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Filed Pursuant to Rule 424(b)(4)
Commission File No. 333-193798

PROSPECTUS


Logo

Antero Midstream Partners LP

40,000,000 Common Units
Representing Limited Partner Interests


This is the initial public offering of 40,000,000 common units representing limited partner interests of Antero Midstream Partners LP. No public market currently exists for our common units.

Our common units have been approved for listing on the New York Stock Exchange under the symbol "AM," subject to official notice of issuance.

Investing in our common units involves risks. Please read "Risk Factors" beginning on page 22 of this prospectus.

These risks include the following:

Because all of our revenue currently is, and a substantial majority of our revenue over the long term is expected to be, derived from Antero Resources Corporation ("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 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.

On a pro forma basis, we would not have had sufficient cash available for distribution to pay any distributions on our common units or subordinated units for the year ended December 31, 2013 or the twelve-month period ended June 30, 2014.

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 that Antero produces or any decrease in the number of wells that Antero completes could adversely affect our business and operating results.

Antero, our general partner and their respective affiliates, including Antero Investment, which will own 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.

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

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.

You will experience immediate dilution in tangible net book value of $17.92 per common unit.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, which could cause you to lose all or part of your investment.

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.

 
  Per
Common Unit
  Total  

Offering price to the public

  $ 25.000   $ 1,000,000,000  

Underwriting discounts and commissions

  $ 1.125   $ 45,000,000  

Proceeds to us (before expenses)(1)

  $ 23.875   $ 955,000,000  

(1)
Excludes an aggregate structuring fee of 0.5% of the gross offering proceeds payable to Barclays Capital Inc. and Citigroup Global Markets Inc. Please read "Underwriting."

We have granted the underwriters the option to purchase 6,000,000 additional common units on the same terms and conditions set forth above if the underwriters sell more than 40,000,000 common units in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units on or about November 10, 2014.


Barclays                 Citigroup   Wells Fargo Securities



Credit Suisse   J.P. Morgan   Morgan Stanley



Baird   BMO Capital Markets   Raymond James

Tudor, Pickering, Holt & Co.   Scotiabank / Howard Weil

Prospectus dated November 4, 2014


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Table of Contents


TABLE OF CONTENTS

SUMMARY

    1  

Overview

    1  

Our Contractual Arrangements with Antero

    4  

Our Contractual Arrangements with Third Parties

    5  

Our Existing Assets and Growth Projects

    5  

Business Strategies

    6  

Competitive Strengths

    7  

Recent Developments

    9  

Our Relationship with Antero and Antero Investment

    9  

Our Management

    10  

Partnership Structure

    11  

Emerging Growth Company Status

    12  

Risk Factors

    12  

Partnership Information

    13  

The Offering

    14  

Summary Historical and Pro Forma Financial and Operating Data

    19  

Non-GAAP Financial Measure

    21  

RISK FACTORS

   
22
 

Risks Related to Our Business

    22  

Risks Inherent in an Investment in Us

    35  

Tax Risks to Common Unitholders

    45  

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

   
50
 

USE OF PROCEEDS

   
51
 

CAPITALIZATION

   
52
 

DILUTION

   
53
 

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

   
55
 

General

    55  

Our Minimum Quarterly Distribution

    57  

Subordinated Units

    57  

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and the Twelve-Month Period Ended June 30, 2014

    58  

Estimated Cash Available for Distribution for the Twelve-Month Period Ending September 30, 2015

    61  

Assumptions and Considerations

    64  

HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

   
71
 

General

    71  

Operating Surplus and Capital Surplus

    71  

Capital Expenditures

    74  

Subordination Period

    75  

Distributions From Operating Surplus During the Subordination Period

    76  

Distributions From Operating Surplus After the Subordination Period

    77  

General Partner Interest

    77  

Incentive Distribution Rights

    77  

Percentage Allocations of Distributions From Operating Surplus

    77  

General Partner's Right to Reset Incentive Distribution Levels

    78  

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Distributions From Capital Surplus

    80  

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

    81  

Distributions of Cash Upon Liquidation

    82  

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

   
85
 

Non-GAAP Financial Measure

    86  

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

   
88
 

Overview

    88  

Sources of Our Revenues

    88  

How We Evaluate Our Operations

    89  

Items Affecting Comparability of Our Financial Results

    90  

Principal Components of Our Cost Structure

    90  

Results of Operations

    92  

Liquidity and Capital Resources

    97  

Our Critical Accounting Policies and Estimates

    100  

New Accounting Pronouncements

    101  

Off-Balance Sheet Arrangements

    101  

Quantitative and Qualitative Disclosures About Market Risk

    102  

INDUSTRY

   
103
 

General

    103  

Midstream Services

    103  

BUSINESS

   
105
 

Our Company

    105  

Our Areas of Operation

    107  

Our Relationship with Antero

    108  

Our Contractual Arrangements with Third Parties

    110  

Our Existing Assets and Growth Projects

    110  

Business Strategies

    111  

Competitive Strengths

    112  

Antero's Existing Third-Party Commitments

    114  

Title to Properties

    114  

Seasonality

    115  

Competition

    115  

Regulation of Operations

    115  

Pipeline Safety Regulation

    116  

Regulation of Environmental and Occupational Safety and Health Matters

    117  

Employees

    122  

Legal Proceedings

    122  

MANAGEMENT

   
123
 

Management of Antero Midstream Partners LP

    123  

Executive Officers and Directors of Our General Partner

    123  

Committees of the Board of Directors

    127  

EXECUTIVE COMPENSATION

   
128
 

Summary Compensation Table

    128  

Salary and Cash Incentive Awards in Proportion to Total Compensation

    129  

Outstanding Equity Awards at 2013 Fiscal Year-End

    129  

Additional Narrative Disclosure

    130  

Compensation of Directors

    133  

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

    134  

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

   
136
 

Distributions and Payments to Our General Partner and Its Affiliates

    136  

Agreements with Affiliates in Connection with the Transactions

    138  

Other Contractual Relationships with Antero

    139  

Procedures for Review, Approval and Ratification of Transactions with Related Persons

    143  

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

   
144
 

Conflicts of Interest

    144  

Duties

    149  

DESCRIPTION OF THE COMMON UNITS

   
152
 

The Units

    152  

Transfer Agent and Registrar

    152  

Transfer of Common Units

    152  

THE PARTNERSHIP AGREEMENT

   
154
 

Organization and Duration

    154  

Purpose

    154  

Cash Distributions

    154  

Capital Contributions

    154  

Voting Rights

    155  

Applicable Law; Forum, Venue and Jurisdiction

    156  

Reimbursement of Partnership Litigation Costs

    156  

Limited Liability

    156  

Issuance of Additional Interests

    157  

Amendment of the Partnership Agreement

    158  

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

    160  

Dissolution

    160  

Liquidation and Distribution of Proceeds

    161  

Withdrawal or Removal of Our General Partner

    161  

Transfer of General Partner Interest

    162  

Transfer of Ownership Interests in the General Partner

    162  

Transfer of Subordinated Units and Incentive Distribution Rights

    162  

Change of Management Provisions

    163  

Limited Call Right

    163  

Non-Taxpaying Holders; Redemption

    163  

Non-Citizen Assignees; Redemption

    164  

Meetings; Voting

    164  

Voting Rights of Incentive Distribution Rights

    165  

Status as Limited Partner

    165  

Indemnification

    166  

Reimbursement of Expenses

    166  

Books and Reports

    166  

Right to Inspect Our Books and Records

    167  

Registration Rights

    167  

UNITS ELIGIBLE FOR FUTURE SALE

   
168
 

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

   
170
 

Taxation of the Partnership

    170  

Tax Consequences of Unit Ownership

    172  

Tax Treatment of Operations

    177  

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Disposition of Units

    177  

Uniformity of Units

    180  

Tax-Exempt Organizations and Other Investors

    180  

Administrative Matters

    181  

State, Local and Other Tax Considerations

    183  

INVESTMENT IN ANTERO MIDSTREAM PARTNERS LP BY EMPLOYEE BENEFIT PLANS

   
184
 

General Fiduciary Matters

    184  

Prohibited Transaction Issues

    184  

Plan Asset Issues

    185  

UNDERWRITING

   
186
 

Commissions and Expenses

    186  

Option to Purchase Additional Common Units

    187  

Lock-Up Agreements

    187  

Offering Price Determination

    188  

Indemnification

    188  

Directed Unit Program

    188  

Stabilization, Short Positions and Penalty Bids

    188  

Electronic Distribution

    189  

New York Stock Exchange

    189  

Discretionary Sales

    190  

Stamp Taxes

    190  

Other Relationships

    190  

Direct Participation Program Requirements

    191  

Selling Restrictions

    191  

VALIDITY OF OUR COMMON UNITS

   
194
 

EXPERTS

   
194
 

WHERE YOU CAN FIND MORE INFORMATION

   
194
 

INDEX TO FINANCIAL STATEMENTS

   
F-1
 

ANNEX A—FORM OF AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

    A-1  

ANNEX B—GLOSSARY OF TERMS

    B-1  

        You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or to which we have referred you. We have not authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We are offering to sell common units and seeking offers to buy common units only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common units. Our business, financial condition, results of operations and prospects may have changed since that date.

        This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read "Risk Factors" and "Cautionary Statement Regarding Forward-Looking Statements."

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Industry and Market Data

        The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled "Risk Factors." These and other factors could cause results to differ materially from those expressed in these publications.


Reserve Information

        The estimates of Antero's net proved, probable and possible reserves as of June 30, 2014 included in this prospectus are based on evaluations prepared by Antero's internal reserve engineers, which have been audited by Antero's independent reserve engineers, DeGolyer and MacNaughton, using SEC pricing and assuming ethane rejection.


Certain Terms Used in this Prospectus

        All references in this prospectus to:

    "we," "our," "us" or like terms when used in the present tense or prospectively refer to Antero Midstream Partners LP and its subsidiaries;

    "Predecessor," "we," "our," "us" or like terms when used in a historical context refer to the portion of Antero's midstream business and assets, consisting of its gathering systems and compressor stations, to be contributed to Midstream Operating prior to the closing of this offering;

    "Midstream Operating" refer to Antero Midstream LLC, which will own Antero's midstream business and assets at the closing of this offering, at which point Midstream Operating will be contributed to us;

    "Antero" refer to Antero Resources Corporation;

    "Antero Investment" refer to Antero Resources Investment LLC, the owner of our general partner;

    "our general partner" or "Midstream Management" refer to Antero Resources Midstream Management LLC;

    "our employees" refer to the employees of Antero that will conduct our business;

    "Sponsors" refer to Warburg Pincus LLC, Yorktown Partners LLC and Trilantic Capital Partners;

    "excluded acreage" refer to Antero's existing acreage not dedicated to us for gathering and compression services, consisting of 131,000 net leasehold acres dedicated to third-party gatherers as described in "Business—Antero's Existing Third-Party Commitments—Excluded Acreage"; and

    "existing third-party commitments" refer to Antero's existing minimum volume commitments to parties other than us, as described in "Business—Antero's Existing Third-Party Commitments—Other Commitments," together with the excluded acreage.

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SUMMARY

        This summary provides a brief overview of information contained elsewhere in this prospectus. You should read this entire prospectus and the documents to which we refer you before making an investment decision. You should carefully consider the information set forth under "Risk Factors," "Cautionary Statement Regarding Forward-Looking Statements" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" as well as the historical financial statements and the related notes to those financial statements included elsewhere in this prospectus and the pro forma financial statements and related notes to those financial statements included elsewhere in this prospectus. The information presented in this prospectus assumes, unless otherwise indicated, that the underwriters' option to purchase additional common units is not exercised.

        We include a glossary of some of the terms used in this prospectus as Appendix B.


Antero Midstream Partners LP

Overview

        We are a growth-oriented limited partnership formed by Antero Resources Corporation (NYSE: AR) to own, operate and develop midstream energy assets to service Antero's rapidly increasing production. Our assets consist of gathering pipelines and compressor stations through which we provide midstream services to Antero under a long-term, fixed-fee contract. Our assets are located in the rapidly developing liquids-rich southwestern core of the Marcellus Shale in northwest West Virginia and liquids-rich core of the Utica Shale in southern Ohio, which Antero believes are 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 covering substantially all of Antero's current and future acreage for gathering and compression services. All of Antero's existing acreage is dedicated to us for gathering and compression services except for the existing third-party commitments, which includes 131,000 Marcellus Shale net leasehold acres characterized by dry gas and liquids-rich production that have been previously dedicated to third-party gatherers. Please read "Business—Antero's Existing Third-Party Commitments." Net of the excluded acreage, our contract for gathering and compression services covers approximately 370,000 net leasehold acres held by Antero as of September 5, 2014. 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. In April 2014, we began providing condensate gathering services to Antero under the gathering and compression agreement.

        We have an option to purchase Antero's fresh water distribution systems at fair market value. In addition, Antero has an option to participate for up to a 20% non-operating equity interest in the 800-mile Energy Transfer LLC Rover Pipeline project (the "ET Rover Pipeline") that it will assign to us in connection with the completion of this offering. Antero also has a right to participate for up to a 15% non-operating equity interest in an unnamed 50-mile regional gathering pipeline extension (the "Regional Gathering System") that will expire six months following the date on which the Regional Gathering System is placed into service, which is currently scheduled to occur during the fourth quarter of 2015. Antero intends to assign this option to us in connection with the completion of this offering. In addition, we have entered into a right-of-first-offer agreement with Antero to allow for us to provide Antero with natural gas processing services in the future.

        Antero is our only customer and is one of the largest producers of natural gas and NGLs in the Appalachian Basin, where it produced on average over 1 Bcfe/d net (14% liquids) during July 2014. As of June 30, 2014, Antero's estimated net proved, probable and possible reserves were 9.1 Tcfe, 21.1 Tcfe

 

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and 7.3 Tcfe, respectively, of which 85% was natural gas. As of June 30, 2014, Antero's drilling inventory consisted of 5,011 identified potential horizontal well locations (3,159 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 robust drilling program continues and its production increases. Based on information from RigData, Antero is currently the most active driller in the Appalachian Basin with 22 operated rigs, including 15 operated rigs in the Marcellus Shale (where it is the most active driller) and seven operated rigs in the Utica Shale (where it is one of the most active drillers). On August 26, 2014, Antero announced a revised 2014 drilling and completion capital expenditures budget of approximately $2.4 billion that provides for the drilling of approximately 215 wells, a substantial increase over the 162 wells drilled in 2013 and also announced an expected 2015 drilling and capital expenditure budget of $2.3 billion to $2.5 billion. Antero's average Appalachian production during 2013 represented an increase of 119% as compared to 2012, and its net production in the second quarter of 2014 averaged 891 MMcfe/d. We anticipate that Antero's robust drilling program will significantly increase throughput on our gathering and compression systems.

        The charts below illustrate the significant Appalachian Basin production growth achieved by Antero since the acquisition of its Marcellus Shale leasehold in 2008 and the growth in wells drilled as it has undertaken its development program. We believe that Antero will primarily rely on us to deliver the midstream infrastructure necessary to support its continued growth, which should result in significant increases in our gathering and compression volumes.

Antero's Average Net Daily Production(1)   Antero's Operated Gross Wells Spud(1)


GRAPHIC

 



GRAPHIC

(1)
Represents all of Antero's Appalachian Basin production and wells drilled for the periods indicated, including production from wells drilled on the excluded acreage. For a discussion of the anticipated throughput of our gathering and compression systems, please read "Our Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations—Results, Volumes and Fees."

(2)
Represents the mid-point of Antero's anticipated average net daily production for the six months ending December 31, 2014.

(3)
Represents Antero's estimate of the number of wells it intends to spud in 2014.

        The following table highlights the scale of Antero's net acreage position and gross drilling locations dedicated to us as of June 30, 2014. With 5,011 identified potential horizontal well locations included in Antero's net proved, probable and possible reserves as of June 30, 2014, Antero maintains a 23-year

 

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drilling inventory (based on expected 2014 drilling activity), which we believe will provide significant demand for further gathering and compression services.

 
   
  Gross Drilling Locations(1)   2014
Estimated
Drilling
Activity
 
 
  Net
Acres(1)
  Dry
Gas
  Rich
Gas
  Highly
Rich Gas
  Highly
Rich Gas/
Condensate
  Condensate   Total   Average
Rigs
  Wells  

Marcellus Gathering and Compression

    237,000     383     362     864     715         2,324 (2)   11     110  

Utica Gathering and Compression

    118,000     222     208     88     113     204     835     6     60  
                                       

Total Gathering and Compression Dedicated to Us(3)

    355,000     605     570     952     828     204     3,159     17     170  

Excluded acreage(4)

    131,000     1,045     774     33             1,852     4     45  
                                       

Total

    486,000     1,650     1,344     985     828     204     5,011     21     215  
                                       
                                       

(1)
Net acres and gross drilling locations as of June 30, 2014.

(2)
Includes 305 Upper Devonian locations not expected to be drilled during the twelve-month period ending September 30, 2015. See "Our Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve-Months Ending September 30, 2015."

(3)
Antero's estimated net proved, probable and possible reserves associated with this acreage were 4.1 Tcfe, 17.0 Tcfe and 4.1 Tcfe, respectively, as of June 30, 2014. See "Business—Antero's Existing Third-Party Commitments."

(4)
The excluded acreage is associated with approximately 5.0 Tcfe, 4.1 Tcfe and 3.2 Tcfe of Antero's net proved, probable and possible reserves, respectively, as of June 30, 2014.

        Antero's core operating areas are located in liquids-rich portions of the Marcellus and Utica Shales, which Antero believes are two of North America's premier shale plays. The Marcellus Shale is characterized by consistent and predictable geology, high well recoveries relative to drilling and completion costs and significant hydrocarbon resources in place. Based on these attributes, as well as Antero's drilling results and those publicly released by other operators, Antero believes that the Marcellus Shale offers some of the most attractive single-well rates of return of all North American conventional and unconventional play types. Antero believes that the Marcellus Shale has two core areas: the southwestern core in northern West Virginia and southwestern Pennsylvania and the northeastern core in northeastern Pennsylvania. Substantially all of Antero's approximately 380,000 net leasehold acres in the Marcellus Shale are located within the southwestern core. According to RigData, as of August 29, 2014, approximately 90% of the 101 drilling rigs operating in the Marcellus Shale were located in these two core areas.

        Based on drilling results and initial production from Antero's 37 core area Utica Shale wells, Antero believes that the Utica Shale also offers some of the most attractive single-well rates of return of all North American conventional and unconventional plays. Antero believes that the core area is located in the southern portion of the play, where the majority of the most productive Utica Shale wells are located. Antero owns approximately 121,000 net leasehold acres in the core of the Utica Shale and expects to continue to add to its sizeable land position.

        We believe that Antero's large portfolio of repeatable, low cost, liquids-rich drilling opportunities in the Marcellus and Utica Shales supports strong well economics in a variety of commodity price environments. As a result, we expect strong and growing demand for our gathering and compression services as Antero's production increases.

 

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        In addition to the growth we anticipate as a result of Antero's development drilling, we believe we may be able to attract third-party customers as other upstream operators in the Marcellus and Utica Shales require infrastructure to move their product to market.


Our Contractual Arrangements with Antero

        We believe that Antero's acreage dedication to us, robust drilling program and expected production growth, combined with our fixed-fee, life of reserves business model and our right to provide additional services to Antero in the future, provide us with significant growth opportunities.

Gathering and Compression

        Pursuant to our 20-year gathering and compression agreement, 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). For a discussion of Antero's existing third-party commitments, please read "Business—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 and a compression fee of $0.18 per Mcf, in each case subject to CPI-based adjustments. Our handling and treating of condensate is priced on a cost of services basis. 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.

Option to Acquire Antero's Fresh Water Distribution Business

        In addition to the gathering and compression agreement, Antero has also granted us an option to purchase its fresh water distribution systems at fair market value. Antero owns and operates two independent fresh water distribution systems that distribute fresh water from the Ohio River and several other regional water sources for producers' well completion operations in the Marcellus and Utica Shales. These systems consist of a combination of permanent buried pipelines, portable surface pipelines and fresh water storage facilities, as well as pumping stations to transport the fresh water throughout the pipeline networks. By December 31, 2014, Antero anticipates that its fresh water distribution system will be expanded to include 107 miles and 48 miles of buried water pipelines in the Marcellus and Utica operating areas, respectively, as well as 26 and 8 fresh water storage impoundments, respectively.

        If we purchase Antero's fresh water distribution systems, we will enter into a 20-year fresh water distribution agreement with Antero, pursuant to which a service area encompassing all of Antero's areas of operation in West Virginia, Ohio and Pennsylvania will be dedicated to us. If Antero requires fresh water distribution services outside of the initial service area, we will have the option to provide those services on the same terms and conditions. Under the fresh water distribution agreement, we will receive a fee of $3.50 per barrel for fresh water deliveries by pipeline to well sites or $3.00 per barrel if Antero accesses the water by truck directly from our fresh water storage facilities, in each case subject to CPI-based adjustments. Please see "Certain Relationships and Related Transactions—Other Contractual Relationships with Antero—Fresh Water Distribution."

 

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Processing

        Although we do not currently have any processing or NGL 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 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 a discussion of Antero's existing third-party commitments, please read "Business—Antero's Existing Third-Party Commitments."


Our Contractual Arrangements with Third Parties

        Due to its leading position in the Marcellus and Utica Shales, Antero is frequently invited to be an anchor shipper in new regional pipeline projects and often has the opportunity to participate as an equity owner in such projects. As part of our relationship with Antero, we expect that Antero will assign us the right to participate in the equity ownership of these types of projects in the future, allowing us to diversify and vertically integrate our midstream asset base. Please see "Our Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations—Capital Expenditures—Expansion Capital Expenditures."

Option to Participate in ET Rover Pipeline

        In connection with Antero's agreement to become an anchor shipper on the recently announced ET Rover Pipeline, Antero has an option to participate for up to a 20% non-operated equity interest in the ET Rover Pipeline. Antero will assign the option to us in connection with the completion of this offering. The ET Rover Pipeline is being designed to transport 3.25 Bcf/d through approximately 800 miles of 36-inch and 42-inch pipeline and to enable the flow of natural gas from processing facilities and other receipt points located in the Marcellus and Utica Shale areas to market regions in the U.S. and Canada. The ET Rover Pipeline is expected to provide new natural gas pipeline infrastructure to move natural gas to local utilities, to other pipelines for Midwest and Gulf Coast markets, and to the Dawn Hub in Canada for Canadian and U.S. Northeast markets. The project is expected to be placed into service during the first quarter of 2017. Subject to confirmatory diligence, we have not determined to what extent, if any, we would exercise such option.

Option to Participate in Regional Gathering System

        In connection with Antero's agreement to become an anchor shipper on the Regional Gathering System, Antero was granted an option to participate for up to a 15% non-operated equity interest in the system. Antero's option will expire six months following the date on which the Regional Gathering System is placed into service, which is currently scheduled to occur during the fourth quarter of 2015. Antero intends to assign the option to us in connection with the completion of this offering. The Regional Gathering System is expected to connect a portion of Antero's Marcellus Shale operating areas with its downstream interstate pipelines upon which Antero has firm transportation commitments. The Regional Gathering System is expected to be completed and placed into service in the fourth quarter of 2015. Subject to confirmatory diligence, we have not determined to what extent, if any, we would exercise such option.


Our Existing Assets and Growth Projects

        In connection with the completion of this offering, Antero will contribute its gathering and compression assets to us, as well as the right to develop additional midstream infrastructure to service Antero's rapidly growing production. Because of our close operational and contractual relationship with Antero, we expect to grow significantly as Antero pursues its development plan.

 

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        The following table provides information regarding our gathering and compression system as of December 31, 2013 and operations for the second quarter of 2014, as well as our expectations for organic growth in these assets as of December 31, 2014, based on Antero's drilling and completion plans.

 
  Low-Pressure
Pipeline
(miles)
  High-Pressure
Pipeline
(miles)
  Condensate
Pipeline
(miles)
  Compression
Capacity
(MMcf/d)
   
 
 
  Average Daily
Throughput for the
Three Months Ended
June 30, 2014
(MMcfe/d)
 
 
  As of December 31,  
 
  2013   2014E   2013   2014E   2013   2014E   2013   2014E  

Gathering and Compression System:

                                                       

Marcellus

    54     110     38     70             105     370     278  

Utica

    26     51     23     34     10     20             139  
                                       

Total

    80     161     61     104     10     20     105     370     417  
                                       
                                       

        Our midstream infrastructure includes a network of 8-, 12-, 16- and 20-inch gathering pipelines and compressor stations that collects raw natural gas from Antero's operations in the Marcellus and Utica Shales. In addition, we have a system of condensate gathering pipelines to collect wellhead condensate associated with Antero's liquids rich production in the Utica Shale. Our compression assets currently only service Antero's operations in the Marcellus Shale area, but we may expand our compression capacity to service the Utica Shale area in 2015.

        By December 31, 2014, we anticipate expanding our Marcellus and Utica Shale gathering systems to 180 miles and 105 miles, respectively, and growing our year-end daily Marcellus compression capacity to 370 MMcf/d.


Business Strategies

        Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business. We expect to achieve this objective through the following business strategies:

    Leveraging our extensive asset base to meet Antero's current and future infrastructure needs.  We own and operate a high-capacity asset base that we have recently constructed that will allow us to gather and compress significant incremental natural gas volumes. We intend to continue to develop our midstream infrastructure to move Antero's production to market. In the short-term, we anticipate significant growth in demand for our gathering and compression services driven by Antero's plan to drill approximately 215 horizontal wells in 2014 with an average lateral length of approximately 7,900 feet. In addition, as of June 30, 2014, Antero's drilling inventory consisted of 5,011 identified potential horizontal well locations (3,159 of which were located on acreage dedicated to us) for gathering and compression services, giving Antero a 23-year drilling inventory (based on expected 2014 drilling activity) and, consequently, visible long-term demand for our services.

    Focusing on stable, fixed-fee business to avoid direct commodity price exposure.  The gathering and compression agreement with Antero provides for a fixed-fee structure, and we intend to continue to pursue additional fixed-fee opportunities with Antero and third parties in order to avoid direct commodity price exposure. We will focus on obtaining additional long-term commitments from customers, which may include reservation-based charges, volume commitments and acreage dedications.

    Growing our business by pursuing accretive acquisitions from Antero and third parties.  Antero has granted us an option to purchase its fresh water distribution systems at fair market value. Our other agreements with Antero also grant us the right to purchase at cost certain midstream facilities that Antero may acquire in the future. We believe that Antero will be incentivized to

 

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      support the growth of our business as a result of its economic interest in us. In addition, our management team has significant experience in mergers and acquisitions and will selectively review opportunities to acquire assets from third parties.

    Exercising options to acquire non-operating interests in regional pipeline projects.  Due to its leading position in the Marcellus and Utica Shales, Antero is frequently invited to be an anchor shipper in new regional pipeline projects and often has the opportunity to participate as an equity owner in such projects. As part of our relationship with Antero, we expect that Antero will assign us the right to participate in the equity ownership of these types of projects in the future, allowing us to diversify and vertically integrate our midstream asset base. To date, Antero has negotiated an option to participate as an equity owner in two separate natural gas pipelines: the ET Rover Pipeline, a 36-inch and 42-inch, 800-mile pipeline currently scheduled to be in service during the first quarter of 2017 and the Regional Gathering System currently scheduled to be in service beginning in the fourth quarter of 2015. Antero has an option to participate for up to a 20% non-operating equity interest in the ET Rover Pipeline that it will assign to us in connection with the completion of this offering. Antero intends to convey its right to participate for up to a 15% non-operating equity interest in the Regional Gathering System to us in connection with the completion of this offering. Each of these projects represents an attractive long-term investment opportunity for us. These investments, if the options are exercised, would create a new line of business and incremental growth opportunities while providing stable, long-term fixed-fee driven cash flows. We believe our relationship with Antero and its extensive drilling inventory will afford us additional opportunities to invest in large-scale infrastructure projects, such as regional and long-haul pipelines, that will serve to support our long-term growth profile.

    Attracting third-party customers.  While we will devote substantially all of our resources to meeting Antero's needs in the near term, we expect to market our services to, and pursue strategic relationships with, third-party producers over time. We believe that our early, significant footprint of gathering and compression systems in the Marcellus and Utica Shales provides us with a competitive advantage that we believe will allow us to attract third-party natural gas volumes in the future.


Competitive Strengths

        We believe we are well-positioned to successfully execute our business strategies because of the following competitive strengths:

    Economic strength of Antero's development program.  We believe the attractiveness of Antero's liquids-rich portfolio of acreage and its low development cost relative to recoveries will support long-term demand for our gathering and compression services in a variety of commodity price environments. The economic strength of Antero's development program is substantially supported by:

    Antero's position in the core of the Marcellus and Utica Shales.  Antero owns and operates extensive and contiguous land positions in the core areas of two of the most economically attractive North American shale plays, which Antero believes are characterized by consistent geology and high well recoveries relative to drilling and completion costs.

    Antero's multi-year, low-risk drilling inventory.  Antero's drilling inventory at June 30, 2014 consisted of 5,011 identified potential horizontal well locations (3,159 of which were located on acreage dedicated to us) that will require gathering and compression services. Based on its expected 2014 drilling activity, these locations give Antero a 23-year drilling inventory.

    Antero's exposure to a large resource of liquids-rich gas and condensate.  Liquids-rich gas production generally enhances well economics due to the processing margin generated by

 

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        higher-value NGL products, such as propane and butane. In addition, the wellhead condensate often associated with liquids-rich production can further increase well economics. Approximately 67% of Antero's 5,011 identified potential horizontal well locations as of June 30, 2014 target the liquids-rich gas regions of the Marcellus and Utica Shales.

      Antero's status as a low-cost leader.  Antero has implemented operational efficiencies to give it some of the lowest development costs per Mcfe in the Marcellus and Utica Shales, such as (i) drilling longer laterals, (ii) pad drilling, (iii) the use of shorter stage lengths, (iv) the use of less expensive, shallow vertical drilling rigs to drill to the kick-off point of the horizontal wellbore, (v) the use of natural gas powered rigs and (vi) the use of its fresh water distribution systems.

      Antero's access to committed processing and firm takeaway capacity in the Marcellus and Utica Shales.  We believe Antero's existing contractual commitments for processing and firm long-haul transportation help minimize disruptions to its drilling program that might otherwise exist as a result of insufficient outlets for growing production. Antero has contracted for a total of 1,350 MMcf/d of processing capacity in the Marcellus Shale, 800 MMcf/d of which is currently in service. Similarly, Antero has 600 MMcf/d of contracted processing capacity in the Utica Shale, of which 450 MMcf/d is currently in service. Antero also has secured an average of 3,430,000 MMBtu/d of long-haul firm transportation capacity or firm sales by 2016 and has committed to 20,000 Bbl/d of ethane takeaway capacity and has entered into agreements to provide an additional 30,000 Bbl/d of ethane to the proposed Appalachian Shale Cracker Enterprise ("Ascent") ethane cracker, pending a final investment decision by Ascent, and 25,000 Bbl/d of ethane to the proposed Shell Chemical LP ("Shell") ethane cracker, pending a final investment decision by Shell, and firm transportation of 51,500 Bbl/d of NGLs with the Mariner East II project, subject to the completion of an open season. We believe our midstream infrastructure, together with Antero's significant processing and takeaway capacity, will allow Antero to commercialize its production more quickly at favorable prices and keep pace with its robust drilling plan.

      Antero's active hedging program.  Antero maintains an active hedging program designed to mitigate volatility in commodity prices and regional basis differentials and to protect its expected future cash flows. As of June 30, 2014, Antero had entered into hedging contracts for July 1, 2014 through December 31, 2019 covering a total of approximately 1.32 Tcfe of its projected natural gas and oil production at average index prices of $4.58/MMBtu and $94.13/Bbl, respectively. We believe that Antero's active hedging program will allow its drilling schedule to remain robust in a variety of commodity price environments.

    Extensive dedication, system scale and long-term, fixed fee contract to support stable cash flows.  Pursuant to our long-term contract with Antero, we have secured a 20-year dedication covering approximately 370,000 net leasehold acres held by Antero as of September 5, 2014 (net of the approximately 131,000 excluded net leasehold acres) for gathering and compression services. Please read "Business—Antero's Existing Third-Party Commitments." 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. We believe that Antero's drilling activity will result in significant growth of our midstream operations. Our fixed-fee, long-term contract structure eliminates our direct exposure to commodity price risk and provides us with long-term cash flow stability.

    Financial flexibility and strong capital structure.  At the closing of this offering, we expect to have no outstanding indebtedness and available borrowing capacity of $500.0 million under a new

 

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      $1.0 billion revolving credit facility. We believe that our borrowing capacity and our expected ability to effectively access debt and equity capital markets provide us with the financial flexibility necessary to execute our business strategy.

    Experienced and incentivized management team.  Antero's officers, who will also manage our business, have an average of over 30 years of industry experience and have successfully built, grown and sold two unconventional resource-focused upstream companies and one midstream company in the past 15 years. We believe Antero's experience and expertise from both an upstream and midstream perspective provides a distinct competitive advantage. Through our management's ownership interests in Antero Investment, which owns our incentive distribution rights, and their indirect ownership interests in Antero, which will own 35,940,957 of our common units and all of our subordinated units, our management team is highly incentivized to grow our distributions and the value of our business.


Recent Developments

Operating Update

        For the three months ended September 30, 2014, Antero's average net daily equivalent production and average realized prices were as follows:

    average net daily gas production was 1,080 MMcfe/d, including 25,000 Bbl/d of liquids (14%);

    average realized natural gas price (before hedging) was $3.63 per Mcf, a $0.43 negative differential to the NYMEX average for the period;

    average realized natural gas price (including hedging) was $4.31 per Mcf, a $0.25 positive differential to the NYMEX average for the period;

    average realized NGL price was $46.66 per barrel, or approximately 48% of the NYMEX WTI oil price average for the period;

    average realized oil price (before hedging) was $84.17 per barrel; and

    average natural gas equivalent price (including NGLs, oil and hedging) was $4.91 per Mcfe.


Our Relationship with Antero and Antero Investment

        One of our principal strengths is our relationship with Antero. We believe Antero's interests are aligned with ours because Antero relies on our ability to develop infrastructure in tandem with its drilling and production activities. Upon completion of this offering, Antero will own 35,940,957 common units and 75,940,957 subordinated units in us. Antero's interests are further aligned with ours in that the value of its retained common and subordinated units should increase to the extent we are successful in growing our operations. However, as a result of many of the risks associated with Antero's business, we cannot ensure that we will ultimately realize any benefit from our relationship with Antero. Please read "Risk Factors—Risks Related to Our Business."

        In addition to the alignment of Antero's interests with ours, Antero Investment, which includes members of our and Antero's management and the Sponsors, will own our general partner, which will own all of the incentive distribution rights. The value of the incentive distribution rights is driven by growth in our distributions. As a result, Antero Investment, including its management members, are additionally incentivized to facilitate our growth.

        Although our relationship with Antero and Antero Investment provides us with a significant advantage in the midstream market, it also provides a source of potential conflicts. Antero Investment will own our general partner, which provides Antero Investment with control of our business and may allow Antero Investment to operate our business in a manner inconsistent with the interests of our

 

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unitholders. In addition, Antero Investment will have the right to receive an increasing percentage of our quarterly cash distributions in excess of specified target distribution levels.


Our Management

        Our general partner has sole responsibility for conducting our business and for managing our operations and will be controlled by Antero Investment. Pursuant to the services agreement that we will enter into concurrently with the closing of this offering, our general partner and Antero will be entitled to reimbursement for all direct and indirect expenses that they incur on our behalf. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Principal Components of Our Cost Structure—General and Administrative Expenses" and "Certain Relationships and Related Transactions—Agreements with Affiliates in Connection with the Transactions—Services Agreement."

        Neither our general partner nor its board of directors will be elected by our unitholders. Antero Investment is the sole member of our general partner and will have the right to appoint our general partner's entire board of directors. All of our officers and certain of our directors are also officers and directors of Antero.

 

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Partnership Structure

        In connection with the closing of this offering, Antero will contribute Midstream Operating to us. In connection with that contribution, we will convert from a limited liability company to a limited partnership, Antero Midstream Partners LP. The diagram below illustrates our organizational structure and ownership based on total units outstanding after giving effect to the offering and the related transactions and assumes that the underwriters' option to purchase additional common units is not exercised.

Common Units held by the public

    26.3 %

Common Units held by Antero

    23.7 %

Subordinated Units held by Antero

    50.0 %

General Partner Interest

           *
       

Total

    100 %
       
       

*
General partner interest is non-economic.

GRAPHIC


(1)
Includes each of our Sponsors and certain members of our management team who have made investments in Antero Investment in exchange for investment units.

(2)
Holds profits interests in Antero Investment on behalf of members of our management team and other employees. All of the membership interests in Antero Resources Employee Holdings LLC are held by employees of Antero. The compensation committee of Antero Investment has voting and control rights over the shares held by Antero Resources Employee Holdings LLC.

 

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Emerging Growth Company Status

        We are an "emerging growth company" as defined in the Jumpstart Our Business Startups Act, or the JOBS Act. For as long as we are an "emerging growth company," unlike other public companies, we will not be required to:

    provide an auditor's attestation report on management's assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002;

    comply with any new requirements adopted by the Public Company Accounting Oversight Board, or the PCAOB, requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

    comply with any new audit rules adopted by the PCAOB after April 5, 2012, unless the Securities and Exchange Commission, or the SEC, determines otherwise;

    provide certain disclosure regarding executive compensation required of larger public companies; or

    obtain unitholder approval of any golden parachute payments not previously approved.

        We will cease to be an "emerging growth company" upon the earliest of:

    the last day of the fiscal year in which we have $1.0 billion or more in annual revenues;

    the date on which we become a large accelerated filer;

    the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or

    the last day of the fiscal year following the fifth anniversary of our initial public offering.

        In addition, Section 107 of the JOBS Act provides that an "emerging growth company" can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards, but we intend to irrevocably opt out of the extended transition period.


Risk Factors

        An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. Because of our relationship with Antero, adverse developments or announcements concerning Antero could materially adversely affect our business.

        Below is a summary of certain key risk factors that you should consider in evaluating an investment in our common units. However, this list is not exhaustive. Please read the full discussion of these risks and the other risks described under "Risk Factors" and "Cautionary Statement Regarding Forward-Looking Statements."

Risks Related to Our Business

    Because all of our revenue currently is, and a substantial majority of our revenue over the long term is expected to be, 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.

 

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    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.

    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 that Antero produces or any decrease in the number of wells that Antero completes could adversely affect our business and operating results.

    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.

Risks Inherent in an Investment in Us

    Antero, our general partner and their respective affiliates, including Antero Investment, which will own 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.

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

    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.

    You will experience immediate dilution in tangible net book value of $17.92 per common unit.

    There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, which could cause you to lose all or part of your investment.

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 Internal Revenue Service (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.


Partnership Information

        Our principal executive offices are located at 1615 Wynkoop Street, Denver, Colorado 80202, and our telephone number is (303) 357-7310. Our website is located at www.anteromidstream.com. We expect to make available our periodic reports and other information filed with or furnished to the SEC free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

 

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The Offering

Common units offered to the public

 

40,000,000 common units.

 

 

46,000,000 common units if the underwriters exercise their option to purchase additional common units in full.

 

Units outstanding after this offering

 

75,940,957 common units and 75,940,957 subordinated units, for a total of 151,881,914 limited partner units. If and to the extent the underwriters exercise their option to purchase additional common units, we intend to use the net proceeds resulting from any issuance of common units upon such exercise to acquire an equivalent number of common units from Antero, which common units would be cancelled. Accordingly, the exercise of the underwriters' option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units.

 

Use of proceeds

 

We intend to use the anticipated net proceeds of approximately $946.5 million from this offering, after deducting the estimated underwriting discounts, structuring fees and offering expenses, (i) to pay $1.0 million of financing costs in connection with our new revolving credit facility, (ii) to make a $237.5 million distribution to Antero to reimburse it for certain capital expenditures it incurred in connection with the Predecessor prior to Midstream Operating being contributed to us, (iii) to repay in full $458.0 million of indebtedness that we will assume from Antero in connection with the contribution of Midstream Operating to us by Antero, which indebtedness was incurred by Antero to fund capital expenditures with respect to the Predecessor, and (iv) for general partnership purposes. If and to the extent the underwriters exercise their option to purchase additional common units, we intend to use the net proceeds resulting from any issuance of common units upon such exercise to acquire an equivalent number of common units from Antero, which common units would be cancelled, to reimburse Antero for capital expenditures incurred in connection with the Predecessor prior to Midstream Operating being contributed to us. Accordingly, the exercise of the underwriters' option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read "Use of Proceeds."

 

 

Affiliates of certain of the underwriters are lenders under Midstream Operating's existing midstream credit facility and, accordingly, will receive a portion of the proceeds of this offering. Please read "Underwriting."

 

 

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Cash distributions

 

Within 60 days after the end of each quarter, beginning with the quarter ending December 31, 2014, we expect to make a minimum quarterly distribution of $0.17 per common unit and subordinated unit ($0.68 per common unit and subordinated unit on an annualized basis) to unitholders of record on the applicable record date. For the first quarter that we are publicly traded, we will pay a prorated distribution covering the period from the completion of this offering through December 31, 2014, based on the actual length of that period.

 

 

The board of directors of our general partner will adopt 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 described in more detail in "Our Cash Distribution Policy and Restrictions on Distributions."

 

 

Our partnership agreement generally provides that we will 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
 

 

 

Total Quarterly Distribution
Target Amount

 

Unitholders

 

General Partner
(as holder of
IDRs)

 

  above $0.1955 up to $0.2125     85.0 %   15.0 %

  above $0.2125 up to $0.2550     75.0 %   25.0 %

  above $0.2550     50.0 %   50.0 %

 

We refer to the additional increasing distributions to our general partner as "incentive distributions." Please read "How We Make Distributions to Our Partners—Incentive Distribution Rights."

 

 

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We believe, based on our financial forecast and related assumptions included in "Our Cash Distribution Policy and Restrictions on Distributions," that we will have sufficient cash available for distribution to pay the minimum quarterly distribution of $0.17 on all of our common units and subordinated units for the twelve-month period ending September 30, 2015. However, we do not have a legal or contractual obligation to pay quarterly distributions at the minimum quarterly distribution rate or at any other rate and there is no guarantee that we will pay distributions to our unitholders in any quarter. Please read "Our Cash Distribution Policy and Restrictions on Distributions."

 

Subordinated units

 

Antero will initially own 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 will not be entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

 

Conversion of subordinated 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.

 

 

Notwithstanding the foregoing, the subordination period will end on the first business day after we have earned and paid at least $1.02 (150.0% of the minimum quarterly distribution on an annualized basis) on each outstanding common and subordinated unit and the related distribution on the incentive distribution rights, for any four-quarter period ending on or after September 30, 2015 and there are no outstanding arrearages on our common units.

 

 

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units will thereafter no longer be entitled to arrearages.

 

Issuance of additional units

 

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read "Units Eligible for Future Sale" and "The Partnership Agreement—Issuance of Additional Interests."

 

 

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Limited voting rights

 

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except for cause by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, Antero will own an aggregate of 73.7% of our outstanding units (or 69.7% of our outstanding units, if the underwriters exercise their option to purchase additional common units in full). This will give Antero the ability to prevent the removal of our general partner. In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This will provide Antero the ability to prevent the removal of our general partner. Please read "The Partnership Agreement—Voting Rights."

 

Limited call right

 

If at any time our general partner and its affiliates (including Antero) own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) 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 (2) 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. Please read "The Partnership Agreement—Limited Call Right."

 

Registration rights

 

In connection with the completion of this offering, we intend to enter into a registration rights agreement with Antero, pursuant to which we may be required to register the resale of common units, subordinated units or other partnership securities held by Antero. We may be required pursuant to the registration rights agreement and our partnership agreement to undertake a future public or private offering and use the net proceeds to redeem an equal number of common units from Antero. In addition, our partnership agreement grants certain registration rights to our general partner and its affiliates. Please read "Certain Relationships and Related Transactions—Agreements with Affiliates in Connection with the Transactions—Registration Rights Agreement" and "The Partnership Agreement—Registration Rights."

 

 

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Estimated ratio of taxable income to distributions

 

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2017, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 20% of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $0.68 per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $0.136 per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read "Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership" for the basis of this estimate.

 

Material federal income tax consequences

 

For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read "Material U.S. Federal Income Tax Consequences."

 

Exchange listing

 

Our common units have been approved for listing on the New York Stock Exchange (the "NYSE") under the symbol "AM," subject to official notice of issuance.

 

        The information above excludes 10,000,000 common units reserved for issuance under the Antero Midstream Partners LP Long-Term Incentive Plan (the "Midstream LTIP") that our general partner intends to adopt in connection with the completion of this offering.

 

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Summary Historical and Pro Forma Financial and Operating Data

        We were formed in September 2013 and do not have historical financial statements. Therefore, in this prospectus we present the historical financial statements of our Predecessor. The following table presents summary historical financial data of our Predecessor as of the dates and for the periods indicated.

        This prospectus includes audited financial statements of our Predecessor as of December 31, 2012 and 2013 and for the years ended December 31, 2011, 2012 and 2013 and unaudited financial information of our Predecessor as of and for the six months ended June 30, 2013 and 2014. This prospectus also includes summary pro forma financial data for the year ended December 31, 2013 and as of and for the six months ended June 30, 2014. For a detailed discussion of the summary historical financial information contained in the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table should also be read in conjunction with "Use of Proceeds" and the audited and unaudited historical financial statements of the Predecessor included elsewhere in this prospectus. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

        The summary pro forma financial data presented as of and for the year ended December 31, 2013 and the six months ended June 30, 2014 was derived from the audited and unaudited financial statements of our Predecessor included elsewhere in this prospectus. Please read the unaudited pro forma financial statements and the notes thereto included elsewhere in this prospectus for a description of the pro forma adjustments.

 
  Predecessor   Pro Forma  
 
  Year Ended
December 31,
  Six Months
Ended
June 30,
   
   
 
 
   
  Six Months
Ended
June 30,
2014
 
 
  Year Ended
December 31,
2013
 
 
  2011   2012   2013   2013   2014  
 
  (in thousands, except per unit amounts)
 

Statement of Operations Data:

                                           

Revenue:

                                           

Gathering and compression—affiliate

  $ 441   $ 647   $ 22,363   $ 5,492   $ 28,696   $ 22,363   $ 28,696  
                               

Operating expenses:

                                           

Direct operating expenses

    802     652     2,079     694     2,602     2,079     2,602  

General and administrative expenses (including $15,931 and $3,803 of stock compensation in the year ended December 31, 2013 and the six months ended June 30, 2014, respectively)

    397     2,894     23,124     3,464     10,091     23,124     10,091  

Depreciation expense

    997     1,679     11,346     3,126     14,764     11,346     14,764  
                               

Total operating expenses

    2,196     5,225     36,549     7,284     27,457     36,549     27,457  
                               

Operating income (loss)

    (1,755 )   (4,578 )   (14,186 )   (1,792 )   1,239     (14,186 )   1,239  

Interest expense

    2     8     146     63     1,200     10,575     8,945  
                               

Net income (loss)

  $ (1,757 ) $ (4,586 ) $ (14,332 ) $ (1,855 ) $ 39   $ (24,761 ) $ (7,706 )
                               
                               

Pro forma basic earnings per unit(1)

                                $ (0.16 ) $ (0.05 )

Pro forma diluted earnings per unit(1)

                                $ (0.16 ) $ (0.05 )

 

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  Predecessor   Pro Forma  
 
  Year Ended
December 31,
  Six Months
Ended
June 30,
   
   
 
 
   
  Six Months
Ended
June 30,
2014
 
 
  Year Ended
December 31,
2013
 
 
  2011   2012   2013   2013   2014  
 
  (in thousands, except per unit amounts)
 

Balance Sheet Data (at period end):

                                           

Cash and cash equivalents

        $   $   $   $         $ 250,000  

Property and equipment, net

          173,351     566,476     324,820     844,256           844,256  

Total assets

          173,510     578,089     332,782     898,271           1,149,271  

Long-term liabilities

          320     4,864     5,322     233,574           4,650  

Total net equity—parent net investment

          142,862     532,520     298,926     595,469           1,075,393  

Cash Flow Data:

                                           

Net cash provided by (used in) operating activities

  $ (618 ) $ (3,152 ) $ 10,613   $ 213   $ 17,040              

Net cash used in investing activities

    (15,795 )   (115,571 )   (404,049 )   (163,954 )   (303,564 )            

Net cash provided by financing activities

    16,413     118,723     393,436     163,741     286,524              

Other Financial Data:

                                           

Adjusted EBITDA(2)

  $ (758 ) $ (2,899 ) $ 13,091   $ 1,334   $ 19,806   $ 13,091   $ 19,806  

(1)
Earnings per unit is not provided for historical periods prior to the contribution of Midstream Operating to us because the nature of our Predecessor makes the presentation of earnings per unit not relevant, or comparable on a prospective basis, for investors.

(2)
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.


Operating Data

        The following table presents summary historical operating data of our Predecessor as of the dates and for the periods indicated.

 
  Year Ended
December 31,
  Six Months
Ended
June 30,
 
 
  2011   2012   2013   2013   2014  

Operating Data:

                               

Gathering—low pressure (MMcf)

    1,703     2,320     61,406     15,669     64,935  

Gathering—high pressure (MMcf)

            11,736     918     35,524  

Compression (MMcf)

            9,900     3,409     6,994  

Condensate gathering (MBbl)

                    266  

Gathering—low pressure (MMcf/d)

   
5
   
6
   
168
   
87
   
359
 

Gathering—high pressure (MMcf/d)

            32     5     196  

Compression (MMcf/d)

            27     19     39  

Condensate gathering (MBbl/d)

                    1  

Average realized fees:

   
 
   
 
   
 
   
 
   
 
 

Average gathering—low pressure fee ($/Mcf)

  $ 0.26   $ 0.28   $ 0.30   $ 0.30   $ 0.31  

Average gathering—high pressure fee ($/Mcf)

          $ 0.18   $ 0.18   $ 0.18  

Average compression fee ($/Mcf)

          $ 0.18   $ 0.18   $ 0.18  

Average gathering—condensate fee ($/Bbl)

                  $ 4.08  

 

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Non-GAAP Financial Measure

        We use Adjusted EBITDA as a performance measure to assess the ability of our assets to generate cash sufficient to pay interest costs, support indebtedness and make cash distributions. We expect that Adjusted EBITDA will be a financial measure reported to our lenders and used as a gauge for compliance with some of the financial covenants that we expect to be included in our new revolving credit facility. We define Adjusted EBITDA as net income (loss) before stock compensation expense, interest expense, income taxes and depreciation and amortization expense.

        We use Adjusted EBITDA to assess:

    the financial performance of our assets, without regard to financing methods, 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 companies in the midstream energy sector, without regard to financing or capital structure; and

    the viability of acquisitions and capital expenditure projects.

        Adjusted EBITDA is a non-GAAP financial measure. The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by (used in) operating activities. The non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to the GAAP measure of net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool because it includes some, but not all, items that affect net income. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of results as reported under GAAP. Our and our Predecessor's definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

        The following table represents a reconciliation of our Adjusted EBITDA to its most directly comparable GAAP financial measures for the periods presented:

 
  Predecessor    
   
 
 
  Pro Forma  
 
  Year Ended
December 31,
  Six Months Ended
June 30,
 
 
   
  Six Months
Ended
June 30,
2014
 
 
  Year Ended
December 31,
2013
 
 
  2011   2012   2013   2013   2014  
 
  ($ in thousands)
 

Net income (loss)

  $ (1,757 ) $ (4,586 ) $ (14,332 ) $ (1,855 ) $ 39   $ (24,761 ) $ (7,706 )

Add:

                                           

Interest expense

    2     8     146     63     1,200     10,575     8,945  

Income tax expense

                             

Depreciation expense

    997     1,679     11,346     3,126     14,764     11,346     14,764  

Stock compensation expense

            15,931         3,803     15,931     3,803  
                               

Adjusted EBITDA

  $ (758 ) $ (2,899 ) $ 13,091   $ 1,334   $ 19,806   $ 13,091   $ 19,806  
                               

Less:

                                           

Interest expense

    (2 )   (8 )   (146 )   (63 )   (1,200 )            

Changes in operating assets and liabilities which used (provided) cash

    142     (245 )   (2,332 )   (1,058 )   (1,566 )            
                                   

Net cash provided by (used in) operating activities

  $ (618 ) $ (3,152 ) $ 10,613   $ 213   $ 17,040              
                                   
                                   

 

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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. In that case, we may not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.


Risks Related to Our Business

Because all of our revenue currently is, and a substantial majority of our revenue over the long term is expected to be, 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 our only current 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;

    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;

    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.

        Further, we are subject to the risk of non-payment or non-performance by Antero, including with respect to our gathering and compression agreement. We cannot predict the extent to which Antero's business would be impacted if conditions in the energy industry were to deteriorate, nor can we estimate the impact such conditions would have on Antero's ability to execute its drilling and development program or perform under our gathering and compression agreement. 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.

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        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 $25.8 million per quarter, or approximately $103.3 million per year, based on the common units and subordinated units outstanding immediately after completion of this offering. 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 natural gas we gather and compress;

    the volume of condensate we gather;

    the rates we charge third parties, if any, for our 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;

    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 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;

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    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.

On a pro forma basis, we would not have had sufficient cash available for distribution to pay any distributions on our common units or subordinated units for the year ended December 31, 2013 or the twelve-month period ended June 30, 2014.

        Our pro forma cash available for distribution for the year ended December 31, 2013 would have been a deficit of approximately $1.3 million, which would not have been sufficient to pay any distributions on our common units or subordinated units. Our pro forma cash available for distribution for the twelve-month period ended June 30, 2014 would have been a deficit of approximately $0.7 million, which would not have been sufficient to pay any distributions on our common units or subordinated units. For a calculation of our ability to make cash distributions to our unitholders based on our historical as adjusted results, please read "Our Cash Distribution Policy and Restrictions on Distributions." If we are not able to generate additional cash for distribution to our unitholders in future periods, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.

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 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 activity or otherwise ceases to drill and complete wells, revenues for our gathering and compression services will be directly and adversely affected. 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.

        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. 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;

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    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. Antero could elect to reduce its drilling and completion activity if commodity prices decrease. Declines in commodity prices could have a negative impact on Antero, development and production activity, and if sustained, could lead to a material decrease in such activity. 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 may choose not to develop those reserves. If reductions in development activity result in our inability to maintain the current levels of throughput on our systems, those reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

The assumptions underlying the forecast of cash available for distribution, as set forth in "Our Cash Distribution Policy and Restrictions on Distributions," are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

        The forecast of cash available for distribution set forth in "Our Cash Distribution Policy and Restrictions on Distributions" includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve-month period ending September 30, 2015. Our ability to pay the full minimum quarterly distribution in the forecast period is based on a number of assumptions that may not prove to be correct and that are discussed in "Our Cash Distribution Policy and Restrictions on Distributions." Management has prepared the financial forecast and has not received an opinion or report on it from our or any other independent auditor. The assumptions and estimates underlying the forecast are substantially driven by Antero's anticipated drilling and completion schedule and, although we consider our assumptions as to Antero's ability to maintain that schedule reasonable as of the date of this prospectus, those estimates and Antero's ability to achieve anticipated drilling and production targets are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the forecast. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

The gathering and compression agreement only includes minimum volume commitments under certain circumstances.

        The gathering and compression agreement includes minimum volumes commitments only on new high-pressure pipelines and compressor stations that we construct at Antero's request. Our existing compressor stations, 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, 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, all of our revenues were earned from Antero. Our ability to increase throughput on our gathering and compression systems and any related revenue from third parties is subject to numerous factors beyond our control, including competition from third

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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 NGL 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 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 option to purchase Antero's fresh water distribution systems, our right-of-first-offer agreement with Antero for gas processing services and our rights to participate in the ET Pipeline and Regional Gathering System are subject to risks and uncertainty, and thus may not enhance our ability to grow our business.

        Antero has granted us an option to purchase its fresh water distribution systems at fair market value. In addition, pursuant to our right-of-first-offer agreement, 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. The development of gas processing infrastructure in connection with the exercise of our right-of-first-offer will depend upon, among other things, our ability to obtain financing on acceptable terms for the construction of such facilities and our ability to provide such services on the same or better terms than third parties. We can offer no assurance that we will be able to successfully develop processing infrastructure pursuant to these rights.

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Additionally, Antero is under no obligation to accept any offer made by us. Furthermore, for a variety of reasons, we may decide not to exercise these rights when they become available.

        Antero has an option to participate for up to a 20% non-operating equity interest in the ET Rover Pipeline that it will assign to us in connection with the completion of this offering. Antero also has a right to participate for up to a 15% non-operating equity interest in the Regional Gathering System that will expire six months following the date on which the Regional Gathering System is placed into service, which is currently scheduled to occur during the fourth quarter of 2015. Antero intends to assign the option to us in connection with the completion of this offering. Subject to confirmatory diligence, we have not determined to what extent, if any, we would exercise these options. We can offer no assurance that our participation in the ET Rover Pipeline and the Regional Gathering System, if we exercise these options, will enhance our cash flows or ability to pay distributions.

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.

Our construction or purchase of new gathering and compression, processing or other assets 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 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, if we build a processing facility, the construction may occur over an extended period of time, and we may 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 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

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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 to commodity price risk. Future exposure to the volatility of natural gas, NGL and oil prices 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 new revolving credit facility could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

        We expect to enter into a new revolving credit facility in connection with the closing of this offering. Our new revolving credit facility is expected to limit 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 new revolving credit facility also is expected to contain 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.

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        The provisions of our new 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 new 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."

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of such assets, which may cause our revenues to decline and our operating expenses to increase.

        Our gathering and transportation operations are exempt from regulation by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or NGA. Section 1(b) of the NGA, exempts natural gas gathering facilities from regulation by 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 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 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 Natural Gas Policy Act of 1978, or 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.

        Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. 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, may 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. 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.

        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.

        For more information regarding federal and state regulation of our operations, please read "Business—Regulation of Operations."

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Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas, NGLs and oil production by our customers, which could reduce the throughput on our gathering and compression systems, 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, various studies are currently underway by the U.S. Environmental Protection Agency, or 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 move through our gathering systems, which in turn could materially adversely affect our revenues 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 numerous 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.

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        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.

Climate change laws and regulations restricting emissions of "greenhouse gases" 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.

        In response to findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources that are already potential sources of conventional pollutants. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the U.S. on an annual basis. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. In any event, the Obama administration announced its Climate Action Plan in 2013, which, among other things, directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and gas industry. As part of the Climate Action Plan, the Obama Administration also announced that it intends to adopt additional regulations to reduce emissions of GHGs and to encourage greater use of low carbon technologies in the coming years. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the natural gas we gather. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may

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produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair or preventative or remedial measures.

        The United States Department of Transportation, 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, increases the maximum civil penalty for pipeline safety violations and directs 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. In September 2013, the Pipelines and Hazardous Materials Safety Administration, or PHMSA, finalized rules consistent with the signed act that increased the maximum administrative civil penalties for violations of the pipeline safety laws and regulations that occur after January 2012 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 has also published advanced notices of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to extend the integrity management requirements to additional types of facilities pipelines, such as gathering pipelines and related facilities. Additionally, in 2012, PHMSA issued an advisory bulletin providing guidance on the verification of records related to pipeline maximum allowable operating pressure, which could result in additional requirements for the pressure testing of pipelines or the reduction of maximum operating pressures. 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.

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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.

        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. 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.

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

        We depend on the services of a relatively small group of our general partner's senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our general partner's senior management or technical personnel, including Paul M. Rady, Chairman and Chief Executive Officer, and Glen C. Warren, Jr., President 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.

Increases in interest rates could adversely affect our business.

        We will have significant exposure to increases in interest rates. After the consummation of this offering on a pro forma basis, we do not expect to have any outstanding indebtedness. However, in connection with the completion of this offering we expect to enter into a new revolving credit facility. Assuming estimated average indebtedness of $122.0 million during the twelve-month period ending September 30, 2015, comprised of funds drawn on our new revolving credit facility, an increase of one percentage point in the assumed interest rate will result in an increase in annual interest expense of

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$1.2 million. As a result, our results of operations, cash flows and financial condition and, as a result, our ability to make cash distributions to our unitholders, could be materially adversely affected by significant increases in interest rates.

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 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 Investment, which will own 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.

        Following this offering, Antero Investment will indirectly own and control our general partner and will appoint all of the officers and directors of our general partner. All of our initial officers and a majority of our initial directors will also be officers or directors of Antero Investment. Similarly, all of our officers and a majority of our directors 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 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;

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    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. Please read "How We Make Distributions to Our Partners—Capital Expenditures" for a discussion on when a capital expenditure constitutes a maintenance capital expenditure or an expansion capital expenditure. 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. Please read "How We Make Distributions to Our Partners—Subordination Period";

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

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

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

    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.

        Please read "Conflicts of Interest and Fiduciary Duties."

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Ongoing cost reimbursements due to our general partner and its affiliates for services provided, which will be 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 will reimburse our general partner and its affiliates for all expenses they incur on our behalf. These expenses will 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 will determine the expenses that are allocable to us in good faith. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

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

        We plan to distribute most of our cash available for distribution, which may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. In addition, the incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the cash that we have available to distribute to our unitholders.

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

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

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

        By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above. Please read "Conflicts of Interest and Fiduciary Duties—Duties."

Our partnership agreement will designate 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 would limit 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 will provide 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. By purchasing a common unit, a limited partner is irrevocably consenting 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. For additional information about the exclusive forum provision of our partnership agreement, please read "The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction." For additional information about the potential obligation to reimburse us for all fees, costs and expenses incurred in connection with claims, suits, actions or proceedings initiated by a unitholder that are not successful, please read "The Partnership Agreement—Reimbursement of Partnership Litigation Costs."

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 "Management—Management of Antero Midstream Partners LP" and "Certain Relationships and Related Transactions." Unlike publicly-traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of

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stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

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

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

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. Please read "How We Make Distributions to Our Partners—General Partner's Right to Reset Incentive Distribution Levels."

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

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

        Unitholders' voting rights are further restricted by the partnership agreement provision providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates (including Antero), 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.

You will experience immediate dilution in tangible net book value of $17.92 per common unit.

        The initial public offering price of $25.00 per unit exceeds our pro forma net tangible book value of $7.08 per unit. Based on the initial public offering price of $25.00 per unit, you will incur immediate and substantial dilution of $17.92 per common unit after giving effect to the offering of common units and the application of the related net proceeds. Dilution results primarily because the assets being contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost and not their fair value. Please read "Dilution."

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We may issue additional units, including units that are senior to the common units, without your approval, which would dilute your 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.

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

        In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may, among other adverse effects: (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

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.

        After the sale of the common units offered hereby, Antero will hold 35,940,957 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 same of 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.

        Prior to the completion of this offering, we intend to file a registration statement on Form S-8 under the Securities Act to register 10,000,000 common units issuable under the Midstream LTIP. Subject to applicable vesting requirements, Rule 144 limitations applicable to affiliates and the expiration of lock-up agreements, common units registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

        Future sales of common units in public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop. Please read "Units Eligible for Future Sale."

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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 affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (i) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, or the Exchange Act. Upon consummation of this offering, and assuming the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates (including Antero) will own an aggregate of 47.3% of our common and all of our subordinated units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), our general partner and its affiliates will own 73.7% of our common units. For additional information about the limited call right, please read "The Partnership Agreement—Limited Call Right."

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 will initially 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.

        For a discussion of the implications of the limitations of liability on a unitholder, please read "The Partnership Agreement—Limited Liability."

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

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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.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, which could cause you to lose all or part of your investment.

        Prior to this offering, there has been no public market for the common units. After this offering, there will be only 40,000,000 publicly-traded common units (assuming no exercise of the underwriters' over-allotment option). In addition, Antero, an affiliate of our general partner, will own 35,940,957 common units and 75,940,957 subordinated units, representing an aggregate approximately 73.7% limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, a lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

        The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be 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 after the consummation of this offering 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.

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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.

For as long as we are an "emerging growth company," we will not be required to comply with certain disclosure requirements that apply to other public companies.

        We are classified as an "emerging growth company" under the JOBS Act. For as long as we are an "emerging growth company," which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor's attestation report on management's assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) provide certain disclosure regarding executive compensation required of larger public companies or (4) hold nonbinding advisory votes on executive compensation. We will remain an "emerging growth company" for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, become a large accelerated filer or issue more than $1.0 billion of non-convertible debt over a three-year period.

        To the extent that we rely on any of the exemptions available to "emerging growth companies", you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not "emerging growth companies." If some investors find our common units to be less attractive as a result, there may be a less active trading market for our common units and our trading price may be more volatile.

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 have been approved for listing on the NYSE under the symbol "AM," subject to official notice of issuance. Because we will be 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 will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read "Management—Management of Antero Midstream Partners LP."

We will incur increased costs as a result of being a publicly-traded partnership.

        We have no history operating as a publicly-traded partnership. As a publicly-traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. 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 of being a publicly-traded partnership. As a result, the amount of cash we have available for distribution to our unitholders will be affected by the costs associated with being a publicly-traded partnership.

        Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become 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

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on internal controls over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements.

        We also expect to incur significant expense in order to obtain 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.

        We estimate that we will incur approximately $2.5 million of incremental costs per year associated with being a publicly-traded partnership; however, it is possible that our actual incremental costs of being a publicly-traded partnership will be higher than we currently estimate.


Tax Risks to Common Unitholders

        In addition to reading the following risk factors, you should read "Material U.S. Federal Income Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

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. While we have requested a ruling from the IRS as to whether 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 will initially 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.

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

        The present U.S. federal income tax treatment of publicly-traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. 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. We are unable to predict whether any of these changes, or other proposals, will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. For a discussion of the importance of our treatment as a partnership for federal income purposes, please read "Material U.S. Federal Income Tax Consequences—Taxation of the Partnership—Partnership Status" for a further discussion.

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.

        The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with some or all of our counsel's conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

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 will be 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.

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. Please read "Material U.S. Federal Income Tax Consequences—Disposition of Units—Recognition of Gain or Loss" for a further discussion of the foregoing.

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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. Please read "Material U.S. Federal Income Tax Consequences—Tax Exempt Organizations and Other Investors."

We will 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 will adopt 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. Please read "Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction—Section 754 Election" for a further discussion of the effect of the depreciation and amortization positions we adopted.

We will 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 will 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 use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. The U.S. Treasury Department has issued proposed Treasury regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed 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. Please read "Material U.S. Federal Income Tax Consequences—Disposition of Units—Allocations Between Transferors and Transferees."

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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 may adopt certain valuation methodologies that could result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

        When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

        A successful IRS challenge to these methods or allocations could adversely affect the amount 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. Immediately following this offering, Antero will own 73.7% 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

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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. Please read "Material U.S. Federal Income Tax Consequences—Disposition of Units—Constructive Termination" for a discussion of the consequences of our termination for federal income tax purposes.

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 will initially 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.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

        Some of the information in this prospectus 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 prospectus. 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's inability to meet its drilling and development plan;

    business strategy;

    realized natural gas, 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 prospectus 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 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 prospectus.

        Should one or more of the risks or uncertainties described in this prospectus 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 prospectus 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 prospectus.

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USE OF PROCEEDS

        We intend to use the anticipated net proceeds of approximately $946.5 million from this offering, after deducting the estimated underwriting discounts, structuring fees and offering expenses, (i) to pay $1.0 million of financing costs in connection with our new revolving credit facility, (ii) to make a $237.5 million distribution to Antero to reimburse it for certain capital expenditures it incurred in connection with the Predecessor prior to Midstream Operating being contributed to us, (iii) to repay in full $458.0 million of indebtedness that we will assume from Antero in connection with the contribution of Midstream Operating to us by Antero, which indebtedness was incurred by Antero to fund capital expenditures with respect to the Predecessor and (iv) for general partnership purposes.

        The following table illustrates our anticipated use of the proceeds of this offering:

Sources of Funds (in millions)   Uses of Funds (in millions)  

Gross proceeds from this offering

  $ 1,000.0  

Payment of financing costs in connection with our new revolving credit facility

  $ 1.0  

       

Distribution to Antero

  $ 237.5  

       

Repayment of indebtedness assumed in connection with contribution to us of Midstream Operating

  $ 458.0  

       

General partnership purposes

  $ 250.0  

       

Estimated underwriting discounts, structuring fees and offering expenses

  $ 53.5  
               

Total

  $ 1,000.0       $ 1,000.0  
               
               

        The indebtedness that we will assume will have been incurred under Midstream Operating's existing midstream credit facility to fund capital expenditures incurred with respect to the Predecessor. As of June 30, 2014, there was approximately $320.0 million of outstanding borrowings under the existing midstream credit facility, which matures on the earlier of May 12, 2016 or the consummation of a Qualified IPO (as defined in the credit facility agreement which would include this offering) and bears interest at a variable rate, which was approximately 1.94% as of June 30, 2014. Of the outstanding balance, $228.9 million was related to the gathering and compression assets. The borrowings to be repaid were incurred to fund the development of the Predecessor. In addition, we expect to enter into a new revolving credit facility in connection with the closing of this offering.

        If and to the extent the underwriters exercise their option to purchase additional common units, we intend to use the net proceeds resulting from any issuance of common units upon such exercise to acquire an equivalent number of common units from Antero, which common units would be cancelled, to reimburse Antero for capital expenditures incurred in connection with the Predecessor prior to Midstream Operating being contributed to us. Accordingly, the exercise of the underwriters' option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read "Underwriting."

        Affiliates of certain of the underwriters are lenders under Midstream Operating's existing midstream credit facility and, accordingly, will receive a portion of the proceeds of this offering. Please read "Underwriting."

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CAPITALIZATION

        The following table shows our capitalization as of June 30, 2014:

    on an actual basis for our Predecessor;

    on a pro forma basis to reflect the issuance and sale of our common units in this offering, the application of the net proceeds from this offering as described under "Use of Proceeds," and the other transactions that will occur in connection with the completion of this offering.

        This table is derived from, and should be read together with, the audited historical financial statements of our Predecessor and the unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with "Summary—Partnership Structure," "Use of Proceeds" and "Management's Discussion and Analysis of Financial Condition and Results of Operations."

 
  As of June 30, 2014  
 
  Predecessor   Antero
Midstream
Partners LP
 
 
  Actual   Pro Forma  
 
  (in thousands)
 

Cash and cash equivalents

  $   $ 250,000  
           
           

Long-term debt:

             

Existing midstream credit facility(1)

  $ 228,924   $  

New revolving credit facility(2)

         
           

Total long-term debt

    228,924      

Total net equity-parent net investment/partners' capital:

             

Total net equity—parent net investment

    595,469      

Common units—public

        946,500  

Common units—Antero

        41,406  

Subordinated units—Antero

        87,487  

General partner interest(3)

         
           

Total partners' capital

    595,469     1,075,393  
           

Total capitalization

  $ 824,393   $ 1,075,393  
           
           

(1)
Midstream Operating entered into a midstream credit facility on February 28, 2014, which was amended on May 5, 2014. Borrowings under the midstream credit facility are limited to an aggregate of $500.0 million and aggregate lender commitments under the facility are $500.0 million. In connection with the completion of this offering, we will use a portion of the proceeds to repay all $458.0 million of the indebtedness that we will assume from Antero under the existing midstream credit facility, which indebtedness was incurred by Antero to fund capital expenditures with respect to the Predecessor. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Debt Agreements and Contractual Obligations."

(2)
In connection with the completion of this offering, we expect to enter into a new revolving credit facility. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Debt Agreements and Contractual Obligations."

(3)
Our general partner owns a non-economic general partner interest in us.

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DILUTION

        Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per common unit after the offering. On a pro forma basis as of June 30, 2014, after giving effect to the offering of common units, the contribution of Midstream Operating to us and the related transactions, our net tangible book value would have been approximately $1,075.4 million, or $7.08 per common unit. Purchasers of our common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.

Initial public offering price per common unit

        $ 25.00  

Predecessor net tangible book value per common unit before the offering(1)

  $ 5.32        

Increase in net tangible book value per common unit attributable to purchasers in the offering

    4.83        

Decrease in net tangible book value per common unit attributable to the distribution to Antero

    (3.07 )      
             

Less: Pro forma net tangible book value per common unit after the offering(2)

          7.08  
             

Immediate dilution in net tangible book value per common unit to purchasers in the offering(3)

        $ 17.92  
             
             

(1)
Determined by dividing our Predecessor's net tangible book value by the number of units (35,940,957 common units and 75,940,957 subordinated units) to be issued to Antero for its contribution of assets and liabilities to us.

(2)
Determined by dividing our pro forma net tangible book value, after giving effect to the use of the net proceeds of the offering, by the total number of units (75,940,957 common units and 75,940,957 subordinated units) to be outstanding after the offering.

(3)
Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters' option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the option.

        The following table sets forth the number of units that we will issue and the total consideration contributed to us by Antero and by the purchasers of our common units in this offering upon consummation of the transactions contemplated by this prospectus. The following table excludes common units reserved for issuance under the Midstream LTIP.

 
  Units   Total
Consideration
 
 
  Number   Percent   Amount   Percent  

Antero(1)(2)(3)

    111,881,914     73.7 % $ 128,893,000 (4)   11.4 %

Purchasers in the offering

    40,000,000     26.3 %   1,000,000,000     88.6 %
                   

Total

    151,881,914     100 % $ 1,128,893,000     100 %
                   
                   

(1)
Upon the consummation of the transactions contemplated by this prospectus, Antero will own 35,940,957 common units and 75,940,957 subordinated units.

(2)
The contributed assets will be recorded at historical cost. The pro forma book value of the consideration provided by Antero as of June 30, 2014 would have been approximately $595,469,000.

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(3)
Assumes the underwriters' option to purchase additional common units is not exercised.

(4)
Reflects the distribution, on a pro forma basis, of $466.6 million of the net proceeds of this offering to Antero as reimbursement for certain capital expenditures it incurred with respect to the Predecessor prior to Midstream Operating being contributed to us.

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

        You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. In addition, you should read "Cautionary Statement Regarding Forward-Looking Statements" and "Risk Factors" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

        For additional information regarding our historical results of operations, you should refer to our Predecessor's audited financial statements and the related notes to those financial statements as of December 31, 2012 and 2013 and for the years ended December 31, 2011, 2012 and 2013 and the unaudited financial information of our Predecessor as of and for the six months ended June 30, 2013 and 2014. For additional information regarding our pro forma results of operations, you should refer to our pro forma financial statements and the related notes to those financial statements as of and for the year ended December 31, 2013.


General

Our Cash Distribution Policy

        The board of directors of our general partner will adopt 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. Furthermore, we expect that if we are successful in executing our business strategy, we will grow our business in a steady and sustainable manner and distribute to our unitholders a portion of any increase in our cash available for distribution resulting from such growth.

        Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing rather than retaining our cash available for distribution. Because we believe we will generally finance any expansion capital expenditures from external financing sources, including borrowings under our new revolving credit facility and the issuance of debt and equity securities, we believe that our investors are best served by distributing all of our available cash. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case were we subject to tax.

        The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or any other basis.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

        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 is subject to certain restrictions and may be changed at any time.

        The reasons for such uncertainties in our stated cash distribution policy include the following factors:

    Our cash distribution policy will be subject to restrictions on cash distributions under our new revolving credit facility, which is expected to contain financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions or if we are otherwise in default under our new revolving credit facility, we will be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy.

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    Our general partner will have the authority to establish cash reserves for the prudent conduct of our business, including for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish.

    Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates (including Antero) for all direct and indirect expenses they incur on our behalf. 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 see the notes to the pro forma financial statements included elsewhere in this prospectus for a description of the methodology behind how general and administrative expenses are allocated to us. Our obligations to reimburse our general partner and its affiliates are governed by our partnership agreement and the services agreement that we expect to enter into with our general partner and Antero. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available to pay distributions to our unitholders.

    Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner.

    Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

    We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to common unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase.

    If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels. Please read "How We Make Distributions to Our Partners—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels." We do not anticipate that we will make any distributions from capital surplus.

    If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly cash distributions in order to service or repay our debt or fund expansion capital expenditures.

Our Ability to Grow may be Dependent on Our Ability to Access External Financing Sources

        We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after the establishment of cash reserves and payment of our expenses. Therefore, our growth may not be as fast as businesses that reinvest most or all of their cash to expand ongoing operations. Moreover, our future growth may be slower than our historical growth. We expect that we will rely primarily upon external financing sources, including borrowings under our new revolving credit facility and issuances of debt and equity securities, to fund our expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

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Our Minimum Quarterly Distribution

        Upon the consummation of this offering, our partnership agreement will provide for a minimum quarterly distribution of $0.17 per unit for each whole quarter, or $0.68 per unit on an annualized basis. The payment of the full minimum quarterly distribution on all of the common units and subordinated units to be outstanding after completion of this offering would require us to have cash available for distribution of approximately $25.8 million per quarter, or $103.3 million per year. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under "—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy."

        The table below sets forth the amount of common units and subordinated units that will be outstanding immediately after this offering, assuming the underwriters do not exercise their option to purchase additional common units, and the cash available for distribution needed to pay the aggregate minimum quarterly distribution on all of such units for a single fiscal quarter and a four quarter period:

 
   
  Minimum
Quarterly Distributions
 
 
  Number of Units   One Quarter   Annualized  

Common units held by the public(1)

    40,000,000   $ 6,800,000   $ 27,200,000  

Common units held by Antero(1)

    35,940,957     6,109,963     24,439,851  

Subordinated units held by Antero

    75,940,957     12,909,963     51,639,851  
               

Total

    151,881,914   $ 25,819,926   $ 103,279,702  
               
               

(1)
Assumes no exercise of the underwriters' option to purchase additional common units. Please read "Summary—The Offering—Use of Proceeds" for a description of the impact of an exercise of the option on the common unit ownership.

        Because our general partner's interest in us entitles it to control us without a right to any percentage of our distributions, our general partner will not receive ongoing distributions in respect of its general partner interest. However, our general partner will also hold the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 50.0%, of the cash we distribute in excess of $1.02 per unit per quarter.

        We expect to pay our distributions on or about the last day of each of February, May, August and November to holders of record on or about the 15th day of each such month. We will adjust the quarterly distribution for the period after the closing of this offering through December 31, 2014, based on the actual length of the period.


Subordinated Units

        Antero will initially own 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.

        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. Please read "How We Make Distributions to Our Partners—Subordination Period."

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        In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $0.68 per unit for the twelve-month period ending September 30, 2015. In those sections, we present two tables, consisting of:

    "Unaudited Pro Forma Cash Available for Distribution for the Twelve-Month Period Ended June 30, 2014," in which we present the amount of cash we would have had available for distribution on a pro forma basis for the twelve-month period ended June 30, 2014, derived from our unaudited pro forma financial data that are included in this prospectus, as adjusted to give pro forma effect to this offering and the related formation transactions; and

    "Estimated Cash Available for Distribution for the Twelve-Month Period Ending September 30, 2015," in which we demonstrate our ability to generate sufficient cash available for distribution for us to pay the minimum quarterly distribution on all units for the twelve-month period ending September 30, 2015.


Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and the Twelve-Month Period Ended June 30, 2014

Overview

        If we had completed this offering and the related transactions on January 1, 2013, our unaudited pro forma cash available for distribution for the year ended December 31, 2013 would have been a deficit of approximately $1.3 million. If we had completed this offering and the related transactions on July 1, 2013, our unaudited pro forma cash available for distribution for the twelve-month period ended June 30, 2014 would have been a deficit of approximately $0.7 million. These amounts would not have been sufficient to pay any distribution on our common units or subordinated units.

        Our unaudited pro forma available cash for the twelve-month period ended June 30, 2014 includes $10.0 million of general and administrative expenses, including an incremental $2.5 million of general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership, and excludes $19.7 million of stock compensation expense allocated to us by Antero. Incremental general and administrative expenses related to being a publicly traded partnership include: expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance expenses; and director compensation. These expenses are not reflected in the historical financial statements of our Predecessor or our unaudited pro forma financial statements included elsewhere in the prospectus.

Unaudited Pro Forma Cash Available for Distribution

        We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had this offering and related formation transactions been completed as of the date indicated. In addition, cash available for distribution is primarily a cash accounting concept, while the historical financial statements of our Predecessor and our unaudited pro forma financial statements included elsewhere in the prospectus have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available for distribution only as a general indication of the amount of cash available for distributions that we might have generated had we completed this offering on the date indicated. The pro forma amounts below are presented on a twelve-month basis, and we would not have had available cash sufficient to pay any distribution on our outstanding common units for each quarter within the twelve-month period presented. Our unaudited pro forma cash available for distribution should be read together with "Selected Historical and Pro Forma Financial and Operating Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and

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the audited historical financial statements of the Predecessor and the notes to those statements included elsewhere in this prospectus.

        The following table illustrates, on a pro forma basis, for the twelve-month period ended June 30, 2014, the amount of cash that would have been available for distribution to our unitholders, assuming that this offering and the related formation transactions had been completed on January 1, 2013. Each of the adjustments reflected or presented below is explained in the footnotes to such adjustments.


Antero Midstream Partners LP
Unaudited Pro Forma Cash Available for Distribution

 
  Year Ended
December 31, 2013
(In millions)
  Twelve-Month
Period Ended
June 30, 2014
(In millions)
 

Operating Revenues:

             

Gathering and compression—affiliate

  $ 22.4   $ 45.6  

Operating Expenses:

             

Operating and maintenance

    2.1     4.0  

General and administrative (including $15.9 and $19.7 million of stock compensation in the year ended December 31, 2013 and the twelve-month period ended June 30, 2014, respectively)(1)

    23.1     29.7  

Depreciation

    11.3     23.0  
           

Total Operating Expenses

    36.5     56.7  
           

Operating (Loss)

    (14.1 )   (11.1 )

Interest expense(2)

    (10.6 )   (15.3 )
           

Pro Forma Net (Loss):

    (24.7 )   (26.4 )
           

Add:

             

Depreciation

    11.3     23.0  

Interest expense(2)

    10.6     15.3  

Non-cash stock compensation expense

    15.9     19.7  
           

Pro Forma Adjusted EBITDA(3)

    13.1     31.6  
           

Less:

             

Cash interest expense(4)

    (10.6 )   (15.1 )

Expansion capital expenditures(5)

    (394.2 )   (489.3 )

Maintenance capital expenditures(6)

    (1.3 )   (14.7 )

Incremental public partnership general and administrative expenses(7)          

    (2.5 )   (2.5 )

Add:

             

Contributions from parent to fund expansion capital expenditures

    394.2     489.3  
           

Pro Forma Cash Available for Distribution

  $ (1.3 ) $ (0.7 )
           
           

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  Year Ended
December 31, 2013
(In millions, except
per unit data)
  Twelve-Month
Period Ended
June 30, 2014
(In millions, except
per unit data)
 

Pro Forma Cash Distributions:

             

Distribution per unit (based on a minimum quarterly distribution rate of $0.17 per unit)

  $ 0.68   $ 0.68  

Aggregate distributions to:

             

Common units held by the public

  $ 27.2   $ 27.2  

Common units held by Antero

    24.4     24.4  

Subordinated units held by Antero

    51.6     51.6  

Total distributions to Antero

    76.1     76.1  
           

Total Distributions

  $ 103.3   $ 103.3  
           
           

Excess (Shortfall)

  $ (104.6 ) $ (104.0 )
           
           

Percent of minimum quarterly distribution payable to common unitholders

    %   %
           
           

Percent of minimum quarterly distribution payable to subordinated unitholders

    %   %
           
           

(1)
Comprised of general and administrative expenses allocated to us by Antero.

(2)
Interest expense includes assumed commitment fees on, and the amortization of assumed origination fees incurred in connection with, our new revolving credit facility.

(3)
We define Adjusted EBITDA as net income (loss) before stock compensation expense, interest expense, income taxes and depreciation and amortization expense. Please read "Summary—Non-GAAP Financial Measure."

(4)
Cash interest expense includes assumed commitment fees on our new revolving credit facility. Cash interest on borrowings to fund capital expenditures assumes that the borrowings were incurred ratably over the twelve-month period ended June 30, 2014.

(5)
Expansion capital expenditures are 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. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines and compressor stations, in each case to the extent such capital expenditures are expected to expand our operating capacity or revenue. Antero recently constructed a significant portion of the midstream assets that will be contributed to us, which is reflected in the amount of the expansion capital expenditures for the twelve-month period ended June 30, 2014.

(6)
Maintenance capital expenditures are 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. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain gathering and compression throughput, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

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(7)
Comprised of $2.5 million of general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership, such as costs associated with: annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance expenses; and director compensation.


Estimated Cash Available for Distribution for the Twelve-Month Period Ending September 30, 2015

        We forecast that our estimated cash available for distribution during the twelve-month period ending September 30, 2015 will be approximately $118.8 million. This amount represents an increase of $120.1 million and $119.5 million from the pro forma cash available for distribution for the year ended December 31, 2013 and the twelve-month period ended June 30, 2014, respectively. This amount would exceed by $15.5 million the amount needed to pay the minimum quarterly distribution of $0.17 per unit on all of our common and subordinated units for the twelve-month period ending September 30, 2015. As explained below, this substantial increase in cash available for distribution is driven by the substantial increase in demand for our gathering and compression services as Antero executes is drilling program.

        We are providing the forecast of estimated cash available for distribution to supplement our historical financial statements and our unaudited pro forma financial statements included elsewhere in this prospectus in support of our belief that we will have sufficient cash available to allow us to pay cash distributions at the minimum quarterly distribution rate on all of our units for the twelve-month period ending September 30, 2015. To the extent we have distributable cash flow in excess of our quarterly distributions in the twelve-month period ending September 30, 2015, we expect that our general partner will reserve such excess amount. However, during the twelve-month period ending September 30, 2015, we expect that our general partner will not reserve amounts that impair our ability to pay our minimum quarterly distribution. Please read "—Assumptions and Considerations" for further information as to the assumptions we have made for the forecast. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Our Critical Accounting Policies and Estimates" for information as to the accounting policies we have followed for the financial forecast.

        Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve-month period ending September 30, 2015. We believe that our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. If our estimates are not achieved, we may not be able to pay the minimum quarterly distribution or any other distribution on our common units. The assumptions and estimates underlying the forecast are substantially driven by Antero's anticipated drilling and completion schedule and, although we consider our assumptions as to Antero's ability to maintain that schedule reasonable as of the date of this prospectus, those estimates and Antero's ability to achieve anticipated drilling and production targets are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the forecast, including, among others, risks and uncertainties contained in "Risk Factors." Accordingly, there can be no assurance that the forecast is indicative of our future performance or that actual results will not differ materially from those presented in the forecast. Inclusion of the forecast in this prospectus should not be regarded as a representation by any person that the results contained in the forecast will be achieved.

        We have prepared the following forecast to present the estimated cash available for distribution to our common unitholders during the forecasted period. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information,

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but, in our view, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management's knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not necessarily indicative of future results.

        Neither our independent registered public accounting firm, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information. The independent registered public accounting firm's report included in this prospectus relates to historical financial information. It does not extend to prospective financial information and should not be read to do so.

        We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast or the assumptions used to prepare the forecast to reflect events or circumstances after the completion of this offering. In light of this, the statement that we believe that we will have sufficient cash available for distribution to allow us to make the full minimum quarterly distribution on all of our outstanding units for the twelve-month period ending September 30, 2015, should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.

        The table below presents our projection of operating results for the twelve-month period ending September 30, 2015.

 
  Twelve-Month
Period Ending
September 30,
2015
(In millions)
 

Operating Revenues:

       

Gathering and compression—affiliate

  $ 185.9  

Operating Expenses:

       

Operating and maintenance

  $ 27.8  

General and administrative (including $6.6 million of non-cash stock compensation expense)(1)

    28.5  

Depreciation

    65.3  
       

Total Operating Expenses

    121.6  
       

Operating Income

    64.3  

Interest expense(2)

    (2.7 )
       

Net Income

  $ 61.6  

Add:

       

Depreciation

    65.3  

Interest expense(2)

    2.7  

Non-cash stock compensation expense

    6.6  
       

Adjusted EBITDA(3)

    136.2  

Less:

       

Cash interest expense(4)

    (2.7 )

Expansion capital expenditures(5)

    (587.3 )

Maintenance capital expenditures(6)

    (14.7 )

Add:

       

Borrowings and retained offering proceeds to fund expansion capital expenditures

    587.3  
       

Estimated Cash Available for Distribution

  $ 118.8  
       
       

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  Twelve-Month
Period Ending
September 30,
2015
(In millions, except
per unit data)
 

Estimated Cash Distributions:

       

Distribution per unit (based on a minimum quarterly distribution rate of $0.17 per unit)

  $ 0.68  

Aggregate distributions to(7):

       

Common units held by the public

  $ 27.2  

Common units held by Antero

    24.4  

Subordinated units held by Antero

    51.6  

Total distributions to Antero

    76.1  
       

Total Distributions

  $ 103.3  
       
       

Excess (Shortfall)

  $ 15.5  
       
       

Percent of minimum quarterly distribution payable to common unitholders

    100 %
       
       

Percent of minimum quarterly distribution payable to subordinated unitholders

    100 %
       
       

(1)
Comprised of approximately $28.5 million of general and administrative expenses allocated to us by Antero, including $6.6 million of non-cash stock compensation expense, as well as $2.5 million of general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership, such as costs associated with: annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance expenses; and director compensation. Stock compensation is allocated to us by Antero and is not dilutive to our common unitholders.

(2)
Interest expense includes interest costs on funds used for expansion capital expenditures.

(3)
We define Adjusted EBITDA as net income (loss) before stock compensation expense, interest expense, income taxes and depreciation and amortization expense. Please read "Summary—Non-GAAP Financial Measure."

(4)
Cash interest expense includes interest costs on funds used for expansion capital expenditures (under our new revolving credit facility or otherwise).

(5)
Expansion capital expenditures are 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. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines and compressor stations, in each case to the extent such capital expenditures are expected to expand our operating capacity or revenue. In order to keep pace with Antero's expected production growth and drilling schedule, we will need to significantly expand our midstream system. Please read "—Assumptions and Considerations—Capital Expenditures."

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(6)
Maintenance capital expenditures are 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. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain gathering and compression throughput, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations. Please read "—Assumptions and Considerations—Capital Expenditures."

(7)
Reflects the number of common and subordinated units that we anticipate will be outstanding immediately following the closing of this offering, and the aggregate distribution amounts payable on those units during the forecast period at our minimum quarterly distribution rate of $0.68 per unit on an annualized basis assuming that the underwriters' option to purchase additional common units has not been exercised.


Assumptions and Considerations

        We believe our estimated available cash for distribution for the twelve-month period ending September 30, 2015 will not be less than $118.8 million. This amount of estimated minimum available cash for distribution is approximately $120.1 million and $119.5 million more than the unaudited pro forma available cash for distribution for the year ended December 31, 2013 and the twelve-month period ended June 30, 2014, respectively. Substantially all of this increase in available cash for distribution is attributable to increased revenues from (i) higher natural gas throughput volumes resulting from Antero's robust drilling program and (ii) incremental development of in-service gathering pipelines and related compression infrastructure. Our estimates do not assume any incremental revenue, expenses or other costs associated with potential future acquisitions or processing infrastructure or services.

        While the assumptions disclosed in this prospectus are not all-inclusive, the assumptions listed are those that we believe are significant to our forecasted results of operations and any assumptions not discussed below were not deemed significant. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results, including without limitation, the anticipated in-service dates of our growth projects, will be achieved.

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Results, Volumes and Fees

        The following table summarizes the pro forma volumes, fees, revenues, capital expenditures and Adjusted EBITDA for our gathering and compression business during the twelve-month period ended June 30, 2014, as well as our assumptions regarding those same amounts for the twelve-month period ending September 30, 2015:

 
   
  Forecasted  
 
  Pro Forma  
 
  Twelve-Month
Period Ending
September 30,
2015
 
 
  Twelve-Month
Period Ended
June 30, 2014
 

Low-pressure gathering volumes (Bcf)

    111     352  

Low-pressure gathering volumes (MMcf/d)

    303     964  

Low-pressure gathering fees ($/Mcf)

  $ 0.30   $ 0.31 (1)

High-pressure gathering volumes (Bcf)

   
46
   
282
 

High-pressure gathering volumes (MMcf/d)

    127     773  

High-pressure gathering fees ($/Mcf)

  $ 0.18   $ 0.19 (1)

Condensate gathering volumes (MBbls)

   
   
1,665
 

Condensate gathering volumes (Bbl/d)

    1     4,562  

Condensate gathering fees ($/Bbl)

  $ 4.08   $ 4.14  

Compression volumes (Bcf)

   
14
   
91
 

Compression volumes (MMcf/d)

    37     249  

Compression fees ($/Mcf)

  $ 0.18   $ 0.19 (1)

Revenues ($ in millions)

 
$

45.6
 
$

185.9
 

Capital expenditures ($ in millions)

  $ 504.0   $ 602.0  

Adjusted EBITDA ($ in millions)(2)

  $ 31.6   $ 136.2  

(1)
Assumes a 1.5% CPI-based adjustment pursuant to the terms of the applicable contract with Antero.

(2)
We define Adjusted EBITDA as net income (loss) before stock compensation expense, interest expense, income taxes and depreciation and amortization expense. Please read "Summary—Non-GAAP Financial Measure."

        We have assumed that substantially all of our gathering and compression volumes and revenues during the twelve-month period ending September 30, 2015 will be generated pursuant to our long-term contracts with Antero. For more information, please read "Business—Our Relationship with Antero—Contractual Arrangements with Antero."

        The aggregate results, volumes and fees for the twelve-month period ending September 30, 2015 are further subject to the assumptions described below.

Total Revenue

        We estimate that our total revenues for the twelve-month period ending September 30, 2015 will be approximately $185.9 million, as compared to approximately $45.6 million for the pro forma twelve-month period ended June 30, 2014.

        The gathering and compression agreement includes certain minimum volume commitments related to new high-pressure gathering and compression infrastructure that we may construct at Antero's request. However, we have not assumed any impact from minimum volume commitments for the

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twelve-month period ending September 30, 2015 because we expect Antero's aggregate volumes during the period to be in excess of any such minimum volume commitments.

    Low-pressure gathering:

    Marcellus Shale:  At September 30, 2015, we expect to have 130 miles of low-pressure pipelines in the Marcellus Shale compared to 54 miles of low-pressure pipelines in place as of December 31, 2013. Antero forecasts running 12 rigs on average and completing 126 gross wells in our dedicated area in the Marcellus Shale during the twelve-month period ending September 30, 2015. We estimate that, as a result of these completions as well as production from existing wells on our system, we will gather 241 Bcf, or an average of 660 MMcf/d. Our expected increase in volumes is based on the expectation that Antero will continue its robust drilling and development activities in our Marcellus Shale acreage dedication. We will receive fees of $0.31/Mcf for low-pressure gathering under the gathering and compression agreement.

    Utica Shale:  At September 30, 2015, we expect to have 72 miles of low-pressure pipelines in the Utica Shale, compared to 26 miles of low-pressure pipelines in place as of December 31, 2013. Antero forecasts running 8 rigs on average and completing 57 gross wells in the Utica Shale (all of which is dedicated to us) during the twelve-month period ending September 30, 2015. We estimate that, as a result of these completions as well as production from existing wells on our system, we will gather 111 Bcf, or an average of 304 MMcf/d. Our expected increase in volumes is based on the expectation that Antero will continue its robust drilling and development activities in our Utica Shale acreage dedication. We will receive fees of $0.31/Mcf for low-pressure gathering under the gathering and compression agreement.

    High-pressure gathering:

    Marcellus Shale:  At September 30, 2015, we expect to have 89 miles of high-pressure pipelines in the Marcellus Shale, compared to 38 miles of high-pressure pipelines in place as of December 31, 2013. We estimate that we will gather 171 Bcf, or an average of 469 MMcf/d. Our expected increase in volumes is based on the expectation that Antero will continue its robust drilling and development activities in our Marcellus Shale acreage dedication. Additionally, the expected increase in high-pressure gathering revenues is less than the expected increase in low-pressure gathering revenues due primarily to the exclusion of approximately 30% of Antero's wellhead volumes flowing into existing third-party high-pressure gathering pipelines. Please read "Business—Antero's Existing Third-Party Commitments." We will receive fees of $0.19/Mcf for high-pressure gathering under the gathering and compression agreement.

    Utica Shale:  At September 30, 2015, we expect to have 36 miles of high-pressure pipelines in the Utica Shale compared to 23 miles of high-pressure pipelines in place as of December 31, 2013. We estimate that we will gather 111 Bcf, or an average of 304 MMcf/d. Our expected increase in volumes is based on the expectation that Antero will continue its robust drilling and development activities in our Utica Shale acreage dedication. We will receive fees of $0.19/Mcf for high-pressure gathering under the gathering and compression agreement.

    Compression:

    Marcellus Shale:  During the twelve-month period ending September 30, 2015, we expect to add or expand eight compressor stations, resulting in 835 MMcf/d of compression capacity at period end. This will lead to compression volumes of 91 Bcf, or an average of 249 MMcf/d. A majority of the additional compression capacity is expected to be placed into service in the second half of the twelve-month period ending September 30, 2015 as volumes begin to exceed system capacity. We will receive fees of $0.19/Mcf for compression under the gathering and compression agreement.

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    Utica Shale:  We have not assumed that we will make any expenditures related to, or generate any revenues from, Utica Shale compression during the twelve-month period ending September 30, 2015.

    Condensate Gathering:

    Marcellus Shale:  We have not assumed that we will make any expenditures related to, or generate any revenues from, Marcellus Shale condensate gathering during the twelve-month period ending September 30, 2015.

    Utica Shale:  At September 30, 2015, we expect to have 27 miles of condensate gathering pipelines in the Utica Shale, compared to 10 miles of condensate gathering pipelines in place as of December 31, 2013. We estimate that we will gather 1,665 MBbls, or an average of 4,562 Bbl/d during the twelve-month period ending September 30, 2015. Our expected increase in volumes is based on the expectation that Antero will continue its drilling and development activities in our Utica Shale acreage dedication. We will receive fees of $4.14/Bbl for condensate gathering under the gathering and compression agreement.

Operating and Maintenance Expense

        We estimate that operating and maintenance expense for the twelve-month period ending September 30, 2015 will be $27.8 million. Our increase in operating and maintenance expense is primarily due to our significantly higher activity levels, including higher:

    gathering and compression throughput in the Marcellus Shale and gathering throughput in the Utica Shale;

    maintenance and contract service costs;

    regulatory and compliance costs;

    operating costs associated with our internal growth projects, including:

    increased pipeline mileage; and

    additional compressor stations; and

    ad valorem taxes.

General and Administrative Expenses

        Our general and administrative expense will primarily consist of direct general and administrative expenses incurred by us and payments we make to Antero in exchange for the provision of general and administrative services, including the $2.5 million of incremental expenses we expect to incur as a result of becoming a publicly traded partnership. We estimate that general and administrative expenses for the twelve-month period ending September 30, 2015 will be $28.5 million (including $6.6 million of non-cash stock compensation expense). In addition to the incremental expenses attributable to being a publicly traded partnership, the increase is primarily due to additional general and administrative expenses allocated to us by Antero. This increased allocation relates to Antero's overall increase in general and administrative expenses during the twelve-month period ending September 30, 2015, the majority of which relates to significant personnel and related administrative additions during 2013 and 2014 due to Antero's rapid growth. In the future, we expect Antero's general and administrative expenses, and our allocated portion thereof, to grow modestly in line with our overall growth, as compared to the substantial increases experienced over the last two years.

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Depreciation Expense

        We estimate that depreciation expense for the twelve-month period ending September 30, 2015 will be $65.3 million. Our expected increase is primarily attributable to the effect of a full year of depreciation on the infrastructure built during 2013 and depreciation on the new infrastructure constructed and to be constructed during the twelve-month period ending September 30, 2015.

Capital Expenditures

        The gathering and compression business is capital intensive, requiring significant investment for the maintenance of existing assets or development of new systems and facilities. We categorize our capital expenditures as either:

    Expansion capital expenditures:  Expansion capital expenditures are 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. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines and compressor stations, in each case to the extent such capital expenditures are expected to expand our operating capacity or revenue. In the future, if we make acquisitions that increase system throughput or capacity, the associated capital expenditures may also be considered expansion capital expenditures.

    Maintenance capital expenditures:  Maintenance capital expenditures are 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. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations. In addition, we designate a portion of our capital expenditures to connect new wells to maintain gathering and compression throughput as maintenance capital to the extent such capital expenditures are necessary to maintain, over the long term, the operating capacity or revenue.

        We generally categorize specific capital expenditures as either expansion capital expenditures or maintenance capital expenditures based on the nature of the expenditure. However, a portion of our capital expenditures relate to the connection of our gathering and compression system to new wells. While these capital expenditures could generally be considered expansion capital expenditures because they will result in increased throughput or cash flows produced by our systems, we categorize a portion of these capital expenditures as maintenance capital expenditures because they are necessary to offset the natural production declines Antero will experience on all of its wells over time.

        Because Antero is significantly accelerating its drilling program, our total natural gas volumes gathered are experiencing growth that substantially exceeds natural production declines. Accordingly, the substantial majority of our capital expenses for new well connections are considered expansion capital expenditures, with a minority considered maintenance capital expenditures. As Antero's drilling program and production profile matures, we would expect a larger percentage of wells placed on line to represent maintenance capital expenditures.

        To categorize our estimated expansion capital expenditures and maintenance capital expenditures during the twelve-month period ending September 30, 2015, we first estimate the number of new well connections needed during the twelve-month period ending September 30, 2015 in order to offset the natural production decline and maintain the average throughput volume on our system over the twelve months preceding such period. We then compare this number of well connections to the total number of well connections estimated to be made during such period and designate an equal percentage of our

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estimated gathering capital expenditures as maintenance capital expenditures. All remaining gathering and compression capital expenditures are characterized as expansion capital expenditures.

        We estimate that total capital expenditures for the twelve-month period ending September 30, 2015 will be $602.0 million, based on the following assumptions.

    Expansion Capital Expenditures

        We estimate that expansion capital expenditures for the twelve-month period ending September 30, 2015 will be $587.3 million. During the twelve-month period ending September 30, 2015, we have assumed that we will fund our expansion capital expenditures with borrowings under our new revolving credit facility and with a portion of the proceeds of this offering. In general, our expansion capital expenditures are necessary to increase the size and scope of our midstream infrastructure in order to continue servicing Antero's drilling and completion schedule and increasing production. A majority of Antero's planned well completions and production growth during the twelve-month period ending September 30, 2015 will drive our need for expansion capital expenditures on our low-pressure gathering systems. However, because of existing high-pressure gathering and compression infrastructure owned by third parties in the more developed portions of Antero's acreage, a smaller proportion of Antero's planned well completions and production growth is associated with expansion capital expenditures for these services.

        These expenditures are primarily comprised of the following expansion capital projects that we intend to pursue during the twelve-month period ending September 30, 2015:

    Low-pressure gathering:  We expect to spend $155.9 million related to low-pressure gathering pipeline expansion in the Marcellus Shale in order to complete the addition of 36 miles of pipeline, giving us a total of 145 miles at September 30, 2015. Similarly, we expect to spend $89.8 million related to low-pressure gathering pipeline expansion in the Utica Shale in order to complete the addition of 22 miles of pipeline, giving us a total of 60 miles at September 30, 2015. We also expect to spend $8.3 million related to condensate gathering pipeline in the Utica Shale in order to complete the addition of 8 miles of pipeline, giving us a total of 37 miles at September 30, 2015.

    High-pressure gathering:  We expect to spend $131.8 million during the twelve-month period ending September 30, 2015 related to high-pressure gathering pipeline expansion in the Marcellus Shale in order to complete the addition of 28 miles of pipeline, giving us a total of 92 miles at September 30, 2015. Similarly, we expect to spend $15.9 million related to high-pressure gathering pipeline expansion in the Utica Shale in order to complete the addition of 2 miles of pipeline, giving us a total of 25 miles at September 30, 2015.

    Compression:  We expect to spend $185.6 million related to the expansion or construction of seven additional compression stations in the Marcellus Shale, resulting in total capacity of 835 MMcf/d at September 30, 2015. We do not expect to make any expenditures related to Utica Shale compression during the twelve-month period ending September 30, 2015.

    Maintenance Capital Expenditures

        We estimate that our capital expenditures will be $602.0 million for the twelve-month period ending September 30, 2015, $14.7 million of which will be maintenance capital expenditures and the remaining $587.3 million will be expansion capital expenditures. We expect to fund these maintenance capital expenditures with cash generated by our operations. Because our gathering and compression systems are relatively new, having been substantially built within the last two years, we believe that the capital expenditures necessary to repair, refurbish and replace pipelines, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations during the twelve-month period ending September 30, 2015 will be immaterial. Accordingly, we have not categorized any

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specific capital expenditures as maintenance capital expenditures during the twelve-month period ending September 30, 2015. All maintenance capital expenditures included in the twelve-month period ending September 30, 2015 represent that portion of our estimated capital expenditures associated with 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. The methodology we use to categorize these capital expenditures is described above.

Financing

        We estimate that interest expense will be approximately $2.7 million for the twelve-month period ending September 30, 2015. Our interest expense for the twelve-month period ending September 30, 2015 is based on the following assumptions:

    average borrowings under our new revolving credit facility of approximately $122.0 million; and

    an average interest rate under our new revolving credit facility of 2.3%, the same rate as under Antero's revolving credit facility (with an increase or decrease of 1.0% in the assumed interest rate resulting in increased or decreased, as applicable, annual interest expense of $1.2 million).

Other Assumptions

        Our estimated cash available for distribution for the twelve-month period ending September 30, 2015 is based on the following significant additional assumptions:

    no new federal, state or local regulation of the midstream energy sector, or any new interpretation of existing regulations, that will be materially adverse to our or Antero's business;

    no major adverse change in the midstream energy sector, commodity prices, capital or insurance markets or general economic conditions;

    no material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our facilities or those of third parties on which we or Antero depend;

    no acquisitions or other significant expansion capital expenditures (other than as described above); and.

    no substantial change in market, insurance and overall economic conditions.

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HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

General

Cash Distribution Policy

        While our partnership agreement provides that our general partner will make a determination as to whether to make a distribution, our partnership agreement does not require us to pay distributions at any time or in any amount. Instead, the board of directors of our general partner will adopt a cash distribution policy to be effective as of the closing of this offering that will set forth our general partner's intention with respect to the distributions to be made to unitholders. Pursuant to our cash distribution policy, within 60 days after the end of each quarter, beginning with the quarter ending December 31, 2014, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.17 per unit, or $0.68 on an annualized basis, 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. We will prorate the distribution for the period after the closing of the offering through December 31, 2014.

        The board of directors of our general partner may change our distribution policy at any time and from time to time, and even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our distribution policy and the decision to make any distribution is determined by our general partner. Our partnership agreement does not contain a requirement for us to pay distributions to our unitholders, and there is no guarantee that we will pay the minimum quarterly distribution, or any distribution, on the units in any quarter. However, our partnership agreement does contain provisions intended to motivate our general partner to make steady, increasing and sustainable distributions over time.

        As described in further detail below, we may make distributions out of either operating surplus or capital surplus. We do not anticipate that we will make any distributions from capital surplus. To the extent that we make distributions from capital surplus, they will be made pro rata to all unitholders, but the holder of the incentive distribution rights would generally not participate in any capital surplus distributions with respect to those incentive rights.

        In order to pay any distribution on our subordinated units, we must first make distributions from operating surplus in respect of all of our outstanding common units of at least the minimum quarterly distribution of $0.17 per unit (plus any arrearages resulting from the failure to pay the minimum quarterly distribution on all of our common units). Moreover, the subordination period will ordinarily not end until we have made distributions from operating surplus in excess of certain targets and generated sufficient adjusted operating surplus. Adjusted operating surplus is intended to serve as a proxy for the amount of operating surplus that was "earned" (rather than, for example, borrowed) during the relevant distribution period. Distributions from capital surplus will not count toward satisfying the tests to end the subordination period. Finally, holders of our incentive distribution rights will generally only participate in distributions from operating surplus above certain threshold distribution levels.

        Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.


Operating Surplus and Capital Surplus

General

        Any distributions we make will be characterized as made from "operating surplus" or "capital surplus." Distributions from operating surplus are made differently than cash distributions that we would make from capital surplus. Operating surplus distributions will be made to our unitholders and,

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if we make quarterly distributions above the first target distribution level described below, to the holder of our incentive distribution rights. We do not anticipate that we will make any distributions from capital surplus. In such an event, however, any capital surplus distribution would be made pro rata to all unitholders, but the holder of the incentive distribution rights would generally not participate in any capital surplus distributions with respect to those rights.

Operating Surplus

        We define operating surplus as:

    $75.0 million (as described below); plus

    all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below) provided that cash receipts from the termination of any hedge contract prior to its stipulated settlement or termination date will be included in equal quarterly installments over the remaining scheduled life of such hedge contract had it not been terminated; plus

    cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights), other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period from such financing until the earlier to occur of the date the asset commences commercial service and the date that it is abandoned or disposed of; plus

    cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights), other than equity issued in this offering, to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the expansion capital expenditures referred to above, in each case, in respect of the period from such financing until the earlier to occur of the date the asset commences commercial service and the date that it is abandoned or disposed of; less

    all of our operating expenditures (as defined below) after the closing of this offering; less

    the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

    all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such twelve-month period with the proceeds of additional working capital borrowings; less

    any cash loss realized on disposition of an investment capital expenditure.

        Disbursements made, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period but on or before the date on which cash or cash equivalents will be distributed with respect to such period shall be deemed to have been made, received, established, increased or reduced, for purposes of determining operating surplus, within such period if our general partner so determines. Furthermore, cash received from an interest in an entity for which we account using the equity method will not be included to the extent it exceeds our proportionate share of that entity's operating surplus (calculated as if the definition of operating surplus applied to such entity from the date of our acquisition of such an interest without any basket similar to described in the first bullet above). Operating surplus does not reflect cash generated by our operations. For example, it includes a basket of $75.0 million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash

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distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

        The proceeds of working capital borrowings increase operating surplus, and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deemed repayment.

        We define operating expenditures in our partnership agreement, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner or its affiliates, payments made under interest rate hedge agreements or commodity hedge agreements (provided that (1) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (2) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), officer compensation, repayment of working capital borrowings, interest on indebtedness and maintenance capital expenditures (as discussed in further detail below). However, operating expenditures will not include:

    repayment of working capital borrowings deducted from operating surplus pursuant to the penultimate bullet point of the definition of operating surplus above when such repayment actually occurs;

    payments (including prepayments and prepayment penalties and the purchase price of indebtedness that is repurchased and cancelled) of principal of and premium on indebtedness, other than working capital borrowings;

    expansion capital expenditures;

    investment capital expenditures;

    payment of transaction expenses relating to interim capital transactions;

    distributions to our partners (including distributions in respect of our incentive distribution rights);

    repurchases of equity interests except to fund obligations under employee benefit plans; or

    any other expenditures or payments using the proceeds of this offering that are described in "Use of Proceeds."

Capital Surplus

        Capital surplus is defined in our partnership agreement as any cash distributed in excess of our operating surplus. Accordingly, capital surplus would generally be generated only by the following (which we refer to as "interim capital transactions"):

    borrowings other than working capital borrowings;

    sales of our equity interests and long-term borrowings; and

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    sales or other dispositions of assets for cash, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

Characterization of Cash Distributions

        Our partnership agreement provides that we treat all cash distributed as coming from operating surplus until the sum of all cash distributed since the closing of this offering (other than any distributions of proceeds of this offering) equals the operating surplus from the closing of this offering. However, operating surplus includes a basket of $75.0 million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. Our partnership agreement provides that we treat any amount distributed in excess of operating surplus, regardless of its source, as distributions of capital surplus. We do not anticipate that we will make any distributions from capital surplus.


Capital Expenditures

        Maintenance capital expenditures reduce operating surplus, but expansion capital expenditures and investment capital expenditures do not. Maintenance capital expenditures are 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. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain gathering and compression throughput to maintain equipment reliability, integrity and safety and to address environmental laws and regulations. Our business, facilities and equipment are currently not subject to major turnaround, overhaul or rebuilds. Cash expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

        Expansion capital expenditures are 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. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines or compressor stations, in each case to the extent such capital expenditures are expected to expand our operating capacity or our operating income. In the future, if we make acquisitions that increase system throughput or capacity, the associated capital expenditures may also be considered expansion capital expenditures. Expenditures made solely for investment purposes will not be considered expansion capital expenditures.

        Investment capital expenditures are those capital expenditures, including transaction expenses, that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of an asset for investment purposes or development of assets that are in excess of the maintenance of our operating capacity or revenue, but which are not expected to expand, for more than the short term, operating capacity or revenue.

        As described above, neither investment capital expenditures nor expansion capital expenditures are operating expenditures, and thus will not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

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        Cash expenditures that are made in part for maintenance capital purposes, investment capital purposes or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditures by our general partner.


Subordination Period

General

        Our partnership agreement provides that, during the subordination period (described below), the common units will have the right to receive distributions from operating surplus each quarter in an amount equal to $0.17 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient cash from operating surplus to pay the minimum quarterly distribution on the common units.

Determination of Subordination Period

        Antero will initially own all of our subordinated units. Except as described below, the subordination period will begin on the closing date of this offering and expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending September 30, 2017, if each of the following has occurred:

    distributions from operating surplus on each of the outstanding common and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

    the "adjusted operating surplus" (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distribution on all of the outstanding common and subordinated units during those periods on a fully diluted weighted average basis; and

    there are no arrearages in payment of the minimum quarterly distribution on the common units.

        For the period after closing of this offering through December 31, 2014, our partnership agreement will prorate the minimum quarterly distribution based on the actual length of the period, and use such prorated distribution for all purposes, including in determining whether the test described above has been satisfied.

Early Termination of Subordination Period

        Notwithstanding the foregoing, the subordination period will automatically terminate, and all of the subordinated units will convert into common units on a one-for-one basis, on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending September 30, 2015, if each of the following has occurred:

    distributions from operating surplus equaled or exceeded $1.02 per unit (150% of the annualized minimum quarterly distribution) on all outstanding common units and subordinated units for a four-quarter period immediately preceding that date;

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    the "adjusted operating surplus" (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded $1.02 per unit (150% of the annualized minimum quarterly distribution) on all of the outstanding common and subordinated units during that period on a fully diluted weighted average basis, plus the related distribution on the incentive distribution rights; and

    there are no arrearages in payment of the minimum quarterly distributions on the common units.

        For the period after the closing of this offering through December 31, 2014, our partnership agreement will prorate the minimum quarterly distribution based on the actual length of the period and use such prorated distribution for all purposes, including in determining whether the test described above has been satisfied.

Expiration of the Subordination Period

        When the subordination period ends, each outstanding subordinated unit will convert into one common unit, which will then participate pro-rata with the other common units in distributions.

Adjusted Operating Surplus

        Adjusted operating surplus is intended to generally reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods if not utilized to pay expenses during that period. Adjusted operating surplus for any period consists of:

    operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under "—Operating Surplus and Capital Surplus—Operating Surplus" above); less

    any net increase during that period in working capital borrowings; less

    any net decrease during that period in cash reserves for operating expenditures not relating to an operating expenditure made during that period; plus

    any net decrease during that period in working capital borrowings; plus

    any net increase during that period in cash reserves for operating expenditures required by any debt instrument for the repayment of principal, interest or premium; plus

    any net decrease made in subsequent periods in cash reserves for operating expenditures initially established during such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above.

        Any disbursements received, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period that the general partner determines to include in operating surplus for such period shall also be deemed to have been made, received or established, increased or reduced in such period for purposes of determining adjusted operating surplus for such period.


Distributions From Operating Surplus During the Subordination Period

        If we make a distribution from operating surplus for any quarter during the subordination period, our partnership agreement requires that we make the distribution in the following manner:

    first, to the common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter and any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters;

    second, to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

    thereafter, in the manner described in "—Incentive Distribution Rights" below.

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Distributions From Operating Surplus After the Subordination Period

        If we make distributions of cash from operating surplus for any quarter after the subordination period, our partnership agreement requires that we make the distribution in the following manner:

    first, to all common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter; and

    thereafter, in the manner described in "—Incentive Distribution Rights" below.


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 incentive distribution rights 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.


Incentive Distribution Rights

        Incentive distribution rights represent the right to receive increasing percentages (15%, 25% and 50%) of quarterly distributions from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest.

        If for any quarter:

    we have distributed cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

    we have distributed cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then we will make additional distributions from operating surplus for that quarter among the unitholders and the holders of the incentive distribution rights in the following manner:

    first, to all unitholders, pro rata, until each unitholder receives a total of $0.1955 per unit for that quarter (the "first target distribution");

    second, 85% to all common unitholders and subordinated unitholders, pro rata, and 15% to the holders of our incentive distribution rights, until each unitholder receives a total of $0.2125 per unit for that quarter (the "second target distribution");

    third, 75% to all common unitholders and subordinated unitholders, pro rata, and 25% to the holders of our incentive distribution rights, until each unitholder receives a total of $0.2550 per unit for that quarter (the "third target distribution"); and

    thereafter, 50% to all common unitholders and subordinated unitholders, pro rata, and 50% to the holders of our incentive distribution rights.


Percentage Allocations of Distributions From Operating Surplus

        The following table illustrates the percentage allocations of distributions from operating surplus between the unitholders and the holders of our incentive distribution rights based on the specified target distribution levels. The amounts set forth under the column heading "Marginal Percentage Interest in Distributions" are the percentage interests of the holders of our incentive distribution rights and the unitholders in any distributions from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit." The percentage interests

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shown for our unitholders and the holders of our incentive distribution rights for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below assume there are no arrearages on common units.

 
   
  Marginal Percentage
Interest in
Distributions
 
 
  Total Quarterly
Distribution Per Unit
  Unitholders   IDR Holders  

Minimum Quarterly Distribution

  up to $0.1700     100 %   %

First Target Distribution

  above $0.1700 up to $0.1955     100 %   %

Second Target Distribution

  above $0.1955 up to $0.2125     85 %   15 %

Third Target Distribution

  above $0.2125 up to $0.2550     75 %   25 %

Thereafter

  above $0.2550     50 %   50 %


General Partner's Right to Reset Incentive Distribution Levels

        Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the target distribution levels upon which the incentive distribution payments would be set. If our general partner transfers all or a portion of the incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made.

        The right to reset the target distribution levels upon which the incentive distributions are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for the prior four consecutive fiscal quarters. The reset target distribution levels will be higher than the target distribution levels prior to the reset such that there will be no incentive distributions paid under the reset target distribution levels until cash distributions per unit following the reset event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made.

        In connection with the resetting of the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on the formula described below that takes into account the "cash parity" value of the cash distributions related to the incentive distribution rights for the quarter prior to the reset event as compared to the cash distribution per common unit in such quarter.

        The number of common units to be issued in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels would equal the quotient determined by dividing (x) the amount of cash distributions received in respect of the incentive distribution rights for the fiscal quarter ended immediately prior to the date of such reset election by (y) the amount of cash distributed per common unit with respect to such quarter.

        Following a reset election, a baseline minimum quarterly distribution amount will be calculated as an amount equal to the cash distribution amount per unit for the fiscal quarter immediately preceding the reset election (which amount we refer to as the "reset minimum quarterly distribution") and the

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target distribution levels will be reset to be correspondingly higher such that we would make distributions from operating surplus for each quarter thereafter as follows:

    first, to all common unitholders, pro rata, until each unitholder receives an amount per unit equal to 115% of the reset minimum quarterly distribution for that quarter;

    second, 85% to all common unitholders, pro rata, and 15% to the holders of our incentive distribution rights, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for the quarter;

    third, 75% to all common unitholders, pro rata, and 25% to the holders of our incentive distribution rights, until each unitholder receives an amount per unit equal to 150% of the reset minimum quarterly distribution for the quarter; and

    thereafter, 50% to all common unitholders, pro rata, and 50% to the holders of our incentive distribution rights.

        Because a reset election can only occur after the subordination period expires, the reset minimum quarterly distribution will have no significance except as a baseline for the target distribution levels.

        The following table illustrates the percentage allocation of distributions from operating surplus between the unitholders and the holders of our incentive distribution rights at various distribution levels (1) pursuant to the distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (2) following a hypothetical reset of the target distribution levels based on the assumption that the quarterly distribution amount per common unit during the fiscal quarter immediately preceding the reset election was $0.50.

 
   
  Marginal Percentage
Interest in
Distributions
   
 
  Quarterly
Distribution Per Unit
Prior to Reset
  Unitholders   IDR
Holders
  Quarterly Distribution Per
Unit Following
Hypothetical Reset

Minimum Quarterly Distribution

  up to $0.1700     100 %   % up to $0.500000(1)

First Target Distribution

  above $0.1700 up to $0.1955     100 %   % above $0.500000 up to $0.575000(2)

Second Target Distribution

  above $0.1955 up to $0.2125     85 %   15 % above $0.575000 up to $0.625000(3)

Third Target Distribution

  above $0.2125 up to $0.2550     75 %   25 % above $0.625000 up to $0.750000(4)

Thereafter

  above $0.2550     50 %   50 % above $0.750000

(1)
This amount is equal to the hypothetical reset minimum quarterly distribution.

(2)
This amount is 115% of the hypothetical reset minimum quarterly distribution.

(3)
This amount is 125% of the hypothetical reset minimum quarterly distribution.

(4)
This amount is 150% of the hypothetical reset minimum quarterly distribution.

        The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and the holders of incentive distribution rights, based on the amount distributed for the quarter immediately prior to the reset. The table assumes that immediately prior to

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the reset there would be 151,881,914 common units outstanding and the distribution to each common unit would be $0.50 for the quarter prior to the reset.

 
  Quarterly Distribution
Per Unit Prior to Reset
  Cash
Distributions to
Common
Unitholders Prior
to Reset
  Cash
Distributions to
Holders of IDRs
Prior
to Reset
  Total
Distributions
 

Minimum Quarterly Distribution

  up to $0.1700   $ 25,819,925   $   $ 25,819,925  

First Target Distribution

  above $0.1700 up to $0.1955     3,872,989         3,872,989  

Second Target Distribution

  above $0.1955 up to $0.2125     2,581,993     455,646     3,037,639  

Third Target Distribution

  above $0.2125 up to $0.2550     6,454,981     2,151,660     8,606,641  

Thereafter

  above $0.2550     37,211,069     37,211,069     74,422,138  
                   

      $ 75,940,957   $ 39,818,375   $ 115,759,332  
                   
                   

        The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and the holders of incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that, as a result of the reset, there would be 231,518,664 common units outstanding and the distribution to each common unit would be $0.50. The number of common units to be issued upon the reset was calculated by dividing (1) the amount received in respect of the incentive distribution rights for the quarter prior to the reset as shown in the table above, or $39,818,375, by (2) the cash distributed on each common unit for the quarter prior to the reset as shown in the table above, or $0.50.

 
   
  Cash
Distributions
to Common
Unitholders
Prior to
Reset
  Cash Distributions to
Holders of
IDRs After Reset
   
 
 
  Quarterly Distributions
per Unit
  Common
Units(1)
  IDRs   Total   Total
Distributions
 

Minimum Quarterly Distribution

  up to $0.500000   $ 75,940,957   $ 39,818,375   $   $ 39,818,375   $ 115,759,332  

First Target Distribution

  above $0.500000 up to $0.575000                      

Second Target Distribution

  above $0.575000 up to $0.625000                      

Third Target Distribution

  above $0.625000 up to $0.750000                      

Thereafter

  above $0.750000                      
                           

      $ 75,940,957   $ 39,818,375   $   $ 39,818,375   $ 115,759,332  
                           
                           

(1)
Represents distributions in respect of the common units issued upon the reset.

        The holders of our incentive distribution rights will be entitled to cause the target distribution levels to be reset on more than one occasion. There are no restrictions on the ability of holders of our incentive distribution rights to exercise the reset right multiple times, but the requirements for exercise must be met each time. Because one of the requirements is that we make cash distributions in excess of the then-applicable third target distribution for the prior four consecutive fiscal quarters, a minimum of four quarters must elapse between each reset.


Distributions From Capital Surplus

How Distributions From Capital Surplus Will Be Made

        Our partnership agreement requires that we make distributions from capital surplus, if any, in the following manner:

    first, to all common unitholders and subordinated unitholders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below;

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    second, to the common unitholders, pro rata, until we distribute for each common unit an amount from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

    thereafter, we will make all distributions from capital surplus as if they were from operating surplus.

Effect of a Distribution From Capital Surplus

        Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the distribution of capital surplus to the fair market value of the common units prior to the announcement of the distribution. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the minimum quarterly distribution is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

        Once we reduce the minimum quarterly distribution and target distribution levels to zero, all future distributions will be made such that 50% is paid to all unitholders, pro rata, and 50% is paid to the holder or holders of incentive distribution rights, pro rata.


Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

        In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, our partnership agreement specifies that the following items will be proportionately adjusted:

    the minimum quarterly distribution;

    the target distribution levels;

    the initial unit price, as described below under "—Distributions of Cash Upon Liquidation";

    the per unit amount of any outstanding arrearages in payment of the minimum quarterly distribution on the common units; and

    the number of subordinated units.

        For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the initial unit price would each be reduced to 50% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units using the same ratio applied to the common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

        In addition, if, as a result of a change in law or interpretation thereof, we or any of our subsidiaries is treated as an association taxable as a corporation or is otherwise subject to additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, our general partner may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is cash for that quarter (after deducting our general partner's estimate of our additional aggregate liability for the quarter for such income and withholdings taxes payable by reason of such

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change in law or interpretation) and the denominator of which is the sum of (1) cash for that quarter, plus (2) our general partner's estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation thereof. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in distributions with respect to subsequent quarters.


Distributions of Cash Upon Liquidation

General

        If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the holders of the incentive distribution rights, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

        The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of units to a repayment of the initial value contributed by unitholders for their units in this offering, which we refer to as the "initial unit price" for each unit. The allocations of gain and loss upon liquidation are also intended, to the extent possible, to entitle the holders of common units to a preference over the holders of subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the common unitholders to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights.

Manner of Adjustments for Gain

        The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will generally allocate any gain to the partners in the following manner:

    first, to our general partner to the extent of certain prior losses specially allocated to our general partner;

    second, to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of: (1) the initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

    third, to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of: (1) the initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

    fourth, to all unitholders, pro rata, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the minimum quarterly distribution per unit that we distributed to the unitholders, pro rata, for each quarter of our existence;

    fifth, 85% to all unitholders, pro rata, and 15% to the holders of our incentive distribution rights, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess

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      of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to the holders of our incentive distribution rights for each quarter of our existence;

    sixth, 75% to all unitholders, pro rata, and 25% to the holders of our incentive distribution rights, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to the holders of our incentive distribution rights for each quarter of our existence; and

    thereafter, 50% to all unitholders, pro rata, and 50% to holders of our incentive distribution rights.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

        We may make special allocations of gain among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Manner of Adjustments for Losses

        If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

    first, to the holders of subordinated units in proportion to the positive balances in their capital accounts until the capital accounts of the subordinated unitholders have been reduced to zero;

    second, to the holders of common units in proportion to the positive balances in their capital accounts, until the capital accounts of the common unitholders have been reduced to zero; and

    thereafter, 100% to our general partner.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

        We may make special allocations of loss among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Adjustments to Capital Accounts

        Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for federal income tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the holders of our incentive distribution rights in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in the partners' capital account balances

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equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and the holders of our incentive distribution rights based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders' capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

        We were formed in September 2013 and do not have historical financial statements. Therefore, in this prospectus we present the historical financial statements of our Predecessor. The following table presents selected historical financial data of our Predecessor as of the dates and for the periods indicated.

        This prospectus includes audited financial statements of our Predecessor as of December 31, 2012 and 2013 and for the years ended December 31, 2011, 2012 and 2013 and unaudited financial information of our Predecessor as of and for the six months ended June 30, 2013 and 2014. This prospectus also includes selected pro forma financial data for the year ended December 31, 2013 and as of and for the six months ended June 30, 2014. For a detailed discussion of the selected historical financial information contained in the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table should also be read in conjunction with "Use of Proceeds" and the audited and unaudited historical financial statements of the Predecessor included elsewhere in this prospectus. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.