisites achievement of objective pre-established performance goals tied to operational and strategic objectives x No management contracts  Evaluate the risk of our compensation programs  Use and review compensation tally sheets  Use an independent compensation consultant Implementing Our Compensation Program Objectives Role of the Compensation Committee The role of the Compensation Committee is to oversee all matters of the Company’s executive compensation program. Each year, the Compensation Committee reviews, modifies (if necessary) and approves the Company’s peer 80 group, corporate goals and objectives relevant to the compensation of the Chief Executive Officer (“CEO”) and other executive officers, and the executive compensation program. In addition, it is responsible for reviewing the performance of the CEO and President, Chief Financial Officer and Secretary (“President/CFO”), and in consultation with the CEO and President/CFO, the performance of other executive officers within the framework of the Company’s executive compensation goals and objectives. Based on this evaluation, the Compensation Committee sets the compensation of the CEO and President/CFO, and in consultation with the CEO and President/CFO, the compensation of the other executive officers. In addition to the responsibilities listed above, the Compensation Committee also has the authority to retain an independent executive compensation consultant. For 2015, the Compensation Committee retained Frederic W. Cook & Co., Inc. (“F.W. Cook”). In compliance with the U.S. Securities and Exchange Commission (“SEC”) and the New York Stock Exchange (“NYSE”) disclosure requirements, the Compensation Committee reviewed the independence of F.W. Cook under six independence factors. After its review, the Compensation Committee determined that F.W. Cook was independent. Role of External Advisors In 2015, F.W. Cook: • Collected and reviewed all relevant company information, including our historical compensation data and our organizational structure; • With input of management, established a peer group of companies to use for executive compensation comparisons; • Assessed our compensation program’s position relative to market for our Named Executive Officers and stated compensation philosophy; • Prepared a report of its analysis, findings and recommendations for our executive compensation program; and • Assisted with other ad hoc assignments such as the design of incentive arrangements and special awards. F.W. Cook’s reports were provided to the Compensation Committee in 2015. Their report dealing with competitive compensation levels was also utilized by Messrs. Rady and Warren when making their recommendations to the Board for fiscal 2015 compensation decisions. Role of Executive Officers Executive compensation decisions are typically made on an annual basis by the Compensation Committee with input from the CEO and the President/CFO. Specifically, after reviewing relevant market data and surveys within our industry, Messrs. Rady and Warren typically provide recommendations to the Compensation Committee regarding the compensation levels for our existing Named Executive Officers and our executive compensation program as a whole. Messrs. Rady and Warren attend all Compensation Committee meetings. After considering these recommendations, the Compensation Committee typically meets in executive session and adjusts base salary levels, cash bonus awards and determines the amount of any equity grants for each of our Named Executive Officers. In making executive compensation recommendations, Messrs. Rady and Warren consider each Named Executive Officer’s performance during the year, the Company’s performance during the year, as well as comparable company compensation levels and independent oil and gas company compensation surveys. While the Compensation Committee gives considerable weight to Messrs. Rady and Warren’s recommendations on compensation matters, the Compensation Committee has the final decision-making authority on all executive compensation matters. No other officers have assumed a role in the evaluation, design or administration of our executive officer compensation program. 81 Competitive Benchmarking When assessing the appropriateness of the Company’s compensation programs, the Compensation Committee compares the pay practices for our Named Executive Officers against the pay practices of other companies. This process recognizes our Company’s philosophy that, while our compensation practices should be competitive in the marketplace, marketplace information is only one of the many factors considered in assessing the reasonableness of our executive compensation program. Messrs. Rady and Warren used information provided by F.W. Cook to assess the total compensation levels of our top eight executives relative to market. In addition, Messrs. Rady and Warren used statistical information from the 2015 Oil and Gas E&P Industry Compensation Survey (the “ECI Survey”) prepared by Effective Compensation, Incorporated (“ECI”) to supplement F.W. Cook’s Peer Group data. Messrs. Rady and Warren considered the results of the F.W. Cook Survey data and ECI Survey data when making their recommendations to the Board for fiscal 2016 decisions. F.W. Cook Survey Data. In 2015, F.W. Cook identified a peer group of onshore publicly traded oil and gas companies that are reasonably similar to us in terms of size and operations comprised of the following 16 companies (the “F.W. Cook Peer Group”): • Cabot Oil & Gas Corporation; • Cimarex Energy Co.; • Concho Resources Inc.; • Energen Corporation; • EQT Corporation; • Laredo Petroleum, Inc.; • Newfield Exploration Company; • Oasis Petroleum Inc.; • Pioneer Natural Resources Company; • QEP Resources, Inc.; • Range Resources Corporation; • SM Energy Company; • Southwestern Energy Company; • Ultra Petroleum Corporation; • Whiting Petroleum Corporation; and • WPX Energy, Inc. ECI Survey Data. Data from ECI was used because it is specific to the energy industry and derives its data from direct contributions from a large number of participating companies with which we compete for talent. The ECI Survey was used to compare our executive compensation program against the executive compensation programs at the following 10 companies (collectively, the “Peer Group”): • Energen Corporation; • EQT Corporation; • Newfield Exploration Company; • Oasis Petroleum Inc.; • Range Resources Corporation; • SM Energy Company; • Ultra Petroleum Corporation; • Whiting Petroleum Corporation; and • Pioneer Natural Resources Company; • WPX Energy, Inc. Positioning versus Market. Due to the broad responsibilities of our Named Executive Officers, applying survey data to them is sometimes difficult. However, as discussed above, our compensation objective is designed to be competitive with the peer companies listed above. Therefore, in assessing the competitive positioning of our Named Executive Officers’ compensation relative to the market, the Compensation Committee considered the productivity of the Company relative to its peers and determined that it was appropriate to target the median of the Peer Group for base salaries and annual cash incentive awards and the 75th percentile of the Peer Group for long-term equity-based incentive awards. The Compensation Committee considered, among other things, publicly available data of peer companies that measures productivity using various individual employee metrics. These metrics included: EBITDAX per employee, drilling and completion capital per employee, production per employee, proved reserves per employee, and market value per 82 employee. In each case Antero ranked either 1st or 2nd amongst the Peer Group. Therefore, the Compensation Committee determined that the relative performance of our Named Executive Officers was sufficiently distinguishable from our Peer Group to support a differentiated pay strategy with respect to long-term incentives. Actual compensation decisions for individual officers are the result of a subjective analysis of a number of factors, including the individual officer’s role within our organization, performance, experience, skills or tenure with us, changes to the individual’s position and trends in compensation practices within the Peer Group or industry. Each of our Named Executive Officer’s current and prior compensation is considered in setting future compensation. Specifically, the amount of each Named Executive Officer’s current compensation is considered as a base against which the Compensation Committee makes determinations as to whether adjustments are necessary to retain the executive in light of competition and in order to provide continuing performance incentives. Thus, the Compensation Committee’s determinations regarding compensation are the result of the exercise of judgment based on all reasonably available information and, to that extent, are discretionary. Assessment of Individual and Company Performance We believe that a balance of individual and company performance criteria should be used in establishing total compensation. Therefore, in determining the level of compensation for each Named Executive Officer, the Compensation Committee subjectively considers our overall financial and operational performance and the relative contribution and performance of each of our Named Executive Officers as described in more detail below. Elements of Compensation Our Named Executive Officers’ compensation includes the following key components: • Base salaries; • Annual cash incentive payments; and • Long-term equity-based incentive awards. Base Salaries Base salaries are designed to provide a minimum, fixed level of cash compensation for services rendered during the year. Base salaries are generally reviewed annually, but are not systematically increased if the Compensation Committee believes that (1) our executives are currently compensated at proper levels in light of our Company’s performance or external market factors, or (2) an increase or addition to other elements of compensation would be more appropriate in light of our stated objectives. In addition to providing a base salary that is competitive with other independent oil and gas exploration and production companies, the Compensation Committee also considers pay levels within our Company to appropriately align each of our Named Executive Officer’s base salary level relative to the base salary levels of our other officers so that it accurately reflects such officer’s relative skills, responsibilities, experience and contributions to our Company. To that end, annual base salary adjustments are based on a subjective analysis of many individual factors, including: • • • • • the responsibilities of the officer; the period over which the officer has performed these responsibilities; the scope, level of expertise and experience required for the officer’s position; the strategic impact of the officer’s position; and the potential future contribution and demonstrated individual performance of the officer. 83 In addition to the individual factors listed above, our overall business performance and implementation of company objectives are taken into consideration in connection with determining annual base salaries. While these metrics generally provide context for making salary decisions, base salary decisions do not depend on attainment of specific goals or performance levels and no specific weighting is given to one factor over another. The following table provides an overview of the changes in base salary for the Named Executive Officers from 2014 to 2015. These changes reflect market adjustments intended to bring the base salaries of our Named Executive Officers in line with the competitive market. The adjusted base salary amounts were slightly below the median of both the F.W. Cook Peer Group and the ECI Peer Group. Executive Officer Paul M. Rady . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 800,000 $ Glen C. Warren, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 600,000 $ Alvyn A. Schopp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 400,000 $ Kevin J. Kilstrom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 400,000 $ Ward D. McNeilly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 360,000 $ 825,000 620,000 415,000 415,000 375,000 3 % 3 % 4 % 4 % 4 % 2014 Base Salary 2015 Base Salary (as of March 2015) % Increase Annual Cash Incentive Payments Annual cash incentive payments, which we also refer to as cash bonuses, are a key component of each Named Executive Officer’s annual compensation package. Historically, the Compensation Committee had used an annual discretionary cash bonus; however, based on recommendations from F.W. Cook, the Compensation Committee implemented a new annual incentive plan design beginning in fiscal 2014. This annual incentive plan is based on a balanced scorecard that is used to measure the Company’s performance. In connection with the adoption of a more structured bonus program, the Company adopted bonus targets for each of the Named Executive Officers. These bonus targets are listed below and were determined based on our compensation strategy to provide bonus compensation that is competitive with the market median: Executive Officer Paul M. Rady . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Glen C. Warren, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Alvyn A. Schopp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Kevin J. Kilstrom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ward D. McNeilly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2015 Target Bonus (as a% of base salary) 120 % 100 % 85 % 85 % 80 % With respect to the 2015 fiscal year, the Compensation Committee selected certain financial, operational and other metrics that aligned with the Company’s business strategy and would lead to long-term shareholder value. The Compensation Committee then established relative weightings for each category of measure. The level of each weighting was intended to indicate the relative importance of management focus for the year. Following the adoption of 84 the scorecard measures for 2015, the Compensation Committee then established threshold, target and maximum bonus levels. The table below provides an overview of the performance measures selected for the 2015 annual incentive plan: Performance Category Financial . . . . . . . . . . . . . . . . . . . . . . . Approximate Weighting 25% Operational . . . . . . . . . . . . . . . . . . . . . 35% Discretionary . . . . . . . . . . . . . . . . . . . . 40% Total . . . . . . . . . . . . . . . . . . . . . . . . . . 100% 2015 Year End Scorecard Performance EBITDAX (YE 2014 Strip) • • Net Debt to EBITDAX (12/31/2015) Selected Metrics • Net Production vs. Plan • Development Costs ($/Mcfe) • Cash Production Expense ($/Mcfe) • G&A ($/Mcfe) • CAPEX vs. Plan • Lost Time Incident Rate (LTIR) Succession Planning Strategic Planning • • • Antero Midstream Sarbanes Oxley Implementation • Safety Training and Subcontractor Management • Meaningful Environmental Incident Record In order to determine the appropriate payout levels for the 2015 annual incentive scorecard, the Compensation Committee reviewed the Company’s performance against each of the scorecard categories. Management provided information dealing with the Company’s performance as well as market context, including changes in assumptions from the beginning of the year to the end of the year. The following table summarizes the Compensation Committee’s assessment and the resulting payout: Performance Category Financial . . . . . . . . . . Approximate Weighting 25% Compensation Committee Payout Determination Threshold Operational . . . . . . . . 35% Target + Discretionary . . . . . . . 40% Target Compensation Committee Assessment In spite of strong performance against goals, the Company performed below target (at the threshold level) primarily due to falling commodity prices during the year, negatively impacting EBITDAX. Net Debt/EBITDAX was at target. The Compensation Committee determined the Company performed at or above target levels for key operational measures, including strong results related to Net Production, Development Costs, and Cash Production Expense. The Compensation Committee assessed the Company’s performance to be strong in delivering results related to key strategic measures of this category, including execution against the strategic plan, corporate governance implementation, key employee succession planning, and safety initiative. After deliberations and considering the overall performance of the Company, the Compensation Committee determined that a Target payout under the annual incentive scorecard was warranted, and elected to pay 2015 bonuses in 85 March 2016 in the following amounts for the Named Executive Officers without any adjustments for individual performance: Executive Officer Paul M. Rady . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Glen C. Warren, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Alvyn A. Schopp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Kevin J. Kilstrom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Ward D. McNeilly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2015 Actual Bonus ($) 990,000 620,000 352,750 352,750 300,000 2015 Target Bonus (as a % of Base Salary) 120 % 100 % 85 % 85 % 80 % 2015 Actual Bonus (% of Target) 100 % 100 % 100 % 100 % 100 % Long-Term Equity-Based Incentive Awards Under the Company’s Long-Term Incentive Plan (the “AR LTIP”), the Compensation Committee, in its sole discretion, may grant stock-based compensation awards, including options to purchase shares of our common stock, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, other stock-based awards and performance awards, to our employees (including our Named Executive Officers), consultants and directors. The terms and conditions of the awards granted are established by the Compensation Committee and based on the 75th percentile long-term strategy, as described above. 2015 AR LTIP Grants The Compensation Committee granted restricted stock unit awards and stock options under the AR LTIP to each of our Named Executive Officers in April 2015 in connection with the Company’s 2015 annual long-term equity based incentive program. The Company’s compensation strategy was reviewed and revised in 2015 to add more emphasis on long-term incentives in response to the Company’s superior operating efficiency and growth. Pursuant to our 2015 annual long-term equity based incentive program, we granted unit-based awards to our Named Executive Officers comprised approximately 60% of restricted stock unit awards and 40% of stock option awards. The stock option awards were granted with an exercise price in excess of the fair market value of the Company’s common stock in order to require a significant increase in share price, thereby strengthening the alignment of our Named Executive Officers with our shareholders. The exercise price of these options was set at 21% above the fair market value of the stock at the time of the award. The Compensation Committee believes that the respective grant levels of restricted unit awards and stock option awards were appropriate in light of the Company’s compensation strategy and individual contributions of our Named Executive Officers. The restricted stock unit awards and stock options granted pursuant to the 2015 annual long-term equity-based incentive program will vest (and, in the case of the options, will become exercisable) on April 15 of each of 2016, 2017, 2018 and 2019, so long as the applicable Named Executive Officer remains continuously employed by us from the grant date through the applicable vesting date. For a further discussion of the vesting terms, exercise price, and other restrictions applicable to the restricted stock unit awards and stock options granted in 2015, see the discussion under the heading of “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table” below. As of December 31, 2015 no restricted stock unit awards or stock options in 2015 had become vested. 2016 AR LTIP Grants For 2016, the Compensation Committee decided to adopt performance-based long-term incentives as part of its ongoing program. The Company adjusted its approach to equity-based awards to include a combination of performance share units (weighted 50%) and restricted stock units (weighted 50%). The number of performance share units earned will ultimately be determined by the Company’s total shareholder return performance against a peer group of comparable E&P companies. The Compensation Committee believes that this allocation strikes the appropriate balance between equity-based awards that include a performance component to align executive compensation with the Company’s performance and a retentive element to attract and retain top executive talent. 86 In addition, as part of a broader equity award program, the Compensation Committee made a one-time recognition and retention equity award to three of our Named Executive Officers (Messrs. Schopp, Kilstrom, and McNeilly) in February 2016. These February 2016 awards were delivered 50% in the form of time vested restricted stock units and 50% in the form of performance vested performance share units that are earned based on the Company’s stock price attaining specified growth levels over the next 5 years. Antero Midstream Phantom Units Our Named Executive Officers also spend a portion of their time providing services to the Partnership and thus are entitled to receive grants of equity-based awards under the Midstream LTIP. In November 2014, each of our Named Executive Officers was granted phantom units under the Midstream LTIP in connection with the initial public offering of the Partnership. Twenty-five percent of the phantom units granted to each of our Named Executive Officers will become vested on each of the first four anniversaries of the grant date so long as the applicable Named Executive Officer remains continuously employed by us from the grant date through the applicable vesting date. For a further discussion of the vesting terms and other restrictions applicable to the phantom units, see the discussion under the heading “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table—Phantom Unit Awards” below. No phantom unit awards were granted to any of our Named Executive Officers in 2015 and as of December 31, 2015, twenty-five percent of the phantom unit awards previously granted pursuant to the Midstream LTIP had vested. Other Benefits Health and Welfare Benefits Our Named Executive Officers are eligible to participate in all of our employee health and welfare benefit arrangements on the same basis as other employees (subject to applicable law). These arrangements include medical, dental and disability insurance, as well as health savings accounts. These benefits are provided in order to ensure that we are able to competitively attract and retain officers and other employees. This is a fixed component of compensation, and these benefits are provided on a non-discriminatory basis to all employees. Retirement Benefits We maintain an employee retirement savings plan through which employees may save for retirement or future events on a tax-advantaged basis. Participation in the 401(k) plan is at the discretion of each individual employee, and our Named Executive Officers participate in the plan on the same basis as all other employees. The plan permits us to make discretionary matching and non-elective contributions, and, effective as of January 1, 2014, the plan provides safe harbor matching contributions equal to 100% of employees’ pre-tax contributions under the plan, but not as to pre-tax contributions exceeding 4% of their eligible compensation. Perquisites and Other Personal Benefits We believe that the total mix of compensation and benefits provided to our Named Executive Officers is currently competitive and, therefore, perquisites do not play a significant role in our Named Executive Officers’ total compensation. 87 2016 Changes to Base Salaries and Annual Incentive Plan In February 2016, after comparing base salary levels to the F.W. Cook Peer Group and the ECI Peer Group (as described in more detail above under “Compensation Discussion and Analysis—Implementing Our Objectives— Competitive Benchmarking”) and considering the individual and business factors described above, Messrs. Rady and Warren recommended, and the Compensation Committee approved, increases in the base salaries of our Named Executive Officers. The increases are identified in the table below and became effective as of March 1, 2016. The adjusted base salary amounts were slightly above the median of both the F.W. Cook Peer Group and the ECI Peer Group. Executive Officer Paul M. Rady . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Glen C. Warren, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Alvyn A. Schopp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Kevin J. Kilstrom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Ward D. McNeilly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ March 2015 825,000 $ 620,000 $ 415,000 $ 415,000 $ 375,000 $ March 2016 833,000 626,000 419,000 419,000 379,000 Base Salary as of Base Salary as of Percentage Increase 1 % 1 % 1 % 1 % 1 % The following table identifies the performance categories, weighting, and selected metrics that the Compensation Committee selected for the 2016 fiscal year under our annual incentive plan: Performance Category Financial . . . . . . . . . . . . . Operational . . . . . . . . . . . Approximate Weighting 25 % • EBITDAX (YE 2015 Strip) Selected Metrics • Net Debt to EBITDAX (12/31/2016) 35 % • Net Production vs. Plan • Development Costs ($/Mcfe) • Cash Production Expense ($/Mcfe) • G&A ($/Mcfe) • CAPEX vs. Plan • Lost Time Incident Rate (LTIR) Discretionary . . . . . . . . . . 40 % • • • • Meaningful Environmental Incident Record Succession Planning Strategic Planning Compliance Activities Safety Training and Subcontractor Management Total . . . . . . . . . . . . . . . . 100 % Employment, Severance or Change in Control Agreements We do not maintain any employment, severance or change in control agreements with any of our Named Executive Officers. As discussed below under “Potential Payments Upon a Termination or a Change in Control,” Messrs. Rady, Warren, Schopp, Kilstrom, and McNeilly could be entitled to receive accelerated vesting of his unit awards in Antero Resources Employee Holdings LLC (“Holdings”), restricted stock units in the Company, or phantom units in the Partnership, as applicable, that remain unvested upon his termination of employment with us under certain circumstances or the occurrence of certain corporate events. 88 Other Matters Stock Ownership Guidelines and Prohibited Transactions Under our stock ownership guidelines adopted in 2013, the Company’s executive officers and certain of the Company’s non-employee directors are required to own a minimum number of shares of our common stock within five years of the adoption of the guidelines, or within five years of becoming an executive officer or being appointed to the Board, as applicable. In particular, each of our executive officers is required to own shares of our common stock having an aggregate fair market value equal to at least a designated multiple of the executive officer’s base salary based on the executive officer’s position. The guidelines for executive officers are set forth in the table below: Officer Level Chief Executive Officer, President, and Chief Financial Officer . . . . . . . . . . . . . . . . . . . . . . . . Vice President . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Officers (if applicable) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ownership Guideline 5x annual base salary 3x annual base salary 1x annual base salary In addition, each of our non-employee directors other than Messrs. Kagan, Keenan, and Manning are required to hold shares of our common stock with a fair market value equal to at least five times the amount of the annual cash retainer we pay to our non-employee directors. These stock ownership guidelines are designed to align our executive officers’ and directors’ interests more closely with those of the Company’s stockholders. The Company’s insider trading policy also prohibits directors, officers or employees from (i) purchasing shares of our common stock on margin, (ii) engaging in short sales of our common stock or (iii) purchasing or selling puts or calls on shares of our common stock. Tax and Accounting Treatment of Executive Compensation Decisions Section 162(m) of the Internal Revenue Code of 1986, as amended (the “Code”), generally imposes a $1 million limit on the amount compensation paid to certain executive officers that a public corporation may deduct for federal income tax purposes in any year unless the compensation qualifies as “performance-based compensation” within the meaning of Section 162(m) of the Code. In our fiscal 2013 proxy, our stockholders approved the material terms of the AR LTIP so that we may grant qualified “performance-based compensation” under the AR LTIP, if determined by the Compensation Committee to be in our best interest and in the best interest of our stockholders. While we will continue to monitor our compensation programs in light of Section 162(m) of the Code, our Compensation Committee considers it important to retain the flexibility to design compensation programs that are in the best long-term interests of our Company and our stockholders. As a result, we have not adopted a policy requiring that all compensation be deductible and our Compensation Committee may conclude that paying compensation at levels that are subject to limits under Section 162(m) of the Code is nevertheless in the best interests of our Company and our stockholders. Many other Code provisions and accounting rules affect the payment of executive compensation and are generally taken into consideration as our compensation arrangements are developed. Our goal is to create and maintain compensation arrangement that are efficient, effective and in full compliance with these requirements. Risk Assessment We have reviewed our compensation policies and practices to determine where they create risks that are reasonably likely to have a material adverse effect on our Company. In connection with this risk assessment, we reviewed the design of our compensation and benefits program and related policies and the potential risks that could be created by the programs and determined that certain features of our programs and corporate governance generally help mitigate risk. Among the factors considered were the mix of cash and equity compensation, the balance between short- and long term objectives of our incentive compensation, the degree to which programs provided for discretion to determine payout amounts and our general governance structure. 89 Our Compensation Committee believes that our approach of evaluating overall business performance and implementation of company objectives assist in mitigating excessive risk-taking that could harm our value or reward poor judgment by our executives. Several features of our programs reflect sound risk management practices. The Compensation Committee believes our overall compensation program provides a reasonable balance between short and long-term objectives, which helps mitigate the risk of excessive risk-taking in the short term. Further, with respect to our incentive compensation programs, the metrics that determine ultimate value are associated with total company value and avoid an environment that might cause pressure to meet specific financial or individual performance goals. In addition, the performance criteria reviewed by the Compensation Committee in determining cash bonuses are based on overall individual performance relative to continually evolving company objectives, and the Compensation Committee uses its subjective judgment in setting bonus levels for our officers. This is based on the Compensation Committee’s belief that applying company-wide objectives encourages decision making that is in the best long-term interests of our Company and our stakeholders as a whole. The multi-year vesting of our equity awards for executive compensation discourage excessive risk-taking and properly accounts for the time horizon of risk. Accordingly, the Compensation Committee concluded that our compensation policies and practices for all employees, including our Named Executive Officers, do not create policies that are reasonably likely to have a material adverse effect on our Company. Board Report The material in this report is not “soliciting material,” is not deemed “filed” with the SEC, and is not to be incorporated by reference into any filing under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in such filing. The Board has reviewed and discussed the foregoing Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussion, the Board has determined that the Compensation Discussion and Analysis shall be included in this Annual Report on Form 10-K. Board Members: Peter R. Kagan W. Howard Keenan, Jr. Christopher R. Manning Richard W. Connor David A. Peters Brooks J. Klimley 90 Summary Compensation Table The following table summarizes, with respect to our Named Executive Officers, information relating to the compensation earned for services rendered in all capacities during the fiscal years ended December 31, 2015, 2014 and 2013: Summary Compensation Table for the Years Ended December 31, 2015, 2014 and 2013 Name and Principal Position Year Salary ($)(1) Bonus ($)(2) Stock Awards ($)(3) Option All Other Awards ($)(3) Compensation ($)(5) Total ($) Paul M. Rady . . . . . . . . . . . . . . . . . . . . . . . . . (Chairman of the Board and Chief Executive Officer) 2015 $ 2014 $ 2013 $ 820,833 $ 800,000 $ 650,000 $ 1,200,000 990,000 $ 960,000 $ 25,567,995 — 6,000,009 $ $ 1,474,000 — $ —(4) Glen C. Warren, Jr. . . . . . . . . . . . . . . . . . . . . . (Director, President and Chief Financial Officer and Secretary) 2015 $ 2014 $ 2013 $ 616,667 $ 600,000 $ 525,000 $ 3,999,992 $ 620,000 $ 600,000 $ 17,051,968 — 950,000 $ 982,672 — $ —(4) Alvyn A. Schopp . . . . . . . . . . . . . . . . . . . . . . . (Chief Administrative Officer and Regional Senior Vice President)(6) 2015 $ 2014 $ 2013 $ 412,500 $ 400,000 $ 350,000 $ 352,750 $ 340,000 $ 500,000 1,500,013 $ 9,392,024 — $ 368,500 — $ —(4) Kevin J. Kilstrom . . . . . . . . . . . . . . . . . . . . . . (Senior Vice President— Production)(6) 2015 $ 2014 $ 2013 $ 412,500 $ 400,000 $ 350,000 $ 352,750 $ 340,000 $ 475,000 1,500,013 $ 9,392,024 — 368,500 — — $ $ Ward D. McNeilly . . . . . . . . . . . . . . . . . . . . . . (Senior Vice President— Reserves, Planning and Midstream)(6) 2015 $ 2014 $ 2013 $ 372,500 $ 360,000 $ 315,000 $ 300,000 $ 288,000 $ 425,000 1,349,995 $ 7,391,986 — $ 331,650 — $ —(4) 10,600 $ 9,295,442 6,677 $ 27,334,673 — $ 1,850,000 10,600 $ 6,229,931 10,400 $ 18,262,368 — $ 1,475,000 10,600 $ 2,644,363 10,400 $ 10,142,424 850,000 — $ 10,600 $ 2,644,363 10,400 $ 10,142,424 825,000 — $ 10,600 $ 2,364,745 10,400 $ 8,050,386 740,000 — $ (1) The amounts reflected in this column may differ from those reported above under “Compensation Discussion and Analysis— Elements of Compensation—Base Salaries” due to the fact that adjustments to the base salaries of our Named Executive Officers for the 2015 fiscal year took effect on March 1, 2015. (2) Represents the aggregate amount of the annual discretionary cash bonuses paid to each Named Executive Officer. (3) The amounts reflected in this column represent the grant date fair value of (i) restricted stock unit awards and stock option awards granted to the Named Executive Officers pursuant to the AR LTIP and (ii) phantom units (which include tandem distribution equivalent rights) granted to the Named Executive Officers pursuant to the Midstream LTIP, computed in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) Topic 718. See Note 5 to our consolidated financial statements for additional detail regarding assumptions underlying the value of these equity awards. (4) In May 2013, Messrs. Rady, Warren, Schopp and McNeilly were each granted additional units in Holdings. As indicated above under the heading “—Compensation Discussion and Analysis—Elements of Compensation—Long-Term Equity-Based Incentive Awards,” the units in Holdings are intended to constitute “profits interests” for federal tax purposes. Accordingly, if Holdings had been liquidated as of the date these units were granted, Messrs. Rady, Warren, Schopp and McNeilly would not have been entitled to receive a distribution with respect to such units. (5) The amounts reflected in this column represent the amount of the Company’s 401(k) match for fiscal 2014 and 2015 for each participating Named Executive Officer. (6) Each of these Named Executive Officers’ titles were changed to “Senior Vice President” effective January 2016. 91 Grants of Plan-Based Awards for Fiscal Year 2015 Name Paul M. Rady Number of Shares of Stock or Units (#)(1) Number of Securities Underlying Options (#)(1) Exercise or Base Price of Option Awards ($/Sh)(2) Grant Date Fair Value of Stock Awards ($)(3) Grant Date Restricted Stock Units . . . . . . . . . . . . . . Stock Options . . . . . . . . . . . . . . . . . . . . . 4/15/2015 4/15/2015 145,103 100,000 $ $ 50.00 $ 6,000,009 1,474,000 Glen C. Warren, Jr. Restricted Stock Units . . . . . . . . . . . . . . Stock Options . . . . . . . . . . . . . . . . . . . . . 4/15/2015 4/15/2015 96,735 66,667 $ $ 50.00 $ 3,999,992 982,672 Alvyn A. Schopp Restricted Stock Units . . . . . . . . . . . . . . Stock Options . . . . . . . . . . . . . . . . . . . . . 4/15/2015 4/15/2015 Kevin J. Kilstrom Restricted Stock Units . . . . . . . . . . . . . . Stock Options . . . . . . . . . . . . . . . . . . . . . 4/15/2015 4/15/2015 Ward D. McNeilly Restricted Stock Units . . . . . . . . . . . . . . Stock Options . . . . . . . . . . . . . . . . . . . . . 4/15/2015 4/15/2015 36,276 36,276 32,648 25,000 $ $ 50.00 $ 1,500,013 368,500 25,000 $ $ 50.00 $ 1,500,013 368,500 22,500 $ $ 50.00 $ 1,349,995 331,650 (1) The equity awards that are disclosed in this Grants of Plan-Based Awards for Fiscal Year 2015 table are restricted stock unit awards and stock option awards of the Company granted under the AR LTIP on April 15, 2015. (2) The closing price our common stock underlying each option on the grant date was $41.35 per share. This amount was less than the $50.00 exercise price of such option. (3) The amounts reflected in this column represent the grant date fair value of restricted stock unit awards and stock option awards granted to the Named Executive Officers pursuant to the AR LTIP, computed in accordance with FASB ASC Topic 718. See Note 5 to our consolidated financial statements for additional detail regarding assumptions underlying the value of these equity awards. Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table The following is a discussion of material factors necessary to an understanding of the information disclosed in the Summary Compensation Table and the Grants of Plan-Based Awards for Fiscal Year 2015 table. Restricted Stock Unit Awards and Stock Option Awards On April 15, 2015, the Compensation Committee granted restricted stock unit awards and stock options under the AR LTIP to each of our Named Executive Officers in April 2015. The restricted stock unit awards and stock option awards granted in 2015 will vest (and, in the case of stock option awards, become exercisable) on April 15 of each of 2016, 2017, 2018 and 2019, so long as the applicable Named Executive Officer remains continuously employed by us from the grant date through the applicable vesting date. All of the restricted stock units and stock option awards will also vest in full (and, in the case of stock option awards, become exercisable) upon a termination of a Named Executive Officer’s employment due to his death or disability. Vested restricted stock units (less any restricted stock units withheld to satisfy applicable tax withholding obligations) will be settled through the issuance of common stock within 30 days following the applicable vesting date. While a Named Executive Officer holds unvested restricted stock units, he is entitled to receive distribution equivalent right credits (the “AR DERs”) equal to cash distributions paid in respect of a share of our common stock. The AR DERs will be paid in cash within 30 days following the vesting of the associated restricted stock units (and will be forfeited at the same time the associated restricted stock units are forfeited). The potential acceleration and forfeiture events related 92 to these restricted stock units are described in greater detail under the heading “Potential Payments Upon Termination or Change in Control” below. Phantom Unit Awards On November 12, 2014, the Compensation Committee granted phantom units under the Midstream LTIP to each of our Named Executive Officers in connection with the initial public offering of the Partnership. Twenty-five percent of the phantom units granted to each of our Named Executive Officers will become vested on each of the first four anniversaries of the grant date so long as the applicable Named Executive Officer remains continuously employed by us from the grant date through the applicable vesting date. All of the phantom units granted to each Named Executive Officer will also become fully vested immediately if such Named Executive Officer’s employment terminates due to his death or disability. Vested phantom units (less any phantom units withheld to satisfy applicable tax withholding obligations) will be settled through the issuance of common units within 30 days following the applicable vesting date. While a Named Executive Officer holds unvested phantom units, he is entitled to receive distribution equivalent right credits (the “Midstream DERs”) equal to cash distributions paid in respect of a common unit of the Partnership. The Midstream DERs will be paid in cash within 30 days following the vesting of the associated phantom units (and will be forfeited at the same time the associated phantom units are forfeited). The potential acceleration and forfeiture events relating to these phantom units are described in greater detail under the heading “Potential Payments Upon Termination or Change of Control” below. 93 Outstanding Equity Awards at 2015 Fiscal Year-End The following table provides information concerning equity awards that have not vested for our Named Executive Officers as of December 31, 2015: Number of Securities Underlying Unexercised Options Unexercisable (#)(2) Option Awards(1) Number of Securities Underlying Unexercised Options Exercisable (#)(3) Option Exercise Price ($) Stock Awards(7) Number of Units That Have Not Vested (#)(8) Market Value of Units That Have Not Vested ($)(9) Option Expiration Date — — 1,250,000 113,670 500,000 1,250,000 N/A(6) N/A(6) N/A(6) N/A(6) N/A(6) N/A(6) 100,000 — $ 50.00 4/15/2025 — — 833,333 75,780 333,333 833,334 N/A(6) N/A(6) N/A(6) N/A(6) N/A(6) N/A(6) 66,667 — $ 50.00 4/15/2025 — — 212,500 50,000 125,000 212,500 N/A(6) N/A(6) N/A(6) N/A(6) N/A(6) N/A(6) 25,000 — $ 50.00 4/15/2025 — — 200,000 400,000 N/A(6) N/A(6) N/A(6) N/A(6) 25,000 — $ 50.00 4/15/2025 — — 20,000 — 55,000 50,000 50,000 120,000 50,000 55,000 N/A(6) N/A(6) N/A(6) N/A(6) N/A(6) N/A(6) N/A(6) N/A(6) N/A(6) N/A(6) 22,500 — $ 50.00 4/15/2025 452,417 $ 9,862,691 144,000 $ 3,286,080 301,713 $ 6,577,343 96,000 $ 2,190,720 128,471 $ 2,800,657 821,520 36,000 $ 128,471 $ 2,800,657 821,520 36,000 $ 101,794 $ 2,219,098 821,520 36,000 $ Name Paul M. Rady Class A-2 Units . . . . . . . . . . . . . . . . . . . . . . . . . Class B-2 Units . . . . . . . . . . . . . . . . . . . . . . . . . Class B-4 Units(4) . . . . . . . . . . . . . . . . . . . . . . Restricted Stock Units . . . . . . . . . . . . . . . . . . . Phantom Units . . . . . . . . . . . . . . . . . . . . . . . . . Stock Options(5) . . . . . . . . . . . . . . . . . . . . . . . . Glen C. Warren, Jr. Class A-2 Units . . . . . . . . . . . . . . . . . . . . . . . . . Class B-2 Units . . . . . . . . . . . . . . . . . . . . . . . . . Class B-4 Units(4) . . . . . . . . . . . . . . . . . . . . . . Restricted Stock Units . . . . . . . . . . . . . . . . . . . Phantom Units . . . . . . . . . . . . . . . . . . . . . . . . . Stock Options(5) . . . . . . . . . . . . . . . . . . . . . . . . Alvyn A. Schopp Class A-2 Units . . . . . . . . . . . . . . . . . . . . . . . . . Class B-2 Units . . . . . . . . . . . . . . . . . . . . . . . . . Class B-4 Units(4) . . . . . . . . . . . . . . . . . . . . . . Restricted Stock Units . . . . . . . . . . . . . . . . . . . Phantom Units . . . . . . . . . . . . . . . . . . . . . . . . . Stock Options(5) . . . . . . . . . . . . . . . . . . . . . . . . Kevin J. Kilstrom Class A-2 Units . . . . . . . . . . . . . . . . . . . . . . . . . Class B-2 Units . . . . . . . . . . . . . . . . . . . . . . . . . Restricted Stock Units . . . . . . . . . . . . . . . . . . . Phantom Units . . . . . . . . . . . . . . . . . . . . . . . . . Stock Options(5) . . . . . . . . . . . . . . . . . . . . . . . . Ward D. McNeilly Class A-2 Units . . . . . . . . . . . . . . . . . . . . . . . . . Class B-2 Units . . . . . . . . . . . . . . . . . . . . . . . . . Class B-4 Units(4) . . . . . . . . . . . . . . . . . . . . . . Class B-7 Units . . . . . . . . . . . . . . . . . . . . . . . . . Class B-13 Units(4) . . . . . . . . . . . . . . . . . . . . . Restricted Stock Units . . . . . . . . . . . . . . . . . . . Phantom Units . . . . . . . . . . . . . . . . . . . . . . . . . Stock Options(5) . . . . . . . . . . . . . . . . . . . . . . . . (1) The equity awards that are disclosed in this Outstanding Equity Awards at 2015 Fiscal Year-End table under Option Awards are (i) units in Holdings that are intended to constitute profits interests for federal tax purposes rather than traditional option awards and (ii) stock option awards granted under the AR LTIP. (2) Awards reflected as “Unexercisable” are Holdings units and stock option awards that have not yet become vested. 94 (3) Awards reflected as “Exercisable” are Holdings units that have become vested, but have not yet been settled. (4) One-half of the unvested Holdings units reflected in this row will become vested on each of May 7, 2016 and May 7, 2017 so long as the applicable Named Executive Officer remains continuously employed by us or one of our affiliates through each such date. (5) One-fourth of the unvested stock option awards reflected in this row will become vested and exercisable on each of April 15, 2016, April 15, 2017, April 15, 2018 and April 15, 2019 so long as the applicable Named Executive Officer remains continuously employed by us or one of our affiliates through each such date. (6) These equity awards are not traditional options and, therefore, there is no exercise price or expiration date associated with them. (7) The equity awards that are disclosed in this Outstanding Equity Awards at 2015 Fiscal Year-End table under the Stock Awards column consist of restricted stock units granted under the AR LTIP and phantom units granted under the AM LTIP. (8) Except as otherwise provided in the applicable award agreement, (1) 2015 restricted unit awards will vest on April 15 of each of 2016, 2017, 2018 and 2019, (2) 2014 restricted unit awards (A) with respect to Messrs. Rady and Warren, 50% will vest on October 22 of each of 2016 and 2017 or (B) with respect to Messrs. Schopp, Kilstrom, and McNeilly, 25% of the remaining restricted stock units will vest on April 1 of each of 2016, 2017, and 2018 and (3) 25% of the remaining phantom units will vest on November 12 of each of 2016, 2017, and 2018, in each case, so long as the applicable Named Executive Officer remains continuously employed by us from the grant date through the applicable vesting date. (9) The amounts reflected in this column represent the market value of (i) common stock underlying the restricted stock unit awards granted to the Named Executive Officers, computed based on the closing price of our common stock on December 31, 2015, which was $21.80 per share, and (ii) common units of the Partnership underlying the phantom unit awards granted to the Named Executive Officers, computed based on the closing price of the Partnership’s common units on December 31, 2015, which was $22.82 per unit. Option Exercises and Stock Vested in Fiscal Year 2015 The following table provides information concerning equity awards that vested or were exercised by our Named Executive Officers during the 2015 fiscal year: Name Paul M. Rady Restricted Stock Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Phantom Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Glen C. Warren, Jr. Restricted Stock Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Phantom Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Alvyn A. Schopp Restricted Stock Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Phantom Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Kevin J. Kilstrom Restricted Stock Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Phantom Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ward D. McNeilly Restricted Stock Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Phantom Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Option Awards(1) Stock Awards(2) Number of Shares Acquired on Exercise (#) Value Realized on Exercise ($) Number of Shares Acquired on Vesting (#) Value Realized on Vesting ($)(3) — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — — — — — — — — — — — $ — 48,000 $ 1,092,480 — $ 32,000 $ — 728,320 30,731 $ 1,086,341 273,120 12,000 $ 30,731 $ 1,086,341 273,120 12,000 $ 23,048 $ 12,000 $ 814,747 273,120 (1) The units in Holdings are intended to constitute profits interests for federal tax purposes rather than traditional option awards and thus do not have any exercise features associated with them. There were no other stock option exercises during the 2015 fiscal year. 95 (2) The equity awards that vested during the 2015 fiscal year disclosed under the Stock Awards columns consist of restricted stock units granted under the AR LTIP and phantom units granted under the AM LTIP. (3) The amounts reflected in this column represent the aggregate market value realized by each Named Executive Officer upon vesting of (i) the restricted stock unit awards held by such Named Executive Officer, computed based on the closing price of our common stock on the applicable vesting date, and (ii) the phantom unit awards held by such Named Executive Officer, computed based on the closing price of the Partnership’s common units on the applicable vesting date. Pension Benefits We do not provide pension benefits to our employees. Nonqualified Deferred Compensation We do not provide nonqualified deferred compensation benefits to our employees. Payments Upon Termination or Change in Control Holdings Units As described above, we do not maintain individual employment agreements, severance agreements or change in control agreements with our Named Executive Officers; however, the unvested units in Holdings granted to Messrs. Rady, Warren, Schopp and McNeilly could be affected by the termination of their employment or the occurrence of certain corporate events. The impact of such a termination or corporate event upon the units is governed by the terms of both the restricted unit agreements issued to them in connection with the grant of their unit awards, as well as the limited liability company agreement of Holdings (the “Holdings LLC Agreement”). The Holdings LLC Agreement provides that upon the termination of a Named Executive Officer’s employment with us by reason of death or “disability” (as defined below) or upon the occurrence of an “exit event” (as defined below) while the Named Executive Officer is employed by us, any unvested portion of the Holdings units granted to the Named Executive Officer will become vested; our termination of the Named Executive Officer’s employment with or without “cause,” as well as the officer’s voluntary termination of employment, generally results in the forfeiture of all unvested Holdings units. In addition, a termination for “cause” results in a forfeiture of all vested units. Any unvested portion of the Holdings units granted to a Named Executive Officer may also become immediately vested under such circumstances and at such times as the board of directors of Holdings determines to be appropriate in its discretion. The Holdings LLC Agreement also provides that upon the voluntary resignation of a Named Executive Officer or the occurrence of an exit event, any portion of the Holdings units granted to the officer that have vested as of the time of the applicable event are subject to repurchase, at Holdings’ option, at a purchase price equal to the “fair market value” of such units, as determined by the unanimous resolution of the board of directors of Holdings. Such amount may be paid by Holdings in cash or by promissory note. In addition, in lieu of electing to repurchase all or any portion of a Named Executive Officer’s vested units in Holdings, the board of directors of Holdings has the right to modify such units so that the aggregate amount that may potentially be distributed with respect to such units is “capped” at the lesser of (a) the aggregate amount that the Named Executive Officer is entitled to receive with respect to such units under the Holdings LLC Agreement or (b) an amount equal to the sum of (x) the fair market value of such units as of the date the Named Executive Officer’s employment terminates (the “Termination Value”) and (y) an accretion amount with respect to the Termination Value calculated based upon a rate equal to 5% per annum, compounding annually in arrears as of the Termination Date. Under the Holdings LLC Agreement, a Named Executive Officer will be considered to have incurred a “disability” if the officer becomes incapacitated by accident, sickness or other circumstance that renders the officer mentally or physically incapable of performing the officer’s duties with us on a full time basis for a period of at least 120 days during any 12 month period. A termination for “cause” will occur following an employee’s (1) gross negligence or willful misconduct, (2) conviction of a felony or a crime involving theft, fraud or moral turpitude, (3) refusal to perform material duties or responsibilities, (4) willful and material breach of a corporate policy or code of conduct or (5) willful engagement in conduct that damages the integrity, reputation or financial success of Antero or any of its affiliates. Further, an “exit event” generally includes the sale of our Company, in one transaction or a series of related transactions, 96 whether structured as (a) a sale or other transfer of all or substantially all of our units (including by way of merger, consolidation, share exchange, or similar transaction), (b) a sale or other transfer of all or substantially all of our assets promptly followed by a dissolution and liquidation of our Company or (c) a combination of the transactions described in clauses (a) and (b). Restricted Stock Units, Phantom Units and Stock Options As noted above, any unvested restricted stock units, unvested phantom units or unvested stock options granted to our Named Executive Officers will become immediately fully vested (and, in the case of stock options, fully exercisable) if the applicable Named Executive Officer’s employment with us terminates due to his death or “disability.” For purposes of these awards, a Named Executive Officer will be considered to have incurred a “disability” if he is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or which has lasted or can be expected to last for a continuous period of not less than 12 months. Potential Payments Upon Termination or Change in Control Table for Fiscal 2015 Because the right to repurchase vested Holdings units is optional rather than mandatory, none of our Named Executive Officers would have had a right to receive any amounts in respect of their Holdings units on or after a termination of their employment or the occurrence of an exit event as of December 31, 2015. However, if Messrs. Rady, Warren, Schopp and McNeilly’s employment with us would have terminated due to the Named Executive Officers’ death or disability or if an exit event occurred, the unvested portion of his Holdings units would have become vested. The Holdings units effectively represent an indirect interest in certain shares of our common stock and, as of December 31, 2015, all of the units in Holdings held by our Named Executive Officers were fully vested. The closing price of our common stock on December 31, 2015 was $21.80 per share. Similarly, if any of our Named Executive Officers’ employment with us would have terminated due to the Named Executive Officers’ death or disability, the unvested portion of his restricted stock units, phantom units and stock options, as applicable, would have become vested. The restricted stock units (and, if exercised, the stock options) represent a direct interest in shares of our common stock, and the closing price of our common stock on December 31, 2015 was $21.80 per share. The phantom units represent a direct interest in the Partnership’s common units, and the closing price of the Partnership’s common units on December 31, 2015 was $22.82 per unit. The amounts that each of our Named Executive Officers would receive in connection with the accelerated vesting of their equity awards (other than stock options) upon a termination due to their death or disability (assuming such termination occurred on December 31, 2015) are reflected in the last column of the Outstanding Equity Awards at 2015 Fiscal Year-End table above. Because the exercise price of stock options held by our Named Executive Officers exceeded the fair market value of the Company’s common stock on December 31, 2015, no value would have been received by our Named Executive Officers with respect to their stock options in connection with the accelerated vesting of these awards. Compensation of Directors General Each director of our general partner who is not an officer or employee of Antero receives the following compensation for serving as a director: • • an annual retainer fee of $60,000 per year; an additional retainer of $7,500 per year if such director is a member of the audit committee (or an additional retainer of $12,500 per year if such director serves as the chairperson of the audit committee); and 97 • an additional retainer of $5,000 per year if such director is a member of the conflicts committee (or an additional retainer of $10,000 per year if such director serves as the chairperson of the conflicts committee). In addition to cash compensation, our non-employee directors receive annual equity-based compensation consisting of restricted units under the Midstream LTIP with an aggregate grant date value equal to $100,000, subject to the terms and conditions of the Midstream LTIP and the award agreements pursuant to which such awards are granted. All retainers are paid in cash on a quarterly basis in arrears, but directors have the option to elect to receive their retainers in the form of common units pursuant to the Midstream LTIP rather than in cash. Our non-employee directors do not receive any meeting fees, but each director is reimbursed for (i) travel and miscellaneous expenses to attend meetings and activities of the board of directors of our general partner or its committees and (ii) travel and miscellaneous expenses related to participation in general education and orientation programs for directors. Effective December 15, 2015 the Company adopted a non-employee director compensation policy that increases the annual base retainer to $70,000 per year and calls for quarterly grants of fully vested common units with an aggregate value equal to $100,000 per year. In addition, the policy increases the retainer for members of the conflicts committee to $10,000 per year. Director Compensation Table Officers or employees of Antero who also serve as directors of our general partner do not receive additional compensation for such service. The following table provides information concerning the compensation of our non- employee directors for the fiscal year ended December 31, 2015: Name Peter R. Kagan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ W. Howard Keenan, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Christopher R. Manning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Richard W. Connor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ David A. Peters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Brooks J. Klimley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Fees Earned or Paid in Cash ($)(1) Unit Awards ($)(2) Total ($) 60,000 $ 60,000 $ 60,000 $ 78,750 $ 82,500 $ 73,750 $ 20,660 $ 80,660 20,660 $ 80,660 20,660 $ 80,660 20,660 $ 99,410 20,660 $ 103,160 20,660 $ 94,410 (1) Includes annual cash retainer fee and committee chair fees for each non-employee director during fiscal 2015, as more fully explained above. (2) Effective December 15, 2015 the Partnership adopted a non-employee director compensation policy that calls for quarterly grants of fully vested units. Under the previous policy, the annual equity awards were granted in advance of each fiscal year. The amounts reported in this column reflect only the prorated grant amount for the period from October 16, 2015 to December 31, 2015. The equity awards for the portion of 2015 prior to the prorated portion of the 4th quarter were granted in 2014. The prorated grant was made on January 11, 2016 and reflects the aggregate grant date fair value of restricted units granted under the Midstream LTIP in fiscal year 2015, computed in accordance with FASB ASC Topic 718. See Note 5 to our consolidated financial statements for additional detail regarding assumptions underlying the value of these equity awards. The grant date fair value for restricted unit awards is based on the closing price of our common units on the grant date of January 11, 2016, which was $19.13 per unit. 98 Equity Compensation Plan Information The following table sets forth information about equity securities that may be issued under all existing equity compensation plans of the Partnership as of December 31, 2015: Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) Weighted-average exercise price of outstanding options, warrants and rights (b) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) Plan Category Equity compensation plans approved by security holders Antero Resources Corporation Long-Term Incentive Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,242,846(1) $ 50.44 (3) 9,377,755 Antero Midstream Partners LP Long Term Incentive Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,663,778(2) N/A(4) 7,947,771 Equity compensation plans not approved by security holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 8,906,624 — — 17,325,526 (1) The Antero Resources Corporation Long-Term Incentive Plan (the “AR LTIP”) was approved by our sole stockholder prior to our IPO and by our shareholders at the 2014 annual meeting of stockholders. (2) The Antero Midstream Partners LP Long Term Incentive Plan (the “Midstream LTIP”) was approved by the Company and the general partner of the Partnership prior to its IPO. (3) The calculation of the weighted-average exercise price of outstanding options, warrants and rights excludes restricted stock unit awards granted under the AR LTIP. (4) Only phantom unit awards and restricted unit awards have been granted under the Midstream LTIP, and there is no weighted average exercise price associated with these awards. Item 12. Security Ownership of Certain Beneficial Owners and Management The following table sets forth the beneficial ownership of common units and subordinated units of Antero Midstream Partners LP that were issued and outstanding as of February 19, 2016 held by: • • • • our general partner; beneficial owners of 5% or more of our common units; each director and named executive officer; and all of our general partner’s directors and executive officers as a group. Except as otherwise noted, the person or entities listed below have sole voting and investment power with respect to all of our common units beneficially owned by them, except to the extent this power may be shared with a spouse. All information with respect to beneficial ownership has been furnished by the respective directors, officers or 99 beneficial owners of 5% or more of our common units, as the case may be. Unless otherwise noted, the address for each beneficial owner listed below is 1615 Wynkoop Street, Denver, Colorado 80202. Percentage of Percentage of Common and Name of Beneficial Owner Antero Resources Corporation(¹) . . . . . . . Antero Resources Midstream Common Units Beneficially Owned Percentage of Common Units Beneficially Owned Subordinated Subordinated Subordinated Units Beneficially Owned Units Beneficially Owned Units Beneficially Owned 40,929,378 40.8% 75,940,957 100 % 66.3% Management LLC(²) . . . . . . . . . . . . . . . Goldman Sachs Asset Management(3) . . Tortoise Capital Advisors, L.L.C.(4) . . . . Richard W. Connor . . . . . . . . . . . . . . . . . Peter R. Kagan(5) . . . . . . . . . . . . . . . . . . . W. Howard Keenan, Jr. (6) . . . . . . . . . . . . Brooks J. Klimley(7)(8) . . . . . . . . . . . . . . . Christopher R. Manning . . . . . . . . . . . . . David A. Peters . . . . . . . . . . . . . . . . . . . . Paul M. Rady . . . . . . . . . . . . . . . . . . . . . . Glen C. Warren, Jr. . . . . . . . . . . . . . . . . . Kevin J. Kilstrom . . . . . . . . . . . . . . . . . . Alvyn A. Schopp . . . . . . . . . . . . . . . . . . . Ward D. McNeilly . . . . . . . . . . . . . . . . . . All directors and executive officers as a — 12,754,491 9,944,451 10,080 5,080 5,080 5,134 15,080 11,080 85,892 59,654 6,410 12,410 6,410 —% 12.7 % 9.9 % * % * % * % * % * % * % * % * % * % * % * % group (12 persons) . . . . . . . . . . . . . . . . 237,919 * % — — — — — — — — — — — — — — — —% —% —% —% —% —% —% —% —% —% —% —% —% —% —% —% 7.2 % 5.6 % * % * % * % * % * % * % * % * % * % * % * % * % Less than 1%. * (1) Under Antero’s amended and restated certificate of incorporation and bylaws, the voting and disposition of any of our common or subordinated units held by Antero will be controlled by the board of directors of Antero. The board of directors of Antero, which acts by majority approval, comprises Peter R. Kagan, W. Howard Keenan, Jr., Christopher R. Manning, Robert J. Clark, Richard W. Connor, Benjamin A. Hardesty, James R. Levy, Paul M. Rady and Glen C. Warren, Jr. Each of the members of Antero’s board of directors disclaims beneficial ownership of any of our units held by Antero. (2) Under our general partner’s amended and restated limited liability company agreement, the voting and disposition of any of our common or subordinated units or the incentive distribution rights held by our general partner will be controlled by its sole member, Antero Investment. The board of directors of Antero Investment, which acts by majority approval, comprises Peter R. Kagan, W. Howard Keenan, Jr., Christopher R. Manning, Paul M. Rady and Glen C. Warren, Jr. Each of the members of Antero Investment’s board of directors disclaims beneficial ownership of any of our securities held by our general partner. (3) Goldman Sachs Asset Management, L.P. and GS Investment Strategies, LLC (collectively, “Goldman Sachs Asset Management”) have a mailing address of 200 West Street, New York, New York 10282 and share voting and dispositive power with respect to all of our common units reported as beneficially owned. (4) Tortoise Capital Advisors, L.L.C. (“TCA”) has a mailing address of 11550 Ash Street, Suite 300, Leawood, Kansas 66211. TCA acts as an investment adviser to certain investment companies registered under the Investment Company Act of 1940 and also acts as an investment adviser to certain managed accounts. TCA has sole voting and dispositive power with respect to 117,536 of our common units, shared voting power with respect to 9,103,270 of our common units and shared dispositive power with respect to 9,826,915 of our common units by virtue of investment advisory agreements with these investment companies, and contractual agreements with these managed account clients (5) Has a mailing address of 450 Lexington Avenue, New York, New York 10017. (6) Has a mailing address of 410 Park Avenue, 19th Floor, New York, New York 10022. (7) Has a mailing address of 599 Lexington Avenue, 47th Floor, New York, New York 10022. (8) Includes 4,054 common units that remain subject to vesting. 100 The following table sets forth the number of shares of common stock of Antero owned by each of the named executive officers and directors of our general partner and all directors and executive officers of our general partner as a group as of February 19, 2016: Shares Beneficially Percentage of Shares Beneficially Owned Owned Name of Beneficial Owner Richard W. Connor(1)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,229 Peter R. Kagan(1)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38,399 W. Howard Keenan, Jr.(1)(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,189 2,500 Brooks J. Klimley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Christopher R. Manning(1)(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43,939 David A. Peters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Paul M. Rady(6)(7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,926,948 Glen C. Warren, Jr.(8)(9)(10) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,618,115 Kevin J. Kilstrom(11) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 347,476 Alvyn A. Schopp(12) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,220,081 Ward D. McNeilly(13) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 340,805 All directors and executive officers as a group (12 persons) . . . . . 33,791,078 * * * * * — 6.8 % 4.6 % * * * 12.2 % Less than 1%. * (1) Includes options to purchase 1,477 shares of common stock that expire ten years from the date of grant, or October 10, 2023, and options to purchase 1,526 shares of common stock that expire ten years from the date of grant, or October 16, 2024. (2) Mr. Connor indirectly owns 40 shares of common stock purchased by a family member, and these shares are included because of his relation to the purchaser. Mr. Connor disclaims beneficial ownership of all shares reported except to the extent of his pecuniary interest therein. (3) Has a mailing address of 450 Lexington Avenue, New York, New York 10017. (4) Has a mailing address of 410 Park Avenue, 19th Floor, New York, New York 10022. (5) Mr. Manning indirectly owns 35,750 shares of common stock purchased by TCP Antero Principals LLC, a Trilantic Capital Partners entity, and these shares are included because of his affiliation with Trilantic Capital Partners, as described above. (6) Includes 5,770,806 shares of common stock held by Salisbury Investment Holdings LLC (“Salisbury”) and 2,511,712 shares of common stock held by Mockingbird Investments LLC (“Mockingbird”). Mr. Rady owns a 95% limited liability company interest in Salisbury and his spouse owns the remaining 5%. Mr. Rady owns a 3.68% limited liability company interest in Mockingbird, and a trust under his control owns the remaining 96.32%. Mr. Rady disclaims beneficial ownership of all shares held by Salisbury and Mockingbird except to the extent of his pecuniary interest therein. (7) Includes 452,417 shares of common stock that remain subject to vesting and options to purchase 25,000 shares of common stock that expire ten years from the date of grant, or April 15, 2025. (8) Mr. Warren indirectly owns 7 shares of common stock purchased by a family member, and these shares are included because of his relation to the purchaser. Mr. Warren disclaims beneficial ownership of all shares reported except to the extent of his pecuniary interest therein. (9) Includes 3,847,251 shares of common stock held by Canton Investment Holdings LLC (“Canton”). Mr. Warren is the sole member of Canton. Mr. Warren disclaims beneficial ownership of all shares held by Canton except to the extent of his pecuniary interest therein. (10) Includes 301,713 shares of common stock that remain subject to vesting and options to purchase 16,666 shares of common stock that expire ten years from the date of grant, or April 15, 2025. (11) Includes 215,971 shares of common stock that remain subject to vesting and options to purchase 6,250 shares of common stock that expire ten years from the date of grant, or April 15, 2025. (12) Includes 328,471 shares of common stock that remain subject to vesting and options to purchase 6,250 shares of common stock that expire ten years from the date of grant, or April 15, 2025. (13) Includes 189,294 shares of common stock that remain subject to vesting and options to purchase 5,625 shares of common stock that expire ten years from the date of grant, or April 15, 2025. 101 Securities Authorized for Issuance Under Equity Compensation Plan Please read the information under “Item 11. Executive Compensation – Compensation Discussion and Analysis – Equity Compensation Plan Information.” Item 13. Certain Relationships and Related Transactions and Director Independence As of February 19, 2016, Antero owned 40,929,378 common units and 75,940,957 subordinated units representing an aggregate approximately 66.3% limited partner interest in us. Antero Investment owns and controls (and appoints all the directors of) our general partner, which owns a non-economic general partner interest in us and the incentive distribution rights. Distributions and Payments to Our General Partner and Its Affiliates The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the conversion, ongoing operation and any liquidation of us. Conversion of Antero Resources Midstream LLC to Antero Midstream Partners LP The aggregate consideration received by our general partner in connection with the conversion of its special membership interest pursuant to the limited liability company agreement of Antero Resources Midstream LLC The aggregate consideration received by Antero in connection with the conversion of its common economic interest pursuant to the limited liability company agreement of Antero Resources Midstream LLC • the non-economic general partner interest; and • the incentive distribution rights. • 35,940,957 common units; • 75,940,957 subordinated units; • a distribution of $332.5 million to reimburse it for certain capital expenditures it incurred in connection with the Predecessor prior to Midstream Operating being contributed to us; • our assumption of $510 million of indebtedness incurred in connection with the Predecessor prior to Midstream Operating being contributed to us; and • we will also undertake a public or private offering of common units in the future upon request by Antero and use the proceeds thereof (net of underwriting or placement agency discounts and commissions, as applicable) to redeem an equal number of common units from Antero as a distribution to reimburse Antero for certain capital expenditures incurred in connection with the Predecessor prior to Midstream Operating being contributed to us. Option units or proceeds from option In connection with the completion of the IPO, the underwriters exercised units their option to purchase additional common units. We used the net proceeds resulting from the issuance of 6,000,000 common units upon such exercise to acquire an equivalent number of common units from Antero, which common units were cancelled, to reimburse Antero for capital expenditures incurred in connection with the Predecessor prior to Midstream Operating being contributed to us. 102 Operational Stage Distributions of cash available for distribution to our general partner and its affiliates Payments to our general partner and its affiliates Withdrawal or removal of our general partner Liquidation Stage Liquidation Agreements with Antero We will generally make cash distributions 100% to our unitholders, including affiliates of our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level. Assuming we have sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our outstanding common units and subordinated units for four quarters, our general partner and its affiliates (including Antero) would receive an annual distribution of approximately $76.1 million on their units. Antero provides customary management and general administrative services to us. Our general partner reimburses Antero at cost for its direct expenses incurred on behalf of us and a proportionate amount of its indirect expenses incurred on behalf of us, including, but not limited to, compensation expenses. Our general partner does not receive a management fee or other compensation for its management of our partnership, but we reimburse our general partner and its affiliates for all direct and indirect expenses they incur and payments they make on our behalf, including payments made to Antero for customary management and general administrative services. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. If our general partner withdraws or is removed, its non-economic general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement—Withdrawal or Removal of Our General Partner.” Upon our liquidation, the partners, including our general partner,will be entitled to receive liquidating distributions according to their respective capital account balances. We have entered into certain agreements with Antero, as described in more detail below. Registration Rights Agreement Pursuant to the registration rights agreement, we may be required to register the sale of Antero’s (i) common units issued (or issuable) to it pursuant to the contribution agreement, (ii) subordinated units and (iii) common units issuable upon conversion of subordinated units pursuant to the terms of the partnership agreement (together, the “Registrable Securities”) in certain circumstances. 103 Demand Registration Rights Antero has the right to require us by written notice to register the sale of a number of their Registrable Securities in an underwritten offering. We are required to provide notice of the request within 10 days following the receipt of such demand request to all additional holders of Registrable Securities, if any, who may, in certain circumstances, participate in the registration. We are not obligated to effect any demand registration in which the anticipated aggregate offering price included in such offering is less than $50,000,000. While we are eligible to effect a registration on Form S-3, any such demand registration may be for a shelf registration statement. Piggy-back Registration Rights If, at any time, we propose to register an offering of our securities (subject to certain exceptions) for our own account, then we must give to Antero securities to allow it to include a specified number of Registrable Securities in that registration statement. Redemptive Offerings We may be required pursuant to the registration rights agreement to undertake a future public or private offering and use the proceeds (net of underwriting or placement agency discounts, fees and commissions, as applicable) to redeem an equal number of common units from Antero. Conditions and Limitations; Expenses The registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of Registrable Securities to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the registration rights agreement, regardless of whether a registration statement is filed or becomes effective. The obligations to register Registrable Securities under the registration rights agreement will terminate when no Registrable Securities remain outstanding. Registrable Securities shall cease to be covered by the registration rights agreement when they have (i) been sold pursuant to an effective registration statement under the Securities Act, (ii) been sold in a transaction exempt from registration under the Securities Act (including transactions pursuant to Rule 144), (iii) ceased to be outstanding, (iv) been sold in a private transaction in which Antero’s rights under the registration rights agreement are not assigned to the transferee or (v) become eligible for resale pursuant to Rule 144(b) (or any similar rule then in effect under the Securities Act). Services Agreement Pursuant to the services agreement, Antero has agreed to provide customary operational and management services for us in exchange for reimbursement of its direct expenses and an allocation of its indirect expenses attributable to the provision of such services to us. On September 23, 2015, Antero, the Partnership and Midstream Management amended and restated the services agreement to remove provisions relating to operational services in support of our gathering and compression business which is now covered by a secondment agreement and to provide that Antero will perform certain administrative services for us and our subsidiaries, and we will reimburse Antero for expenditures incurred by Antero in the performance of those administrative services. Secondment Agreement In connection with the Water Acquisition, on September 23, 2015, we entered into a secondment agreement with Antero, Midstream Management, Midstream Operating, Antero Water and Antero Treatment, whereby Antero has agreed to provide seconded employees to perform certain operational services with respect to our gathering and compression facilities and the Contributed Assets, and we have agreed to reimburse Antero for expenditures incurred by Antero in the performance of those operational services. The initial term of the secondment agreement is twenty years from November 10, 2014, and from year to year thereafter. 104 Gathering and Compression Pursuant to our 20-year gas gathering and compression agreement with Antero, Antero has agreed to dedicate all of its current and future acreage in West Virginia, Ohio and Pennsylvania to us (other than the existing third-party commitments), so long as such production is not otherwise subject to a pre-existing dedication to third-party gathering systems. Antero’s production subject to a pre-existing dedication will be dedicated to us at the expiration of such pre-existing dedication. In addition, if Antero acquires any gathering facilities, it is required to offer such gathering facilities to us at its cost. 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, a compression fee of $0.18 per Mcf, and a condensate gathering fee of $4.00 per Bbl, in each case subject to CPI-based adjustments. If and to the extent Antero requests that we construct new high pressure lines and compressor stations requested by Antero, the gathering and compression agreement contains minimum volume commitments that require Antero to utilize or pay for 75% and 70%, respectively, of the capacity of such new construction. 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, as well as price adjustment mechanisms, are intended to support the stability of our cash flows. We also have an option to gather and compress natural gas produced by Antero on any acreage it acquires in the future outside of West Virginia, Ohio and Pennsylvania on the same terms and conditions. In the event that we do not exercise this option, Antero will be entitled to obtain gathering and compression services and dedicate production from limited areas to such third-party agreements from third parties. In return for Antero’s acreage dedication, we have agreed to gather, compress, dehydrate and redeliver all of Antero’s dedicated natural gas on a firm commitment, first-priority basis. We may perform all services under the gathering and compression agreement or we may perform such services through third parties. In the event that we do not perform our obligations under the gathering and compression agreement, Antero will be entitled to certain rights and procedural remedies thereunder. Pursuant to the gathering and compression agreement, we have also agreed to build to and connect all of Antero’s wells producing dedicated natural gas, subject to certain exceptions, upon 180 days’ notice by Antero. In the event of late connections, Antero’s natural gas will temporarily not be subject to the dedication. We are entitled to compensation under the gathering and compression agreement for capital costs incurred if a well does not commence production within 30 days following the target completion date for the well set forth in the notice from Antero. We have agreed to install compressor stations at Antero’s direction, but will not be responsible for inlet pressures or for pressuring natural gas to enter downstream facilities if Antero has not directed us to install sufficient compression. Additionally, we will provide high pressure gathering pursuant to the gathering and compression agreement. Upon completion of the initial 20-year term, the gathering and compression agreement will continue in effect from year to year until such time as the agreement is terminated, effective upon an anniversary of the effective date of the agreement, by either us or Antero on or before the 180th day prior to the anniversary of such effective date. Water Services In connection with the Water Acquisition, on September 23, 2015, we entered in a 20-year Water Services Agreement with Antero whereby we have agreed to provide certain fluid handling services to Antero within an area of dedication in defined service areas in Ohio and West Virginia and Antero agrees to pay monthly fees to us for all fluid handling services provided by us in accordance with the terms of the Water Services Agreement. The initial term of the Water Services Agreement is twenty years from the date thereof and from year to year thereafter. Under the agreement, Antero 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 has committed to pay a fee on a minimum volume of fresh water deliveries in calendar years 2016 through 2019. Antero is obligated to 105 pay a minimum of 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 also agreed to pay us a fixed fee of $4.00 per barrel for waste water treatment at the advanced waste water treatment complex and a fee per barrel for waste water collected in trucks owned by us, in each case subject to annual CPI-based adjustments. Until such time as the advanced waste water treatment complex is placed into service or we operate our own fleet of trucks for transporting waste water, we will continue to contract with third parties to provide Antero flow back and produced water services and Antero will reimburse us third party out-of-pocket costs plus 3%. Upon completion of the initial 20-year term, the fresh water distribution agreement will continue in effect from year to year until such time as the agreement is terminated, effective upon an anniversary of the effective date of the agreement, by either us or Antero on or before the 180th day prior to the anniversary of such effective date. Processing Although we do not currently have any processing or NGLs fractionation, transportation or marketing infrastructure, we have entered into a right-of-first-offer agreement with Antero for gas processing services, pursuant to which Antero has agreed, subject to certain exceptions, not to procure any gas processing or NGLs fractionation, transportation or marketing services with respect to its production (other than production subject to a pre-existing dedication) without first offering us the right to provide such services. Antero’s request for offer will describe the production that will be dedicated under the resulting agreement and the capacities of the facilities it desires and, if applicable, details of the facility Antero has acquired or proposes to acquire. Antero is permitted concurrently to seek offers from third parties for the same services on the same terms and conditions, but we have a right to match the fees offered by any third-party. Antero will only be permitted to obtain these services from third parties if we either do not make an offer or do not match a competing third-party offer. The process could result in Antero obtaining certain of the required services from us (for example, gas processing) and certain of such services (for example, NGLs fractionation and related services) from a third-party. Our right of first offer does not apply to production that is subject to a pre-existing dedication. The right of first offer agreement has a 20-year term. Pursuant to the procedures provided for in the right of first offer agreement, if our offer prevails, Antero will enter into a gas processing agreement or other appropriate services agreement with us and, if applicable, transfer the acquired facility to us for the price for which Antero acquired it. Relevant production will be dedicated under such agreement. We will provide the relevant services for the offered fees, subject to price adjustments based on the consumer price index, or CPI, and Antero will be obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. We may perform all services under the gas processing or other services agreement or may perform such services through third parties. In the event that we do not perform our obligations under the agreement, Antero will be entitled to certain rights and procedural remedies thereunder. If pursuant to the foregoing procedures Antero enters into a gas processing agreement with us, we will agree to construct or cause to be constructed a processing plant to process the dedicated natural gas, except to the extent rendered unnecessary if Antero is transferring an acquired facility to us. If Antero requires additional capacity in the future at the plant at which we are providing the services, we will have the option to provide such additional capacity on the same terms and conditions. In the event that we do not exercise this option, Antero will be entitled to obtain proposals from third parties to process such production. License Pursuant to a license agreement with Antero, we have the right to use certain Antero-related names and trademarks in connection with our operation of the midstream business. Procedures for Review, Approval and Ratification of Transactions with Related Persons The board has adopted a written code of business conduct and ethics, under which a director would be expected to bring to the attention of our chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The 106 resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors. If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by the conflicts committee. Pursuant to our code of business conduct, our general partner’s executive officers are required to avoid conflicts Conflicts of Interest Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its directors, officers, affiliates (including Antero) and owners, on the one hand, and us and our limited partners, on the other hand. Conflicts may arise as a result of the duties of our general partner and its directors and officers to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. We are managed and operated by the board of directors and officers of our general partner, Midstream Management, which is owned by Antero Investment. All of our initial officers and a majority of our initial directors will also be officers or directors of Antero Investment. Similarly, all of the officers and a majority of the directors of our general partner are also officers or directors of Antero. Although our general partner has a contractual duty to manage us in a manner that it believes is not adverse to our interests, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to Antero Investment. Our general partner’s directors and officers who are also directors and officers of Antero have a fiduciary duty to manage Antero in a manner that is beneficial to Antero and its shareholders. Our partnership agreement specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership. Whenever a conflict arises between our general partner or its owners and affiliates (including Antero), on the one hand, and us or our limited partners, on the other hand, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by us and all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is: • • approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval; or approved by the holders of a majority of the outstanding common units, excluding any such units owned by our general partner or any of its affiliates. Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as described above. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, 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. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, a determination, other action or failure to act by our general partner, the board of directors of our general partner or any committee 107 thereof (including the conflicts committee) will be deemed to be “in good faith” unless our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) believed such determination, other action or failure to act was adverse to the interest of the partnership. Please read “Management— Committees of the Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors. Director Independence Rather than adopting categorical standards, the Board assesses director independence on a case-by-case basis, in each case consistent with applicable legal requirements and the listing standards of the NYSE. After reviewing all relationships each director has with us, including the nature and extent of any business relationships between us and each director, as well as any significant charitable contributions we make to organizations where our directors serve as board members or executive officers, the Board has affirmatively determined that the following directors have no material relationships with us and are independent as defined by the current listing standards of the NYSE: Messrs. Kagan, Keenan, Klimley, Manning, Connor and Peters. Neither Mr. Rady, the Chairman and Chief Executive Officer of our general partner, nor Mr. Warren, the President and Secretary of our general partner, is considered by the Board to be an independent director because of his employment with Antero. Item 14. Principal Accountant Fees and Services The table below sets forth the aggregate fees and expenses billed by KPMG LLP, our independent registered public accounting firm, for the Partnership and its Predecessor for the year ended December 31, 2015: (in thousands) Audit Fees (1): For the Year Ended December 31, 2015 Audit and Quarterly Reviews . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Filings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 450 140 590 (1) Includes audit of the Predecessor’s annual financial statements for the year ended December 31, 2013, the audit of the Partnership’s annual combined consolidated financial statements for the years ended December 31, 2014 and 2015 included in this Annual Report on form 10-K, review of the Partnership's quarterly financial statements included in its Quarterly Reports on Form 10-Q and review of the Partnership’s other filings with the SEC, including work performed in conjunction with S-1 filings, consents and other research work necessary to comply with generally accepted auditing standards for the years ended December 31, 2013, 2014, and 2015. The charter of the Audit Committee and its pre-approval policy require that the Audit Committee review and pre- approve our independent registered public accounting firm's fees for audit, audit-related, tax and other services. The Chairman of the Audit Committee has the authority to grant pre-approvals, provided such approvals are within the pre- approval policy and are presented to the Audit Committee at a subsequent meeting. For the year ended December 31, 2015, the audit committee of our predecessor approved 100% of the services described above under the captions "Audit Fees." 108 PART IV Item 15. Exhibits and Financial Statement Schedules (a)(1) and (a)(2) Financial Statements and Financial Statement Schedules The combined consolidated financial statements are listed on the Index to Financial Statements to this report beginning on page F-1. (a)(3) Exhibits. Exhibit Number 2.1** 3.1 3.2 3.3 3.4* 10.1 10.2 10.3 10.4† 10.5 Description of Exhibit Contribution, Conveyance and Assumption Agreement, dated as of September 17, 2015, by and among Antero Resources Corporation, Antero Midstream Partners LP and Antero Treatment LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (Commission File No. 001-36719) filed on September 18, 2015). Certificate of Conversion of Antero Resources Midstream LLC, dated November 5, 2014 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (Commission File No. 001- 36719) filed on November 7, 2014). Certificate of Limited Partnership of Antero Midstream Partners LP, dated November 5, 2014 (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K (Commission File No. 001- 36719) filed on November 7, 2014). Agreement of Limited Partnership, dated as of November 10, 2014, by and between Antero Resources Midstream Management LLC, as the General Partner, and Antero Resources Corporation, as the Organizational Limited Partner (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014). Amendment No. 1 to Agreement of Limited Partnership of Antero Midstream Partners LP, dated as of February 23, 2016. Common Unit Purchase Agreement, dated as of September 17, 2015, by and among Antero Midstream Partners LP and the Purchasers named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K(Commission File No. 001-36719) filed on September 18, 2015). Secondment Agreement, dated as of September 23, 2015, by and between Antero Midstream Partners LP, Antero Resources Midstream Management LLC, Antero Midstream LLC, Antero Water LLC, Antero Treatment LLC and Antero Resources Corporation (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-36719) filed on September 24, 2015). Amended and Restated Services Agreement, dated as of September 23, 2015, by and among Antero Midstream Partners LP, Antero Resources Midstream Management LLC and Antero Resources Corporation (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8- K (Commission File No. 001-36719) filed on September 24, 2015). Water Services Agreement, dated as of September 23, 2015, by and between Antero Resources Corporation and Antero Water LLC (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q (Commission File No. 001-36719) filed on October 28, 2015). Amended and Restated Contribution Agreement, dated as of November 10, 2014, by and between Antero Resources Corporation and Antero Midstream Partners LP (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014). 109 10.6 10.7 10.8 10.9 10.10 10.11 10.12 10.13 10.14 10.15 10.16* 10.17 10.18 10.19 Gathering and Compression Agreement, dated as of November 10, 2014, by and between Antero Resources Corporation and Antero Midstream LLC (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014). Right of First Offer Agreement, dated as of November 10, 2014, by and between Antero Resources Corporation and Antero Midstream LLC (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014). License Agreement, dated as of November 10, 2014, by and between Antero Resources Corporation and Antero Midstream Partners LP (incorporated by reference to Exhibit 10.4 to Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014). Registration Rights Agreement, dated as of November 10, 2014, by and among Antero Midstream Partners LP and Antero Resources Corporation (incorporated by reference to Exhibit 10.5 to Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014). Credit Agreement, dated as of November 10, 2014, among Antero Midstream Partners LP and certain of its subsidiaries, certain lenders party thereto, Wells Fargo Bank, National Association, as administrative agent, l/c issuer and swingline lender and the other parties thereto (incorporated by reference to Exhibit 10.6 to Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014). First Amendment and Joinder Agreement, dated as of September 23, 2015 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K (Commission File No. 001-36719) filed on September 24, 2015). Form of Antero Midstream Partners LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.11 to Amendment No. 4 to Antero Resources Midstream LLC’s Registration Statement on Form S-1, filed on July 11, 2014, File No. 333-193798). Form of Indemnification Agreement (incorporated by reference to Exhibit 10.12 to Amendment No. 4 to Antero Resources Midstream LLC’s Registration Statement on Form S-1, filed on July 11, 2014, File No. 333-193798). Form of Phantom Unit Grant Notice and Phantom Unit Agreement under the Antero Midstream Partners LP Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to Midstream Partners’ Registration Statement on Form S-8 (Commission File No. 001- 36719) filed on November 12, 2014). Form of Restricted Unit Grant Notice and Restricted Unit Agreement under the Antero Midstream Partners LP Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to Midstream Partners’ Registration Statement on Form S-8 (Commission File No. 001- 36719) filed on November 12, 2014). Form of Bonus Unit Grant Notice and Bonus Unit Agreement (Form for Non-Employee Directors) under the Antero Midstream Partners LP Long-Term Incentive Plan. Antero Resources Corporation Long-Term Incentive Plan, effective as of October 1, 2013 (incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-8 (Commission File No. 001- 36120) filed on October 11, 2013). Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement under the Antero Resources Corporation Long-Term Incentive Plan (incorporated by reference to Exhibit 10.28 to Annual Report on Form 10-K (Commission File No. 001-36120) filed on February 25, 2015). Form of Bonus Stock Grant Notice and Bonus Stock Agreement (Form for Non-Employee Directors) under the Antero Resources Corporation Long-Term Incentive Plan (incorporated by reference to Exhibit 10.36 to Antero’s Annual Report on Form 10-K (Commission File No. 001-36120) filed on February 24, 2016). 110 10.20 21.1* 23.1* 31.1* 31.2* 32.1* 32.2* 101* Form of Performance Share Unit Grant Notice and Performance Share Unit Agreement (Form for Special Retention Awards) under the Antero Resources Corporation Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Antero’s Annual Report on Form 10-K (Commission File No. 001-36120) filed on February 12, 2016). Subsidiaries of Antero Midstream Partners LP. Consent of KPMG, LLP. Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241). Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241). Certification of the Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350). Certification of the Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350). The following financial information from this Form 10-K of Antero Midstream Partners LP for the year ended December 31, 2015, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations and Comprehensive Income (Loss), (iii) Consolidated Statements of Equity, (iv) Consolidated Statements of Cash Flows, and (v) Notes to the Combined Consolidated Financial Statements, tagged as blocks of text. The exhibits marked with the asterisk symbol (*) are filed or furnished with this Annual Report on Form 10-K. ** Pursuant to Item 601(b)(2) of Regulation S-K, the Partnership agrees to furnish supplementally a copy of any omitted exhibit or schedule to the U.S. Securities and Exchange Commission upon request. †Portions of this exhibit have been omitted pursuant to a request for confidential treatment. 111 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SIGNATURES ANTERO MIDSTREAM PARTNERS LP By: By: ANTERO RESOURCES MIDSTREAM MANAGEMENT LLC, its general partner /s/ Michael N. Kennedy Michael N. Kennedy Chief Financial Officer Date: February 24, 2016 112 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities and on the dates indicated. Signature Title (Position with Antero Resources Midstream Management LLC) Date /s/ PAUL M. RADY Chairman of the Board, Director and Chief Executive officer February 24, 2016 Paul M. Rady (principal executive officer) /s/Michael N. Kennedy Chief Financial Officer February 24, 2016 Michael N. Kennedy (principal financial officer) /s/ K. PHIL YOO K. Phil Yoo Chief Accounting Officer and Corporate Controller (principal accounting officer) February 24, 2016 /s/ Glen C. Warren, Jr. Glen C. Warren, Jr. President, Director, and Secretary February 24, 2016 /s/ RICHARD W. CONNOR Richard W. Connor Director /s/ W. HOWARD KEENAN, JR. Director W. Howard Keenan, Jr. /s/ PETER R. KAGAN Peter R. Kagan Director /s/ BROOKS J. KLIMLEY Brooks J. Klimley Director /s/ DAVID A. PETERS David A. Peters Director /s/ CHRISTOPHER R. MANNING Director Christopher R. Manning February 24, 2016 February 24, 2016 February 24, 2016 February 24, 2016 February 24, 2016 February 24, 2016 113 (This page has been left blank intentionally.) INDEX TO COMBINED CONSOLIDATED FINANCIAL STATEMENTS Audited Historical Combined Consolidated Financial Statements as of December 31, 2014 and 2015 and for the Years Ended December 31, 2013, 2014 and 2015 Reports of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Statements of Combined Consolidated Operations and Comprehensive Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . Statements of Combined Consolidated Partners’ Capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Statements of Combined Consolidated Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes to Combined Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page F-2 F-4 F-5 F-6 F-7 F-8 F-1 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Unitholders Antero Midstream Partners LP: We have audited the accompanying combined consolidated balance sheets of Antero Midstream Partners LP (“the Partnership”) and its accounting predecessor as of December 31, 2014 and 2015, and the related combined consolidated statements of operations and comprehensive income, partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2015. These combined consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these combined consolidated financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the combined consolidated financial statements referred to above present fairly, in all material respects, the financial position of Antero Midstream Partners LP and its accounting predecessor as of December 31, 2014 and 2015, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Antero Midstream Partners LP’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 24, 2016 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting. As discussed in Note 2 to the combined consolidated financial statements of Antero Midstream Partners LP, the balance sheets, and the related combined consolidated statements of operations and comprehensive income, partners’ capital, and cash flows have been prepared on a combined basis of accounting. /s/ KPMG LLP Denver, Colorado February 24, 2016 F-2 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Unitholders Antero Midstream Partners LP: We have audited Antero Midstream Partners LP’s (“the Partnership”) internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Antero Midstream Partners LP’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting within Item 9A. Controls and Procedures. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, Antero Midstream Partners LP maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the combined consolidated balance sheets of Antero Midstream Partners LP and its accounting predecessor as of December 31, 2014 and 2015, and the related combined consolidated statements of operations and comprehensive income, partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2015, and our report dated February 24, 2016 expressed an unqualified opinion on those combined consolidated financial statements. /s/ KPMG LLP Denver, Colorado February 24, 2016 F-3 ANTERO MIDSTREAM PARTNERS LP Combined Consolidated Balance Sheets December 31, 2014, and 2015 (In thousands, except unit counts) Assets 2014 2015 Current assets: Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts receivable–Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts receivable–third party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Property and equipment: Gathering and compressions systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Water handling and treatment systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Liabilities and Partners' capital Current liabilities: Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable–Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued ad valorem tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term liabilities Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Contingent acquisition consideration (Note 8) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ Contingencies (Note 10) Partners' capital: Common unitholders - public (59,286,451 units issued and outstanding) . . . . . . . Common unitholder - Antero (40,929,378 units issued and outstanding) . . . . . . . Subordinated unitholder - Antero (75,940,957 units issued and outstanding) . . . . General partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total partners' capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Parent net investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total liabilities and partners' capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 230,192 31,563 5,574 518 267,847 1,180,707 421,012 (70,124) 1,531,595 17,168 1,816,610 13,021 1,380 49,974 5,862 9,254 357 79,848 115,000 — 859 195,707 1,090,037 71,665 180,757 — 1,342,459 278,444 1,620,903 1,816,610 $ $ $ $ 6,883 65,712 2,707 — 75,302 1,485,835 565,616 (157,625) 1,893,826 10,904 1,980,032 10,941 2,138 50,022 7,195 28,168 150 98,614 620,000 178,049 624 897,287 1,351,317 30,186 (299,727) 969 1,082,745 — 1,082,745 1,980,032 See accompanying notes to combined consolidated financial statements. F-4 ANTERO MIDSTREAM PARTNERS LP Combined Consolidated Statements of Operations and Comprehensive Income Years Ended December 31, 2013, 2014, and 2015 (In thousands, except unit counts and per unit amounts) 2013 2014 2015 Revenue: Gathering and compression–Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Water handling and treatment–Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gathering and compression–third party . . . . . . . . . . . . . . . . . . . . . . . . . . . Water handling and treatment–third party . . . . . . . . . . . . . . . . . . . . . . . . . Total revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,363 $ 35,871 — — 58,234 95,746 $ 162,283 — 8,245 266,274 230,210 155,954 382 778 387,324 Operating expenses: Direct operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative (including $24,349, $11,618 and $22,470 of equity-based compensation in 2013, 2014, and 2015, respectively) . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Contingent acquisition consideration accretion . . . . . . . . . . . . . . . . . . . . . Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income and comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . Pre-IPO net income attributed to parent . . . . . . . . . . . . . . . . . . . . . . . . . . . Pre-Water Acquisition net income attributed to parent . . . . . . . . . . . . . . . General partner interest in net income attributable to incentive 7,871 48,821 78,852 34,065 14,119 — 56,055 2,179 164 2,015 (2,015) — 30,366 53,029 — 132,216 134,058 6,183 127,875 (98,219) (22,234) 51,206 86,670 3,333 220,061 167,263 8,158 159,105 — (40,193) distribution rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Limited partners' interest in net income . . . . . . . . . . . . . . . . . . . . . . . . . . $ — — $ — 7,422 $ (1,264) 117,648 Net income per limited partner unit: Basic: Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Diluted: Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Weighted average number of limited partner units outstanding: Basic: Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted: Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — $ — $ — $ — $ — — — — 0.05 $ 0.05 $ 0.05 $ 0.05 $ 75,941 75,941 75,941 75,941 0.76 0.73 0.76 0.73 82,538 75,941 82,586 75,941 See accompanying notes to combined consolidated financial statements. F-5 ANTERO MIDSTREAM PARTNERS LP Combined Consolidated Statements of Partners’ Capital Years Ended December 31, 2013, 2014, and 2015 (In thousands) Partnership Balance at December 31, 2012 . . . . . . $ — $ — $ — $ — $ 144,897 $ 144,897 Common Unitholders Public Common Unitholder Antero Subordinated Unitholder General Partner Parent Net Investment Total Net income and comprehensive income . . . . . . . . . . . . . . . . . . . . . . Deemed contribution from Antero, net . . . . . . . . . . . . . . . . . . . . . . . . . . Equity-based compensation . . . . . . Balance at December 31, 2013 . . . . . . Net income and comprehensive income . . . . . . . . . . . . . . . . . . . . . . Deemed distribution to Antero, net . Equity-based compensation . . . . . . Balance at November 10, 2014 (prior to IPO) . . . . . . . . . . . . . . . . . . . . . . . . Allocation of net investment to unitholders . . . . . . . . . . . . . . . . . . . Net proceeds from IPO . . . . . . . . . . . Distribution to Antero . . . . . . . . . . . . Net income and comprehensive — — — — — — — — — — — — — — — — — — — — — — — — — 1,087,224 — 163,458 — (94,023) 414,587 — (238,477) income . . . . . . . . . . . . . . . . . . . . . . Equity-based compensation . . . . . . Balance at December 31, 2014 . . . . . . 2,248 565 1,090,037 1,463 767 71,665 3,711 936 180,757 — — — — — — — 2,015 2,015 560,800 24,349 732,061 560,800 24,349 732,061 98,219 (5,375) 8,696 98,219 (5,375) 8,696 — 833,601 833,601 — — — — — — (578,045) — — — 1,087,224 (332,500) 22,234 654 278,444 29,656 2,922 1,620,903 Net income and comprehensive income . . . . . . . . . . . . . . . . . . . . . . Distributions to unitholders . . . . . . . Deemed distribution to Antero, net . Equity-based compensation . . . . . . . Issuance of common units upon vesting of equity-based compensation awards, net of units withheld for income tax withholdings . . . . . . . . . . . . . . . . . . Net proceeds from private placement of common units . . . . . . . . . . . . . . Issuance of common units to Antero in Water Acquisition . . . . . . . . . . . Purchase price in excess of net assets acquired in Water Acquisition . . . Carrying value of net assets acquired in Water Acquisition . . . . . . . . . . . 37,368 (33,834) — 4,577 25,053 (22,292) 55,227 (50,827) — — 7,363 7,086 1,264 (295) — — 40,193 — (52,669) 3,444 159,105 (107,248) (52,669) 22,470 12,466 (17,272) — 240,703 — — — 229,988 — — (264,319) (491,970) — — — — — (4,806) — 240,703 — 229,988 — (756,289) Balance at December 31, 2015 . . . . . . $ 1,351,317 $ — — — 30,186 $ (299,727) $ — 969 $ (269,412) (269,412) — $ 1,082,745 See accompanying notes to combined consolidated financial statements. F-6 ANTERO MIDSTREAM PARTNERS LP Combined Consolidated Statements of Cash Flows Years Ended December 31, 2013, 2014, and 2015 (In thousands) 2013 2014 2015 Cash flows provided by operating activities: Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Adjustment to reconcile net income to net cash provided by operating activities: 2,015 $ 127,875 $ 159,105 Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion of contingent acquisition consideration . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amortization of deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Changes in assets and liabilities: Accounts receivable–Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts receivable–third party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable–Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued ad valorem tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,119 — 24,349 — (6,267) — — — — 1,948 2,081 38,245 53,029 — 11,618 135 (29,988) (5,574) (518) 863 1,059 3,868 7,066 169,433 86,670 3,333 22,470 1,144 (35,148) 2,867 518 2,803 475 1,333 14,108 259,678 Cash flows used in investing activities: Additions to gathering and compression systems . . . . . . . . . . . . . . . . . . . . . . . . . . . Additions to Water handling and treatment systems . . . . . . . . . . . . . . . . . . . . . . . . . Amounts paid to Antero for property and equipment . . . . . . . . . . . . . . . . . . . . . . . . Change in other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (389,340) (200,256) — (8,581) (598,177) (553,582) (200,116) (40,277) (3,530) (797,505) (320,002) (132,633) — 7,180 (445,455) Cash flows provided by (used in) financing activities: Deemed contribution from (distribution to) Antero, net . . . . . . . . . . . . . . . . . . . . . . Distributions to unitholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net proceeds from initial public offering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Borrowings on bank credit facilities, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distribution to Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from private placement of common units, net . . . . . . . . . . . . . . . . . . . . . . Payments of deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . . . . . . . Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Supplemental disclosure of cash flow information: 560,800 — — — — — — (868) 559,932 — — — $ 230,192 $ (5,375) — 1,087,224 115,000 (332,500) — (4,871) (1,214) 858,264 230,192 — (52,669) (107,248) — 505,000 (620,997) 240,703 (2,059) (262) (37,532) (223,309) 230,192 6,883 Cash paid during the period for interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 164 $ 5,864 $ 7,765 Supplemental disclosure of noncash investing activities: Increase in accrued capital expenditures and accounts payable for property and equipment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 29,852 $ 37,596 $ 4,552 See accompanying notes to combined consolidated financial statements. F-7 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements Years Ended December 31, 2013, 2014, and 2015 (1) Business and Organization Antero Midstream Partners LP (the “Partnership”) is a growth-oriented limited partnership formed by Antero Resources Corporation (“Antero”) to own, operate and develop midstream energy assets to service Antero’s increasing production. The Partnership’s assets consist of gathering pipelines, compressor stations and water handling and treatment assets, through which the Partnership provides midstream services to Antero under long- term, fixed-fee contracts. Our assets are located in the southwestern core of the Marcellus Shale in northwest West Virginia and the core of the Utica Shale in southern Ohio. The Partnership’s combined consolidated financial statements as of December 31, 2015, include the accounts of the Partnership, Antero Midstream LLC (“Midstream Operating”), Antero Water LLC Predecessor (“Antero Water”), and Antero Treatment LLC (“Antero Treatment”), all of which are entities under common control. References in these financial statements to “Predecessor,” “we,” “our,” “us” or like terms, when referring to periods prior to November 10, 2014, refer to Antero’s gathering, compression and water assets, the Partnership’s 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’s water 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 the Partnership. On September 23 2015, pursuant to the terms of the Contribution, Conveyance and Assumption Agreement (the “Contribution Agreement”) between the Partnership, Antero Treatment and Antero, Antero contributed (the “Water Acquisition”) (i) all of the outstanding limited liability company interests of Antero Water to the Partnership and (ii) all of the assets, contracts, rights, permits and properties owned or leased by Antero and used primarily in connection with the construction, ownership, operation, use or maintenance of Antero’s advanced waste water treatment complex to be constructed in Doddridge County, West Virginia, to Antero Treatment (collectively, (i) and (ii) are referred to herein as the “Contributed Assets”). In consideration for the contribution of the Contributed Assets, the Partnership (i) paid Antero a cash distribution equal to $553 million, less $171 million of assumed debt, (ii) issued 10,988,421 common units valued at $230 million representing limited partner interests in the Partnership to Antero, (iii) distributed proceeds of approximately $241 million from the Partnership’s private placement of 12,898,000 common units at $18.84 per common unit to a group of institutional investors and (iv) agreed to pay Antero (a) $125 million in cash if the Partnership delivers 176,295,000 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 the Partnership delivers 219,200,000 barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020, representing a discounted net present value of $175 million at the time of the Water Acquisition. The Partnership borrowed $525 million on its bank credit facility in connection with this transaction (the “Water Acquisition”). The Partnership’s gathering and compression assets consist of 8-, 12-, 16-, and 20-inch high and low pressure gathering pipelines and compressor stations that collect natural gas, NGLs and oil from Antero’s wells in the Marcellus Shale in West Virginia and the Utica Shale in Ohio. The Partnership’s assets also include two independent fresh water distribution systems that deliver water used by Antero for hydraulic fracturing activities in Antero’s operating areas. The fresh water distribution systems consist of permanent buried pipelines, surface pipelines and fresh water storage facilitates, as well as pumping stations and impoundments to transport the fresh water throughout the pipeline system. The Partnership has right to participate in up to a 15% non-operating equity interest in the 67-mile Stonewall gathering pipeline for which Antero is an anchor shipper. The Stonewall gathering pipeline was placed into service on November 30, 2015 and Antero has a firm commitment of 900 MMcf/d through the system. The F-8 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 Partnership’s option expires six months following the date on which the regional gathering system was placed into service, or May 30, 2016. In addition, the Partnership has entered into a right-of-first-offer agreement with Antero to provide Antero with gas processing or NGLs fractionation, transportation or marketing services in the future. (2) Summary of Significant Accounting Policies (a) Basis of Presentation Our combined consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). In the opinion of management, the accompanying combined consolidated financial statements include all adjustments considered necessary to present fairly our financial position as of December 31, 2014 and 2015, and the results of our operations and our cash flows for the years ended December 31, 2013, 2014, and 2015. We have no items of other comprehensive income or loss; therefore, net income is identical to comprehensive income. The accompanying combined consolidated financial statements represent the assets, liabilities, and results of operations of Antero’s gathering and compression assets and water handling and treatment assets as the accounting predecessor (the “Predecessor”) to the Partnership, presented on a carve-out basis of Antero’s historical ownership of the Predecessor. The Predecessor financial statements have been prepared from the separate records maintained by Antero and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. Certain costs of doing business incurred by Antero on our behalf have been reflected in the accompanying combined consolidated financial statements. These costs include general and administrative expenses attributed to us by Antero in exchange for: • • • business services, such as payroll, accounts payable and facilities management; corporate services, such as finance and accounting, legal, human resources, investor relations and public and regulatory policy; and employee compensation, including equity-based compensation. Transactions between us and Antero have been identified in the combined consolidated financial statements as transactions between affiliates (see Note 3). As of the date these combined consolidated financial statements were filed with the SEC, the Partnership completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified, except the declaration of a cash distribution to unitholders, as described in Note 6—Partnership Equity and Distributions. (b) Revenue Recognition We provide gathering and compression and water handling and treatment services under fee-based contracts primarily based on throughput or cost plus margin. Under these arrangements, we receive fees for gathering oil and gas products, compression services, and water handling and treatment services. The revenue we earn from these arrangements is directly related to (1) in the case of natural gas gathering and compression, the volumes of metered natural gas that we gather, compress and deliver to natural gas compression sites or other F-9 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 transmission delivery points, (2) in the case of oil and condensate gathering, the volumes of metered oil and condensate that we gather and deliver to other transmission delivery points, (3) in the case of fresh water handling and treatment services, the quantities of fresh water delivered to our customers for use in their well completion operations, or (4) in the case of waste water handling and treatment, the third party out-of-pocket costs plus 3%. We recognize revenue when all of the following criteria are met: (1) persuasive evidence of an agreement exists, (2) services have been rendered, (3) prices are fixed or determinable and (4) collectability is reasonable assured. (c) Use of Estimates The preparation of the combined consolidated financial statements and notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. Items subject to estimates and assumptions include the useful lives of property and equipment and valuation of accrued liabilities, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates. (d) Cash and Cash Equivalents Prior to the IPO, the Predecessor’s gathering and compression operations were funded by Antero, and prior to September 23, 2015 Antero Water’s operations were funded by Antero. Net amounts funded by Antero are reflected as “Deemed contribution from (distribution to) Antero, net” on the accompanying statements of Combined Consolidated Cash Flows. We consider all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. (e) Property and Equipment Property and equipment primarily consists of gathering pipelines, compressor stations and fresh water distribution pipelines and facilities stated at historical cost less accumulated depreciation. We capitalize construction-related direct labor and material costs. Maintenance and repair costs are expensed as incurred. Depreciation is computed using the straight-line method over the estimated useful lives and salvage values of assets. The depreciation of fixed assets recorded under capital lease agreements is included in depreciation expense. Uncertainties that may impact these estimates of useful lives include, among others, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions, and supply and demand for our services in the areas in which we operate. When assets are placed into service, management makes estimates with respect to useful lives and salvage values that management believes are reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts. F-10 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 Our investment in property and equipment for the periods presented is as follows: Estimated useful lives As of December 31, 2014 As of December 31, 2015 (in thousands) Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fresh water surface pipelines and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 years Above ground storage tanks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 years Fresh water permanent buried pipelines and equipment . . . . . . . . . . . . . . . . . . . 20 years Gathering and compression systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 years Construction-in-progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . n/a Total property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,383 $ 20,931 — 359,244 861,609 356,552 1,601,719 (70,124) 3,430 34,402 4,296 410,202 1,291,871 307,250 2,051,451 (157,625) $ 1,531,595 $ 1,893,826 n/a $ (f) Impairment of Long-Lived Assets We evaluate our long-lived assets for impairment when events or changes in circumstances indicate that the related carrying values of the assets may not be recoverable. Generally, the basis for making such assessments are undiscounted future cash flow projections for the unit being assessed. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to the estimated fair value, which are based on discounted future cash flows or other techniques, as appropriate. No impairments for such assets have been recorded through December 31, 2015. (g) Asset Retirement Obligations Our gathering pipelines, compressor stations and fresh water distribution pipelines and facilities have an indeterminate life, if properly maintained. A liability will be recorded only if and when a future retirement obligation with a determinable life can be estimated. It has been determined by our operational management team that abandoning all other ancillary equipment, outside of the assets stated above, would require minimal costs. We are not able to make a reasonable estimate of when future dismantlement and removal dates of our pipelines, compressor stations and facilities, will occur and, because it has been determined that abandonment of all other ancillary assets would only require minimal costs, we have not recorded asset retirement obligations at December 31, 2014 or 2015. (h) Litigation and Other Contingencies An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. We regularly review contingencies to determine the adequacy of our accruals and related disclosures. The ultimate amount of losses, if any, may differ from these estimates. We accrue losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time a remediation feasibility study, or an evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable. F-11 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 (i) Equity-Based Compensation Our combined consolidated financial statements reflect various equity-based compensation awards granted by Antero, as well as compensation expense associated with our own plan. These awards include profits interests awards, restricted stock, stock options, restricted units, and phantom units. For purposes of these combined consolidated financial statements, we recognized as expense in each period an amount allocated from Antero, with the offset included in partners’ capital. See Note 3—Transactions with Affiliates for additional information regarding Antero’s allocation of expenses to us. In connection with the IPO, our general partner adopted the Antero Midstream Partners LP Long-Term Incentive Plan (“Midstream LTIP”), pursuant to which certain non-employee directors of our general partner and certain officers, employees and consultants of our general partner and its affiliates are eligible to receive awards representing equity interests in the Partnership. An aggregate of 10,000,000 common units may be delivered pursuant to awards under the Midstream LTIP, subject to customary adjustments. For accounting purposes, these units are treated as if they are distributed from us to Antero. Antero recognizes compensation expense for the units awarded to its employees and a portion of that expense is allocated to us. See Note 5—Equity-Based Compensation. (j) Income Taxes Our combined consolidated financial statements do not include a provision for income taxes as we are treated as a partnership for federal and state income tax purposes, with each partner being separately taxed on its share of taxable income. (k) Fair Value Measures The Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long-lived assets). The fair value is the price that we estimate would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly. The carrying values on our balance sheet of our cash and cash equivalents, accounts receivable—Antero, accounts receivable—third party, prepaid expenses, other assets, accounts payable, accounts payable—Antero, accrued liabilities, accrued capital expenditures, accrued ad valorem tax, other current liabilities, other liabilities and the revolving credit facility approximate fair values due to their short-term maturities. As discussed in Note 8—Fair Value Measurement, the Partnership has agreed to pay Antero contingent consideration in connection with the Water Acquisition. F-12 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 (3) Transactions with Affiliates (a) Revenues Gathering and compression revenues earned from Antero were $22.4 million, $95.7 million and $230.2 million during the year ended December 31, 2013, 2014, and 2015, respectively. Water handling and treatment revenues earned from Antero were $35.9 million, $162.3 million and $156.0 million during the year ended December 31, 2013, 2014, and 2015, respectively. (b) Accounts receivable—Antero, and Accounts payable—Antero Accounts receivable—Antero represents amounts due from Antero, primarily related to gathering and compression services and water handling and treatment services. Accounts payable—Antero represents amounts due to Antero for general and administrative and other costs. (c) Accounts Payable, Accrued Expenses, and Accrued Capital Expenditures All accounts payable, accrued liabilities and accrued capital expenditures balances are due to transactions with unaffiliated parties. Prior to the IPO, all operating and capital expenditures, related to gathering and compression activities were funded through net capital contributions from Antero and borrowings under its midstream credit facility. Prior to September 23, 2015, all operating and capital expenditures related to Antero Water were funded through capital contributions from Antero and borrowings under the water credit facility. See Note 4 — Long-term Debt. These balances were managed and paid under Antero’s cash management program. Following the IPO, we maintained our own bank accounts and sources of liquidity related to gathering and compression operations, and on September 23, 2015, we began to maintain our own bank accounts and sources of liquidity for water handling and treatment operations. (d) Allocation of Costs The employees supporting our operations are employees of Antero. Direct operating expense includes allocated costs of zero, $1.5 million and $3.0 million during the year ended December 31, 2013, 2014, and 2015, respectively, related to labor charges for Antero employees associated with the operation of our gathering lines and compressor stations. General and administrative expense includes allocated costs of $34.0 million, $30.3 million and $44.2 million during the year ended December 31, 2013, 2014, and 2015, respectively. These costs relate to: (i) various business services, including payroll processing, accounts payable processing and facilities management, (ii) various corporate services, including legal, accounting, treasury, information technology and human resources and (iii) compensation, including equity-based compensation (see Note 5—Equity-Based Compensation for more information). These expenses are charged or allocated to us based on the nature of the expenses and are allocated based on a combination of our proportionate share of Antero’s gross property and equipment, capital expenditures and labor costs, as applicable. (e) Agreements The Partnership has entered into various agreements with Antero, as summarized below. F-13 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 Gathering and Compression In connection with the IPO on November 10, 2014, the Partnership entered in a 20-year gathering and compression agreement, whereby Antero has agreed to dedicate all of its current and future acreage in West Virginia, Ohio and Pennsylvania to us (other than the existing third-party commitments). The initial term of the gathering and compression agreement is 20 years from the date thereof and from year to year thereafter until terminated by either party. We also have an option to gather and compress natural gas produced by Antero 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, a compression fee of $0.18 per Mcf, and a condensate gathering fee of $4.00 per Bbl, in each case subject to CPI-based adjustments. If and to the extent Antero requests that we construct new high pressure lines and compressor stations, the gathering and compression agreement contains minimum volume commitments that require Antero to utilize or pay for 75% and 70%, respectively, of the capacity of such new construction. 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. The Partnership met all commitments on new infrastructure at December 31, 2015. Water Services Agreement In connection with the Water Acquisition on September 23, 2015, the Partnership entered a 20-year Water Services Agreement with Antero whereby we have agreed to provide certain fluid handling services to Antero within an area of dedication in defined service areas in Ohio and West Virginia and Antero agreed to pay monthly fees to us for all fluid handling 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 the date thereof and from year to year thereafter until terminated by either party. Under the agreement, Antero 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 has committed to pay a fee on a minimum volume of fresh water deliveries in calendar years 2016 through 2019. Antero is obligated to pay a minimum volume fee to us in the event the aggregate volume of fresh water delivered to Antero 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 also agreed to pay us a fixed fee of $4.00 per barrel for waste water treatment at the advanced waste water treatment complex and a fee per barrel for waste water collected in trucks owned by the Partnership, in each case subject to annual CPI-based adjustments. Until such time as the advanced waste water treatment complex is placed into service or we operate our own fleet of trucks for transporting waste water, the Partnership will continue to contract with third parties to provide Antero flow back and produced water services and Antero will reimburse us third party out-of-pocket costs plus 3%. Secondment Agreement On September 23, 2015, the Partnership entered into a secondment agreement with Antero, Midstream Management, Midstream Operating, Antero Water and Antero Treatment, whereby Antero has agreed to provide seconded employees to perform certain operational services with respect to the Partnership’s gathering and compression facilities and the Contributed Assets, and the Partnership has agreed to reimburse Antero for expenditures incurred by Antero in the performance of those operational services. The initial term of the secondment agreement is 20 years from November 10, 2014, and from year to year thereafter. F-14 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 Services Agreement Upon the closing of the IPO, we entered into a services agreement with Antero, pursuant to which Antero agrees to provide customary operational and management services for us in exchange for reimbursement of its direct expenses and an allocation of its indirect expenses attributable to the provision of such services to us. To the extent that these expenses are incurred by Antero on our behalf, we reimburse Antero for such expenses under the services agreement. On September 23, 2015, Antero, the Partnership and the General Partner amended and restated their Services Agreement, dated November 10, 2014, to remove provisions relating to operational services in support of the Partnership’s gathering and compression business which is now covered by the secondment agreement and to provide that Antero will perform certain administrative services for the Partnership and its subsidiaries, and the Partnership will reimburse Antero for expenditures incurred by Antero in the performance of those administrative services. (4) Long-term Debt (a) Revolving Credit Facility On November 10, 2014, in connection with the closing of the IPO, the Partnership entered into a revolving credit facility with a syndicate of bank lenders. The revolving credit facility initially provided for lender commitments of $1.0 billion and a letter of credit sublimit of $150 million. On September 23, 2015, aggregate lender commitments under the revolving credit facility increased to $1.5 billion in connection with the Water Acquisition. The revolving credit facility matures on November 10, 2019. The revolving credit facility is ratably secured by mortgages on substantially all of our properties, including the properties of our subsidiaries, and guarantees from our subsidiaries. The revolving credit facility contains certain covenants including restrictions on indebtedness, and requirements with respect to leverage and interest coverage ratios. The revolving credit facility provides that, so long as no event of default exists or would be caused thereby, and only to the extent permitted by our organizational documents, distributions to the holders of our equity interests may be made in accordance with the cash distribution policy adopted by the board of directors of our general partner in connection with the IPO. The Partnership was in compliance with all of the financial covenants under the revolving credit facility as of December 31, 2014 and 2015. Principal amounts borrowed are payable on the maturity date with such borrowings bearing interest that is payable quarterly or, in the case of Eurodollar Rate Loans, at the end of the applicable interest period if shorter than three months. Interest is payable at a variable rate based on LIBOR or the base rate, determined by election at the time of borrowing. Commitment fees on the unused portion of the revolving credit facility are due quarterly at rates ranging from 0.25% to 0.375% of the unused facility based on utilization. At December 31, 2014 and 2015, we had borrowings under the revolving credit facility of zero and $620 million, respectively, with a weighted average interest rate of 1.92%. No letters of credit were outstanding at December 31, 2014 or 2015. (b) Midstream Credit Facility Prior to the closing of the IPO on November 10, 2014, long-term debt represented amounts outstanding under a credit facility agreement between Midstream Operating, then a wholly owned subsidiary of Antero and now a wholly owned subsidiary of the Partnership, and the lenders under Antero’s credit facility (the “Antero credit facility”), that were incurred for the Water Acquisition and construction of the Predecessor’s gathering and F-15 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 compression assets (the “Midstream credit facility”). The facilities were ratably secured by mortgages on substantially all of Antero’s properties, by a security interest on substantially all of Midstream Operating’s personal property and by guarantees from Antero and its subsidiaries. (c) Antero Water Credit Facility On November 10, 2014, in connection with the closing of the IPO, Antero Water assumed the Midstream credit facility under amended terms (the “Water facility”), in order to provide for separate borrowings attributable to Antero’s water handling and treatment business. The Water facility balance of $171 million was repaid in full and terminated on September 23, 2015, in connection with the Water Acquisition. (5) Equity-Based Compensation Our general and administrative expenses include equity-based compensation costs allocated to us by Antero for grants made pursuant to: (i) the Antero Resources Corporation Long-Term Incentive Plan (the “Antero LTIP”); (ii) profits interests awards valued in connection with the Antero reorganization pursuant to its initial public offering of common stock; and (iii) the Midstream LTIP. Equity-based compensation expense allocated to us was $24.3 million, $11.6 million and $22.5 million for the year ended December 31, 2013, 2014 and 2015, respectively. These expenses were allocated to us based on our proportionate share of Antero’s labor costs. Antero has unamortized expense totaling approximately $232.0 million as of December 31, 2015 related to its various equity-based compensation plans, which includes the Midstream LTIP. A portion of this will be allocated to us as it is amortized over the remaining service period of the related awards. Midstream LTIP Our general partner manages our operations and activities and Antero employs the personnel who provide support to our operations. In connection with the IPO, our general partner adopted the Midstream LTIP, pursuant to which non-employee directors of our general partner and certain officers, employees and consultants of our general partner and its affiliates are eligible to receive awards representing ownership interests in the Partnership. An aggregate of 10,000,000 common units may be delivered pursuant to awards under the Midstream LTIP, subject to customary adjustments. A total of 7,947,771 common units are available for future grant under the Midstream LTIP as of December 31, 2015. Restricted units and phantom units granted under the Midstream LTIP vest subject to the satisfaction of service requirements, upon the completion of which common units in the Partnership are delivered to the holder of the restricted units or phantom units. Compensation related to each restricted unit and phantom unit award is recognized on a straight-line basis over the requisite service period of the entire award. The grant date fair values of these awards are determined based on the closing price of the Partnership’s common units on the date of grant. These units are accounted for as if they are distributed by the Partnership to Antero. Antero recognizes compensation expense for the units awarded and a portion of that expense is allocated to the Partnership. Antero allocates equity-based compensation expense to the Partnership based on our proportionate share of Antero’s labor costs. The Partnership’s portion of the equity-based compensation expense is included in general and administrative expenses, and recorded as a credit to the applicable classes of partners’ capital. F-16 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 A summary of restricted unit and phantom unit awards activity during the year ended December 31, 2015 is as follows: Total awarded and unvested, December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . 2,381,440 $ 12,057 $ Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (595,595) $ Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (130,070) $ Total awarded and unvested—December 31, 2015. . . . . . . . . . . . . . . . . . . . . . . . 1,667,832 $ 29.00 $ 24.88 29.00 29.00 28.97 $ 38,060 Number of units Weighted average grant date fair value Aggregate intrinsic value (in thousands) 65,490 Intrinsic values are based on the closing price of the Partnership’s common units on the referenced dates. Midstream LTIP unamortized expense of $46.1 million at December 31, 2015 is expected to be recognized over a weighted average period of approximately 2.9 years and our proportionate share will be allocated to us as it is recognized. We paid $4.8 million in minimum statutory tax withholdings for restricted and phantom units that vested during 2015, which is included in the “Issuance of common units in Antero Midstream Partners LP upon vesting of equity-based compensation awards” line item in the Combined Consolidated Statements of Partners’ Capital. (6) Partnership Equity and Distributions Our Minimum Quarterly Distribution Our partnership agreement provides for a minimum quarterly distribution of $0.17 per unit for each quarter, or $0.68 per unit on an annualized basis. Our partnership agreement generally provides that we distribute cash each quarter during the subordination period in the following manner: • • • first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $0.17 plus any arrearages from prior quarters; second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $0.17; and third, to the holders of common units and subordinated units pro rata until each has received a distribution of $0.1955. F-17 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 If cash distributions to our unitholders exceed $0.1955 per common unit and subordinated unit in any quarter, our unitholders and our general partner, as the holder of our incentive distribution rights (“IDRs”), will receive distributions according to the following percentage allocations: Marginal Percentage Interest in Distributions General Partner Total Quarterly Distribution Target Amount above $0.1955 up to $0.2125 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . above $0.2125 up to $0.2550 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . above $0.2550 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unitholders 85 % 75 % 50 % (as holder of IDRs) 15 % 25 % 50 % 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, our general partner owns the IDRs and may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests. Subordinated Units Antero owns all of our subordinated units. The principal difference between our common units and subordinated units is that, for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution from operating surplus until the common units have 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 will not accrue arrearages. When the subordination period ends, all of the subordinated units will convert into an equal number of common units. The subordination period will end on the first business day after we have earned and paid at least $0.68 (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and subordinated unit for each of three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2017 and there are no outstanding arrearages on our common units. To the extent we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such arrearage payments in the future except during the subordination period. To the extent we have cash available for distribution from operating surplus in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any distribution arrearages on common units related to prior quarters before any cash distribution is made to holders of subordinated units. Cash Distributions On January 13, 2016, we announced that the board of directors of our general partner declared a cash distribution of $0.22 per unit for the quarter ended December 31, 2015. The distribution will be payable on February 29, 2016 to unitholders of record as of February 15, 2016. F-18 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 The following table details all distributions paid or declared as of the date of this filing (in thousands, except per unit data): Distributions Limited Partners Quarter and Year Record Date Distribution Date - $ 14,322 Q4 2014 . . . . . . February 13, 2015 February 27, 2015 $ 7,161 $ - $ 27,338 Q1 2015 . . . . . . May 13, 2015 Q2 2015 . . . . . . August 13, 2015 - $ 28,858 Q3 2015 . . . . . . November 11, 2015 November 30, 2015 $ 20,470 $ 15,568 $ 295 $ 36,333 397 Total 2015 . . . . . . . . . . . . . . . . . . . . . . . . . $ 56,126 $ 50,827 $ 295 $ 107,248 * . . . . . . . . . November 12, 2015 November 20, 2015 $ May 27, 2015 August 27, 2015 397 $ - $ - $ Common unitholders Subordinated unitholders 7,161 $ $ 13,669 $ 13,669 $ $ 14,429 $ 14,429 $ General partner (IDRs) Total Distributions per limited partner unit $ 0.0943 $ 0.1800 $ 0.1900 $ 0.2050 * $ Q4 2015 . . . . . . February 15, 2016 February 29, 2016 $ 22,049 $ 16,707 $ 969 $ 39,725 $ 0.2200 * Distribution equivalent rights on units that vested related to limited partner common units. (7) Net Income Per Limited Partner Unit The Partnership’s net income is attributed to the general partner and limited partners, including subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to incentive distributions paid to the general partner. Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income, less general partner incentive distributions, by the weighted average number of outstanding limited partner units during the period. We compute earnings per unit using the two-class method for master limited partnerships. Under the two- class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period. We calculate net income available to limited partners based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are attributed to the general partner and limited partners in accordance with the contractual terms of the partnership agreement under the two-class method. Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted net income per limited partner unit reflects the potential dilution that could occur if agreements to issue common units, such as awards under long-term incentive plans, were exercised, settled or converted into common units. When it is determined that potential common units resulting from an award should be included in the diluted net income per limited partner unit calculation, the impact is reflected by applying the treasury stock method. Earnings per common unit assuming dilution for the year ended December 31, 2015 was calculated based on the diluted weighted average number of units outstanding of 82,585,508, including 47,669 dilutive units attributable to non-vested restricted unit and phantom unit awards. For the year ended December 31, 2015, 2,139,319 non-vested phantom unit and restricted unit awards were anti-dilutive F-19 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 and therefore excluded from the calculation of diluted earnings per unit. The Partnership’s calculation of net income per common and subordinated unit for the periods indicated is as follows (in thousands, except per unit data): 2013 December 31, 2014 2015 Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,015 $ 127,875 $ 159,105 Less: Pre-IPO net income attributed to parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pre-Water Acquisition net income attributed to parent . . . . . . . . . . . . . . . . . . . . . General partner interest in net income attributable to incentive distribution rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Limited partner interest in net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Net income allocable to common units - basic and diluted . . . . . . . . . . . . . . . . . . . $ Net income allocable to subordinated units - basic and diluted . . . . . . . . . . . . . . . . Limited partner interest in net income - basic and diluted . . . . . . . . . . . . . . . . . . . . $ (2,015) — (98,219) (22,234) — (40,193) — — — — — $ $ $ — 7,422 (1,264) $ 117,648 3,711 3,711 7,422 $ 62,421 55,227 $ 117,648 Net income per limited partner unit - basic Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ — $ 0.05 0.05 Net income per limited partner unit - diluted Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ — $ 0.05 0.05 $ $ $ $ 0.76 0.73 0.76 0.73 Weighted average limited partner units outstanding - basic Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Weighted average limited partner units outstanding - diluted Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — 75,941 75,941 82,538 75,941 75,941 75,941 82,586 75,941 (8) Fair Value Measurement In connection with the Water Acquisition, we have agreed to pay Antero (a) $125 million in cash if the Partnership delivers 176,295,000 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 the Partnership delivers 219,200,000 barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. This contingent consideration liability is valued based on Level 3 inputs. F-20 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 The following table provides a reconciliation of changes in Level 3 financial liabilities measured at fair value on a recurring basis for the periods shown below (in thousands): Beginning balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Initial estimate upon acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ending balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 2014 — — — — 2015 $ — 174,716 3,333 $ 178,049 Contingent Consideration December 31, We account for contingent consideration in accordance with applicable accounting guidance pertaining to business combinations. We are contractually obligated to pay Antero contingent consideration in connection with the Water Acquisition, and therefore recorded this contingent consideration liability at the time of the Water Acquisition. We update our assumptions each reporting period based on new developments and adjust such amounts to fair value based on revised assumptions, if applicable, until such consideration is satisfied through payment upon achievement of the specified objectives or it is eliminated upon failure to achieve the specified objectives. As of December 31, 2015, expect to pay the entire amount of the contingent consideration amounts in 2019 and 2020. The fair value measurement is based on significant inputs not observable in the market and thus represents a Level 3 measurement within the fair value hierarchy. The fair value of the contingent consideration liability associated with future milestone payments was based on the risk adjusted present value of the contingent consideration payout. (9) Reporting Segments The Partnership’s operations are located in the United States and are organized into two reporting segments: (1) gathering and compression and (2) water handling and treatment. Gathering and Compression The gathering and compression segment includes a network of gathering pipelines and compressor stations that collect natural gas, NGLs and oil from Antero’s wells in the Marcellus Shale in West Virginia and the Utica Shale in Ohio. Water Handling and Treatment The Partnership’s water handling and treatment segment includes two independent fresh water distribution systems that source and deliver fresh water from the Ohio River, several regional waterways, and waste water services for well completion operations in Antero’s operating areas. These fresh water systems consist of permanent buried pipelines, surface pipelines and fresh water storage facilitates, as well as pumping stations and impoundments to transport the fresh water throughout the pipelines. The waste water services consist of waste water transportation, disposal, and treatment, including a water treatment facility, currently under construction. These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. We evaluate the performance of the Partnership’s business segments based on operating income. Interest expense is primarily managed and evaluated on a consolidated basis. F-21 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 Summarized financial information concerning the Partnership’s segments for the periods indicated is shown in the following table (in thousands): Gathering and Handling and Consolidated Compression Treatment Total Water Year ended December 31, 2013 Revenues: Revenue - Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 22,363 $ 35,871 $ 58,234 Operating expenses: Direct operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative (before equity-based compensation) . . . . . . . . . . . . . . . . . . . Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,079 7,193 15,931 11,346 36,549 5,792 2,523 8,418 2,773 19,506 7,871 9,716 24,349 14,119 56,055 Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (14,186) $ 16,365 $ 2,179 Segment assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Capital expenditures for segment assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 578,089 $ 389,340 $ 230,248 $ 200,256 $ 808,337 589,596 Year ended December 31, 2014 Revenues: Revenue - Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Revenue - third-party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95,746 $ - 95,746 162,283 $ 8,245 170,528 258,029 8,245 266,274 Operating expenses: Direct operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative (before equity-based compensation) . . . . . . . . . . . . . . . . . . . Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,470 13,416 8,619 36,789 74,294 33,351 5,332 2,999 16,240 57,922 48,821 18,748 11,618 53,029 132,216 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 21,452 $ 112,606 $ 134,058 Segment assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Capital expenditures for segment assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,395,121 $ 553,582 $ 421,489 $ 200,116 $ 1,816,610 753,698 Year ended December 31, 2015 Revenues: Revenue - Antero . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Revenue - third-party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 230,210 $ 382 230,592 155,954 $ 778 156,732 386,164 1,160 387,324 Operating expenses: Direct operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative (before equity-based compensation) . . . . . . . . . . . . . . . . . . . Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Contingent acquisition consideration accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,783 22,608 17,840 60,838 - 127,069 53,069 6,128 4,630 25,832 3,333 92,992 78,852 28,736 22,470 86,670 3,333 220,061 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 103,523 $ 63,740 $ 167,263 Segment assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Capital expenditures for segment assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,428,796 $ 320,002 $ 551,236 $ 132,633 $ 1,980,032 452,635 F-22 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 (10) Contingencies Environmental Obligations We are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. During the third quarter of 2015, the West Virginia Department of Environmental Protection issued us a Notice of Violation for improper installation of an engine. We do not expect that any ultimate sanction will have a material impact on our financial position, results of operations, or liquidity. (11) Quarterly Financial Information (Unaudited) The Partnership’s combined consolidated financial statements have been retrospectively recast for all periods presented prior to the fourth quarter of 2015 to include the historical results of Antero Water because the Water Acquisition was between entities under common control. See Note 1 – Business and Organization. F-23 ANTERO MIDSTREAM PARTNERS LP Notes to Combined Consolidated Financial Statements (Continued) Years Ended December 31, 2013, 2014, and 2015 Our quarterly financial information for the years ended December 31, 2014 and 2015 is as follows (in thousands, except per unit data): Year ended December 31, 2014 First quarter Second quarter Third quarter Forth quarter Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 36,532 $ 57,441 $ 71,583 $ 100,718 42,758 Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57,960 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55,898 Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (26,242) Less: Pre-IPO net income attributed to parent . . . . . . . . . . . . . . . . (22,234) Less: Pre-Water Acquisition net income attributed to parent . . . . Net income attributable to limited partner units . . . . . . . . . . . . . . . $ 7,422 Net income per limited partner unit: Basic: 33,653 23,788 22,380 (22,380) — — $ 20,965 15,567 15,309 (15,309) — — $ 34,840 36,743 34,288 (34,288) — — $ Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Diluted: Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ — $ 0.05 0.05 0.05 0.05 Year ended December 31, 2015 Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 85,834 $ 88,093 $ 81,704 $ 131,693 79,793 Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51,900 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49,008 Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Less: Pre-Water Acquisition net income attributed to parent . . . . Less general partner's interest in net income . . . . . . . . . . . . . . . . . (969) Net income attributable to limited partner units . . . . . . . . . . . . . . . $ 15,647 $ 19,450 $ 34,512 $ 48,039 Net income per limited partner unit: Basic: 51,333 36,760 35,124 (15,674) — 51,923 33,911 32,325 (16,678) — 37,012 44,692 42,648 (7,841) (295) Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.10 $ 0.10 $ 0.13 $ 0.13 $ 0.23 $ 0.22 $ Diluted: Common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Subordinated units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.10 $ 0.10 $ 0.13 $ 0.13 $ 0.23 $ 0.22 $ 0.27 0.27 0.27 0.27 F-24 PARTNERSHIP INFORMATION DIRECTORS RICHARD W. CONNOR Audit Committee Director PETER R. K AGAN Director W. HOWARD KEENAN, JR. Director MANAGEMENT PAUL M. R ADY Chairman and Chief Executive Officer GLEN C. WARREN, JR. President MICHAEL N. KENNEDY Chief Financial Officer ALV YN A. SCHOPP Regional Senior Vice President and Chief Administrative Officer KE VIN J. KILSTROM Senior Vice President—Production BRIAN A. KUHN Senior Vice President—Land MARK D. MAUZ Senior Vice President—Gathering, Marketing and Transportation WARD D. McNEILLY Senior Vice President—Reserves, Planning and Midstream STE VEN M. WOODWARD Senior Vice President—Business Development BROOKS J. KLIMLE Y Audit Committee Director DAVID A. PETERS Audit Committee Director J. KE VIN ELLIS Vice President— Government Relations W. CHAD GREEN Vice President—Finance PAUL L. KOVACH Vice President—Geoscience WILLIAM J. PIERINI Vice President—Land TROY R. ROACH Vice President—Health, Safety and Environment CHRISTOPHER W. TREML Vice President—Land ROBERT S. TUCKER Vice President—Geology K. PHIL YOO Vice President—Accounting, Chief Accounting Officer and Corporate Controller INVESTOR RELATIONS ANTERO MIDSTRE AM PARTNERS LP 1615 Wynkoop Street Denver, Colorado 80202 (303) 357-7310 extension 6782 www.anteromidstream.com TRANSFER AGENT AND REGISTRAR AMERICAN STOCK TR ANSFER AND TRUST COMPANY, LLC 6201 15th Avenue Brooklyn, New York 11219 (800) 937-5449 INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM KPMG LLP Denver, Colorado LEGAL COUNSEL VINSON & ELKINS LLP Houston, Texas UNITHOLDER INFORMATION Our common units are publicly traded on the NYSE under the symbol “AM” PARTNERSHIP HEADQUARTERS ANTERO MIDSTRE AM PARTNERS LP 1615 Wynkoop Street Denver, Colorado 80202 FORWARD-LOOKING STATEMENTS The Annual Report 2015 includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero’s control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this annual report. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. 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 the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas, NGLs and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Item 1A. Risk-Facts” in our Annual Report on Form 10-K for the year ended December 31, 2015. A N T E R O M I D S T R E A M / / 2 0 1 5 A N N U A L R E P O R T 

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