UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Amendment No. 1
to
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

Antero Resources Midstream LLC
to be converted as described herein into a limited partnership named

Antero Midstream Partners LP
(Exact Name of Registrant as Specified in Its Charter)

Approximate date of commencement of proposed sale to the public:
As soon as practicable after this registration statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

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

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission becomes effective. This preliminary prospectus is not an offer to sell these securities and we are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

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

We have applied to list our common units on the New York Stock Exchange under the symbol "AM."

We anticipate that the initial public offering price will be between $ and $ per common unit.

Investing in our common units involves risks. Please read "Risk Factors" beginning on page 21 of this prospectus.

We have granted the underwriters the option to purchase additional common units on the same terms and conditions set forth above if the underwriters sell more than 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.

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."

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.

The estimates of Antero's net proved, probable and possible reserves as of December 31, 2013 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.

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 an initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover page of this prospectus) and, 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, compressor stations and fresh water distribution systems, through which we provide midstream services to Antero under long-term, fixed-fee contracts. Our assets are located in the rapidly developing liquids-rich southwestern core of the Marcellus Shale in northwest West Virginia and 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.

In the future, we may also provide condensate gathering services to Antero under the gathering and compression agreement. We also 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. As a result of Antero's acreage dedication and its contribution to us of substantially all of its midstream assets in connection with this offering, we believe that we possess significant organic growth potential and, unlike many other midstream companies, our growth does not depend on future acquisitions of assets from our sponsor or third parties.

Antero is our only customer and is one of the largest producers of natural gas and NGLs in the Appalachian Basin. As of December 31, 2013, Antero's estimated net proved, probable and possible reserves were 7.6 Tcfe, 19.8 Tcfe and 7.5 Tcfe, respectively, of which 85% was natural gas. As of December 31, 2013, Antero's drilling inventory consisted of 4,778 identified potential horizontal well

locations (2,978 of which were located on acreage dedicated to us) for gathering and compression services, which provides us with significant opportunity 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 20 operated rigs, including 15 operated rigs in the Marcellus Shale (where it is the most active driller) and 5 operated rigs in the Utica Shale (where it is one of the most active drillers). On January 29, 2014, Antero announced a 2014 drilling and completion capital expenditures budget of approximately $1.8 billion that provides for the drilling of approximately 193 wells, a substantial increase over the 157 wells drilled in 2013. Antero's average Appalachian production during 2013 represented an increase of 115% as compared to 2012, and its net production in the fourth quarter of 2013 averaged 678 MMcfe/d. We anticipate that Antero's robust drilling program will significantly increase throughput on our gathering and compression systems and will result in a significant demand for our fresh water distribution services.

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 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 and fresh water distribution volumes.


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

⁽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 year ending December 31, 2014 of between 925 and 975 MMcfe/d.
⁽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 December 31, 2013. With 4,778 identified potential horizontal well locations included in Antero's net proved, probable and possible reserves as of December 31, 2013, Antero

maintains a 24-year drilling inventory (based on expected 2014 drilling activity), which we believe will provide significant demand for further gathering and compression and fresh water distribution services.

			Gross Drilling Locations											2014 Estimated Completion Activity

	Net Acres		Dry Gas		Rich Gas		Highly Rich Gas		Highly Rich Gas/ Condensate		Total			Average Rigs		Wells
Gathering and Compression:
Marcellus Gathering and Compression		220,000		340		374		861		644		2,219	⁽¹⁾		9		72
Utica Gathering and Compression		106,000		211		182		161		205		759			4		41


Total Gathering and Compression Dedicated to Us⁽²⁾		326,000		551		556		1,022		849		2,978			13		113
Excluded acreage⁽³⁾		128,000		957		811		32		—		1,800			5		68


Total		454,000		1,508		1,367		1,054		849		4,778			18		181




Fresh Water Distribution:
Marcellus		348,000		1,297		1,185		893		644		4,019			14		126
Utica		106,000		211		182		161		205		759			4		37


Total		454,000		1,508		1,367		1,054		849		4,778			18		163

⁽¹⁾: Includes Upper Devonian locations not expected to be drilled during the twelve-month period ending March 31, 2015. See "Our Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve-Months Ending March 31, 2015."
⁽²⁾: Antero's estimated net proved, probable and possible reserves associated with this acreage were 3.1 Tcfe, 15.3 Tcfe and 4.6 Tcfe, respectively, as of December 31, 2013. See "Business—Antero's Existing Third-Party Commitments."
⁽³⁾: The excluded acreage is associated with approximately 4.5 Tcfe, 4.5 Tcfe and 2.9 Tcfe of Antero's net proved, probable and possible reserves, respectively, as of December 31, 2013.

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. All of Antero's approximately 351,000 net leasehold acres in the Marcellus Shale are located within the southwestern core, where it has experienced virtually no geologic complexity in its drilling activities to date. According to RigData, as of February 28, 2014, approximately 90% of the 94 drilling rigs operating in the Marcellus Shale were located in these two core areas.

Based on drilling results and initial production from Antero's 16 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 106,000 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 and fresh water distribution services as the number of Antero's well completions and throughput volumes increase.

In addition to the growth we anticipate as a result of Antero's development drilling, we believe we will 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 and ensure distribution of fresh water for their well completions.

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, 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. Any handling and treating of condensate will be 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.

Fresh Water Distribution

In addition to the gathering and compression agreement, we have also entered 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 is 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 storage facilities.

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 Existing Assets and Growth Projects

In connection with the completion of this offering, Antero will contribute substantially all of its midstream 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.

Gathering and Compression

The following table provides information regarding our gathering and compression system as of December 31, 2013 and operations for the fourth quarter of 2013, 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)				Oil Pipeline (miles)				Compression Capacity (MMcf/d)

	Low-Pressure Pipeline (miles)				High-Pressure Pipeline (miles)				Oil Pipeline (miles)				Compression Capacity (MMcf/d)				Average Daily Throughput for the Three Months Ended December 31, 2013 (MMcf/d)
	As of December 31,
	2013		2014E		2013		2014E		2013		2014E		2013		2014E
Gathering and Compression System:
Marcellus		54		125		38		67		—		—		105		410		232
Utica		26		55		23		37		10		20		—		120		61


Total		80		180		61		104		10		20		105		530		293

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. 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 2014.

In 2014, we anticipate expanding our Marcellus and Utica Shale gathering systems to 192 miles and 92 miles, respectively, and growing our year-end daily Marcellus and Utica compression capacity to 410 MMcf/d and 120MMcf/d, respectively.

Fresh Water Distribution

The following table provides information regarding our fresh water distribution systems as of December 31, 2013 and our expectations for these assets through December 31, 2014, based on organic growth driven by Antero's drilling and completion plans as announced on January 29, 2014.

	Wells Serviced

	Wells Serviced				Pipeline (miles)				Fresh Water Storage Impoundments				Water Storage Capacity (MBbl)
	For the year ended December 31,				Pipeline (miles)				Fresh Water Storage Impoundments				Water Storage Capacity (MBbl)
	For the year ended December 31,				As of December 31,
	2013		2014E		2013		2014E		2013		2014E		2013		2014E
Water Distribution Systems:
Marcellus		50		126		74		122		14		31		1,475		3,266
Utica		17		37		23		48		7		16		925		3,501


Total		67		163		97		170		21		47		2,400		6,767

Our midstream infrastructure also includes 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. To the extent

necessary, we will move surface pipelines to service completion operations in concert with Antero's robust drilling program. While our fresh water distribution agreement only requires us to distribute 35 barrels of fresh water per minute, our system is capable of distributing approximately 80 barrels of fresh water per minute.

Because hydraulic fracturing depends on substantial volumes of fresh water, our fresh water distribution services will be in greatest demand in connection with completion activities rather than ongoing well production. For example, for a typical Antero well that includes a 7,000 foot horizontal lateral and shorter stage lengths, we expect our fresh water distribution services will generate between $650,000 and $700,000 of revenue for each well Antero completes using water delivered through our system. In addition, we believe that our ability to transport fresh water from the Ohio River, which is considered reliable in comparison to other water sources in our areas of operation, coupled with our substantial capacity of fresh water impoundments, should enable us to distribute fresh water for Antero's robust drilling program without material interruption as a result of rainfall variations or other restrictions. We anticipate that approximately 90% of Antero's 2014 well completions will utilize our fresh water distribution systems.

In 2014, we anticipate expanding our fresh water distribution systems and expect to have 122 and 48 miles of buried water pipelines in the Marcellus and Utica operating areas, respectively.

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 and provide fresh water distribution services for Antero's robust and growing drilling program. We intend to continue to develop our midstream infrastructure to move Antero's production to market and distribute fresh water for its well completions. In the short-term, we anticipate significant growth in demand for our gathering and compression and fresh water distribution services driven by Antero's plan to complete approximately 181 horizontal wells in 2014 with an average lateral length of 7,500 feet. In addition, as of December 31, 2013, Antero's drilling inventory consisted of 4,778 identified potential horizontal well locations (2,978 of which were located on acreage dedicated to us) for gathering and compression services, giving Antero a 24-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 and fresh water distribution agreements with Antero provide for fixed-fee structures, and we intend to continue to pursue additional fixed-fee opportunities with Antero and third parties in order to avoid direct commodity price exposure. We will focus on obtaining additional long-term commitments from customers, which may include reservation-based charges, volume commitments and acreage dedications.
•: 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 and fresh water distribution 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 and fresh water 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 and fresh water distribution 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 December 31, 2013 consisted of 4,778 identified potential horizontal well locations (2,978 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 24-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 higher-value NGL products, such as propane and butane. In addition, the condensate often associated with liquids-rich production can further increase well economics. Approximately 68% of Antero's 4,778 identified potential horizontal well locations as of December 31, 2013 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 our 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 950 MMcf/d of processing capacity in the Marcellus Shale, 550 MMcf/d of which is currently in service. Similarly, Antero has 600 MMcf/d of contracted processing capacity in the Utica Shale, of which 200 MMcf/d is currently in service, with the option to access 50 MMcf/d of additional capacity. Antero also has secured 1,657,000 MMBtu/d of long-haul firm transportation capacity or firm sales and has committed to 20,000 Bbl/d of ethane takeaway capacity. We believe our midstream infrastructure, together with Antero's significant processing and takeaway capacity, will allow Antero to commercialize its production more quickly at optimal 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 December 31, 2013, Antero had entered into hedging contracts through December 31, 2019 covering a total of approximately 1.3 Tcfe of its projected natural gas and oil production at average index prices of $4.64/MMBtu and

$96.54/Bbl, respectively. We believe that Antero's active hedging program will allow its drilling schedule to remain active in a variety of commodity price environments.

•: Extensive dedication, system scale and long-term, fixed fee contracts to support stable cash flows. Pursuant to our long-term contracts with Antero, we have secured 20-year dedications covering approximately 329,000 net leasehold acres held by Antero as of February 28, 2014 (net of the approximately 128,000 excluded net leasehold acres) for gathering and compression services and all 457,000 of Antero's existing net leasehold acres for fresh water distribution services. Please read "Business—Antero's Existing Third-Party Commitments." In addition to Antero's existing acreage dedication, our agreements provide that any acreage Antero acquires in the future will be dedicated to us for gathering and compression and fresh water distribution 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 $ million under a new $ million 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 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.

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 common units and 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 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.

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		%
Common Units held by Antero		%
Subordinated Units held by Antero		%
General Partner Interest		*


Total	100	%

*: General partner interest is non-economic.

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.

•: 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. Additionally, our fresh water distribution services are directly associated with Antero's well completion activities and water needs, which are partially driven by horizontal lateral lengths and the number of completion stages per well. Any decrease in volumes of natural gas that Antero produces, any decrease in the number of wells that Antero completes, or any decrease in the length of the laterals Antero drills, 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 $ 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 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 1625 17^th Street, Denver, Colorado 80202, and our telephone number is (303) 357-7310. Our website is located at . 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.

The Offering


Common units offered to the public		common units.
		common units if the underwriters exercise their option to purchase additional common units in full.
Units outstanding after this offering		common units and subordinated units, for a total of 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 $ million from this offering (based on an assumed initial offering price of $ per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discounts and offering expenses, to (i) repay in full $ million of indebtedness that we will assume in connection with the contribution of Midstream Operating to us from Antero and (ii) reimburse Antero for $ million of capital expenditures incurred in connection with the Predecessor prior to Midstream Operating being contributed to us. 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. Please read "Use of Proceeds."
		Affiliates of certain of the underwriters are lenders under our Predecessor's existing midstream credit facility and, accordingly, will receive a portion of the proceeds of this offering. Please read "Underwriting."

		Marginal Percentage Interest in Distributions

Cash distributions	Within 60 days after the end of each quarter, beginning with the quarter ending , 2014, we expect to make a minimum quarterly distribution of $ per common unit and subordinated unit ($ 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 , 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 $ plus any arrearages from prior quarters;
	• second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $ ; and
	• third, to the holders of common units and subordinated units pro rata until each has received a distribution of $ .
	If cash distributions to our unitholders exceed $ 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:
	Total Quarterly Distribution Target Amount	Unitholders			General Partner (as holder of IDRs)
	above $ up to $		85.0	%		15.0	%
	above $ up to $		75.0	%		25.0	%
	above $		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."


		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 $ on all of our common units and subordinated units for the twelve-month period ending March 31, 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 $ (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 , 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 $ (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 , 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."


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 % of our outstanding units (or % 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 % 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. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%. 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."


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 , , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than % of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $ per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $ 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		We have applied to list our common units on the New York Stock Exchange (the "NYSE") under the symbol "AM."

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 and for the years ended December 31, 2011, 2012 and 2013. This prospectus also includes summary pro forma financial data as of and for the year ended December 31, 2013. 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 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 was derived from the audited 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,
	Year Ended December 31,								Year Ended December 31, 2013
	2011			2012			2013		Year Ended December 31, 2013
	(in thousands, except per unit amounts)
Statement of Operations Data:
Revenue:
Gathering and compression—affiliate	$	441		$	647		$	22,363	$	22,363
Fresh water distribution—affiliate		—			—			35,871		35,871


Total revenue		441			647			58,234		58,234


Operating expenses:
Direct operating expenses		802			698			7,871		7,871
General and administrative expenses (including $24,349 of stock compensation in 2013)		397			2,977			34,065		34,065
Depreciation expense		997			1,679			14,119		14,119


Total operating expenses		2,196			5,354			56,055		56,055


Operating income (loss)		(1,755	)		(4,707	)		2,179		2,179
Interest expense		2			8			164		7,459


Net income (loss)	$	(1,757	)	$	(4,715	)	$	2,015	$	(5,280	)




Pro forma basic earnings per unit⁽¹⁾
Pro forma diluted earnings per unit⁽¹⁾

	Predecessor									Pro Forma

	Year Ended December 31,
	Year Ended December 31,									Year Ended December 31, 2013
	2011			2012			2013			Year Ended December 31, 2013
	(in thousands, except per unit amounts)
Balance Sheet Data (at period end):
Cash and cash equivalents				$	—		$	—		$	—
Property and equipment, net					180,249			793,330			793,330
Total assets					180,408			808,337			809,337
Long-term liabilities					320			6,062			6,062
Total net equity—parent net investment					144,897			732,061			733,061
Cash Flow Data:
Net cash provided by (used in) operating activities	$	(618	)	$	(3,236	)	$	29,664
Net cash used in investing activities		(15,795	)		(117,652	)		(597,349	)
Net cash provided by financing activities		16,413			120,888			567,685
Other Financial Data: (unaudited)
Adjusted EBITDA⁽²⁾	$	(758	)	$	(3,028	)	$	40,647		$	40,647

⁽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,

	2011		2012		2013
Operating Data:
Gathering—low pressure (MMcf)		1,703		2,320		61,406
Gathering—high pressure (MMcf)		—		—		11,736
Compression (MMcf)		—		—		9,900
Fresh water distribution (MBbl)		—		—		10,481
Gathering—low pressure (MMcf/d)		5		6		168
Gathering—high pressure (MMcf/d)		—		—		32
Compression (MMcf/d)		—		—		27
Fresh water distribution (MBbl/d)		—		—		29
Average realized fees:
Average gathering—low pressure fee ($/Mcf)	$	0.26	$	0.28	$	0.30
Average gathering—high pressure fee ($/Mcf)		—		—	$	0.18
Average compression fee ($/Mcf)		—		—	$	0.18
Average fresh water distribution ($/Bbl)		—		—	$	3.42

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,
	Year Ended December 31,									Year Ended December 31, 2013
	2011			2012			2013			Year Ended December 31, 2013
	($ in thousands)
Net income (loss)	$	(1,757	)	$	(4,715	)	$	2,015		$	(5,280	)
Add:
Interest expense		2			8			164			7,459
Income tax expense		—			—			—			—
Depreciation expense		997			1,679			14,119			14,119
Stock compensation expense		—			—			24,349			24,349


Adjusted EBITDA	$	(758	)	$	(3,028	)	$	40,647		$	40,647


Less:
Interest expense		(2	)		(8	)		(164	)
Changes in operating assets and liabilities which used (provided) cash		142			(200	)		(10,819	)


Net cash provided by (used in) operating activities	$	(618	)	$	(3,236	)	$	29,664

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.

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.

Also, due to our relationship with Antero, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairment to Antero's financial condition or adverse changes in its credit ratings.

Any material limitation on our ability to access capital as a result of such adverse changes at Antero could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes at Antero could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect our ability to engage in, expand or pursue our business activities, and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.

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

In order to make our minimum quarterly distribution of $ per common unit and subordinated unit per quarter, or $ per unit per year, we will require available cash of approximately $ million per quarter, or approximately $ 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.

If we had completed this offering and the related transactions on January 1, 2013, our unaudited pro forma cash available for distribution for the twelve-month period ended December 31, 2013 would have been approximately $30.7 million. This amount would not have been sufficient to pay the minimum quarterly distribution of $ per unit per quarter ($ per unit on an annualized basis) for the twelve-month period ended December 31, 2013 on all of our common units. Specifically, this amount would only have been sufficient to allow us to pay a distribution of $ per unit per quarter ($ per unit on an annualized basis) on all of the common units, or only approximately % of the minimum quarterly distribution on all of our common units for such period. Because of this deficiency, we would not have been able to pay any distribution on the subordinated units.

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:

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

Because of the natural decline in production from existing wells, our success depends, in part, on Antero's ability to replace declining production and our ability to secure new sources of natural gas from Antero or third parties. Additionally, our fresh water distribution services are directly associated with Antero's well completion activities and water needs, which are partially driven by horizontal lateral lengths and the number of completion stages per well. Any decrease in volumes of natural gas that Antero produces, any decrease in the number of wells that Antero completes, or any decrease in the length of the laterals Antero drills, 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 and fresh water distribution services will be directly and adversely affected. Our ability to maintain fresh water distribution services revenues is dependent on continued completion activity by Antero or third parties over time. In addition, natural gas volumes from completed wells will naturally decline and our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering systems, we must obtain new sources of natural gas from Antero or third parties. The primary factors affecting our ability to obtain additional sources of natural gas include (i) the success of Antero's drilling activity in our areas of operation, (ii) Antero's acquisition of additional acreage and (iii) our ability to obtain dedications of acreage from third parties. Our fresh water distribution will be in greatest demand in connection with completion activities. To the extent that Antero or other fresh water distribution customers complete wells with shorter lateral lengths, the demand for our fresh water distribution services would be reduced.

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

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 or our fresh water distribution services, or if reductions in lateral lengths result in a decrease in demand for our fresh water distribution services on a per well basis, those reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

The 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 March 31, 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 and fresh water distribution pipelines are not supported by minimum volume commitments from Antero. Any decrease in the current levels of throughput on our gathering and compression systems or in the number of well completions for which we distribute fresh water could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

We may not be able to attract third-party gathering and compression volumes or opportunities to provide fresh water distribution services, which could limit our ability to grow and increase our dependence on Antero.

Part of our long-term growth strategy includes diversifying our customer base by identifying opportunities to offer services to third parties. To date, all of our revenues were earned from Antero. Our ability to increase throughput on our gathering and compression systems and fresh water distribution systems and any related revenue from third parties is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when requested by third parties. To the extent that we lack available capacity on our systems for third-party volumes or wells, we may not be able to compete effectively with third-party systems for additional oil and natural gas production and completions 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 and fresh water distribution 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 right-of-first-offer agreement with Antero for gas processing services is subject to risks and uncertainty, and thus may not enhance our ability to grow our business.

Pursuant to our right-of-first-offer agreement, 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. 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. 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.

Our gathering and compression and fresh water distribution systems are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating in one major geographic area.

We rely primarily on revenues generated from gathering and compression and fresh water distribution 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, water shortages or other drought related conditions 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, fresh water distribution, 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, fresh water distribution, 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, connect new fresh water distribution pipelines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

A shortage of equipment and skilled labor in the Appalachian Basin could reduce equipment availability and labor productivity and increase labor and equipment costs, which could have a material adverse effect on our business and results of operations.

Gathering and compression and fresh water distribution 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.

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 and the amount of fresh water we provide, 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:

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.

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."

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

All of Antero's natural gas, NGL 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 or reduce the number of wells drilled and completed that require fresh water for hydraulic fracturing activities, which in turn could materially adversely affect our revenues and results of operations.

Oil and natural gas producers' operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on the ability to obtain water or changes in wastewater disposal requirements may incentivize water recycling efforts by oil and natural gas producers, which would decrease the demand for our fresh water distribution services.

Our business includes fresh water distribution for use in our customers' natural gas, NGL and oil exploration and production activities. Water is an essential component of natural gas, NGL and oil production during the drilling, and in particular, the hydraulic fracturing process. We depend on Antero to source the fresh water we distributed. The availability of Antero's water supply may be limited due to reasons such as prolonged drought. Some state and local governmental authorities have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to ensure adequate local water supply. If Antero and other producers of natural gas, NGL and oil are unable to obtain water to use in their operations from local sources, they may be incentivized to recycle and reuse water, which would decrease the demand for fresh water distribution services. Any such decrease in the demand for fresh water distribution could adversely affect our business and results of operations.

Additionally, the fresh water distribution industry is subject to the introduction of alternative sources to water for fracturing fluids, such as treated waste water products and other existing or developing technologies. As competitors and others use or develop new technologies, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be

unable to implement new technologies or products at all, on a timely basis or at an acceptable cost. New technology could also make it easier for our customers to vertically integrate their operations, thereby reducing or eliminating the need for third-party water transportation. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition 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, compressor stations and fresh water distribution systems, 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.

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 potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards that will be established by the states or, in some cases, by the EPA 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 and believe that our monitoring activities are in substantial compliance with applicable reporting obligations. 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 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:

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.

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 and the distribution of fresh water, including:

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:

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.

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 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.

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 our average debt level of $ million, comprised of funds drawn on our new revolving credit facility, an increase of one percentage point in the interest rates will result in an increase in annual interest expense of $ 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.

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:

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:

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 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. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and

provisions 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. This provision 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."

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 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."

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 $ per common unit.

The assumed initial public offering price of $ per unit exceeds our pro forma net tangible book value of $ per unit. Based on the assumed initial public offering price of $ per unit, you will incur immediate and substantial dilution of $ 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."

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:

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.

Antero may sell 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 common units and all 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. The sale of these 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."

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 % 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. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%. 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 % 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 % 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:

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 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 publicly-traded common units (assuming no exercise of the underwriters' over-allotment option). In addition, Antero, an affiliate of our general partner, will own common units and subordinated units, representing an aggregate approximately % 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:

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

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.

In April 2012, President Obama signed into law the JOBS Act. 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.

We have applied to list our common units on the NYSE. 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 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.

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 our fresh water distribution services and certain other fluid handling activities satisfy the qualifying income requirements, 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.

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.

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—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."

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 of the total interests in our capital and

profits. Therefore, a transfer by Antero of all or a portion of its interests in us could, in conjunction with the trading of common units held by the public, result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once.

Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder's taxable year that includes our termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS recently announced a relief procedure whereby if a publicly-traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs. 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.

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:

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the gathering and compression and fresh water distribution businesses. 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.

We intend to use the anticipated net proceeds of approximately $ million from this offering (based on an assumed initial offering price of $ per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discounts and offering expenses, to (i) repay in full $ million of indebtedness that we will assume in connection with the contribution of Midstream Operating to us from Antero and (ii) reimburse Antero for $ million of capital expenditures incurred in connection with the Predecessor prior to Midstream Operating being contributed to us.

The indebtedness that we will assume will have been incurred under our Predecessor's existing midstream credit facility. As of , 2014 there was approximately $ 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) and bears interest at a variable rate, which was approximately % as of , 2014. 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. 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."

A $1.00 increase or decrease in the assumed initial public offering price of $ per common unit would cause the net proceeds from this offering, after deducting the estimated underwriting discount and offering expenses payable by us, to increase or decrease, respectively, by approximately $ million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of 1.0 million common units offered by us, together with a $1.00 increase in the assumed public offering price to $ per common unit, would increase net proceeds to us from this offering by approximately $ million. Similarly, each decrease of 1.0 million common units offered by us, together with a $ decrease in the assumed initial offering price to $ per common unit, would decrease the net proceeds to us from this offering by approximately $ million. Any increase or decrease in the net proceeds would change the amount of our reimbursement of Antero for its capital expenditures.

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

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 December 31, 2013

	Predecessor		Antero Midstream Partners LP
	Actual		Pro Forma
	(in thousands)
Cash and cash equivalents	$	—	$




Long-term debt:
New revolving credit facility⁽¹⁾	$	—	$	—


Total long-term debt		—		—
Total net equity-parent net investment/partners' capital:
Total net equity—parent net investment		732,061		—
Common units—public		—
Common units—Antero		—
Subordinated units—Antero		—
General partner interest⁽²⁾		—		—


Total partners' capital		732,061


Total capitalization	$	732,061	$

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. Assuming an initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover page of this prospectus), on a pro forma basis as of September 30, 2013, 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 $ million, or $ 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.

⁽¹⁾: Determined by dividing the pro forma net tangible book value of the contributed assets and liabilities by the number of units ( common units and subordinated units) to be issued to our general partner and its affiliates for their 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 ( common units and subordinated units) to be outstanding after the offering.
⁽³⁾: A $1.00 increase or decrease in the assumed initial public offering price of $ per common unit would increase or decrease, respectively, our pro forma net tangible book value by approximately $ million, or approximately $ per common unit, and dilution per common unit to investors in this offering by approximately $ per common unit, after deducting the estimated underwriting discount and offering expenses payable by us. We may also increase or decrease the number of common units we are offering. Each increase of 1.0 million common units offered by us, together with a $1.00 increase in the assumed initial offering price to $ per common unit, would result in a pro forma net tangible book value of approximately $ million, or $ per common unit, and dilution per common unit to investors in this offering would be $ per common unit. Similarly, each decrease of 1.0 million common units offered by us, together with a $1.00 decrease in the assumed initial public offering price to $ per common unit, would result in an pro forma net tangible book value of approximately $ million, or $ per common unit, and dilution per common unit to investors in this offering would be $ per common unit. The information discussed above is illustrative only and will be adjusted based on the actual public offering price, the number of common units offered by us and other terms of this offering determined at pricing.
⁽⁴⁾: 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.

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. 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.

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 $ per unit ($ 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 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.

Upon the consummation of this offering, our partnership agreement will provide for a minimum quarterly distribution of $ per unit for each whole quarter, or $ 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 $ million per quarter, or $ 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:

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 $ 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 , 2014, based on the actual length of the period.

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."

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 $ per unit for the twelve-month period ending March 31, 2015. In those sections, we present two tables, consisting of:

Unaudited Pro Forma Cash Available for Distribution for the Twelve-Month Period Ended December 31, 2013

Our unaudited pro forma available cash for the twelve-month period ended December 31, 2013 includes $34.0 million of general and administrative expenses, including $24.3 million of stock compensation expense allocated to us by Antero as well as an incremental $2.5 million of general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership. 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.

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 there is no guarantee that we would have had available cash sufficient to pay % of the minimum quarterly

distribution on all of 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 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 December 31, 2013, 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

	Twelve-Month Period Ended December 31, 2013 (In millions)

Operating Revenues:
Gathering and compression—affiliate	$	22.4
Fresh water distribution—affiliate		35.9


Total Operating Revenues	$	58.3


Operating Expenses:
Operating and maintenance	$	7.9
General and administrative (including $24.3 million of stock compensation)⁽¹⁾		34.0
Depreciation		14.1


Total Operating Expenses		56.0


Operating Income		2.3
Interest expense⁽²⁾		(7.5	)


Pro Forma Net Income:	$	(5.2	)


Add:
Depreciation		14.1
Interest expense⁽²⁾		7.5
Non-cash stock compensation expense		24.3


Pro Forma Adjusted EBITDA⁽³⁾	$	40.7
Less:
Cash interest expense⁽⁴⁾		(7.5	)
Expansion capital expenditures⁽⁵⁾		(597.3	)
Maintenance capital expenditures⁽⁶⁾		—
Incremental public partnership general and administrative expenses⁽⁷⁾		(2.5	)
Add:
Contributions from parent to fund expansion capital expenditures		597.3


Pro Forma Cash Available for Distribution	$	30.7

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

Pro Forma Cash Distributions:
Distribution per unit (based on a minimum quarterly distribution rate of $ per unit)
Aggregate distributions to:
Common units held by the public
Common units held by Antero
Subordinated units held by Antero
Total distributions to Antero


Total Distributions




Excess (Shortfall)




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 December 31, 2013.
⁽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 and permanent buried pipelines that increase the scope of our fresh water distribution system. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines, compressor stations and fresh water distribution infrastructure, in each case to the extent such capital expenditures are expected to expand our operating capacity or our operating income. 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 December 31, 2013.
⁽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 operating income. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain

Estimated Cash Available for Distribution for the Twelve-Month Period Ending March 31, 2015

We forecast that our estimated cash available for distribution during the twelve-month period ending March 31, 2015 will be approximately $191.8 million. This amount represents an increase of $161.1 million from the pro forma cash available for distribution for the twelve-month period ended December 31, 2013. This amount would exceed by $ million the amount needed to pay the minimum quarterly distribution of $ per unit on all of our common and subordinated units for the twelve-month period ending March 31, 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 and fresh water distribution 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 March 31, 2015. 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 March 31, 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, 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 March 31, 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 March 31, 2015.

	Twelve-Month Period Ending March 31, 2015 (In millions)

Operating Revenues:
Gathering and compression—affiliate	$	136.3
Fresh water distribution—affiliate		166.5


Total Operating Revenues	$	302.7


Operating Expenses:
Operating and maintenance	$	(58.4	)
General and administrative⁽¹⁾		(20.0	)
Depreciation		(75.8	)


Total Operating Expenses		(154.3	)


Operating Income		148.4
Interest expense⁽²⁾		(8.6	)


Net Income	$	139.8
Add:
Depreciation		75.8
Interest expense⁽²⁾		8.6


Adjusted EBITDA⁽³⁾		224.3
Less:
Cash interest expense⁽⁴⁾		(8.6	)
Expansion capital expenditures⁽⁵⁾		(656.3	)
Maintenance capital expenditures⁽⁶⁾		(23.8	)
Add:
Borrowings to fund expansion capital expenditures		656.3


Estimated Cash Available for Distribution	$	191.8

		Twelve-Month Period Ending March 31, 2015 (In millions, except per unit data)

Estimated Cash Distributions:
Distribution per unit (based on a minimum quarterly distribution rate of $ per unit)
Aggregate distributions to⁽⁷⁾:
Common units held by the public
Common units held by Antero
Subordinated units held by Antero
Total distributions to Antero


Total Distributions




Excess (Shortfall)




Percent of minimum quarterly distribution payable to common unitholders				%




Percent of minimum quarterly distribution payable to subordinated unitholders				%

⁽¹⁾: Comprised of approximately $17.5 million of general and administrative expenses allocated to us by Antero 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.
⁽²⁾: Interest expense includes assumed commitment fees on, and the amortization of assumed origination fees incurred in connection with, our new revolving credit facility and interest expense 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 assumed commitment fees on our revolving credit facility and assumed 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 and permanent buried pipelines that increase the scope of our fresh water distribution system. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines, compressor stations and fresh water distribution infrastructure, in each case to the extent such capital expenditures are expected to expand our operating capacity or our operating income. 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."

⁽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 operating income. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain gathering and compression or fresh water 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 $ per unit on an annualized basis assuming that the underwriters' option to purchase additional common units has not been exercised.

We believe our estimated available cash for distribution for the twelve-month period ending March 31, 2015 will not be less than $191.8 million. This amount of estimated minimum available cash for distribution is approximately $161.1 million more than the unaudited pro forma available cash for distribution for the twelve-month period ended December 31, 2013. 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, (ii) incremental development of in-service gathering pipelines and related compression infrastructure and (iii) an increase, proportionately and in the aggregate, of Antero's well completions utilizing our fresh water distribution services. 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.

The following table summarizes the pro forma volumes, fees, revenues, capital expenditures and Adjusted EBITDA for our gathering and compression and fresh water distribution segments during the

twelve-month period ended December 31, 2013, as well as our assumptions regarding those same amounts for the twelve-month period ending March 31, 2015:

	Pro Forma		Forecasted

	Twelve-Month Period Ended December 31, 2013		Twelve-Month Period Ending March 31, 2015
Gathering and Compression:
Low-pressure gathering volumes (Bcf)		61.4		261
Low-pressure gathering volumes (MMcf/d)		168		715
Low-pressure gathering fees ($/Mcf)	$	0.30	$	0.31	⁽¹⁾
High-pressure gathering volumes (Bcf)		11.7		217
High-pressure gathering volumes (MMcf/d)		32		596
High-pressure gathering fees ($/Mcf)	$	0.18	$	0.18	⁽¹⁾
Compression volumes (Bcf)		9.9		71
Compression volumes (MMcf/d)		27		194
Compression fees ($/Mcf)	$	0.18	$	0.18	⁽¹⁾
Segment revenues ($ in millions)	$	22.4	$	136.3
Segment capital expenditures ($ in millions)	$	395.5	$	517.9
Fresh Water Distribution:
Fresh water distribution volumes (MBbls)		10,481		46,419
Fresh water distribution fees ($/Bbl)⁽²⁾	$	3.42	$	3.59	⁽¹⁾
Segment revenues ($ in millions)	$	35.9	$	166.5
Segment capital expenditures ($ in millions)	$	201.9	$	162.2
Total:
Revenues ($ in millions)	$	58.3	$	302.7
Capital expenditures ($ in millions)	$	597.3	$	680.1
Adjusted EBITDA ($ in millions)⁽³⁾	$	40.7	$	224.3

We have assumed that all of our gathering and compression and fresh water distribution volumes and revenues during the twelve-month period ending March 31, 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 March 31, 2015 are further subject to the assumptions described below.

We estimate that our total revenues for the twelve-month period ending March 31, 2015 will be approximately $302.7 million, as compared to approximately $58.3 million for the pro forma twelve-month period ended December 31, 2013. Approximately 55% of these projected revenues are derived from fresh water distribution services while the remaining 45% are derived from gathering and compression systems in the Marcellus and Utica Shales.

We estimate that approximately 45%, or approximately $136.3 million, of our total revenue will be generated from gathering and compression services for the twelve-month period ending March 31, 2015. This compares to approximately 38%, or approximately $22.4 million, of our pro forma revenues that were generated from gathering and compression services during the twelve-month period ended December 31, 2013.

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 twelve-month period ending March 31, 2015 because we expect Antero's aggregate volumes during the period to be in excess of any such minimum volume commitments.

We estimate that approximately 55%, or approximately $166.5 million, of our total revenue will be generated from fresh water distribution for the twelve-month period ending March 31, 2015. We expect our fresh water distribution revenues to increase due to an increase in Antero's robust drilling program and an increased proportion of Antero's well completions that will utilize our fresh water distribution services. Because the necessity for fresh water is primarily driven by hydraulic fracturing activities conducted as part of well completions, our fresh water distribution revenues are not directly impacted by ongoing production volumes. We anticipate that up to 90% of Antero's 2014 well completions and 100% of Antero's 2015 well completions will utilize our fresh water distribution, as compared to only 57% of Antero's 2013 well completions.

We will receive a weighted average fee of $3.59 per barrel for fresh water we distribute directly from our storage facilities. Based on Antero's drilling plan for the twelve-month period ending March 31, 2015, we expect that we will make delivery to the well site by pipeline for all of Antero's fresh water needs that we fulfill, entitling us to the higher per-barrel fee under the fresh water distribution agreement. To the extent that expectation is not met, however, our weighted-average fee per barrel would be lower.

During the twelve-month period ending March 31, 2015, Antero anticipates completing 135 wells in the Marcellus Shale for which we will provide fresh water distribution services. A typical Antero Marcellus Shale well includes a 7,000 foot horizontal lateral and shorter stage lengths. We expect our fresh water distribution services will generate between $650,000 and $700,000 of revenue for each well Antero completes in the Marcellus Shale. Antero's average lateral length for the wells expected to be completed during the twelve-month period ending March 31, 2015 is approximately 7,600 feet. For the twelve-month period ending March 31, 2015, we expect to transport 34.5 million barrels of water by pipeline in the Marcellus Shale, which equates to approximately $123.7 million in revenues.

During the twelve-month period ending March 31, 2015, Antero anticipates completing 42 wells in the Utica Shale for which we will provide fresh water distribution services. A typical Antero Utica

Shale well includes a 7,000 foot horizontal lateral and shorter stage lengths. We expect our fresh water distribution services will generate between $700,000 and $750,000 of revenue for each well Antero completes in the Utica Shale. Antero's average lateral length for the expected wells to be drilled during the period is approximately 7,300 feet. For the twelve-month period ending March 31, 2015, we expect to transport 11.9 million barrels of water by pipeline in the Utica Shale, which equates to approximately $42.8 million in revenues.

We estimate that operating and maintenance expense for the twelve-month period ending March 31, 2015 will be $58.4 million. Our increase in operating and maintenance expense is primarily due to our significantly higher activity levels, including higher:

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 March 31, 2015 will be $20.0 million. 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 March 31, 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.

General and administrative expenses for the twelve-month period ending March 31, 2015 does not include the effect of any allocation to us of the $ million non-cash stock compensation expense that Antero recognized in connection with its initial public offering in the fourth quarter of 2013 or the $ million that it will recognize over the remaining service period of certain incentive units in Antero Investment for which distributions will be made from Antero Investment to Antero Resources Employee Holdings LLC. However, because those charges are non-cash only, they have no effect on our estimated cash available for distribution for either period.

We estimate that depreciation expense for the twelve-month period ending March 31, 2015 will be $75.8 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 March 31, 2015.

The gathering and compression and fresh water distribution businesses are 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:

We estimate that total capital expenditures for the twelve-month period ending March 31, 2015 will be $680.1 million, based on the following assumptions.

We estimate that expansion capital expenditures for the twelve-month period ending March 31, 2015 will be $656.3 million. During the twelve-month period ending March 31, 2015, we have assumed that we will fund our expansion capital expenditures with borrowings under our new revolving credit facility. 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 March 31, 2015 will drive our need for expansion capital expenditures on our low-pressure gathering and fresh water distribution 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 March 31, 2015:

We estimate that maintenance capital expenditures will be $23.8 million for the twelve-month period ending March 31, 2015. We expect to fund these maintenance capital expenditures with cash generated by our operations.

For at least the next several years, we believe that the expansion of our throughput capacity will more than offset any expected throughput decline, including declines attributable to natural production declines. We calculate maintenance capital expenditures for each quarter accordingly:

As a result of its largely consolidated acreage positions in the Marcellus and Utica Shales, much of Antero's robust drilling program utilizes pad drilling. Antero's pad drilling program allows us to distribute fresh water for Antero's completion activities in a more efficient manner because we are able to use existing permanent pipelines to distribute fresh water to multiple well completions located on the same pad. Similarly, Antero's consolidated acreage positions in the Appalachian Basin allows us to use existing compression and high-pressure infrastructure once connected to the pad by newly constructed low-pressure gathering pipelines. As a result, we believe that we will be able to gather a greater amount of future production from existing high-pressure gathering, compression and permanent fresh water distribution infrastructure. Finally, both our gathering and compression and fresh water distribution systems are relatively new, having been substantially built within the last two years. We believe that these factors should result in relatively low maintenance capital expenditures in the future.

We estimate that interest expense will be approximately $8.6 million for the twelve-month period ending March 31, 2015. Our interest expense for the twelve-month period ending March 31, 2015 is based on the following assumptions:

Our estimated cash available for distribution for the twelve-month period ending March 31, 2015 is based on the following significant additional assumptions:

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 , 2014, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $ per unit, or $ 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 , 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 $ 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.

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,

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.

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 $ 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

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:

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"):

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 $ 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.

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 operating income. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain gathering and compression or fresh water 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 and permanent buried pipelines that increase the scope of our fresh water distribution system. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines, compressor stations and fresh water distribution infrastructure, 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 existing operating capacity or operating income, but which are not expected to expand, for more than the short term, our operating capacity or operating income.

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.

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.

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 $ 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.

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 , 2017, if each of the following has occurred:

For the period after closing of this offering through , 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.

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 , 2015, if each of the following has occurred:

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 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:

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.

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:

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:

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 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.

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:

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 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.

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 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:

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 $ .

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 the reset there would be common units outstanding and the distribution to each common unit would be $ for the quarter prior to the reset.

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 common units outstanding and the distribution to each common unit would be $ . 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 $ , by (2) the cash distributed on each common unit for the quarter prior to the reset as shown in the table above, or $ .

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.

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

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:

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 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.

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.

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:

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.

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:

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.

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 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.

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. This prospectus also includes selected pro forma financial data as of and for the year ended December 31, 2013. 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 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 selected pro forma financial data presented as of and the year ended December 31, 2013 was derived from the audited 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

	Year Ended December 31,									Pro Forma
	Year Ended December 31,									Year Ended December 31, 2013
	2011			2012			2013			Year Ended December 31, 2013
	(in thousands, except per unit amounts)
Statement of Operations Data:
Revenue:
Gathering and compression—affiliate	$	441		$	647		$	22,363		$	22,363
Fresh water distribution—affiliate		—			—			35,871			35,871


Total revenue		441			647			58,234			58,234


Operating expenses:
Direct operating expenses		802			698			7,871			7,871
General and administrative expenses (including $24,349 of stock compensation in 2013)		397			2,977			34,065			34,065
Depreciation expense		997			1,679			14,119			14,119


Total operating expenses		2,196			5,354			56,055			56,055


Operating income (loss)		(1,755	)		(4,707	)		2,179			2,179
Interest expense		2			8			164			7,459


Net income (loss)	$	(1,757	)	$	(4,715	)	$	2,015		$	(5,280	)




Pro forma basic earnings per unit⁽¹⁾
Pro forma diluted earnings per unit⁽¹⁾
Balance Sheet Data (at period end):
Cash and cash equivalents				$	—		$	—		$	—
Property and equipment, net					180,249			793,330			793,330
Total assets					180,408			808,337			809,337
Long-term liabilities					320			6,062			6,062
Total net equity—parent net investment					144,897			732,061			733,061
Cash Flow Data:
Net cash provided by (used in) operating activities	$	(618	)	$	(3,236	)	$	29,664
Net cash used in investing activities		(15,795	)		(117,652	)		(597,349	)
Net cash provided by financing activities		16,413			120,888			567,685
Other Financial Data: (unaudited)
Adjusted EBITDA⁽²⁾	$	(758	)	$	(3,028	)	$	40,647		$	40,647

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

	Year Ended December 31,

	2011		2012		2013
Operating Data:
Gathering—low pressure (MMcf)		1,703		2,320		61,406
Gathering—high pressure (MMcf)		—		—		11,736
Compression (MMcf)		—		—		9,900
Fresh water distribution (MBbl)		—		—		10,481
Gathering—low pressure (MMcf/d)		5		6		168
Gathering—high pressure (MMcf/d)		—		—		32
Compression (MMcf/d)		—		—		27
Fresh water distribution (MBbl/d)		—		—		29
Average realized fees:
Average gathering—low pressure fee ($/Mcf)	$	0.26	$	0.28	$	0.30
Average gathering—high pressure fee ($/Mcf)		—		—	$	0.18
Average compression fee ($/Mcf)		—		—	$	0.18
Average fresh water distribution ($/Bbl)		—		—	$	3.42

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

	Predecessor

	Year Ended December 31,									Pro Forma
	Year Ended December 31,									Year Ended December 31, 2013
	2011			2012			2013			Year Ended December 31, 2013
	($ in thousands)
Net income (loss)	$	(1,757	)	$	(4,715	)	$	2,015		$	(5,280	)
Add:
Interest expense		2			8			164			7,459
Income tax expense		—			—			—			—
Depreciation expense		997			1,679			14,119			14,119
Stock compensation expense		—			—			24,349			24,349


Adjusted EBITDA	$	(758	)	$	(3,028	)	$	40,647		$	40,647




Less:
Interest expense		(2	)		(8	)		(164	)
Changes in operating assets and liabilities which used (provided) cash		142			(200	)		(10,819	)


Net cash provided by (used in) operating activities	$	(618	)	$	(3,236	)	$	29,664

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

You should read the following discussion of our historical performance, financial condition and future prospects in conjunction with our audited financial statements as of December 31, 2012 and 2013 and for the years ended December 31, 2011, 2012 and 2013, our unaudited pro forma financial statements as of and for the the year ended December 31, 2013 and the notes thereto, included elsewhere in this prospectus. The information provided below supplements, but does not form part of, our financial statements. This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact our future operating performance or financial condition, please read the sections entitled "Risk Factors" and "Cautionary Statement Regarding Forward-Looking Statements."

We are a growth-oriented limited partnership formed by Antero to own, operate and develop midstream energy assets to service Antero's rapidly increasing production. Our assets consist of gathering pipelines, compressor stations and fresh water distribution systems, through which we provide midstream services to Antero under long-term, fixed-fee contracts. Our assets are located in the rapidly developing liquids-rich southwestern core of the Marcellus Shale in northwest West Virginia and 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.

Our revenues are driven by the volumes of natural gas we gather and compress and the volume of fresh water we distribute. Pursuant to our long-term contracts with Antero, we have secured 20-year dedications covering (i) substantially all of Antero's current and future acreage for gathering and compression services and (ii) all of Antero's current and future acreage for fresh water distribution for well completion operations. All of Antero's existing acreage is dedicated to us for gathering and compression services except for the existing third-party commitments, which includes 128,000 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 contracts cover approximately 329,000 net leasehold acres held by Antero as of February 28, 2014 for gathering and compression services and all 457,000 of Antero's existing net leasehold acres for fresh water distribution services. In addition to Antero's existing acreage dedication, our agreements provide that any acreage Antero acquires in the future will be dedicated to us for gathering and compression and fresh water distribution services. Although we do not currently have any condensate gathering infrastructure, we may provide such services to Antero in the future under the gathering and compression agreement. We also 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. As a result of Antero's acreage dedication and its contribution to us of substantially all of its midstream assets in connection with this offering, we believe that we possess significant organic growth potential and, unlike many other midstream companies, our growth does not depend on future acquisitions of assets from our sponsor or third parties. Please read "Certain Relationships and Related Transactions—Other Contractual Relationships with Antero."

Our gathering and compression operations are substantially dependent upon natural gas production from Antero's upstream activity in its areas of operation. In addition, there is a natural

decline in production from existing wells that are connected to our gathering systems. Although we expect that Antero will continue to devote substantial resources to the development of oil and gas reserves, we have no control over this activity and Antero has the ability to reduce or curtail such development at its discretion. Please read "Our Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending March 31, 2015—Assumptions and Considerations."

Our fresh water distribution operations are substantially dependent upon the number of wells drilled and completed by Antero. As of December 31, 2013, Antero's estimated net proved, probable and possible reserves were 7.6 Tcfe, 19.8 Tcfe and 7.5 Tcfe, respectively, of which 85% was natural gas. As of December 31, 2013, Antero's drilling inventory consisted of 4,778 identified potential horizontal well locations (2,978 of which were located on acreage dedicated to us) for gathering and compression services, which provides us with significant opportunity 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 20 operated rigs, including 15 operated rigs in the Marcellus Shale (where it is the most active driller) and 5 operated rigs in the Utica Shale (where it is one of the most active drillers). On January 29, 2014, Antero announced a 2014 drilling and completion capital expenditures budget of approximately $1.8 billion that provides for the drilling of approximately 193 wells, a substantial increase over the 157 wells drilled in 2013. Antero's Appalachian production during 2013 represented an increase 118% as compared to 2012, and its net production in the fourth quarter of 2013 is expected to average between 675 and 680 MMcfe/d. We anticipate that Antero's robust drilling program will significantly increase throughput on our gathering and compression systems and will result in a significant demand for our fresh water distribution services. Antero relies on us to deliver the midstream infrastructure necessary to accommodate its continuing production growth, which should provide us with significant increases in throughput volumes.

Because fresh water distribution revenues are dependent upon well completions and do not benefit from cumulative production in the way that gathering and compression revenues do, we expect that fresh water distribution will represent relatively less of our aggregate revenues over time.

We believe that meaningful growth in our revenues over the short term will be driven primarily by (i) higher natural gas throughput volumes resulting from Antero's robust drilling program, (ii) incremental development of in-service gathering pipelines and related compression infrastructure and (iii) an increase, proportionately and in the aggregate, of Antero's well completions utilizing our fresh water distribution services.

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 and fresh water for their well completions.

We use a variety of financial and operational metrics to evaluate our performance. These metrics help us identify factors and trends that impact our operating results, profitability and financial condition. The key metrics we use to evaluate our business are provided below.

Adjusted EBITDA is a non-GAAP financial measure. The GAAP measures most directly comparable to Adjusted EBITDA are net income (loss) 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 (loss). 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 (loss). 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. 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 "Summary—Non-GAAP Financial Measure."

We must continually obtain additional supplies of natural gas to maintain or increase throughput on our systems. Our ability to maintain existing supplies of natural gas and obtain additional supplies is primarily impacted by our acreage dedication and the level of successful drilling activity by Antero and, to a lesser extent in the future, the potential for acreage dedications with and successful drilling by

third party producers. Any increase in our throughput volumes over the near term will likely be driven by Antero continuing its robust drilling and development activities in its Marcellus and Utica Shale acreage. In the short term, we expect increases in high-pressure gathering and compression throughput volumes to be less than that for low-pressure gathering revenues, in part because a percentage of Antero's high-pressure gathering needs will be met by existing third-party high-pressure gathering pipelines.

Because the necessity for fresh water is primarily driven by hydraulic fracturing activities conducted as part of well completions, our fresh water throughput volumes are not directly impacted by ongoing production volumes. Antero's consolidated acreage positions allow us to distribute fresh water for Antero's completion activities in a more efficient manner. However, to the extent that Antero's drilling and completion schedule is not met, or Antero uses less fresh water in its well completion operations than expected (for example, as a result of drilling shorter laterals), our fresh water throughput volumes may decline.

The historical financial results of our Predecessor discussed below may not be comparable to our future financial results primarily as a result of the significant increase in the scope of our operations over the last several years. Both our gathering and compression and fresh water distribution systems are relatively new, having been substantially built within the last two years. Accordingly, our revenues and expenses over that time reflect the significant ramp up in our operations. Similarly, Antero has experienced significant growth in its production and drilling and completion schedule over that same period. Accordingly, it may be difficult to project trends from our historical financial data going forward.

The primary components of our operating expenses that we evaluate include direct operating expense, general and administrative, depreciation and interest expense.

We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs, water disposal, pigging, fuel, monitoring costs, repair and non-capitalized maintenance costs, utilities and contract services comprise the most significant portion of our direct operating expense. We will seek to schedule maintenance over time to avoid significant variability in our direct operating expense and minimize the impact on our cash flow. The primary drivers of our direct operating expense include:

Our Predecessor's general and administrative expenses included costs allocated by Antero. These costs were related to: (i) business services, including payroll processing, accounts payable processing and facilities management, (ii) corporate services, including legal, accounting, treasury, information technology and human resources and (iii) compensation and share-based compensation costs. These costs were charged to our Predecessor based on the nature of the expenses and were allocated based on its proportionate share of Antero's gross property, plant and equipment, capital expenditures and direct labor costs as applicable. Management believes these allocation methodologies are reasonable. Following the closing of this offering, Antero will continue to charge us a combination of direct and allocated charges for administrative and operational services based on a similar methodology.

General and administrative expenses include an allocation of compensation expense associated with grants under Antero's long-term incentive plan and any compensation expense associated with grants under our own plan. In addition, we will be allocated a portion of the $365 million non-cash stock compensation expense that Antero recognized in connection with its initial public offering in the fourth quarter of 2013. We will be allocated a portion of the $121 million that will be recognized over the remaining service period of certain incentive units.

We anticipate incurring approximately $2.5 million of incremental general and administrative expenses attributable to operating as 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. These incremental general and administrative expenses are not reflected in our Predecessor's historical or our pro forma financial statements.

Depreciation expense consists of our estimate of the decrease in value of the assets capitalized in property and equipment as a result of using the assets throughout the applicable year. Depreciation is computed over the asset's estimated useful life using the straight-line basis. Gathering pipelines and compressor stations are depreciated over a 20 year useful life. Fresh water distribution systems are depreciated over a 5 to 20 year useful life. Specifically, we use a useful life of 5 years for our above-ground temporary water distribution pipelines and a useful life of 20 years for our permanent underground water distribution pipelines.

Our Predecessor has financed a portion of our equipment, compressor stations and pumps through various capital lease agreements at fixed interest rates ranging from 2.5% to 6.6%. We expect to continue to incur interest expense from our capital lease arrangements as we continue to grow.

In connection with the completion of this offering, we will assume $ million of indebtedness in connection with the contribution of the Midstream Operating to us and use a portion of the proceeds of this offering to repay in full that indebtedness. In addition, in connection with the completion of this offering, we intend to enter into a new revolving credit facility and will incur interest on amounts borrowed thereunder. Please read "—Liquidity and Capital Resources—Debt Agreements and Contractual Obligations."

The Predecessor's financial statements do not include an allocation of income tax as we expect that we will be treated as a partnership for federal and state income tax purposes, with each partner being taxed separately on its share of the taxable income.

The following table sets forth selected operating data for the year ended December 31, 2012 compared to the year ended December 31, 2013:

	Year ended December 31,

	Year ended December 31,					Amount of Increase
	2012			2013		Amount of Increase
	($ in thousands, except average realized fees)
Revenue:
Gathering and compression—affiliate	$	647		$	22,363	$	21,716
Fresh water distribution—affiliate		—			35,871		35,871


Total revenue		647			58,234		57,587


Operating expenses:
Direct operating expenses:
Gathering and compression		652			2,079		1,427
Fresh water distribution		46			5,792		5,746


Total direct operating expenses		698			7,871		7,173
General and administrative expenses (including $24,349 of stock compensation in 2013)		2,977			34,065		31,088
Depreciation expense:
Gathering and compression		1,679			11,346		9,667
Fresh water distribution		—			2,773		2,773


Total depreciation expense		1,679			14,119		12,440


Total operating expenses		5,354			56,055		50,701


Operating income (loss)		(4,707	)		2,179		6,886
Interest expense		8			164		156


Net income (loss)	$	(4,715	)	$	2,015	$	6,730




Adjusted EBITDA(1)	$	(3,028	)	$	40,647	$	43,675
Operating Data:
Gathering—low pressure (MMcf)		2,320			61,406		59,086
Gathering—high pressure (MMcf)		—			11,736		11,736
Compression (MMcf)		—			9,900		9,900
Fresh water distribution (MBbl)		—			10,481		10,481
Gathering—low pressure (MMcf/d)		6			168		162
Gathering—high pressure (MMcf/d)		—			32		32
Compression (MMcf/d)		—			27		27
Fresh water distribution (MBbl/d)		—			29		29
Average realized fees:
Average gathering—low pressure fee ($/Mcf)	$	0.28		$	0.30	$	0.02
Average gathering—high pressure fee ($/Mcf)		*		$	0.18	$	0.18
Average compression fee ($/Mcf)		*		$	0.18	$	0.18
Average fresh water distribution ($/Bbl)		*		$	3.42	$	3.42

Fresh water distribution revenue—affiliate. Revenues from fresh water distribution increased from zero for the year ended December 31, 2012 to $35.9 million for the year ended December 31, 2013. The increase was due to the completion of a portion of the fresh water distribution systems in 2013.

Direct operating expenses. Total direct operating expenses increased from $0.7 million for the year ended December 31, 2012 to $7.9 million for the year ended December 31, 2013, an increase of $7.2 million. On a segment basis:

General and administrative expenses. General and administrative expenses (before stock compensation) increased from $3.0 million for the year ended December 31, 2012 to $9.7 million for the year ended December 31, 2013, an increase of $6.7 million. The increase was primarily as a result of increased staffing levels and related salary and benefits expenses and increases in legal and other general corporate expenses and the related allocation of direct and indirect costs to our Predecessor. The increase was also attributable to an increase in staff required to support our increase in capital expenditure activity which included the construction of the fresh water distribution system that was placed in service in 2013.

Stock compensation expense increased from zero for the year ended December 31, 2012 to $24.3 million for the year ended December 31, 2013, an increase of $24.3 million, due to an allocation of Antero's stock compensation expense to the Predecessor. Antero recognized noncash stock compensation expense of approximately $365 million, almost all of which was related to the interests of its employees in Antero Employee Holdings LLC ("Employee Holdings"), which owns interests in Antero Investment LLC ("Antero Investment"). Prior to Antero's IPO, the interests of Employee Holdings were subject to performance and service conditions which could be met generally only in the event of a liquidation or distribution event. In connection with Antero's IPO, the terms of the Antero Investment operating agreement provided for a mechanism by which the shares of Antero's common stock to be allocated amongst the members of Antero Investment, including Employee Holdings, will be specifically determined. As a result, the satisfaction of all performance and service conditions relative to the membership interests of Employee Holdings in Antero Investment became probable.

Accordingly, Antero recognized approximately $365 million of stock compensation expense in 2013 relative to these interests and will recognize approximately another $121 million over the remaining expected service period.

Depreciation expense. Total depreciation expense increased from $1.7 million for the year ended December 31, 2012 to $14.1 million for the year ended December 31, 2013, an increase of $12.4 million. On a segment basis:

Interest expense. Interest expense increased from less than $0.1 million for the year ended December 31, 2012 to $0.2 million for the year ended December 31, 2013, primarily due to the addition of $7.8 million in borrowings related to additional capital leases in 2013.

Adjusted EBITDA. Adjusted EBITDA increased from $(3.0) million for the year ended December 31, 2012 to $40.7 million for the year ended December 31, 2013, an increase of $43.6 million. The increase is primarily due to an increase in gathering and compression throughput volumes and the completion of a portion of the fresh water distribution systems in 2013.

In early 2013, we completed and placed a portion of our fresh water distribution systems into operation. We had no fresh water distribution operations during the years ended December 31, 2011 or 2012, except for $6.9 million in capital expenditures in 2012 for the construction of the fresh water distribution systems and related ad valorem taxes.

The following table sets forth selected operating data for the year ended December 31, 2011 compared to the year ended December 31, 2012:

	Year ended December 31,

	Year ended December 31,						Amount of Increase (Decrease)
	2011			2012			Amount of Increase (Decrease)
	($ in thousands, except average realized fees)
Revenue:
Gathering and compression—affiliate	$	441		$	647		$	206


Total revenue		441			647			206


Operating expenses:
Direct operating expenses:
Gathering and compression		802			652			(150	)
Fresh water distribution		—			46			46


Total direct operating expenses		802			698			(104	)
General and administrative expenses		397			2,977			2,580
Depreciation expense		997			1,679			682


Total operating expenses		2,196			5,354			3,158


Operating loss		(1,755	)		(4,707	)		(2,952	)
Interest expense		2			8			6


Net loss	$	(1,757	)	$	(4,715	)	$	(2,958	)




Adjusted EBITDA	$	(758	)	$	(3,028	)	$	(2,270	)
Operating Data:
Gathering—low pressure (MMcf)		1,703			2,320			617
Gathering—low pressure (MMcf/d)		5			6			1
Average realized fees
Average gathering—low pressure fee ($/Mcf)	$	0.26		$	0.28		$	0.02

Gathering and compression revenue—affiliate. Revenues from gathering and compression of natural gas increased from $0.4 million for the year ended December 31, 2011 to $0.6 million for the year ended December 31, 2012, an increase of $0.2 million, primarily due to an increase of throughput volumes of 617 MMcf, or 1 MMcf/d, which is primarily due to an increase in volumes gathered. The increase was also due to an increase in the average realized price of $0.02/Mcf.

Direct operating expenses. Total direct operating expenses decreased from $0.8 million for the year ended December 31, 2011 to $0.7 million for the year ended December 31, 2012, a decrease of $0.1 million. The decrease was primarily due to a decrease in water disposal costs as the wells produced less water partially offset by an increase of less than $0.1 million due to ad valorem tax expense related to the fresh water distribution assets in West Virginia.

General and administrative expenses. General and administrative expenses increased from $0.4 million for the year ended December 31, 2011 to $3.0 million for the year ended December 31,

2012, an increase of $2.6 million. The increase was primarily a result of increased staffing levels and related salary and benefits expenses and increases in legal and other general corporate expenses and the related allocation of direct and indirect costs to our Predecessor. The increase was also attributable to an increase in staff required to support our increase in capital expenditure activity which included the initial construction of the new fresh water distribution systems.

Depreciation expense. Depreciation expense increased from $1.0 million for the year ended December 31, 2011 to $1.7 million for the year ended December 31, 2012, an increase of $0.7 million. The increase was primarily due to approximately $49.7 million in gathering and compression capital assets being placed in service and depreciated in 2012 and a full period of depreciation for the capital assets placed in service during 2011.

Interest expense. Interest expense remained relatively constant for the year ended December 31, 2011 compared to the year ended December 31, 2012, there were only $0.3 million in borrowings related to a new capital lease in 2012.

Adjusted EBITDA. Adjusted EBITDA decreased from $(0.8) million for the year ended December 31, 2011 to $(3.0) million for the year ended December 31, 2012, a decrease of $2.2 million. The decrease is primarily due to an increase in general and administrative expense.

Historically, our sources of liquidity included cash generated from operations and funding from Antero. We historically participated in Antero's centralized cash management program for all periods presented, whereby excess cash from most of its subsidiaries was swept into a centralized account. Sales and purchases related to our Predecessor third-party transactions were received or paid in cash by Antero within the centralized cash management system. In the future, we will maintain our own bank accounts and sources of liquidity and will utilize Antero's cash management system and expertise.

Capital and liquidity will be provided by operating cash flow and borrowings under our new revolving credit facility, discussed below. We expect cash flow from operations to continue to contribute to our liquidity in the future. In connection with the completion of this offering, we will assume the $ million of borrowings in connection with the contribution to us and use a portion of the proceeds of this offering to repay them in full. However, other sources of liquidity will include borrowing capacity under the new $ million revolving credit facility we intend to enter into in connection with the closing of this offering and proceeds from the issuance of additional limited partner units. We expect the combination of these capital resources will be adequate to meet our short-term working capital requirements, long-term capital expenditures program and expected quarterly cash distributions.

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute at least the quarterly distribution of $ per unit ($ 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. We expect our future cash requirements relating to working capital, maintenance capital expenditures and quarterly cash distributions to our partners will be funded from cash flows internally generated from our operations. Our expansion capital expenditures will be funded by borrowings under our new revolving credit facility or from potential capital market transactions.

The following table and discussion presents a summary of our Predecessor's combined net cash provided by or used in operating activities, investing activities and financing activities for the periods indicated.

Net cash used in operating activities was $3.2 million for the year ended December 31, 2012 and net cash provided by operating activities was $29.7 million for the year ended December 31, 2013. The increase in cash flow from operations for the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily the result of increased throughput volumes and revenues, which includes the addition of new high-pressure gathering and compression and fresh water distribution capacity in 2013.

Net cash used in operating activities was $0.6 million and $3.2 million for the years ended December 31, 2011 and 2012, respectively. The increase in cash flows used in operations from 2011 to 2012 was primarily the result of increased operating expenses.

During the year ended December 31, 2012, we used cash flows in investing activities totaling $117.7 million for expenditures for gathering systems, compressor stations and fresh water distribution systems. During the year ended December 31, 2013, we used cash flows in investing activities totaling $597.3 million for expenditures for low-pressure gathering systems, compressor stations and fresh water distribution systems.

During the year ended December 31, 2011, we used cash flows in investing activities totaling $15.8 million for expenditures for gathering systems and compressor stations. During the year ended December 31, 2012, we used cash flows in investing activities totaling $117.7 million for expenditures for gathering systems, compressor stations and fresh water distribution systems.

Net cash provided by financing activities for the year ended December 31, 2013 of $567.7 million is the result of $560.8 million in parent contributions and $7.8 million in borrowings on capital leases offset by $0.9 million for payments on capital leases.

Net cash provided by financing activities for the year ended December 31, 2012 of $120.9 million is the result of parent contributions and $0.3 million in borrowings on capital leases offset by less than $0.1 million for payments on capital leases.

Net cash provided by financing activities for the year ended December 31, 2011 of $16.4 million is the result of $16.3 million in parent contributions and $0.1 million in borrowings on capital leases.

The gathering and compression and fresh water distribution businesses are capital intensive, requiring significant investment for the maintenance of existing assets and the development of new systems and facilities. We categorize our capital expenditures as either:

As more completely discussed in "Our Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations," for the twelve-month period ending March 31, 2015, we estimate that our maintenance and expansion capital expenditures will total approximately $680.1 million.

Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us. We expect our future cash requirements relating to working capital, maintenance capital expenditures and quarterly cash distributions to our partners will be funded from cash flows internally generated from our operations. Our growth or expansion capital expenditures will be funded by borrowings under our new revolving credit facility or from potential capital market transactions.

Our Predecessor entered into a midstream credit facility on February 28, 2014. Borrowings under the midstream credit facility are limited to an aggregate of $300.0 million and as of , 2014, there were approximately $ million of borrowings outstanding. In connection with the contribution of the Predecessor to us, we will repay all $ million of the indebtedness that we will assume.

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:

Our new revolving credit facility also is expected to contain covenants requiring us to maintain certain financial ratios.

The following table presents our contractual obligations by period as of December 31, 2013. Our obligations to make payments in the future may vary due to certain assumptions including the duration of our obligations and anticipated actions by third parties.

The following discussion relates to the critical accounting policies and estimates for both us and our Predecessor. The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See note 2 to the financial statements for a discussion of additional accounting policies and estimates made by management.

or fair value, if impaired. We capitalize construction-related direct labor and material costs. Maintenance and repair costs are expensed as incurred.

Depreciation is computed over the asset's estimated useful life using the straight-line method, based on estimated useful lives and salvage values of assets. Gathering pipelines and compressor stations are depreciated over a 20 year useful life. Fresh water distribution systems are depreciated over a 5 to 20 year useful life. Specifically, we use a useful life of 5 years for our above-ground temporary water distribution pipelines and a useful life of 20 years for our permanent underground water distribution pipelines. The depreciation of fixed assets recorded under capital lease agreements is included in depreciation expense. Uncertainties that may impact these estimates include, among others, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are placed into service, management makes estimates with respect to useful lives and salvage values that management believes are reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts.

General and administrative costs were allocated to the Predecessor based on the nature of the expenses and are allocated based on our proportionate share of Antero's gross property and equipment, capital expenditures and direct labor costs, as applicable. These allocations are based on estimates and assumptions that management believes are reasonable.

Stock-based compensation expenses were allocated to the Predecessor based on our proportionate share of Antero's direct labor costs. These allocations are based on estimates and assumptions that management believes are reasonable.

As of December 31, 2013, we did not have any off-balance sheet arrangements other than operating leases.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term "market risk" refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

The gathering and compression and fresh water distribution agreements with Antero provide for fixed-fee structures, and we intend to continue to pursue additional fixed-fee opportunities with Antero and third parties in order to avoid direct commodity price exposure. However, to the extent that our future contractual arrangements with Antero or third parties do not provide for fixed-fee structures, we may become subject to commodity price risk. Please read "Risk Factors—Risks Related to Our Business—Our exposure to commodity price risk may change over time."

As described above, in connection with the closing of this offering, we intend to enter into a new $ million revolving credit facility. We may or may not hedge the interest on portions of our

borrowings under the credit facility from time-to-time in order to manage risks associated with floating interest rates.

We are dependent on Antero as our only customer, and we expect to derive a substantial majority of our revenues from Antero for the foreseeable future. As a result, any event, whether in our area of operations or otherwise, that adversely affects Antero's production, drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect our revenues and cash available for distribution.

Further, we are subject to the risk of non-payment or non-performance by Antero, including with respect to our gathering and compression and fresh water distribution agreements. 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 to perform under our agreements. Any material non-payment or non-performance by Antero could reduce our ability to make distributions to our unitholders. Please read "Risk Factors—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."

The midstream natural gas industry provides the link between the exploration and production of natural gas from the wellhead and the delivery of natural gas and its by-products to industrial, commercial and residential end-users. Companies generate revenues at various links within the midstream value chain by gathering, compressing, processing, treating, fractionating, transporting, storing and marketing natural gas and NGLs. The following diagram illustrates the various components of the midstream value chain:

The services provided by us are generally classified into the categories described below.

Gathering. At the initial stages of the midstream value chain, a network of small diameter pipelines known as gathering systems connect to wellheads and other receipt points in the production area. These gathering systems transport natural gas and oil from the wellhead and other receipt points either to treating and processing plants or directly to interstate or intrastate pipelines. A large gathering system may involve thousands of miles of gathering pipelines connected to thousands of wells and other receipt points. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures. Gathering systems are operated at design pressures that maximize the total throughput from all connected wells.

Compression. Natural gas compression is a mechanical process that involves increasing the pressure of natural gas in order to allow for more natural gas to flow through the same diameter pipeline and to enable delivery into higher pressure long-haul pipeline systems. Field compression is typically used to lower the natural gas pressure at the entry point of a gathering system, while providing sufficient pressure upon exit of the gathering system to deliver natural gas into higher pressure long-haul pipeline systems. Because wells produce at progressively lower field pressures as the

underlying resources are depleted, field compression is required to maintain sufficient pressure across the gathering system.

Processing and Treating. After the natural gas has been gathered, it is usually treated to remove impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide. These impurities must be removed for the natural gas to meet the specifications for transportation on interstate and intrastate pipelines. Additionally, natural gas containing significant amounts of NGLs must be processed to remove these heavier hydrocarbon components. NGLs not only interfere with pipeline transportation, but are also valuable commodities once removed from the natural gas stream and fractionated into their key components.

Water is an essential part of the exploration and production process. The diagram below illustrates the use and disposal of water during the oil and natural gas drilling, completion and production phases:

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. When the pressure exceeds the rock strength, the fractures in the rock formation open or extend up to several hundred feet, thereby increasing the flow of oil and natural gas into the wellbore. The proppant holds the fractures in the shale rock formation open when the pressure is released, which allows hydrocarbons and water to flow up to the surface.

Water and sand (or other proppants) make up more than 99.5% of the fluid used to fracture a well. A majority of the water used in the hydraulic fracturing process is sourced from surface water (including lakes, rivers and municipal water supplies). Groundwater is also used for the fracturing process when it is available in adequate quantities. In the Marcellus Shale, some states control water through commissions like the Susquehanna River Basin Commission and the Delaware River Basin Commission, while in other areas individuals can sell the water.

We do not intend to transport produced water through our fresh water distribution system.

The two primary sources of fresh water for well completions are (i) lakes, municipal reservoirs and similar bodies and (ii) watercourses, such as rivers and streams. In both the Marcellus and Utica Shales, these sources are reasonably well distributed across the plays. However, the sources vary significantly with respect to their reliability, with some sources being significantly more affected by factors such as changes in rainfall, weather and withdrawal rates. The primary sources of fresh water in the Marcellus and Utica Shales include the Susquehanna River basin, the Delaware River basin and the Ohio River basin. The Ohio River, which sources much of Antero's fresh water for our fresh water distribution system in the Marcellus Shale, has the advantage of being one of the most reliable fresh water sources in the region. Specifically, because of its drainage area and associated historical precipitation averages, at its permitted withdrawal rate, Antero's current take point from the Ohio River has been available for 349 days a year on average over the last 16 years.

In the Marcellus and Utica Shales, landowners whose property abuts a river, lake or other fresh water source are entitled to reasonable use of that water. The primary restriction on this ability is that the withdrawal must be reasonable and may not interfere with the rights of downstream users. West Virginia places certain limits on withdrawals from streams based on United States Geological Survey stream flow rate requirements. In Ohio, this right is also subject to certain registration and permitting requirements for amounts of water above certain thresholds. In areas where a producer does not have this right, it can also contract with owners, including in many cases municipalities that have reservoirs.

Antero holds, either through ownership or lease from the landowner, water withdrawal rights with respect to several water sources available for its acreage in the Marcellus and Utica Shales, including from the Ohio River for the Marcellus Shale. In addition, Antero has in the past and will in the future contract with other owners to withdraw fresh water from other sources, including lakes and municipal reservoirs. Because we will initially only distribute water for Antero's completion operations, we will be able to take advantage of those rights and contracts. To the extent we contract with third-party customers in the future, we may be able to transport excess fresh water from Antero to third parties, but those customers may in some cases be responsible for sourcing their own fresh water. Possibilities for our servicing third parties include connecting those producers' wells directly into our fresh water distribution systems or arranging for those producers to pick up fresh water from our available fresh water impoundments at their expense.

There are two primary methods of transporting fresh water from a source to a well location:

In addition to cost considerations, many producers are constrained from building a permanent pipeline system by the lack of availability of a reliable water source for their well completions. Justifying the cost involved in constructing more expensive permanent pipeline infrastructure typically requires the presence of a reliable water source and significant downstream use, because to be useful in well completion operations, a pipeline system is usually designed to supply fresh water at minimum required rates. Many producers prefer to rely on temporary surface pipelines from a smaller, local water source due to the lower overall per-barrel costs. During times when local water sources are unavailable, due to a lack of precipitation or otherwise, such producers must fall back on trucking to supply their fresh water needs.

We believe that our fresh water distribution systems are currently the most extensive in the Marcellus and Utica Shales. In addition, the concentration of Antero's acreage and identified drilling locations allows us to service a relatively greater number of well completions with less pipeline mileage.

Although some of the larger producers in the Marcellus and Utica Shales have (or have begun construction of) fresh water distribution systems like ours, many other producers still rely on third party providers for transportation and distribution services. Providers range from independent, dedicated trucking providers to consolidated service companies that provide a full range of oilfield services, including fresh water distribution. Similarly, some operate only in a single basin, or an even smaller geographic area, while others operate in many basins across the United States. Both trucking and pipeline services are available from third-party providers. As described under "—Transportation of Fresh Water," however, the number and relative location of a producer's well completions factor into which method of distribution is most efficient.

For trucking, contractual arrangements usually relate to a pad or, in some cases, an individual well completion. In most cases, the producer is tasked with sourcing the fresh water. However, some service

providers both source and deliver fresh water and charge a fee for both the water and the transportation. The two most common fee arrangements are:

For temporary pipeline systems, most third-party service providers typically only rent temporary surface pipeline and associated equipment necessary to pull fresh water from a local source for a well completion. These rentals usually include the personnel necessary to put the surface pipeline in place, and fees typically take the form of hourly rental charges for the pipeline, equipment and personnel. In most cases, the third-party provider retains ownership of the pipelines and equipment. Upstream producers typically source their own fresh water for temporary pipeline systems.

In contrast, more permanent fresh water distribution systems like ours, that include permanent buried pipelines and more reliable sources of fresh water, would typically be constructed and operated by or on behalf of the producer. Some service providers both construct the system and provide the source. If we use fresh water sourced by Antero, we expect that our third-party customers would reimburse Antero for expenses incurred in obtaining the water, if any, and pay us a fee for transportation.

Pursuant to our long-term contracts with Antero, we have secured 20-year dedications covering (i) substantially all of Antero's current and future acreage for gathering and compression services and (ii) all of Antero's current and future acreage for fresh water distribution for well completion operations. All of Antero's existing acreage is dedicated to us for gathering and compression services except for the existing third-party commitments, which includes 128,000 Marcellus Shale net leasehold acres characterized by dry gas and liquids-rich production that have been previously dedicated to third-party gatherers. Please read "—Antero's Existing Third-Party Commitments." Net of the excluded acreage, our contracts cover approximately 329,000 net leasehold acres held by Antero as of February 28, 2014 for gathering and compression services and all 457,000 of Antero's existing net leasehold acres for fresh water distribution services. In addition to Antero's existing acreage dedication, our agreements provide that any acreage Antero acquires in the future will be dedicated to us for gathering and compression and fresh water distribution services. Although we do not currently have any condensate gathering infrastructure, we may provide such services to Antero in the future under the gathering and compression agreement. We also 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. As a result of Antero's acreage dedication and its contribution to us of substantially all of its midstream assets in connection with this offering, we believe that we possess significant organic growth potential and, unlike many other midstream companies, our growth does not depend on future acquisitions of assets from our sponsor or third parties.

midstream infrastructure necessary to support its continued growth, which should result in significant increases in our gathering and compression and fresh water distribution volumes.

			Gross Drilling Locations											2014 Estimated Completion Activity

	Net Acres		Dry Gas		Rich Gas		Highly Rich Gas		Highly Rich Gas/Condensate		Total			Average Rigs		Wells
Gathering and Compression:
Marcellus Gathering and Compression		220,000		340		374		861		644		2,219	⁽¹⁾		9		72
Utica Gathering and Compression		106,000		211		182		161		205		759			4		41


Total Gathering and Compression Dedicated to Us⁽²⁾		326,000		551		556		1,022		849		2,978			13		113
Excluded acreage⁽³⁾		128,000		957		811		32		—		1,800			5		68


Total		454,000		1,508		1,367		1,054		849		4,778			18		181




Fresh Water Distribution:
Marcellus		348,000		1,297		1,185		893		644		4,019			14		126
Utica		106,000		211		182		161		205		759			4		37


Total		454,000		1,508		1,367		1,054		849		4,778			18		163

The Appalachian Basin, which covers over 185,000 square miles in portions of Kentucky, Tennessee, Virginia, West Virginia, Ohio, Pennsylvania and New York, is considered a highly attractive energy resource producing region with a long history of oil, natural gas and coal production. Based on forecasted production data, the Appalachian Basin is the second largest overall gas producer in the United States with approximately 12 Bcfe/d in 2013, a 21% increase over 2012. Over the past five years, the focus of many producers has shifted from the younger, shallower conventional sandstone and carbonate reservoirs to the older, deeper Marcellus Shale and the newly emerging Utica Shale plays, which has driven Appalachian Basin production growth. The Marcellus Shale accounted for over 9 Bcfe/d of the 2013 production, making it the largest United States gas field on a stand-alone basis, and the largest unconventional gas play in the world.

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.

Antero has indicated that it believes that the Marcellus Shale is a premier North American shale play due to its 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. All of Antero's approximately 351,000 net leasehold acres in the Marcellus Shale are located within the southwestern core, where it has experienced virtually no geologic complexity in its drilling activities to date. According to RigData, as of February 28, 2014, approximately 90% of the 94 drilling rigs operating in the Marcellus Shale were located in these two core areas.

The Devonian-aged Marcellus Shale is an unconventional reservoir that produces natural gas, NGLs and oil and is one of the largest natural gas fields in the country. The productive limits of the Marcellus Shale cover over 50,000 square miles within Pennsylvania, West Virginia, Ohio and New York. The Marcellus Shale is a black, organic-rich shale deposit generally productive at depths between 5,500 and 7,000 feet. Production from the brittle, gas-charged shale reservoir is best derived from hydraulically fractured horizontal wellbores that exceed 2,000 feet in lateral length and involve multi-stage fracture stimulations. The geology of the Marcellus Shale is analogous to the Barnett, Woodford and Fayetteville Shales, where Antero and its management team have successfully drilled and completed over 220 horizontal wells.

Antero has experienced virtually no geologic complexity in its drilling activities to date, which has contributed to what Antero believes to be a narrow and predictable band of expected well recoveries per 1,000 feet of lateral length on its wells. Further, the lower thermal maturity of the Marcellus Shale in the western half of the southwestern core yields liquids-rich natural gas and condensate, which allows for NGL processing that can significantly improve well economies. As of December 31, 2013, Antero had 4,019 identified potential horizontal well locations in the Marcellus Shale, including 951 identified potential horizontal Upper Devonian well locations.

Antero has indicated that it believes that the Utica Shale is a premier North American shale play. The Ordovician-aged Utica Shale is an unconventional reservoir underlying the Marcellus Shale. The productive limits of the Utica Shale cover over 80,000 square miles within Ohio, Pennsylvania, West Virginia and New York. The Utica Shale is an organic-rich continuous black shale, with most production occurring at vertical depths between 7,000 and 10,000 feet. To date, the rich and dry gas windows of the Utica Shale play have yielded the strongest results. The richest and thickest concentration of organic-carbon content is present within the Point Pleasant Shale layer of the Lower Utica formation. The Point Pleasant Shale is therefore Antero's primary targeted development play of the Utica Shale.

Based on drilling results and initial production from Antero's 16 core 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 106,000 net leasehold acres in the core of the Utica Shale and expects to continue to add to its sizeable land position. Antero has enjoyed a 100% success rate and believes over 74% of its acreage has liquids-rich gas processing potential. As of December 31, 2013, Antero had approximately 759 identified potential horizontal well locations in the Utica Shale.

Antero is our only current customer and is one of the largest producers of natural gas and NGLs in the Appalachian Basin. As of December 31, 2013, Antero's estimated net proved, probable and possible reserves were 7.6 Tcfe, 19.8 Tcfe and 7.5 Tcfe, respectively, of which 85% was natural gas. As of December 31, 2013, Antero's drilling inventory consisted of 4,778 identified potential horizontal well locations (2,978 of which were located on acreage dedicated to us) for gathering and compression services, which provides us with significant opportunity 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 20 operated rigs, including 15 operated rigs in the Marcellus Shale (where it is the most active driller) and 5 operated rigs in the Utica Shale (where it is one of the most active drillers). On January 29, 2014, Antero announced a 2014 drilling and completion capital expenditures budget of approximately $1.8 billion that provides for the drilling of approximately 181 wells, a substantial increase over the 157 wells drilled in 2013. Antero's average Appalachian production during 2013 represented an increase of 115% as compared to 2012, and its net production in the fourth quarter of 2013 averaged 678 MMcfe/d. We anticipate that Antero's robust drilling program will significantly increase throughput on our gathering and compression systems and will result in a significant demand for our fresh water distribution services. Antero relies on us to deliver the midstream infrastructure necessary to accommodate its continuing production growth, which should provide us with significant increases in throughput volumes. For additional information regarding our contracts with Antero, please read "—Contractual Arrangements with Antero."

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. For additional information, please read "Risk Factors—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."

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 "—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. Any handling and treating of condensate will be 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. For additional information, please read "Certain Relationships and Related Transactions—Other Contractual Relationships with Antero—Gathering and Compression."

In addition to the gathering and compression agreement, we have also entered 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 is dedicated to us. If Antero requires fresh water distribution 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 storage facilities. For additional information, please read "Certain Relationships and Related Transactions—Other Contractual Relationships with Antero—Fresh Water Distribution."

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 additional information, please read "—Antero's Existing Third-Party Commitments" and "Certain Relationships and Related Transactions—Other Contractual Relationships with Antero—Processing."

The following table provides information regarding our fresh water distribution systems as of December 31, 2013 and our expectations for these assets as of December 31, 2014, based on organic growth driven by Antero's drilling and completion plans.

Our midstream infrastructure includes 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. To the extent necessary, we will move surface pipelines to service completion operations in concert with Antero's robust drilling program. While our fresh water distribution agreement only requires us to distribute 35 barrels of fresh water per minute, our system is capable of distributing approximately 80 barrels of fresh water per minute.

In 2014, we anticipate expanding our fresh water distribution systems to have 122 and 48 miles of buried water pipelines in the Marcellus and Utica operating areas, respectively.

In addition, we may consider or pursue opportunities to transport, store, treat and dispose of both (i) waste fluids associated with the production of oil and natural gas through hydraulic fracturing and (ii) produced water lifted along with oil and natural gas from actively producing wells.

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

Antero previously dedicated a portion of its acreage in the Marcellus Shale to certain third parties' gathering and compression services. We refer to this acreage dedication as the "excluded acreage." As of December 31, 2013, the excluded acreage consisted of approximately 128,000 of Antero's existing net leasehold acreage. At that same date, 1,800 of Antero's 4,778 identified potential horizontal well locations were located within the excluded acreage.

In addition to the excluded acreage, Antero has entered into take-or-pay contracts with volume commitments for certain third parties' high-pressure gathering and compression services. Specifically, those volume commitments consist of up to an aggregate of 750 MMcf/d on three high-pressure gathering pipelines and 455 MMcf/d on five compressor stations. Similar to the excluded acreage, Antero's use of that infrastructure up to the maximum aggregate high-pressure gathering and compression volumes is not subject to the gathering and compression agreement.

Our real property is classified into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our pipelines and major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our pipelines and major facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We have leased or owned these lands without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership of such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses.

Some of the leases, easements, rights-of-way, permits and licenses that were transferred to us from Antero required the consent of the grantor of such rights, which in certain instances is a governmental entity. Antero obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects. With respect to any remaining consents, permits or authorizations that have not been obtained, we have determined these will not have a material adverse effect on the operation of our business should we or Antero fail to obtain such consents, permits or authorization in a reasonable time frame.

For a description of the sources for our fresh water distribution systems, please read "Industry—Overview of the Water Services Industry—Sources of Fresh Water in the Marcellus and Utica Shales."

Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase demand for our services during the summer and winter months and decrease demand for our services during the spring and fall months.

As a result of our relationship with Antero, we do not compete for the portion of Antero's existing operations for which we currently provide midstream services and will not compete for future portions of Antero's operations that will be dedicated to us pursuant to our gathering and compression and fresh water distribution agreements with Antero. For a description of these contracts, please read "Our Relationship with Antero—Contractual Arrangements with Antero." However, we will face competition in attracting third-party volumes to our gathering and compression systems and to our fresh water distribution systems. In addition, these third parties may develop their own gathering and compression systems and fresh water distribution systems in lieu of employing our assets.

Regulation of pipeline gathering services may affect certain aspects of our business and the market for our services.

Section 1(b) of the Natural Gas Act of 1938 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 some our gathering facilities and intrastate transportation pipelines 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 is not a gathering pipeline and the pipeline provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the 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. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by the FERC.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. States in which we operate may adopt ratable take and common purchaser statutes, which would require our gathering pipelines to take natural gas without undue discrimination in favor of one producer over another producer or one source of supply over another similarly situated source of supply. The regulations under these statutes may have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. States in which we

operate may also adopt a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such regulation will be adopted and whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our system due to state regulations.

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

Some of our gas pipelines are subject to regulation by the PHMSA pursuant to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, and the Pipeline Safety Improvement Act of 2002, or PSIA, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, or the PIPES Act. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas, or HCAs.

The PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. The regulations require operators, including us, to:

The 2011 Pipeline Safety Act, reauthorizes funding for federal pipeline safety programs, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. 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 PHMSA finalized rules consistent with the signed act that increased the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a series of violations. The PHMSA has also issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. In addition, PHMSA has published advanced notice of proposed rulemakings to solicit comments on the need for changes to its natural gas and liquid pipeline safety regulations, including whether to extend the integrity management requirements to gathering lines. The PHMSA also issued an advisory

bulletin providing guidance on the verification of records related to pipeline maximum allowable operating pressure.

The National Transportation Safety Board has recommended that the PHMSA make a number of changes to its rules, including removing an exemption from most safety inspections for natural gas pipelines installed before 1970. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations, particularly by extending through more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subject to such requirements. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

We have incorporated all existing requirements into our programs by the required regulatory deadlines, and are continually incorporating the new requirements into procedures and budgets. We expect to incur increasing regulatory compliance costs, based on the intensification of the regulatory environment and upcoming changes to regulations as outlined above. In addition to regulatory changes, costs may be incurred when there is an accidental release of a commodity transported by our system, or a regulatory inspection identifies a deficiency in our required programs.

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

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and natural resource damages. Certain environmental statutes impose strict joint and several liability for costs required to

clean up and restore sites where hazardous substances, hydrocarbons or solid wastes have been disposed or otherwise released. Moreover, neighboring landowners and other third parties may file common law claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or solid waste into the environment.

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production. Our only customer, Antero, regularly uses hydraulic fracturing as part of its operations as does most of the domestic oil and natural gas industry. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards sometime in 2014. Also, in August 2012, the EPA published final rules under the Clean Air Act requiring new measures to address well flow back emissions and requiring in the future that certain wells employ "green completion" technology after January 1, 2015 to address emissions of volatile organic compounds, including methane, a highly-potent GHG. In addition, the U.S. Department of the Interior published a revised proposed rule on May 24, 2013 that would implement updated requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, well bore integrity, and handling of flowback water.

In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction

requirements on hydraulic fracturing activities. For example, in Ohio, the Department of Natural Resources recently proposed draft regulations that would require a minimum distance between the hydraulic fracturing facilities and streams, require operators to take spill-containment measures, and regulate the types of liners required for waste storage. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where Antero operates, Antero could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. Any such added costs or delays for Antero, could significantly affect our operations.

Certain governmental reviews also have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review this year. Other governmental agencies, including the U.S. Department of Energy have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

Our operations generate solid wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws, which impose requirements for the handling, storage, treatment and disposal of hazardous waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous waste in the future.

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations, such as landfills. Although petroleum as well as natural gas is excluded from CERCLA's definition of "hazardous substance," in the course of our ordinary operations, our operations generate wastes that may be designated as hazardous substances. CERCLA authorizes the EPA, states, and, in some cases, third parties to take actions in response to releases or threatened releases of hazardous substances into the environment and to seek to recover from the classes of responsible persons the costs they incur to address the release. Under CERCLA, we could be subject to strict joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment and for damages to natural resources.

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

The Clean Air Act, and comparable state laws, regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and also impose various emission limits, operational limits and monitoring, reporting and record keeping requirements on air emission sources. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. Such laws and regulations require pre- construction permits for the construction or modification of certain projects or facilities with the potential to emit air emissions above certain thresholds. These pre-construction permits generally require use of best available control technology, or BACT, to limit air emissions. Several EPA new source performance standards, or NSPS, and national emission standards for hazardous air pollutants, or NESHAP, also apply to our facilities and operations. These NSPS and NESHAP standards impose emission limits and operational limits as well as detailed testing, recordkeeping and reporting requirements on the "affected facilities" covered by these regulations. Several of our facilities are "major" facilities requiring Title V operating permits which impose semi-annual reporting requirements. We operate in material compliance with these various air quality regulatory programs. We may incur capital expenditures in the future for air pollution control equipment in connection with complying with existing and recently proposed rules, or with obtaining or maintaining operating permits and complying with federal, state and local regulations related to air emissions. However, we do not believe that such requirements will have a material adverse effect on our operations.

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into jurisdictional waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a delegated state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that we maintain all required discharge permits necessary to conduct our operations, and further believe we are in substantial compliance with the terms thereof. Any unpermitted release of petroleum or other pollutants from our operations could result in government penalties and civil liability.

We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA's hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the applicable worker health and safety requirements.

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

In summary, we believe we are in substantial compliance with currently applicable environmental laws and regulations. Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2013, nor do we anticipate that such expenditures will be material in 2014.

In December 2009, the EPA determined that emissions of greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth's atmosphere and other climatic changes. Based on these findings, EPA has adopted regulations under existing provisions of the federal Clean Air Act, that establish Prevention of Significant Deterioration, or PSD, pre-construction permits, and Title V operating permits for GHG emissions from certain large stationary sources. Under these regulations, facilities required to obtain PSD permits must meet BACT standards for their GHG emissions established by the states or, in some cases, by the EPA, on a case-by-case basis. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities. We believe we are in substantial compliance with all GHG emissions permitting and reporting requirements applicable to our operations. Additionally, while Congress has from time to time considered legislation to reduce emissions of GHGs, the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. Nevertheless, the Obama administration has announced it intends to adopt additional regulations to reduce emissions of GHGs and to encourage greater use of low carbon technologies. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas that exploration and production operators produce, some of whom are our customers, which could thereby reduce demand for our midstream services. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such

effects were to occur, it is uncertain if they would have an adverse effect on our financial condition and operations.

We do not have any employees. The officers of our general partner, who are also officers of Antero will manage our operations and activities. As of December 31, 2013, Antero employed approximately 233 people who will provide direct, full-time support to our operations. All of the employees required to conduct and support our operations will be employed by Antero and all of our direct, full-time personnel are subject to the services agreement that we expect to enter into with our general partner and Antero. Antero considers its relations with its employees to be satisfactory. For additional information regarding the services agreement we expect to enter into with Antero, please read "Certain Relationships and Related Transactions—Agreements with Affiliates in Connection with the Transactions—Services Agreement."

Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, we are not currently subject to any material litigation.

We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

We are managed and operated by the board of directors and executive officers of Midstream Management, which will be our general partner upon the consummation of this offering. Midstream Management is controlled by Antero Investment. All of our officers and certain of our directors are also officers and directors of Antero. 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, including at least three independent directors meeting the independence standards established by the NYSE. At least one of our independent directors will be appointed prior to the date our common units are listed for trading on the NYSE. Our unitholders will not be entitled to directly participate in our management or operations. Our general partner owes certain contractual duties to our unitholders as well as a fiduciary duty to its owners.

Upon the closing of this offering, we expect that our general partner will have directors. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the year following this offering. Antero Investment will appoint at least one member of the audit committee to the board of directors of our general partner by the date our common units first trade on the NYSE.

In evaluating director candidates, Antero Investment will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board's ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

All of the executive officers of our general partner listed below will allocate their time between managing our business and affairs and the business and affairs of Antero. The amount of time that our executive officers will devote to our business and the business of Antero will vary in any given year based on a variety of factors. Our executive officers intend, however, to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.

Following the consummation of this offering, Antero shall provide customary management and general administrative services to us pursuant to a services agreement. Our general partner shall reimburse Antero at cost for its direct expenses incurred on behalf of us and a proportionate amount of its indirect expenses incurred on behalf of us, including, but not limited to, compensation expenses. Neither our general partner nor Antero will receive any management fee or other compensation. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Please read "Certain Relationships and Related Transactions—Agreements with Affiliates in Connection with the Transactions—Services Agreement."

The following table shows information for our executive officers and directors. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. There

are no family relationships among any of our directors or executive officers. Some of our directors and all of our executive officers also serve as executive officers of Antero.

Paul M. Rady has served as Chief Executive Officer and Chairman of the Board of Directors of Midstream Management since February 2014. Mr. Rady also served as Chief Executive Officer and Chairman of the Board of Directors of Antero since May 2004 and of its predecessor company from its founding in 2002 to its ultimate sale to XTO Energy, Inc. in April 2005. Prior to Antero, Mr. Rady served as President, CEO and Chairman of Pennaco Energy from 1998 until its sale to Marathon in early 2001. Prior to Pennaco, Mr. Rady was with Barrett Resources from 1990 until 1998 where he initially was recruited as Chief Geologist in 1990, then served as Exploration Manager, EVP Exploration, President, COO and Director and ultimately CEO. Mr. Rady began his career with Amoco where he served 10 years as a geologist focused on the Rockies and Mid-Continent. Mr. Rady is the managing member of Salisbury Investment Holdings, LLC. Mr. Rady holds a B.A. in Geology from Western State College of Colorado and M.Sc. in Geology from Western Washington University.

Mr. Rady's significant experience as a chief executive of oil and gas companies, together with his training as a geologist and broad industry knowledge, enable Mr. Rady to provide the board with executive counsel on a full range of business, strategic and professional matters.

Glen C. Warren, Jr. has served as President, Chief Financial Officer and Secretary and as a director of Midstream Management since February 2014. Mr. Warren also served as President, Chief Financial Officer and Secretary and as a director of Antero since May 2004 and of its predecessor company from its founding in 2002 to its ultimate sale to XTO Energy, Inc. in April 2005. Prior to Antero, Mr. Warren served as EVP, CFO and Director of Pennaco Energy from 1998 until its sale to Marathon in early 2001. Mr. Warren spent 10 years as a natural resources investment banker focused on equity and debt financing and M&A advisory with Lehman Brothers, Dillons Read & Co. Inc. and Kidder, Peabody & Co. Mr. Warren began his career as a landman in the Gulf Coast region with Amoco, where he spent six years. Mr. Warren is the managing member of Canton Investment Holdings, LLC. Mr. Warren holds a B.A. from the University of Mississippi, a J.D. from the University of Mississippi School of Law and an M.B.A. from the Anderson School of Management at U.C.L.A.

Mr. Warren's significant experience as a chief financial officer of oil and gas companies, together with his experience as an investment banker and broad industry knowledge, enable Mr. Warren to provide the board with executive counsel on a full range of business, strategic, financial and professional matters.

Kevin J. Kilstrom has served as Vice President of Production of Midstream Management since February 2014. Mr. Kilstrom also has served as Vice President of Production of Antero since June 2007. Mr. Kilstrom was a Manager of Petroleum Engineering with AGL Energy of Sydney, Australia from 2006 to 2007. Prior to AGL, Mr. Kilstrom was with Marathon Oil as an Engineering Consultant and Asset Manager from 2003 to 2006 and as a Business Unit Manager for Marathon's Powder River coal bed methane assets from 2001 to 2003. Mr. Kilstrom also served as a member of the board of directors of three Marathon subsidiaries from October 2003 through May 2005. Mr. Kilstrom was an

Operations Manager and reserve engineer at Pennaco Energy from 1999 to 2001. Mr. Kilstrom was at Amoco for more than 22 years prior to 1999. Mr. Kilstrom holds a B.S. in Engineering from Iowa State University and an M.B.A. from DePaul University.

Alvyn A. Schopp has served as Chief Administrative Officer and Regional Vice President of Midstream Management since February 2014. Mr. Schopp has also served as Chief Administrative Officer and Regional Vice President of Antero since September 20, 2013, as Vice President of Accounting and Administration and Treasurer from January 2005 to September 20, 2013, as Controller and Treasurer from 2003 to 2005 and as Vice President of Accounting and Administration and Treasurer of Antero's predecessor company, Antero Resources Corporation, from January 2005 until its ultimate sale to XTO Energy, Inc. in April 2005. From 2002 to 2003, Mr. Schopp was an Executive and Financial Consultant with Duke Energy Field Services. From 1993 to 2000, Mr. Schopp was CFO, Director and ultimately CEO of T-Netix. From 1980 to 1993 Mr. Schopp was with KPMG LLP, most recently as a Senior Manager. Mr. Schopp holds a B.B.A. from Drake University.

Ward D. McNeilly has served as Vice President of Reserves, Planning and Midstream of Midstream Management since February 2014. Mr. McNeilly also has served as Vice President of Reserves, Planning & Midstream of Antero since October 2010. Mr. McNeilly has 34 years of experience in oil and gas asset management, operations, and reservoir management. From 2007 to October 2010, Mr. McNeilly was BHP Billiton's Gulf of Mexico Operations Manager. From 1996 through 2007, Mr. McNeilly served in various North Sea and Gulf of Mexico Deepwater operations and asset management positions with Amoco and then BP. Mr. McNeilly served in a number of different domestic and international positions with Amoco from 1979 to 1996. Mr. McNeilly holds a B.S. in Geological Engineering from the Mackay School of Mines at the University of Nevada.

Peter R. Kagan has served as a director of Midstream Management since February 2014. Mr. Kagan also has served as a director of Antero since 2004. Mr. Kagan has been with Warburg Pincus since 1997 where he leads the firm's investment activities in energy and natural resources. He is a Partner of Warburg Pincus & Co. and a Managing Director of Warburg Pincus LLC. He is also a member of Warburg Pincus LLC's Executive Management Group. Mr. Kagan received a B.A. degree cum laude from Harvard College and J.D. and M.B.A. degrees with honors from the University of Chicago. Prior to joining Warburg Pincus, he worked in investment banking at Salomon Brothers in both New York and Hong Kong. Mr. Kagan currently also serves on the boards of directors of the following public companies: Laredo Petroleum Holdings, Inc., MEG Energy Corp. and Targa Resources Corp., as well as the boards of several private companies. In addition, he is a director of Resources for the Future and a trustee of Milton Academy.

Mr. Kagan has significant experience with energy companies and investments and broad knowledge of the oil and gas industry. We believe his background and skill set make Mr. Kagan well-suited to serve as a member of our board of directors.

W. Howard Keenan, Jr. has served as a director of Midstream Management since February 2014. Mr. Keenan also has served as a director of Antero since 2004. Mr. Keenan has over thirty years of experience in the financial and energy businesses. Since 1997, he has been a Member of Yorktown Partners LLC, a private investment manager focused on the energy industry. Mr. Keenan currently serves on the Board of Directors of GeoMet, Inc. From 1975 to 1997, he was in the Corporate Finance Department of Dillon, Read & Co. Inc. and active in the private equity and energy areas, including the founding of the first Yorktown Partners fund in 1991. He is serving or has served as a director of multiple Yorktown Partners portfolio companies. Mr. Keenan holds an B.A. degree cum laude from Harvard College and an M.B.A. degree from Harvard University.

Mr. Keenan has significant experience with energy companies and investments and broad knowledge of the oil and gas industry. We believe his background and skill set make Mr. Keenan well-suited to serve as a member of our board of directors.

Christopher R. Manning has served as a director of Midstream Management since February 2014. Mr. Manning also has served as a director of Antero since 2005. Mr. Manning has been a Partner with Trilantic Capital Partners since its formation and spin out from Lehman Brothers Merchant Banking in April 2009, and is currently a member of its Executive Committee. His primary focus is on investments in the energy sector. Mr. Manning joined Lehman Brothers Merchant Banking in 2000 and was concurrently the Head of Lehman Brothers' Investment Management Division, including both the Asset Management and Private Equity businesses, in Asia-Pacific from 2006 to 2008. He was also a member of the Global Investment Management Division Executive Committee and the Private Equity Division Operating Committee. Prior to Lehman Brothers, Mr. Manning was the chief financial officer of The Wing Group, a developer of international power projects. Prior to The Wing Group, he was in the investment banking department of Kidder, Peabody & Co., where he worked on M&A and corporate finance transactions in the energy sector. Mr. Manning currently serves on the boards of The Cross Group, Enduring Resources LLC, Templar Energy LLC, Trail Ridge Energy Partners II LLC, VantaCore Partners, and Velvet Energy Ltd. Mr. Manning holds an M.B.A. from The Wharton School of the University of Pennsylvania and a B.B.A. from the University of Texas at Austin.

Mr. Manning has significant experience with energy companies and investments and broad knowledge of the oil and gas industry. We believe his background and skill set make Mr. Manning well-suited to serve as a member of our board of directors.

We expect that the board of directors of our general partner will have an audit committee and a conflicts committee. We do not expect that we will have a compensation committee, but rather that our board of directors will approve equity grants to directors and employees.

Our general partner will establish an audit committee prior to the completion of this offering. Rules implemented by the NYSE and SEC require us to have an audit committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act, subject to transitional relief during the year following this offering. As required by the rules of the SEC and listing standards of the NYSE, the audit committee will consist solely of independent directors, subject to transitional relief. SEC rules also require that a public company disclose whether or not its audit committee has an "audit committee financial expert" as a member. An "audit committee financial expert" is defined as a person who, based on his or her experience, possesses the attributes outlined in such rules. Our board of directors believes satisfies the definition of "audit committee financial expert."

This committee will oversee, review, act on and report on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee will oversee our compliance programs relating to legal and regulatory requirements. We expect to adopt an audit committee charter defining the committee's primary duties in a manner consistent with the rules of the SEC and NYSE.

At least two independent members of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee will determine if the resolution of the conflict of interest is adverse to the interest of the partnership. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Antero Investment and Antero, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Neither we nor our general partner have any employees. All of the executive officers of our general partner and other personnel who provide services to our business are employed by Antero. The named executive officers of our general partner (which we refer to below as our "Named Executive Officers") are listed below along with their respective principal positions with our general partner and Antero:

Our Named Executive Officers currently receive all of their compensation and benefits for services provided to our business from Antero. Although we bear an allocated portion of Antero's costs of providing compensation and benefits to the employees who serve as our Named Executive Officers, we have no control over such costs and do not establish or direct the compensation policies or practices of Antero. Pursuant to the services agreement that we will enter into with Antero and our general partner, we will reimburse Antero for a proportionate amount of compensation expenses incurred on our behalf. Please read "Certain Relationships and Related Transactions—Agreements with Affiliates in Connection with the Transactions—Services Agreement."

The information set forth below describes the compensation paid to our Named Executive Officers by Antero. during the fiscal years ended December 31, 2013 and 2012.

Name and Principal Position		Year			Salary ($)			Bonus ($)			Option Awards ($)			Total ($)

Paul M. Rady			2013
(Chairman of the Board of Directors			2012
and Chief Executive Officer)
Glen C. Warren, Jr.			2013
(Director, President and Chief			2012
Financial Officer and Secretary)
Alvyn A. Schopp			2013
(Chief Administrative Officer and			2012
Regional Vice President)
Kevin J. Kilstrom			2013
(Vice President—Production)			2012

Antero paid 100% of each Named Executive Officer's total compensation for fiscal 2013 in the form of base salary, discretionary annual cash bonuses and special cash bonuses paid in connection with Antero's initial public offering.

The following table provides information concerning equity awards that have not vested for our Named Executive Officers as of December 31, 2013.

Antero has not maintained, and does not currently maintain, a defined benefit pension plan or a nonqualified deferred compensation plan providing for retirement benefits. Antero maintains an employee retirement savings plan through which employees may save for retirement or future events on a tax-advantaged basis. Participation in the 401(k) plan is at the discretion of each individual employee, and our Named Executive Officers participate in the plan on the same basis as all other employees. While the plan permits Antero to make discretionary matching and non-elective contributions, Antero has not made any employer contributions in recent years. However, effective as of January 1, 2014, the plan provides safe harbor matching contributions equal to 100% of employees' pre-tax contributions under the plan, but not as to pre-tax contributions exceeding 4% of their eligible compensation (up to IRS limitations).

Antero does not maintain any employment, severance or change in control agreements with any of our Named Executive Officers. However, the unvested units in Holdings granted to Messrs. Rady, Warren and Schopp could be affected by the termination of their employment or the occurrence of certain corporate events. The impact of such a termination or corporate event upon the units is governed by the terms of both the restricted unit agreements issued to them in connection with the grant of their unit awards, as well as the limited liability company agreement of Holdings (the "Holdings LLC Agreement").

The Holdings LLC Agreement provides that upon the termination of a Named Executive Officer's employment with Antero by reason of death or "disability" (as defined below) or upon the occurrence of an "exit event" (as defined below) while the Named Executive Officer is employed by Antero, any unvested portion of the Holdings units granted to the Named Executive Officer will become vested; Antero's termination of the Named Executive Officer's employment with or without "cause," as well as the officer's voluntary termination of employment, generally results in the forfeiture of all unvested Holdings units. In addition, a termination for "cause" results in a forfeiture of all vested units. Any unvested portion of the Holdings units granted to a Named Executive Officer may also become immediately vested under such circumstances and at such times as the board of directors of Holdings determines to be appropriate in its discretion.

The Holdings LLC Agreement also provides that upon the voluntary resignation of a Named Executive Officer or the occurrence of an exit event, any portion of the Holdings units granted to the

officer that have vested as of the time of the applicable event are subject to repurchase, at Holdings' option, at a purchase price equal to the "fair market value" of such units, as determined by the unanimous resolution of the board of directors of Holdings. Such amount may be paid by Holdings in cash or by promissory note. In addition, in lieu of electing to repurchase all or any portion of a Named Executive Officer's vested units in Holdings, the board of directors of Holdings has the right to modify such units so that the aggregate amount that may potentially be distributed with respect to such units is "capped" at the lesser of (a) the aggregate amount that the Named Executive Officer is entitled to receive with respect to such units under the Holdings LLC Agreement or (b) an amount equal to the sum of (x) the fair market value of such units as of the date the Named Executive Officer's employment terminates (the "Termination Value") and (y) an accretion amount with respect to the Termination Value calculated based upon a rate equal to 5% per annum, compounding annually in arrears as of the Termination Date.

Under the Holdings LLC Agreement, a Named Executive Officer will be considered to have incurred a "disability" if the officer becomes incapacitated by accident, sickness or other circumstance that renders the officer mentally or physically incapable of performing the officer's duties with Antero on a full time basis for a period of at least 120 days during any 12 month period. A termination for "cause" will occur following an employee's (1) gross negligence or willful misconduct, (2) conviction of a felony or a crime involving theft, fraud or moral turpitude, (3) refusal to perform material duties or responsibilities, (4) willful and material breach of a corporate policy or code of conduct or (5) willful engagement in conduct that damages the integrity, reputation or financial success of Antero or any of its affiliates. Further, an "exit event" generally includes the sale of Antero Investment, in one transaction or a series of related transactions, whether structured as (a) a sale or other transfer of all or substantially all of Antero Investment (including by way of merger, consolidation, share exchange, or similar transaction), (b) a sale or other transfer of all or substantially all of our assets promptly followed by a dissolution and liquidation of our company or (c) a combination of the transactions described in clauses (a) and (b).

Officers or employees of Antero who also serve as directors of our general partner will not receive additional compensation for such service. Our general partner has not yet determined what compensation will be paid to its directors who are not also officers or employees of Antero. We expect that each non-employee director will be reimbursed for out-of-pocket expenses incurred in connection with attending board and committee meetings. Each director will be fully indemnified by us for actions associated with serving as a director to the fullest extent permitted under Delaware law.

The following table sets forth the beneficial ownership of common units and subordinated units of Antero Midstream Partners LP that will be issued and outstanding upon the consummation of this offering and the related transactions and held by:

Unless otherwise noted, the address for each beneficial owner listed below is 1625 17^th Street, Denver, Colorado 80202.

Name of Beneficial Owner

Antero Resources Corporation⁽²⁾			%		100	%		%
Antero Resources Midstream Management LLC	—	—		—	—		—
Peter R. Kagan	—	—		—	—		—
W. Howard Keenan, Jr.	—	—		—	—		—
Christopher R. Manning	—	—		—	—		—
Paul M. Rady	—	—		—	—		—
Glen C. Warren, Jr.	—	—		—	—		—
Kevin J. Kilstrom	—	—		—	—		—
Alvyn A. Schopp	—	—		—	—		—
All directors and executive officers as a group (8 persons)	—	—		—	—		—

The following table sets forth the number of shares of common stock of Antero owned by each of the named executive officers and directors of our general partner and all directors and executive officers of our general partner as a group as of , 2014:

After this offering, assuming that the underwriters do not exercise their option to purchase additional common units, Antero will own common units and subordinated units representing an aggregate approximately % limited partner interest in us. Antero Investment will own and control (and appoint all the directors of) our general partner, which will own a non-economic general partner interest in us and the incentive distribution rights.

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm's length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the conversion, ongoing operation and any liquidation of us.

Conversion of Antero Resources Midstream LLC to Antero Midstream Partners LP


The aggregate consideration received by our general partner in connection with the conversion of its special membership interest pursuant to the limited liability company agreement of Antero Resources Midstream LLC		• the non-economic general partner interest; and
		• the incentive distribution rights.
The aggregate consideration receivedby Antero in connection with the conversion of its common economic interest pursuant to the limited liability company agreement of Antero Resources Midstream LLC		• common units;
		• subordinated units;
		• a reimbursement of up to $ million of capital expenditures incurred in connection with the Predecessor prior to Midstream Operating being contributed to us; and
		• we will also undertake a public or private offering of common units in the future upon request by Antero and use the proceeds thereof (net of underwriting or placement agency discounts and commissions, as applicable) to redeem an equal number of common units from Antero as a distribution to reimburse Antero for certain capital expenditures incurred in connection with the Predecessor prior to Midstream Operating being contributed to us.


Option units or proceeds from option 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. Please read "Use of Proceeds."
*Operational Stage*
Distributions of cash available for distribution to our general partner and its affiliates		We will generally make cash distributions 100% to our unitholders, including affiliates of our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level.
		Assuming we have sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our outstanding common units and subordinated units for four quarters, our general partner and its affiliates (including Antero) would receive an annual distribution of approximately $ million on their units.
Payments to our general partner and its affiliates		Antero shall provide customary management and general administrative services to us. Our general partner shall reimburse Antero at cost for its direct expenses incurred on behalf of us and a proportionate amount of its indirect expenses incurred on behalf of us, including, but not limited to, compensation expenses. Our general partner will not receive a management fee or other compensation for its management of our partnership, but we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur and payments they make on our behalf, including payments made to Antero for customary management and general administrative services. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us.


Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its non-economic general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read "The Partnership Agreement—Withdrawal or Removal of Our General Partner."
*Liquidation Stage*
Liquidation		Upon our liquidation, the partners, including our general partner,will be entitled to receive liquidating distributions according to their respective capital account balances.

In connection with this offering, we will enter into certain agreements with Antero, as described in more detail below.

In connection with this offering, we will enter into a registration rights agreement with Antero pursuant to which we may be required to register the sale of the (i) common units issued (or issuable) to Antero pursuant to the contribution agreement, (ii) subordinated units and (iii) common units issuable upon conversion of subordinated units pursuant to the terms of the partnership agreement (together, the "Registrable Securities") it holds. Under the registration rights agreement, Antero will have the right to request that we register the sale of Registrable Securities held by it, and Antero will have the right to require us to make available shelf registration statements permitting sales of Registrable Securities into the market from time to time over an extended period, subject to certain limitations. Pursuant to the registration rights agreement and our partnership agreement, we may be required to undertake a future public or private offering and use the proceeds (net of underwriting or placement agency discounts, fees and commissions, as applicable) to redeem an equal number of common units from them. In addition, the registration rights agreement gives Antero "piggyback" registration rights under certain circumstances. The registration rights agreement also includes provisions dealing with indemnification and contribution and allocation of expenses. All of the Registrable Securities held by Antero and any permitted transferee will be entitled to these registration rights.

In connection with the closing of this offering, we will enter into a services agreement with our general partner and Antero, pursuant to which Antero will agree to provide customary operational and management services for us in exchange for reimbursement of its direct expenses and an allocation of its indirect expenses attributable to the provision of such services to us.

Pursuant to our 20-year gas gathering and compression agreement with Antero, Antero has agreed to dedicate all of its current and future acreage in West Virginia, Ohio and Pennsylvania to us (other than the existing third-party commitments), so long as such production is not otherwise subject to a pre-existing dedication to third-party gathering systems. Antero's production subject to a pre-existing

dedication will be dedicated to us at the expiration of such pre-existing dedication. In addition, if Antero acquires any gathering facilities, it is required to offer such gathering facilities to us at its cost.

Under the gathering and compression agreement, we receive a low-pressure gathering fee of $0.30 per Mcf, a high-pressure gathering fee of $0.18 per Mcf and a compression fee of $0.18 per Mcf, in each case subject to CPI-based adjustments. Any handling and treating of condensate will be priced on a cost of services basis. If and to the extent Antero requests that we construct new high-pressure lines and compressor stations requested by Antero, the gathering and compression agreement contains minimum volume commitments that require Antero to utilize or pay for 75% and 70%, respectively, of the capacity of such new construction. Additional high-pressure lines and compressor stations installed on our own initiative are not subject to such volume commitments. These minimum volume commitments on new infrastructure, as well as price adjustment mechanisms, are intended to support the stability of our cash flows.

We also have an option to gather and compress natural gas produced by Antero on any acreage it acquires in the future outside of West Virginia, Ohio and Pennsylvania on the same terms and conditions. In the event that we do not exercise this option, Antero will be entitled to obtain gathering and compression services and dedicate production from limited areas to such third-party agreements from third parties.

In return for Antero's acreage dedication, we have agreed to gather, compress, dehydrate and redeliver all of Antero's dedicated natural gas on a firm commitment, first-priority basis. We may perform all services under the gathering and compression agreement or we may perform such services through third parties. In the event that we do not perform our obligations under the gathering and compression agreement, Antero will be entitled to certain rights and procedural remedies thereunder.

Pursuant to the gathering and compression agreement, we have also agreed to build to and connect all of Antero's wells producing dedicated natural gas, subject to certain exceptions, upon 180 days' notice by Antero. In the event of late connections, Antero's natural gas will temporarily not be subject to the dedication. We are entitled to compensation under the gathering and compression agreement for capital costs incurred if a well does not commence production within 30 days following the target completion date for the well set forth in the notice from Antero.

We have agreed to install compressor stations at Antero's direction, but will not be responsible for inlet pressures or for pressuring natural gas to enter downstream facilities if Antero has not directed us to install sufficient compression. Additionally, we will provide high-pressure gathering pursuant to the gathering and compression agreement.

Upon completion of the initial 20-year term, the gathering and compression agreement will continue in effect from year to year until such time as the agreement is terminated, effective upon an anniversary of the effective date of the agreement, by either us or Antero on or before the 180^th day prior to the anniversary of such effective date.

In addition to the gathering and compression agreement, we have also entered 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 is 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. In the event we do not exercise this option, Antero will be entitled to obtain proposals for fresh water distribution from third parties. We will then have the right to match any proposal received by Antero from a third-party. Under the fresh water distribution agreement, we will receive a fee of $3.50 per barrel for fresh water deliveries to well sites by pipe or $3.00 per barrel if Antero accesses the water by truck directly from our storage facilities, in

each case subject to CPI-based adjustments. Similar to the gathering and compression agreement, the price adjustment mechanisms in the fresh water distribution agreement are intended to support the stability of our cash flows. In addition, if Antero acquires any facilities for providing water for hydraulic fracturing, it is required to offer such facilities to us at its cost.

The water pipeline system by which we distribute fresh water includes facilities for receiving fresh water at designated sources. Pursuant to the fresh water distribution agreement, we transport and store such fresh water at specific areas of operation. The water pipeline system also includes permanent and temporary water lines for delivering Antero's fresh water from the transportation system to its well sites for hydraulic fracturing operations.

In return for Antero's acreage dedication, we have agreed to receive Antero's fresh water and deliver such fresh water to the water pipeline system storage facilities or to particular well sites for hydraulic fracturing up to the available capacity of the water pipeline system. Antero retains the risk of acquiring water in sufficient quantities. We may perform all services under the fresh water distribution agreement or we may perform such services through third parties. In the event that we do not perform our obligations under the fresh water distribution agreement, Antero will be entitled to certain rights and procedural remedies thereunder.

We have the right to use excess water pipeline system capacity and water from Antero's fresh water sources to provide to third parties, provided that we pay the cost, if any, of such excess water.

Further, we are required to build out and expand the water pipeline system in order to deliver fresh water to all of Antero's wells being drilled, subject to certain exceptions. We are obligated to connect the water system and commence water deliveries to particular wells with the central portions of the initial service area upon 180 days' notice from Antero. Our obligation to connect and commence water deliveries in the outlying areas of the initial service area will be phased in over time, but the 180-day notice period will eventually become applicable to all areas in the initial service area. If we do not connect to a particular well for water deliveries, Antero may transport water from our water storage sites for delivery to its well sites.

Upon completion of the initial 20-year term, the fresh water distribution agreement will continue in effect from year to year until such time as the agreement is terminated, effective upon an anniversary of the effective date of the agreement, by either us or Antero on or before the 180^th day prior to the anniversary of such effective date.

Antero's request for offer will describe the production that will be dedicated under the resulting agreement and the capacities of the facilities it desires and, if applicable, details of the facility Antero has acquired or proposes to acquire. Antero is permitted concurrently to seek offers from third parties for the same services on the same terms and conditions, but we have a right to match the fees offered by any third-party. Antero will only be permitted to obtain these services from third parties if we either do not make an offer or do not match a competing third-party offer. The process could result in Antero obtaining certain of the required services from us (for example, gas processing) and certain of such services (for example, NGL fractionation and related services) from a third-party. Our right of

first offer does not apply to production that is subject to a pre-existing dedication. The right of first offer agreement has a 20-year term.

Pursuant to the procedures provided for in the right of first offer agreement, if our offer prevails, Antero will enter into a gas processing agreement or other appropriate services agreement with us and, if applicable, transfer the acquired facility to us for the price for which Antero acquired it. Relevant production will be dedicated under such agreement. We will provide the relevant services for the offered fees, subject to price adjustments based on the consumer price index, or CPI, and Antero will be obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. We may perform all services under the gas processing or other services agreement or may perform such services through third parties. In the event that we do not perform our obligations under the agreement, Antero will be entitled to certain rights and procedural remedies thereunder.

If pursuant to the foregoing procedures Antero enters into a gas processing agreement with us, we will agree to construct or cause to be constructed a processing plant to process the dedicated natural gas, except to the extent rendered unnecessary if Antero is transferring an acquired facility to us. If Antero requires additional capacity in the future at the plant at which we are providing the services, we will have the option to provide such additional capacity on the same terms and conditions. In the event that we do not exercise this option, Antero will be entitled to obtain proposals from third parties to process such production.

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

We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons. We anticipate the board will adopt a written code of business conduct and ethics, under which a director would be expected to bring to the attention of our chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by the conflicts committee.

Upon our adoption of our code of business conduct, we would expect that any executive officer will be required to avoid conflicts of interest unless approved by the board of directors of our general partner.

Please read "Conflicts of Interest and Fiduciary Duties—Conflicts of Interest" for additional information regarding the relevant provisions of our partnership agreement.

The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result, the transactions described above were not reviewed according to such procedures.

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its directors, officers, affiliates (including Antero) and owners, on the one hand, and us and our limited partners, on the other hand. Conflicts may arise as a result of the duties of our general partner and its directors and officers to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. We are managed and operated by the board of directors and officers of our general partner, Midstream Management, which is owned by Antero Investment. All of our initial officers and a majority of our initial directors will also be officers or directors of Antero Investment. Similarly, all of our officers and a majority of our directors are also officers or directors of Antero. Although our general partner has a contractual duty to manage us in a manner that it believes is not adverse to our interests, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to Antero Investment. Our directors and officers who are also directors and officers of Antero have a fiduciary duty to manage Antero in a manner that is beneficial to Antero and its shareholders. Our partnership agreement specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership.

Whenever a conflict arises between our general partner or its owners and affiliates (including Antero), on the one hand, and us or our limited partners, on the other hand, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by us and all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is:

Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as described above. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, a determination, other action or failure to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be deemed to be "in good faith" unless our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) believed such determination, other action or failure to act was adverse to the interest of the partnership. Please read "Management—Committees of the Board of Directors—

Conflicts Committee" for information about the conflicts committee of our general partner's board of directors.

Conflicts of interest could arise in the situations described below, 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 amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

In addition, our general partner may use an amount, initially equal to $ million, which would not otherwise constitute operating surplus, in order to permit the payment of distributions on subordinated units and the incentive distribution rights. All of these actions may affect the amount of cash or equity distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read "How We Make Distributions To Our Partners."

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make such distribution on all outstanding units. Please read "How We Make Distributions To Our Partners—Operating Surplus and Capital Surplus—Operating Surplus."

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 officers and certain directors of our general partner that are also officers and directors of Antero Investment have fiduciary duties to Antero Investment that may cause them to pursue business strategies that disproportionately benefit Antero Investment or which otherwise are not in our best interests.

Our general partner is allowed to take into account the interests of parties other than us, such as Antero Investment and Antero, in exercising certain rights under our partnership agreement.

Our partnership agreement contains provisions that replace the 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. 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 any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment of the partnership agreement.

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.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement provides that:

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in our partnership agreement, including the provisions discussed above. Please read "—Duties."

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

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates (including Antero), on the other, are not and will not be the result of arm's-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm's-length negotiations. Our general partner will determine, in good faith, the terms of any of such future transactions.

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

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, necessary or appropriate to conduct our business including, but not limited to, the following actions:

Please read "The Partnership Agreement" for information regarding the voting rights of unitholders.

If at any time our general partner and its affiliates (including Antero) own more than % of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at the market price calculated in accordance with the terms of our partnership agreement. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your 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 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. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read "The Partnership Agreement—Limited Call Right."

We may not choose to retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflict committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict, although we may choose not to do so.

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.

Our partnership agreement provides that our general partner is restricted from engaging in any business other than guaranteeing debt of its affiliates and those activities incidental to its ownership of interests in us.

However affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us, and Antero Investment or its affiliates (including Antero) may acquire, construct or dispose of assets in the future without any obligation to offer us the opportunity to acquire those assets. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner and its affiliates. As a result, neither our general partner nor any of its affiliates have any obligation to present business opportunities to us.

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. This election may result in lower distributions to our common unitholders in certain situations.

The holder or holders of a majority of our incentive distribution rights (initially our general partner) have the right, at any time when there are no subordinated units outstanding and they have received incentive distributions at the highest level to which they are entitled (50%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election, a baseline distribution amount will be calculated equal to an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution"), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

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 unit without such conversion. However, our general partner may transfer the incentive distribution rights at any time. It is possible that our general partner or a transferee could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when the holders of the incentive distribution rights expect that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, the holders of the incentive

distribution rights may be experiencing, or may expect to experience, declines in the cash distributions it receives related to the incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for them to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to the holders of the incentive distribution rights in connection with resetting the target distribution levels. Please read "How We Make Distributions To Our Partners—Incentive Distribution Rights."

Duties owed to unitholders by our general partner are prescribed by law and in our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

Our partnership agreement contains various provisions that eliminate and replace the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership in good faith and a duty to manage our general partner in a manner beneficial to its owner. Without these modifications, our general partner's ability to make decisions involving conflicts of interest would be restricted. Replacing the fiduciary duty standards in this manner benefits our general partner by enabling it to take into consideration all parties involved in the proposed action. Replacing the fiduciary duty standards also strengthens the ability of our general partner to attract and retain experienced and capable directors. Replacing the fiduciary duty standards represents a detriment to our public unitholders because it restricts the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permits our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests.

The following is a summary of the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary, the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware laws on our general partner and the rights and remedies of our unitholders with respect to these contractual duties:


Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in "good faith," meaning that it believed its actions or omissions were not adverse to the interest of the partnership, and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These contractual standards replace the obligations to which our general partner would otherwise be held.
		If our general partner does not obtain approval from the conflicts committee of the board of directors of our general partner or our common unitholders, excluding any such units owned by our general partner or its affiliates, and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, its board, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. These standards replace the obligations to which our general partner would otherwise be held.
Rights and remedies of unitholders		The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its duties or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide

this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged in by it in bad faith or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read "The Partnership Agreement—Indemnification."

The common units and the subordinated units are separate classes of limited partner interests in us. Unitholders are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of unitholders in and to partnership distributions, please read this section and "How We Make Distributions To Our Partners." For a description of other rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement."

American Stock Transfer & Trust Company, LLC will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following, which must be paid by our common unitholders:

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed or has not accepted its appointment within 30 days of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Upon the transfer of a common unit in accordance with our partnership agreement, the transferee of the common unit shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

The following is a summary of the material provisions of our partnership agreement, which we will adopt in connection with the closing of this offering. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide investors and prospective investors with a copy of our partnership agreement, when available, upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

We were organized in September 2013 as a Delaware limited liability company and will convert into a Delaware limited partnership—Antero Midstream Partners LP—in connection with the contribution of Midstream Operating to us at the completion of this offering. We will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to take any action that the general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the midstream business, our general partner may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

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.

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its incentive distribution rights. For a description of these cash distribution provisions, please read "How We Make Distributions To Our Partners."

Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that require the approval of a "unit majority" require:

In voting their common and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners.

The incentive distribution rights may be entitled to vote in certain circumstances.


Issuance of additional units		No approval right.
Amendment of the partnership agreement		Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read "—Amendment of the Partnership Agreement."
Merger of our partnership or the sale of all or substantially all of our assets		Unit majority in certain circumstances. Please read "—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets."
Dissolution of our partnership		Unit majority. Please read "—Dissolution."
Continuation of our business upon dissolution		Unit majority. Please read "—Dissolution."
Withdrawal of our general partner		No approval right. Please read "—Withdrawal or Removal of Our General Partner."
Removal of our general partner		Not less than 66²/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates, for cause. 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. Please read "—Withdrawal or Removal of Our General Partner."
Transfer of our general partner interest		No approval right. Please read "—Transfer of General Partner Interest."
Transfer of incentive distribution rights		No approval right. Please read "—Transfer of Subordinated Units and Incentive Distribution Rights."
Transfer of ownership interests in our general partner		No approval right. Please read "—Transfer of Ownership Interests in the General Partner."

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to Antero or to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions 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.

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited is included in the assets of the limited partnership only to the extent that the fair value of that property exceeds that liability. For the purpose of determining the fair value of the assets of a limited

partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years.

Following the completion of this offering, we expect that our subsidiaries will conduct business in several states and we may have subsidiaries that conduct business in other states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing common unitholders in our distributions. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing common unitholders in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to the common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue partnership interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The common unitholders will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, an affiliate of our general partner will own approximately % of our outstanding common and subordinated units.

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:

Any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners, and is not permitted to be adopted by our general partner without limited partner approval, will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. Any such amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any such amendment that would reduce the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any such amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased. For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any of the

amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests (other than incentive distribution rights) immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, we have received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters' rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in "How We Make Distributions To Our Partners—Distributions of Cash Upon Liquidation." The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Our general partner may withdraw as general partner in compliance with our partnership agreement after giving 90 days' written notice to our unitholders.

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read "—Dissolution."

Our general partner may not be removed unless that removal is for cause and is approved by the vote of the holders of not less than 66²/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a class, and the outstanding subordinated units, voting as a class. The ownership of more than 33¹/3% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner's removal. At the closing of this offering, an affiliate of our general partner will own approximately % of our outstanding limited partner units, including all of our subordinated units.

In the event of the removal of our general partner or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner and its affiliates for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws, the departing general partner will have the option to require the successor general partner to purchase the general partner interest and the incentive distribution rights of the departing general partner and its affiliates for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or

other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interest and all its and its affiliates' incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.

At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

At any time, the owner of our general partner may sell or transfer all or part of its ownership interests in our general partner to an affiliate or third party without the approval of our unitholders.

By transfer of subordinated units or incentive distribution rights in accordance with our partnership agreement, each transferee of subordinated units or incentive distribution rights will be admitted as a limited partner with respect to the subordinated units or incentive distribution rights transferred when such transfer and admission is reflected in our books and records. Each transferee:

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of subordinated units or incentive distribution rights as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Subordinated units and incentive distribution rights are securities and any transfers are subject to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner for the transferred subordinated units or incentive distribution rights.

Until a subordinated unit or incentive distribution right has been transferred on our books, we and the transfer agent may treat the record holder of the unit or right as the absolute owner for all purposes, except as otherwise required by law.

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Antero Resources Midstream Management LLC as our general partner or from otherwise changing our management. Please read "—Withdrawal or Removal of Our General Partner" for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates or any transferees of that person or group who are notified by our general partner that they will not lose their voting rights or to any person or group who acquires the units with the prior approval of the board of directors of our general partner. Please read "—Meetings; Voting."

If at any time our general partner and its affiliates (including Antero) own more than % of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10, but not more than 60, days' notice. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%.

As a result of our general partner's right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material U.S. Federal Income Tax Consequences—Disposition of Units."

To avoid any adverse effect on the maximum applicable rates chargeable to customers by us or any of our future subsidiaries, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend our partnership agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners (or their owners, to the extent relevant), has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us or our subsidiaries, then

our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

If our general partner, with the advice of counsel, determines we are subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner (or its owners, to the extent relevant), then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of our unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. Our general partner may postpone any meeting of unitholders one or more times for any reason by giving notice to the unitholders entitled to vote at such meeting. Our general partner may also adjourn any meeting of unitholders one or more times for any reason, including the absence of a quorum, without a vote of the unitholders.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Interests." However, if at any time any person or group, other than our general partner

and its affiliates (including Antero), or a direct or subsequently approved transferee of our general partner or its affiliates and purchasers specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record common unitholders under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

If a majority of the incentive distribution rights are held by our general partner and its affiliates, the holders of the incentive distribution rights will have no right to vote in respect of such rights on any matter, unless otherwise required by law, and the holders of the incentive distribution rights shall be deemed to have approved any matter approved by our general partner.

If less than a majority of the incentive distribution rights are held by our general partner and its affiliates, the incentive distribution rights will be entitled to vote on all matters submitted to a vote of unitholders, other than amendments and other matters that our general partner determines do not adversely affect the holders of the incentive distribution rights in any material respect. On any matter in which the holders of incentive distribution rights are entitled to vote, such holders will vote together with the subordinated units, prior to the end of the subordination period, or together with the common units, thereafter, in either case as a single class, and such incentive distribution rights shall be treated in all respects as subordinated units or common units, as applicable, when sending notices of a meeting of our limited partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our partnership agreement. The relative voting power of the holders of the incentive distribution rights and the subordinated units or common units, depending on which class the holders of incentive distribution rights are voting with, will be set in the same proportion as cumulative cash distributions, if any, in respect of the incentive distribution rights for the four consecutive quarters prior to the record date for the vote bears to the cumulative cash distributions in respect of such class of units for such four quarters.

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us. Please read "Certain Relationships and Related Transactions—Agreements with Affiliates in Connection with the Transactions—Services Agreement."

Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website that we maintain.

We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

Under our partnership agreement, however, each of our limited partners and other persons who acquire interests in our partnership interests, do not have rights to receive information from us or any of the persons we indemnify as described above under "—Indemnification" for the purpose of determining whether to pursue litigation or assist in pending litigation against us or those indemnified persons relating to our affairs, except pursuant to the applicable rules of discovery relating to the litigation commenced by the person seeking information.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the rights to information that a limited partner would otherwise have under Delaware law.

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other limited partner interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts.

In addition, in connection with the completion of this offering, we expect to enter into a registration rights agreement with Antero. Pursuant to the registration rights agreement, we will be required to file a registration statement to register the common units and subordinated units issued to Antero and the common units issuable upon the conversion of the subordinated units upon request of Antero. Pursuant to the registration rights agreement and our partnership agreement, we may be required to undertake a future public or private offering and use the proceeds (net of underwriting or placement agency discounts, fees and commissions, as applicable) to redeem an equal number of common units from them. In addition, the registration rights agreement gives Antero "piggyback" registration rights under certain circumstances. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates of Antero and, in certain circumstances, to third parties. Please read "Units Eligible for Future Sale."

After the sale of the common units offered by this prospectus, Antero will hold an aggregate of common units and subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

Our common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits common units acquired by an affiliate of ours to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned our common units for at least six months, would be entitled to sell those common units under Rule 144, subject only to the current public information requirement. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned our common units for at least one year, would be entitled to sell those common units under Rule 144 without regard to the other provisions.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type and at any time without a vote of the unitholders. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read "The Partnership Agreement—Issuance of Additional Interests."

Under our partnership agreement, our general partner and its affiliates will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of the partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discount. Except as described below, our general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.

In addition, we will enter into a registration rights agreement with Antero pursuant to which we may be required to register the sale of the (i) common units issued (or issuable) to Antero pursuant to the contribution agreement, (ii) subordinated units and (iii) common units issuable upon conversion of subordinated units pursuant to the terms of the partnership agreement (together, the "Registrable Securities") it holds. Under the registration rights agreement, Antero will have the right to request that

we register the sale of Registrable Securities held by it, and Antero will have the right to require us to make available shelf registration statements permitting sales of Registrable Securities into the market from time to time over an extended period, subject to certain limitations. Pursuant to the registration rights agreement and our partnership agreement, we may be required to undertake a future public or private offering of common units and use the net proceeds from such offering to redeem an equal number of common units held by Antero. In addition, the registration rights agreement gives Antero "piggyback" registration rights under certain circumstances. The registration rights agreement also includes provisions dealing with indemnification and contribution and allocation of expenses. All of the Registrable Securities held by Antero and any permitted transferee will be entitled to these registration rights. Please read "Certain Relationships and Related Transactions—Agreements with Affiliates in Connection with the Transactions—Registration Rights Agreement."

The executive officers and directors of our general partner have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. Please read "Underwriting" for a description of these lock-up provisions.

This section summarizes the material federal income tax consequences that may be relevant to prospective unitholders and is based upon current provisions of the Internal Revenue Code of 1986, as amended (the "Code"), existing and proposed Treasury regulations thereunder (the "Treasury Regulations"), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the federal income tax consequences to a prospective unitholder to vary substantially from those described below, possibly on a retroactive basis. Unless the context otherwise requires, references in this section to "we" or "us" are references to Antero Midstream Partners LP and its subsidiaries.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all federal income tax matters that affect us or our unitholders and does not describe the application of the alternative minimum tax that may be applicable to certain unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for federal income tax purposes), who have the U.S. dollar as their functional currency, who use the calendar year as their taxable year, and who hold units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations, partnerships, (including entities treated as partnerships for federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, IRAs, employee benefit plans, real estate investment trusts or mutual funds. Accordingly, we encourage each unitholder to consult the unitholder's own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from ownership or disposition of units and potential changes in applicable tax laws.

We are relying on opinions and advice of Vinson & Elkins L.L.P. with respect to the matters described herein. An opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or a court. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for units and the prices at which our units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution. Furthermore, the tax consequences of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions, which may be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following federal income tax issues: (1) the treatment of 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) (please read "—Tax Consequences of Unit Ownership—Treatment of Securities Loans"); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read "—Disposition of Units—Allocations Between Transferors and Transferees"); and (3) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Uniformity of Units").

We expect to be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for entity-level federal income taxes. Instead, as described below, each of our unitholders will take into account its respective share of our items of income, gain, loss and

deduction in computing its federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder.

Section 7704 of the Code generally provides that publicly-traded partnerships will be treated as corporations for federal income tax purposes. However, if 90% or more of a partnership's gross income for every taxable year it is publicly-traded consists of "qualifying income," the partnership may continue to be treated as a partnership for federal income tax purposes (the "Qualifying Income Exception"). Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of certain natural resources, including crude oil, natural gas and products thereof, as well as other types of income such as interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current gross income is not qualifying income; however, this estimate could change from time to time.

Based upon factual representations made by us and our general partner, Vinson & Elkins L.L.P. is of the opinion that we will be treated as a partnership and each of our limited liability company subsidiaries will be disregarded as an entity separate from us for federal income tax purposes. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied in rendering its opinion include, without limitation:

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then as distributing that stock to our unitholders in liquidation. This deemed contribution and liquidation should not result in the recognition of taxable income by our unitholders or us so long as our liabilities do not exceed the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative or legislative action or judicial interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the Qualifying Income Exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for federal income tax, rather than being passed through to our unitholders. Our taxation as a corporation would materially reduce the cash available for distribution to unitholders and thus would likely

substantially reduce the value of our units. Any distribution made to a unitholder at a time we are treated as a corporation would be (i) a taxable dividend to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder's tax basis in its units, and thereafter (iii) taxable capital gain.

The remainder of this discussion is based on the opinion of Vinson & Elkins L.L.P. that we will be treated as a partnership for federal income tax purposes.

Unitholders who are admitted as limited partners of the partnership, as well as unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of units, will be treated as partners of the partnership for federal income tax purposes. For a discussion related to the risks of losing partner status as a result of securities loans, please read "—Tax Consequences of Unit Ownership—Treatment of Securities Loans." Unitholders who are not treated as partners in us as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under their particular circumstances.

Subject to the discussion below under "—Entity-Level Collections of Unitholder Taxes" with respect to payments we may be required to make on behalf of our unitholders, we will not pay any federal income tax. Rather, each unitholder will be required to report on its federal income tax return each year its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution.

A unitholder's tax basis in its units initially will be the amount paid for those units increased by the unitholder's initial allocable share of our nonrecourse liabilities. That basis generally will be (i) increased by the unitholder's share of our income and any increases in such unitholder's share of our nonrecourse liabilities, and (ii) decreased, but not below zero, by the amount of all distributions to the unitholder, the unitholder's share of our losses, and any decreases in the unitholder's share of our nonrecourse liabilities and its share of our expenditures that are neither deductible nor required to be capitalized. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests.

We estimate that a purchaser of units in this offering who owns those units from the date of closing of this offering through the record date for distributions for the period ending , , will be allocated, on a cumulative basis, an amount of federal taxable income that will be % or less of the cash distributed on those units with respect to that period. These estimates are based upon the assumption that earnings from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and which could be changed or with which the IRS could disagree.

Accordingly, we cannot assure that these estimates will prove to be correct, and our counsel has not opined on the accuracy of such estimates. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could affect the value of units. For example, the ratio of taxable income to cash distributions to a purchaser of units in this offering would be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

Distributions by us to a unitholder generally will not be taxable to the unitholder, unless such distributions exceed the unitholder's tax basis in its units, in which case the unitholder generally will recognize gain taxable in the manner described below under "—Disposition of Units."

Any reduction in a unitholder's share of our "nonrecourse liabilities" (liabilities for which no partner bears the economic risk of loss) will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder's percentage interest in us because of our issuance of additional units may decrease the unitholder's share of our nonrecourse liabilities. For purposes of the foregoing, a unitholder's share of our nonrecourse liabilities generally will be based upon that unitholder's share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the unitholder's share of our profits. Please read "—Disposition of Units."

A non-pro rata distribution of money or property (including a deemed distribution as a result of the reallocation of our liabilities described above) may cause a unitholder to recognize ordinary income, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation and depletion recapture and substantially appreciated "inventory items," both as defined in Section 751 of the Code ("Section 751 Assets"). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for a portion of the non-pro rata distribution. This deemed exchange generally will result in the unitholder's recognition of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder's tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

A unitholder may not be entitled to deduct the full amount of loss we allocate to it because its share of our losses will be limited to the lesser of (i) the unitholder's tax basis in its units, and (ii) in the case of a unitholder that is an individual, estate, trust or certain types of closely-held corporations, the amount for which the unitholder is considered to be "at risk" with respect to our activities. In general, a unitholder will be at risk to the extent of its tax basis in its units, reduced by (1) any portion of that basis attributable to the unitholder's share of our liabilities, (2) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement and (3) any amount of money the unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. A unitholder subject to the at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions deemed to

result from a reduction in a unitholder's share of nonrecourse liabilities) cause the unitholder's at risk amount to be less than zero at the end of any taxable year.

Losses disallowed to a unitholder or recaptured as a result of the basis or at risk limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder's tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of units, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used, and will not be available to offset a unitholder's salary or active business income.

In addition to the basis and at risk limitations, a passive activity loss limitation generally limits the deductibility of losses incurred by individuals, estates, trusts, some closely-held corporations and personal service corporations from "passive activities" (generally, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will be available to offset only passive income generated by us. Passive losses that exceed a unitholder's share of passive income we generate may be deducted in full when the unitholder disposes of all of its units in a fully taxable transaction with an unrelated party. The passive loss rules generally are applied after other applicable limitations on deductions, including the at risk and basis limitations.

The deductibility of a non-corporate taxpayer's "investment interest expense" generally is limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:

The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses other than interest directly connected with the production of investment income. Net investment income generally does not include qualified dividend income or gains attributable to the disposition of property held for investment. A unitholder's share of a publicly-traded partnership's portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

If we are required or elect under applicable law to pay any federal, state, local or non-U.S. tax on behalf of any current or former unitholder or our general partner, we are authorized to treat the payment as a distribution of cash to the relevant unitholder or general partner. Where the tax is payable on behalf of all unitholders or we cannot determine the specific unitholder on whose behalf the tax is payable, we are authorized to treat the payment as a distribution to all current unitholders. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount. Unitholders are urged to consult their tax advisors to determine the consequences to them of any tax payment we make on their behalf.

Our items of income, gain, loss and deduction generally will be allocated amongst our unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or we make incentive distributions, gross income will be allocated to the recipients to the extent of these distributions.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units (a "Book-Tax Disparity"). As a result, the federal income tax burden associated with any Book-Tax Disparity immediately prior to an offering generally will be borne by our partners holding interests in us prior to such offering. In addition, items of recapture income will be specially allocated to the extent possible to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate a Book-Tax Disparity, will generally be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has "substantial economic effect." In any other case, a partner's share of an item will be determined on the basis of the partner's interest in us, which will be determined by taking into account all the facts and circumstances, including (i) the partner's relative contributions to us, (ii) the interests of all the partners in profits and losses, (iii) the interest of all the partners in cash flow and (iv) the rights of all the partners to distributions of capital upon liquidation. Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in "—Section 754 Election" and "—Disposition of Units—Allocations Between Transferors and Transferees," allocations of income, gain, loss or deduction under our partnership agreement will be given effect for federal income tax purposes.

A unitholder whose units are loaned (for example, a loan to "short seller" to cover a short sale of units) may be treated as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those units would not be reportable by the lending unitholder, and (ii) any cash distributions received by the unitholder as to those units may be treated as ordinary taxable income.

Due to a lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder that enters into a securities loan with respect to its units. Unitholders desiring to assure their status as partners and avoid the risk of income recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read "—Disposition of Units—Recognition of Gain or Loss."

Under current law, the highest marginal federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

In addition, a 3.8% net investment income tax ("NIIT") applies to certain net investment income earned by individuals, estates, and trusts. For these purposes, net investment income generally includes a unitholder's allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder's net investment income from all investments, or (ii) the amount by which the unitholder's modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if married filing separately) or $200,000 (if the unitholder is unmarried or in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

We will make the election permitted by Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchasers of our units under Section 743(b) of the Code. That election is irrevocable without the consent of the IRS. The Section 743(b) adjustment separately applies to each purchaser of units based upon the values and bases of our assets at the time of the relevant purchase, and the adjustment will reflect the purchase price paid. The Section 743(b) adjustment does not apply to a person who purchases units directly from us.

Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with applicable Treasury Regulations. A literal application of Treasury Regulations governing a 743(b) adjustment attributable to properties depreciable under Section 167 of the Code may give rise to differences in the taxation of unitholders purchasing units from us and unitholders purchasing from other unitholders. If we have any such properties, we intend to adopt methods employed by other publicly traded partnerships to preserve the uniformity of units, even if inconsistent with existing Treasury Regulations, and Vinson & Elkins L.L.P. has not opined on the validity of this approach. Please read "—Uniformity of Units."

The IRS may challenge the positions we adopt with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units due to lack of controlling authority. Because a unitholder's tax basis for its units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder's basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read "—Disposition of Units—Recognition of Gain or Loss." If a challenge to such treatment were sustained, the gain from the sale of units may be increased without the benefit of additional deductions.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than it would have been allocated had the election not been revoked.

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in its tax return its share of our income, gain, loss and deduction for each taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than one year of our income, gain, loss and deduction. Please read "—Disposition of Units—Allocations Between Transferors and Transferees."

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of those assets. If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation and depletion deductions previously taken, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction."

The costs we incur in offering and selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, the underwriting discounts and commissions we incur will be treated as syndication expenses. Please read "Disposition of Units—Recognition of Gain or Loss."

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders could change, and unitholders could be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

A unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder's amount realized and tax basis in the units sold. A unitholder's amount realized generally will equal the sum of the cash and the fair market value of other property it receives plus its share of our nonrecourse liabilities with respect to the units sold. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, such as depreciation or depletion recapture and our "inventory items," regardless of whether such inventory item is substantially appreciated in value. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and capital gain or loss upon a sale of units. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

For purposes of calculating gain or loss on the sale of units, the unitholder's adjusted tax basis will be adjusted by its allocable share of our income or loss in respect of its units for the year of the sale. Furthermore, as described above, the IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner's tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner's entire interest in the partnership.

Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed in the paragraph above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, it may designate specific units sold for purposes of determining the holding period of the units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of our units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" financial position, including a partnership interest with respect to which gain would be recognized if it were sold, assigned or terminated at its fair market value, in the event the taxpayer or a related person enters into:

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is authorized to issue Treasury Regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units

owned by each of them as of the opening of the applicable exchange on the first business day of the month (the "Allocation Date"). However, gain or loss realized on a sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS 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, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the final Treasury Regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses could be reallocated among our unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

A unitholder who sells or purchases any of its units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction in the case of a seller). Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale through a broker who will satisfy such requirements.

We will be considered to have "constructively" terminated as a partnership for federal income tax purposes upon the sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For such purposes, multiple sales of the same unit are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder's taxable income for the year of termination.

A constructive termination occurring on a date other than December 31 generally would require that we file two tax returns for one fiscal year thereby increasing our administration and tax preparation costs. However, pursuant to an IRS relief procedure the IRS may allow a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. Following a constructive termination, we would be required to make new tax elections, including a new election under Section 754 of the Code, and the termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to

determine that the termination had occurred. Moreover, a termination may either accelerate the application of, or subject us to, any tax legislation enacted before the termination that would not otherwise have been applied to us as a continuing as opposed to a terminating partnership.

Because we cannot match transferors and transferees of units and other reasons, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements. Any non-uniformity could have a negative impact on the value of the units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election."

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units. These positions may include reducing the depreciation, amortization or loss deductions to which a unitholder would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Vinson & Elkins L.L.P. is unable to opine as to the validity of such filing positions.

A unitholder's basis in units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder's basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read "—Disposition of Units—Recognition of Gain or Loss" above and "—Tax Consequences of Unit Ownership—Section 754 Election" above. The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

Ownership of units by employee benefit plans and other tax-exempt organizations as well as by non-resident alien individuals, non-U.S. corporations and other non-U.S. persons (collectively, "Non-U.S. Unitholders") raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective unitholders that are tax-exempt entities or Non-U.S. Unitholders should consult their tax advisors before investing in our units. Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income will be unrelated business taxable income and will be taxable to a tax-exempt unitholder.

Non-U.S. Unitholders are taxed by the United States on income effectively connected with the conduct of a U.S. trade or business ("effectively connected income") and on certain types of U.S.-source non-effectively connected income (such as dividends), unless exempted or further limited by an income tax treaty will be considered to be engaged in business in the United States because of their ownership of our units. Furthermore, is it probable that they will be deemed to conduct such activities through permanent establishments in the United States within the meaning of applicable tax treaties. Consequently, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax on their share of our net income or gain in a manner similar to a taxable U.S. unitholder. Moreover, under rules applicable to publicly traded partnerships, distributions to Non-U.S. Unitholders are subject to withholding at the highest applicable effective tax rate. Each Non-U.S. Unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes.

In addition, because a Non-U.S. Unitholder classified as a corporation will be treated as engaged in a United States trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain as adjusted for changes in the foreign corporation's "U.S. net equity" to the extent reflected in the corporation's effectively connected earnings and profits. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A Non-U.S. Unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the Non-U.S. Unitholder. Under a ruling published by the IRS interpreting the scope of "effectively connected income," gain recognized by a non-U.S. person from the sale of its interest in a partnership that is engaged in a trade or business in the United States will be considered to be effectively connected with a U.S. trade or business. Thus, part or all of a Non-U.S. Unitholder's gain from the sale or other disposition of its units may be treated as effectively connected with a unitholder's indirect U.S. trade or business constituted by its investment in us. Moreover, under the Foreign Investment in Real Property Tax Act, a Non-U.S. Unitholder generally will be subject to federal income tax upon the sale or disposition of a unit if (i) it owned (directly or indirectly constructively applying certain attribution rules) more than 5% of our units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of our worldwide real property interests and our other assets used or held for use in a trade or business consisted of U.S. real property interests (which include U.S. real estate (including land, improvements, and certain associated personal property) and interests in certain entities holding U.S. real estate) at any time during the shorter of the period during which such unitholder held the units or the 5-year period ending on the date of disposition. More than 50% of our assets may consist of U.S. real property interests. Therefore, Non-U.S. Unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder's share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to all of the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

The IRS may audit our federal income tax information returns. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully challenge the positions we adopt, and such a challenge could adversely affect the value of the units. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability and may result in an audit of the unitholder's own return. Any audit of a unitholder's return could result in adjustments unrelated to our returns.

Publicly traded partnerships generally are treated as entities separate from their owners for purposes of federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings of the partners. The Code

requires that one partner be designated as the "Tax Matters Partner" for these purposes, and our partnership agreement designates our general partner.

The Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review may go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Certain penalties may be imposed as a result of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements.. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion. We do not anticipate that any accuracy related penalties will be assessed against us.

In addition to federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property now or in the future or in which the unitholder is a resident. We currently conduct business or own property in West Virginia, Ohio and Pennsylvania, each of which imposes a personal income tax on individuals. In addition, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us.

Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. We strongly recommend that each prospective unitholder consult, and depend upon, its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and non-U.S., as well as U.S. federal tax returns that may be required of it. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, alternative minimum tax or non-U.S. tax consequences of an investment in us.

An investment in our common units by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the prohibited transaction restrictions imposed by Section 4975 of the Internal Revenue Code and may be subject to provisions under certain other laws or regulations that are similar to ERISA or the Internal Revenue Code ("Similar Laws"). For these purposes the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, certain Keogh plans, certain simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization.

ERISA and the Internal Revenue Code impose certain duties on persons who are fiduciaries of an employee benefit plan that is subject to Title I of ERISA or Section 4975 of the Internal Revenue Code (an "ERISA Plan") and prohibit certain transactions involving the assets of an ERISA Plan and its fiduciaries or other interested parties. Under ERISA and the Internal Revenue Code, any person who exercises any discretionary authority or control over the administration of an ERISA Plan or the management or disposition of the assets of an ERISA Plan, or who renders investment advice for a fee or other compensation to an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan. In considering an investment in our common units, among other things, consideration should be given to:

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in our common units is authorized by the appropriate governing instruments and is a proper investment for the employee benefit plan or IRA.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans and certain IRAs that are not considered part of an employee benefit plan from engaging in specified transactions involving "plan assets" with parties that are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code with respect to the employee benefit plan or IRA, unless an exemption is applicable. A party in interest or disqualified person who engages in a

non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA Plan that engaged in such a prohibited transaction may be subject to excise taxes, penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of our common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in our common units, be deemed to own an undivided interest in our assets, with the result that our general partner also would be a fiduciary of the plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code and any other applicable Similar Laws.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed "plan assets" under certain circumstances. Under these regulations, an entity's underlying assets generally would not be considered to be "plan assets" if, among other things:

With respect to an investment in our common units, we believe that our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in (1) and (2) above and may also satisfy the requirements in (3) above (although we do not monitor the level of investment by benefit plan investors as required for compliance with (3)).

The foregoing discussion of issues arising for employee benefit plan investments under ERISA, the Internal Revenue Code and applicable Similar Laws is general in nature and is not intended to be all inclusive, nor should it be construed as legal advice. Plan fiduciaries contemplating a purchase of our common units should consult with their own counsel regarding the consequences of such purchase under ERISA, the Internal Revenue Code and Similar Laws in light of the serious penalties, excise taxes and liabilities imposed on persons who engage in prohibited transactions or other violations.

Barclays Capital Inc., Citigroup Global Markets Inc. and Wells Fargo Securities, LLC are acting as the representatives of the underwriters and the joint book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement of which this prospectus forms a part, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:

The underwriting agreement provides that the underwriters' obligation to purchase common units depends on the satisfaction of the conditions contained in the underwriting agreement, including:

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.

In addition, we will pay an aggregate structuring fee of % of the gross proceeds from this offering to Barclays Capital Inc. and Citigroup Global Markets Inc. for evaluation, analysis and structuring of this offering.

The representatives of the underwriters have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per common unit. After this offering, the representatives may change the offering price and other selling terms. Sales of common units made outside of the United States may be made by affiliates of the underwriters. The offering of the common units by the underwriters is subject to receipt and acceptance by them and subject to their right to reject any order in whole or in part.

The expenses of this offering that are payable by us are estimated to be approximately $ million (excluding underwriting discounts and commissions).

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus, to purchase, from time to time, in whole or in part, up to an aggregate of additional common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter's percentage underwriting commitment in this offering as indicated in the table at the beginning of this "Underwriting" section.

We, Antero, our general partner, and the directors and executive officers of our general partner have agreed that, for a period of 180 days after the date of this prospectus, we and they will not directly or indirectly, without the prior written consent of Barclays Capital Inc., (1) offer for sale, sell, pledge or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any common units (including, without limitation, common units that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units (other than common units issued pursuant to employee benefit plans, qualified unit option plans or other employee compensation plans existing on the date of this prospectus), or sell or grant options, rights or warrants with respect to any common units or securities convertible into or exercisable or exchangeable for common units, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of common units, whether any such transaction described in clause (1) or clause (2) above is to be settled by delivery of common units or other securities, in cash or otherwise, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible into or exercisable or exchangeable for common units or any of our other securities (other than any registration statement on Form S-8), or (4) publicly disclose the intention to do any of the foregoing.

Barclays Capital Inc., in its sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release the common units and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder's reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time. Barclays Capital Inc. does not have any present intention, agreement or understanding, implied or explicit, to release any of the securities subject to the lock-up agreements prior to the expiration of the lock-up period described above.

As described below under "—Directed Unit Program," any participants in the directed unit program shall be subject to a 180-day lock up with respect to any common units sold to them pursuant to that program. This lock up will have similar restrictions as the lock-up agreement described above. Any common units sold in the directed unit program to our directors or officers shall be subject to the lock-up agreement described above.

Prior to this offering, there has been no public market for our common units. The initial public offering price will be negotiated between the representatives and us. In determining the initial public offering price of our common units, the representatives will consider:

We have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the directed unit program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities.

At our request, the underwriters have reserved for sale at the initial public offering price up to common units offered hereby for officers, directors, employees and certain other persons associated with us. The number of common units available for sale to the general public will be reduced to the extent such persons purchase such reserved common units. Any reserved common units not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered hereby. Any participants in this program will be prohibited from selling, pledging or assigning any common units sold to them pursuant to this program for a period of 180 days after the date of this prospectus.

The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Exchange Act.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

A prospectus in electronic format may be made available on Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter's or selling group member's website and any information contained in any other website maintained by an underwriter or selling group member is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

The underwriters have informed us that they do not expect to sell more than 5% of the common units in the aggregate to accounts over which they exercise discretionary authority.

If you purchase common units offered by this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

The underwriters and certain of their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. The underwriters and certain of their respective affiliates have, from time to time, performed, and may in the future perform, various commercial and investment banking and financial advisory services for us and our affiliates, including Antero, for which they received or may in the future receive customary fees and expenses. Specifically, affiliates of Barclays Capital Inc., Citigroup Global Markets Inc. and Wells Fargo Securities, LLC are lenders under Antero's credit facility. In addition, Barclays Capital Inc., Citigroup Global Markets Inc. and Wells Fargo Securities, LLC served as underwriters in Antero's initial public offering in October 2013 and as initial purchasers in Antero Resources Finance Corporation's offering of 5.375% Senior Notes due 2021 in November 2013. Affiliates of Barclays Capital Inc., Citigroup Global Markets Inc. and Wells Fargo Securities, LLC are lenders under the existing midstream credit facility and, accordingly, will receive a portion of the proceeds from this offering. In addition, we anticipate that affiliates of will be lenders under our new revolving credit facility. In connection with these transactions, the underwriters and their affiliates received customary fees for their services.

In the ordinary course of their various business activities, the underwriters and certain of their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of us or our affiliates, including Antero. If the underwriters or their respective affiliates have a lending relationship with us or our affiliates, certain of those underwriters or their respective affiliates may hedge their credit exposure to us or our affiliates consistent with their customary risk management policies. Typically, the underwriters and their respective affiliates would hedge such exposure by entering into transactions that consist of either the purchase of credit default swaps or the creation of short positions in our securities or the securities of our affiliates, including potentially the common units offered hereby. Any such credit default swaps or short positions could adversely affect future trading prices of the common units offered hereby. The underwriters and certain of their respective affiliates may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Because the Financial Industry Regulatory Authority, Inc. ("FINRA") views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with FINRA Rule 2310. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of common units described in this prospectus may not be made to the public in that relevant member state other than:

provided that no such offer of common units shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an "offer of common units to the public" in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the common units to be offered so as to enable an investor to decide to purchase or subscribe for the common units, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression "Prospectus Directive" means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in each relevant member state) and includes any relevant implementing measure in the relevant member state. The expression "2010 PD Amending Directive" means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of common units through any financial intermediary on our behalf, other than offers made by the underwriters with a view to the final placement of the common units as contemplated in this prospectus. Accordingly, no purchaser of the common units, other than the underwriters, is authorized to make any further offer of the common units on behalf of us or the underwriters.

We may constitute a "collective investment scheme" as defined by section 235 of the Financial Services and Markets Act 2000 ("FSMA") that is not a "recognised collective investment scheme" for the purposes of FSMA ("CIS") and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at (i) investment professionals falling within the description of persons in Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) Order 2001, as amended (the "CIS Promotion Order") or Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the "Financial Promotion Order") or (ii) high net worth companies and other persons falling with Article 22(2)(a) to (d) of the CIS Promotion Order or Article 49(2)(a) to (d) of the Financial Promotion Order, or (iii) to any other person to whom it may otherwise lawfully be made (all such persons together being referred to as "relevant persons"). Our common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant

persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. Our common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be distributed in connection with any such public offering. We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 (CISA). Accordingly, our common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be made available through a public offering in or from Switzerland. Our common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this document and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

The offering does not constitute an offer to sell or the solicitation of an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

No placement document, prospectus, product disclosure statement or other disclosure document has been lodged with the Australian Securities and Investments Commission ("ASIC") in relation to the offering. This prospectus does not constitute a prospectus, product disclosure statement or other disclosure document under the Corporations Act 2001 (the "Corporations Act"), and does not purport

to include the information required for a prospectus, product disclosure statement or other disclosure document under the Corporations Act.

Any offer in Australia of the common units may only be made to persons (the "Exempt Investors") who are "sophisticated investors" (within the meaning of section 708(8) of the Corporations Act), "professional investors" (within the meaning of section 708(11) of the Corporations Act) or otherwise pursuant to one or more exemptions contained in section 708 of the Corporations Act so that it is lawful to offer the common units without disclosure to investors under Chapter 6D of the Corporations Act.

The common units applied for by Exempt Investors in Australia must not be offered for sale in Australia in the period of 12 months after the date of allotment under the offering, except in circumstances where disclosure to investors under Chapter 6D of the Corporations Act would not be required pursuant to an exemption under section 708 of the Corporations Act or otherwise or where the offer is pursuant to a disclosure document which complies with Chapter 6D of the Corporations Act. Any person acquiring common units must observe such Australian on-sale restrictions.

This prospectus contains general information only and does not take account of the investment objectives, financial situation or particular needs of any particular person. It does not contain any securities recommendations or financial product advice. Before making an investment decision, investors need to consider whether the information in this prospectus is appropriate to their needs, objectives and circumstances, and, if necessary, seek expert advice on those matters.

The common units have not been and will not be offered or sold in Hong Kong, by means of any document, other than (a) to "professional investors" as defined in the Securities and Futures Ordinance (Cap. 571) of Hong Kong and any rules made under that Ordinance; or (b) in other circumstances which do not result in the document being a "prospectus" as defined in the Companies Ordinance (Cap. 32) of Hong Kong or which do not constitute an offer to the public within the meaning of that Ordinance. No advertisement, invitation or document relating to the common units has been or may be issued or has been or may be in the possession of any person for the purposes of issue, whether in Hong Kong or elsewhere, which is directed at, or the contents of which are likely to be accessed or read by, the public of Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to common units which are or are intended to be disposed of only to persons outside Hong Kong or only to "professional investors" as defined in the Securities and Futures Ordinance and any rules made under that Ordinance.

The validity of our common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.

The financial statements of the Predecessor as of December 31, 2012 and 2013, and for each of the years in the three-year period ended December 31, 2013 and the balance sheet of Antero Midstream Partners LP dated as of December 31, 2013, have been included herein in reliance on the reports of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act with respect to our common units offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information regarding us and our common units offered hereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Room of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC's website is www.sec.gov.

As a result of this offering, we will become subject to the reporting requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing periodic reports and other information with the SEC. We intend to furnish our unitholders with annual reports containing financial statements certified by an independent public accounting firm.

Set forth below are the unaudited pro forma balance sheet of Antero Midstream Partners LP ("we," "us," "our" or the "Partnership") as of December 31, 2013 and the unaudited pro forma statements of operations of the Partnership for the year ended December 31, 2013. The pro forma financial data of the Partnership have been derived by adjusting the historical financial statements of Antero Resources Corporation's ("Antero") midstream business and assets, including its gathering systems, compressor stations and fresh water distribution systems, as our accounting predecessor (our "Predecessor"). At the time of the contribution to us in connection with the closing of this offering, that midstream business and the related assets will be owned by Antero Resources Midstream Operating LLC ("Midstream Operating"). We have recorded the contribution of Midstream Operating, at historical cost, as the contribution will be considered a reorganization of entities under common control.

The historical financial statements of our Predecessor are set forth elsewhere in this prospectus, and the pro forma financial data of the Partnership should be read in conjunction with, and are qualified in their entirety by reference to, such historical financial statements and the related notes contained herein. The pro forma adjustments are based on currently available information and certain estimates and assumptions, and actual results may differ from the pro forma adjustments. However, management believes that these estimates and assumptions provide a reasonable basis for presenting the significant effects of the contemplated transactions and that the pro forma adjustments are factually supportable and give appropriate effect to those estimates and assumptions and are properly applied in the pro forma financial data.

The pro forma adjustments have been prepared as if the transactions to be effected at the closing of the offering had taken place on December 31, 2013, in the case of the pro forma balance sheet. The pro forma statement of operations for the year ended December 31, 2013 have been prepared as if the transactions to be effected at closing of the offering had taken place on January 1, 2013 and the parent net investments to fund capital expenditures had not been made. The pro forma financial data have been prepared on the assumption that we will be treated as a partnership for United States federal income tax purposes.

The unaudited pro forma financial data gives pro forma effect to the matters described in the notes hereto, including:

For the purposes of the unaudited pro forma financial statements, we have assumed that the underwriters' option to purchase additional common units is not exercised. The unaudited pro forma

financial data do not give effect to the estimated $2.5 million in incremental annual general and administrative expenses that we expect to incur as a result of being a publicly traded partnership.

On February 28, 2014, our Predecessor entered into a midstream credit facility (the "midstream credit facility"). As of , 2014, there were approximately $ million of borrowings outstanding under the existing midstream credit facility. In connection with the contribution of the Predecessor to us, we will use a portion of the proceeds of this offering to repay in full $ million of that indebtedness that we will assume.

The unaudited pro forma financial data may not be indicative of the results that actually would have occurred if the Partnership had assumed the operations of our Predecessor on the dates indicated or that would be obtained in the future.

	Predecessor Historical		Pro Forma Adjustments				Pro Forma

	(in thousands, except for per unit amounts)
Revenue:
Gathering and compression—affiliate	$	22,363	$	—			$	22,363
Fresh water distribution—affiliate		35,871		—				35,871


Total revenue		58,234		—				58,234


Operating expenses:
Direct operating expenses		7,871		—				7,871
General and administrative expenses (including $24,349 of stock compensation)		34,065		—				34,065
Depreciation expense		14,119		—				14,119


Total operating expenses		56,055		—				56,055


Operating income		2,179		—				2,179
Interest expense		164		7,295				7,459


Net income (loss)	$	2,015	$	(7,295	)	(a)	$	(5,280	)




Limited partner's interest in net loss attributable Antero Midstream Partners LP
Common units							$	(2,640	)
Subordinated units							$	(2,640	)
Net loss per limited partner unit
Common units							$
Subordinated units							$
Weighted average number of limited partner units outstanding (basic and diluted)
Common units
Subordinated units

	Predecessor Historical			Pro Forma Adjustments				Pro Forma

	(in thousands)
Current assets:
Cash and cash equivalents	$	—		$	500,000		(b)	$	—
					(30,000	)	(c)
					(469,000	)	(e)
					(1,000	)	(f)
Accounts receivable—affiliate		6,426			—				6,426


Total current assets		6,426			—				6,426


Property and equipment:
Gathering and compressions systems		580,800			—				580,800
Fresh water distribution systems		229,627			—				229,627


		810,427			—				810,427
Less accumulated depreciation		(17,097	)		—				(17,097	)


Property and equipment, net		793,330			—				793,330


Deferred financing costs		—			1,000		(f)		1,000
Other assets		8,581			—				8,581


Total assets	$	808,337		$	1,000			$	809,337




Current liabilities:
Accounts payable	$	7,872		$	—			$	7,872
Accrued capital		56,941			—				56,941
Accrued liabilities		4,182			—				4,182
Capital leases—short-term		1,219			—				1,219


Total current liabilities		70,214			—				70,214
Long-term liabilities:
Capital leases—long-term		6,062			—				6,062


Total liabilities		76,276			—				76,276


Parent net investment		732,061			(263,061	)	(d)		—
					(469,000	)	(e)
Common units		—			500,000		(b)		601,531
					(30,000	)	(c)
					131,531		(d)
Subordinated units		—			131,530		(d)		131,530
General partner units		—			—				—


Total equity/partners' capital		732,061			1,000				733,061


Total liabilities and owners' equity	$	808,337		$	1,000			$	809,337

The unaudited pro forma statement of operations of the Partnership for the year ended December 31, 2013 and the unaudited pro forma balance sheet as of December 31, 2013 are based upon the historical financial statements of the Predecessor.

In connection with the contribution of Midstream Operating to it at the completion of this offering, Antero Resources Midstream LLC will be converted into a limited partnership (i.e., the Partnership). The Partnership also anticipates incurring incremental general and administrative expense of approximately $2.5 million per year as a result of being a publicly traded partnership, including expenses associated with annual, quarterly and current reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; investor relations expenses; and registrar and transfer agent fees. The unaudited pro forma financial statements do not reflect these additional public company costs.

The following adjustments for the Partnership have been prepared as if the Partnership's initial public offering and related transactions had taken place at January 1, 2013 in the case of the pro forma statement of operations and on December 31, 2013 in the case of the pro forma balance sheet.

Pro forma net income per limited partner unit is determined by dividing the pro forma net income that would have been allocated, in accordance with the net income and loss allocation provisions of the partnership agreement, to the common and subordinated units expected to be outstanding at the closing of the offering. For purposes of this calculation, we assumed that the minimum quarterly distribution was made to all unitholders during the period presented.

Pro forma Partnership earnings per unit was calculated using common and subordinated units. The common and subordinated units represented an aggregate 100% limited partner interest in Antero Midstream Partners LP. All units were assumed to have been outstanding since January 1, 2013.

We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit.

Basic and diluted pro forma net income per unit are equivalent as there are no dilutive equity instruments at the date of closing of the initial public offering of the common units of the Partnership. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain

targets, our general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to our general partner than to the holders of common and subordinated units. The pro forma net income per unit calculations assume that no incentive distributions were made to our general partner because no such distribution would have been paid based upon the pro forma available cash from operating surplus for the periods.

We have audited the accompanying balance sheets of Antero Resources Midstream LLC Predecessor as of December 31, 2012 and 2013, and the related statements of operations and comprehensive income (loss), equity, and cash flows for each of the years in the three-year period ended December 31, 2013. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Antero Resources Midstream LLC Predecessor as of December 31, 2012 and 2013, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

	December 31,

	2012			2013
Current assets:
Cash and cash equivalents	$	—		$	—
Accounts receivable—affiliate		159			6,426


Total current assets		159			6,426


Property and equipment:
Gathering and compressions systems		176,329			580,800
Fresh water distribution systems		6,898			229,627


		183,227			810,427
Less accumulated depreciation		(2,978	)		(17,097	)


Property and equipment, net		180,249			793,330


Other assets		—			8,581


Total assets	$	180,408		$	808,337




Current liabilities:
Accounts payable	$	5,565		$	7,872
Accrued capital		29,396			56,941
Accrued liabilities		153			4,182
Capital leases—short-term		77			1,219


Total current liabilities		35,191			70,214
Long-term liabilities:
Capital leases—long-term		320			6,062


Total liabilities		35,511			76,276


Total net equity—parent net investment		144,897			732,061


Total liabilities and equity	$	180,408		$	808,337




Commitments and contingencies (see Note 6)

	Year ended December 31,

	2011			2012			2013
Revenue:
Gathering and compression—affiliate	$	441		$	647		$	22,363
Fresh water distribution—affiliate		—			—			35,871


Total revenue		441			647			58,234


Operating expenses:
Direct operating expenses		802			698			7,871
General and administrative expenses (including $24,349 of stock compensation in 2013)		397			2,977			34,065
Depreciation expense		997			1,679			14,119


Total operating expenses		2,196			5,354			56,055


Operating income (loss)		(1,755	)		(4,707	)		2,179
Interest expense		2			8			164


Net income (loss) and comprehensive income (loss)	$	(1,757	)	$	(4,715	)	$	2,015

	Total Net Equity—Parent Net Investment

Balance at December 31, 2010	$	14,466
Net loss and comprehensive loss		(1,757	)
Contributions from parent		16,293


Balance at December 31, 2011		29,002
Net loss and comprehensive loss		(4,715	)
Contributions from parent		120,610


Balance at December 31, 2012		144,897
Net income and comprehensive income		2,015
Contributions from parent		560,800
Stock compensation related to parent		24,349


Balance at December 31, 2013	$	732,061

	Year ended December 31,

	2011			2012			2013
Cash flows from (used in) operating activities:
Net income (loss)	$	(1,757	)	$	(4,715	)	$	2,015
Adjustment to reconcile net income (loss) to net cash provided by operating activities:
Depreciation expense		997			1,679			14,119
Stock compensation		—			—			24,349
Changes in assets and liabilities:
Accounts receivable—affiliate		16			(126	)		(6,267	)
Other assets		—			—			(8,581	)
Accrued liabilities		126			(74	)		4,029


Net cash provided by (used in) operating activities		(618	)		(3,236	)		29,664


Cash flows from investing activities:
Additions to property and equipment		(15,795	)		(117,652	)		(597,349	)


Net cash used in investing activities		(15,795	)		(117,652	)		(597,349	)


Cash flows from financing activities:
Contribution from parent		16,293			120,611			560,800
Borrowings on capital leases		125			304			7,753
Payments on capital lease obligations		(5	)		(27	)		(868	)


Net cash provided by financing activities		16,413			120,888			567,685


Net decrease in cash and cash equivalents		—			—			—
Cash and cash equivalents, beginning of period		—			—			—


Cash and cash equivalents, end of period	$	—		$	—		$	—




Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	2		$	8		$	164
Supplemental disclosure of noncash investing activities:
Increase (decrease) in accrued capital and accounts payable for property and equipment	$	(952	)	$	32,538		$	29,852

These financial statements of the midstream assets and business of Antero Resources Corporation ("Antero") as the accounting predecessor (the "Predecessor," "we" or "our") to Antero Resources Midstream LLC ("Antero Midstream") have been prepared in connection with the initial public offering (the "offering") of common units representing limited partner interests in a limited partnership (the "Partnership"). At the time of the closing of this offering, that midstream business and the related assets will be owned by Antero Resources Midstream Operating LLC ("Midstream Operating"). In connection with the completion of the offering, Antero will contribute Midstream Operating to Antero Midstream, which in turn will convert into a limited partnership (i.e., the Partnership).

The Predecessor assets represent substantially all of Antero's midstream assets and consist of 8-, 12-, 16-, and 20-inch gathering pipelines and compressor stations that collect natural gas from Antero's wells in the Marcellus Shale in West Virginia and Pennsylvania and the Utica Shale in Ohio. The Predecessor assets also include two independent fresh water distribution systems that deliver water used by Antero for well completion operations in Antero's operating areas. The fresh water distribution systems consist of permanent buried pipelines, temporary surface pipelines and fresh water storage facilitates, as well as pumping stations to transport the fresh water throughout the pipeline system.

Antero Midstream was formed as a Delaware limited liability company on September 23, 2013. Prior to the completion of the offering, Antero holds 100% of the common economic interests in Antero Midstream, and Antero Resources Midstream Management LLC ("Midstream Management") holds a special membership interest in Antero Midstream. Antero manages Antero Midstream pursuant to the terms of its limited liability company agreement, and Antero's common economic interests entitle it to 100% of the distributions and other economic rights of Antero Midstream. The special membership interest in Antero Midstream provides Midstream Management with certain rights, including: (i) the right to cause the offering in the form of a master limited partnership or similar structure; and (ii) the right to have the special membership interest converted into the general partner interest in that master limited partnership.

In connection with the closing of Antero's initial public offering, Antero entered into a contribution agreement (the "Contribution Agreement") with Antero Midstream on October 16, 2013, pursuant to which Antero agreed to contribute Midstream Operating to Antero Midstream.

In connection with the contribution of Midstream Operating to Antero Midstream at the closing of the offering, (i) Antero Midstream will be converted into a limited partnership, (ii) Antero's common economic interest will be converted into all of the issued and outstanding common units and subordinated units of the Partnership (prior to the issuance of additional common units to the public in the offering) and (iii) Midstream Management will receive the non-economic general partner interest and the incentive distribution rights in the Partnership in exchange for its special membership interest.

The financial statements of the Predecessor have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") on the basis of Antero's historical ownership of the Predecessor assets. These financial statements have been prepared from the separate records maintained by Antero and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. Because a direct ownership relationship did not exist among the businesses comprising the Predecessor, the net investment in the Predecessor is shown as parent net equity, in lieu of owner's equity, in the financial statements.

The Predecessor's costs of doing business incurred by Antero on behalf of the Predecessor have been reflected in the accompanying financial statements. These costs include general and administrative expenses allocated by Antero to the Predecessor in exchange for:

Transactions between the Predecessor and Antero have been identified in the financial statements as transactions between affiliates (see Note 3).

The Predecessor provides natural gas gathering and compression services, as well as fresh water distribution services, under fee-based contracts based on throughput. Under these arrangements, we receive a fee or fees for gathering of natural gas, compression services and fresh water distribution. The revenue we earn from these arrangements is directly related to, (1) in the case of natural gas gathering and compression, the volumes of metered natural gas that we gather, compress and deliver to natural gas compression sites or other transmission delivery points or, (2) in the case of fresh water distribution, the metered quantities of fresh water delivered to our customers for use in their well completion operations. We recognize revenue when all of the following criteria are met: (1) services have been rendered, (2) the prices are fixed or determinable, and (3) collectability is reasonable assured.

The preparation of the financial statements and notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. Items subject to estimates and assumptions include the useful lives of property and equipment, valuation of accrued liabilities, and obligations related to employee benefits, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.

The Predecessor's operations were funded by Antero and managed under Antero's cash management program. Consequently, the accompanying balance sheets do not include any cash balances. See Note 3—Transactions with Affiliates. Net amounts funded by Antero are reflected as net contributions from parent on the accompanying Statements of Equity and Cash Flows.

Property and equipment primarily consists of gathering pipelines, compressor stations and fresh water distribution systems and are stated at the lower of historical cost less accumulated depreciation, or fair value, if impaired. The Predecessor capitalizes construction-related direct labor and material costs. Maintenance and repair costs are expensed as incurred.

Depreciation is computed over the asset's estimated useful life using the straight-line method, based on estimated useful lives and salvage values of assets. Gathering pipelines and compressor stations are depreciated over a 20 year useful life. Fresh water distribution systems are depreciated over useful lives of 5 to 20 years. Specifically, we use a useful life of 5 years for our above-ground temporary water distribution pipelines and a useful life of 20 years for our permanent underground water distribution pipelines. As of December 31, 2013, our water distribution assets with a useful life of five years had a carrying value of $0.3 million and our water distribution assets with a useful life of 20 years had a carrying value of $229.3 million. The depreciation of fixed assets recorded under capital lease agreements is included in depreciation expense. Uncertainties that may impact these estimates include, among others, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are placed into service, management makes estimates with respect to useful lives and salvage values that management believes are reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts.

Property and equipment included assets under construction of $10.5 million, $117.3 million and $238.5 million at December 31, 2011, 2012 and 2013, respectively.

We evaluate the ability to recover the carrying amount of long-lived assets and determines whether such long-lived assets have been impaired. Impairment exists when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable, based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset's carrying amount over its estimated fair value, such that the asset's carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense.

Fair value represents the estimated price between market participants to sell an asset in the principal or most advantageous market for the asset, based on assumptions a market participant would make. When warranted, management assesses the fair value of long-lived assets using commonly accepted techniques and may use more than one source in making such assessments. Sources used to determine fair value include, but are not limited to, recent third party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes, such as changes in contract rates or terms, the condition of an asset, or management's intent to utilize the asset, generally require management to reassess the cash flows related to long-lived assets. A reduction of carrying value of fixed assets would represent a Level 3 fair value measure. No impairment expense was recognized for the years ended December 31, 2011, 2012 and 2013.

We recognize a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at the fair value measured using discounted expected future cash outflows of the asset retirement obligation when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. The initial recognition of asset retirement obligations represents a Level 3 fair value

measure. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Subsequent to the initial recognition, the liability is also adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property and equipment) until the obligation is settled. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the associated asset carrying amount. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, retirement costs and the estimated timing of settling asset retirement obligations.

We may be obligated by regulatory or other requirements to remove certain facilities or perform other remediation upon retirement of gathering pipelines and compressor stations. However, we are not able to reasonably determine the fair value of the asset retirement obligation since future dismantlement and removal dates are indeterminate. We cannot reasonably predict when production from existing reserves of the fields in which we operate will cease. In the absence of such information, we are not able to make a reasonable estimate of when future dismantlement and removal dates will occur and therefore have not recorded asset retirement obligations at December 31, 2012 or 2013.

An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. We regularly review contingencies to determine the adequacy of our accruals and related disclosures. The amount of ultimate loss may differ from these estimates.

We accrue losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable.

We have not recorded any accruals for loss contingencies or environmental obligations at December 31, 2012 and 2013.

The Predecessor's financial statements reflect various stock-based compensation awards by Antero. These awards include profits interests awards, restricted stock and stock options. For purposes of these financial statements, the Predecessor recognized as expense in each period the required allocation from Antero, with the offset included in net parent equity. See Note 3—Transactions with Affiliates and Note 5—Stock-Based Compensation.

The Predecessor's financial statements do not include income tax allocation as we expect that we will be treated as a partnership for federal and state income tax purposes, with each partner being separately taxed on its share of the taxable income.

FASB ASC Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long-lived assets). The fair value is the price that we estimate would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize input to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

The carrying values on the Predecessor's balance sheet of its cash and cash equivalents, accounts receivable—affiliate, other assets, accounts payable, accrued liabilities and accrued capital approximate fair values due to their short maturities and would be classified as level 1 under the fair value hierarchy.

All revenues in the years ended December 31, 2011, 2012 and 2013 were earned from Antero.

All accounts payable, accrued liabilities and accrued capital balance are due to unaffiliated parties. These balances are managed and paid under Antero's cash management program.

The employees supporting the Predecessor's operations are employees of Antero. General and administrative expense allocated to the Predecessor was $0.4 million, $3.0 million and $34.1 million for the years ended December 31, 2011, 2012 and 2013, respectively. The financial statements of the Predecessor include direct charges for operations of its assets and costs allocated by Antero. These costs are reimbursed and relate to: (i) various business services, including, payroll processing, accounts payable processing and facilities management, (ii) various corporate services, including legal, accounting, treasury, information technology and human resources and (iii) compensation, including stock-based compensation. These expenses were charged or allocated to the Predecessor based on the nature of the expenses and are allocated based on our proportionate share of Antero's gross property and equipment, capital expenditures and direct labor costs, as applicable.

Stock-based compensation expense allocated to the Predecessor was $24.3 million for the year ended December 31, 2013. These expenses were charged or allocated to the Predecessor based our proportionate share of Antero's direct labor costs. See Note 5—Stock-Based Compensation.

The Predecessor is obligated under capital leases covering compressor stations and pumping equipment that expire at various dates over the next seven years. At December 31, 2012 and 2013, the gross amount of property and equipment and related accumulated amortization recorded under capital leases were as follows:

Amortization of assets held under capital leases is included in depreciation expense.

Future minimum capital lease payments as of December 31, 2013 are shown in the following table:

Antero is authorized to grant up to 16,906,500 stock-based compensation awards to employees and directors of Antero under the Antero Resources Corporation Long-Term Incentive Plan (the Plan). The Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent awards, and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of Antero's Board of Directors. A total of 16,791,068 shares are available for future grant under the Plan as of December 31, 2013.

Antero's stock-based compensation expense is as follows for the year ended December 31, 2013 (in thousands):

Restricted stock awards vest subject to the satisfaction of service requirements. The grant date fair value of these awards are determined based on the price of Antero's common stock on the date of the grant. A summary of restricted stock awards activity during the year ended December 31, 2013 is as follows:

The outstanding unvested restricted stock awards at December 31, 2013 are scheduled to vest as follows:

Stock options granted under the Plan to date vest over periods from one to four years and have a maximum contractual life of 10 years. Antero recognizes expense related to stock options on a straight-line basis over the requisite service period, less awards expected to be forfeited. Stock options

are granted with an exercise price equal to the market price of its common stock on the date of grant. A summary of stock option activity for the year ended December 31, 2013 is as follows:

Antero uses a Black-Scholes option-pricing model to determine the fair value of its stock options. Expected volatility was derived from the volatility of the historical stock prices of a peer group of similar publicly traded companies' stock prices. The risk-free interest rate was determined using the implied yield currently available for zero-coupon U.S. government issues with a remaining term approximating the expected life of the options. Antero assumed no dividend yield.

The following table presents information regarding the weighted average fair value for options granted during 2013 and the assumptions used to determine fair value. There were no options exercised during 2013.

As of December 31, 2013, there was $1.3 million of unrecognized stock-based compensation expense related to nonvested stock options. That expense is expected to be recognized over a weighted average period of 4 years.

Employee Holdings, a limited liability company owned by officers and employees, has issued profits interests to employees. The profits interests participate only in distributions from Antero Investment in liquidity events, meeting requisite financial thresholds after the Class I and other classes of unitholders have recovered their investment and special allocation amounts. The profits interests have no voting rights. The limited liability company agreement of Antero Investment executed at the closing of Antero's IPO provides a mechanism by which the shares of Antero's common stock to be allocated among the members of Antero Investment, including Employee Holdings, will be determined. As a result, the satisfaction of all performance and service conditions relative to the profits interests

awards held by Employee Holdings in Antero Investment became probable. Accordingly, Antero recognized approximately $365 million of stock compensation expense for the vested profits interests through December 31, 2013 and will recognize an additional approximate $121 million over the remaining service period. All available profits interest awards were made prior to the date of Antero's IPO and no additional awards will be made.

The Predecessor's operations are located in the United States and are organized into two reporting segments: (1) gathering and compression and (2) fresh water distribution.

The Predecessor's gathering and compression segment includes a network of gathering pipelines and compressor stations that transports natural gas from Antero's wells in the Marcellus and Utica Shales.

The Predecessor's fresh water distribution segment includes two independent fresh water systems that source and deliver fresh water from the Ohio River and several regional waterways for well completion operations in Antero's operating areas. These systems consist of permanent buried pipelines, temporary surface pipelines and fresh water storage facilitates, as well as pumping stations to transport the fresh water throughout the pipeline networks.

These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. We evaluate the performance of the Predecessor's business segments based on income (loss) from operations.

Summarized financial information concerning the Predecessor's segments is shown in the following table (in thousands):

	Gathering and Compression			Fresh Water Distribution			Consolidated Total

Year Ended December 31, 2011
Revenue—affiliate	$	441		$	—		$	441
Loss from operations	$	(1,358	)	$	—		$	(1,358	)
Interest expense	$	2		$	—		$	2
Segment assets	$	31,770		$	—		$	31,770
Capital expenditures for segment assets	$	15,795		$	—		$	15,795
Depreciation expense	$	997		$	—		$	997
Year Ended December 31, 2012
Revenue—affiliate	$	647		$	—		$	647
Loss from operations	$	(1,684	)	$	(46	)	$	(1,730	)
Interest expense	$	8		$	—		$	8
Segment assets	$	173,510		$	6,898		$	180,408
Capital expenditures for segment assets	$	115,571		$	2,081		$	117,652
Depreciation expense	$	1,679		$	—		$	1,679
Year Ended December 31, 2013
Revenue—affiliate	$	22,363		$	35,871		$	58,234
Income from operations	$	8,938		$	27,306		$	36,244
Interest expense	$	147		$	17		$	164
Segment assets	$	578,090		$	230,247		$	808,337
Capital expenditures for segment assets	$	395,469		$	201,880		$	597,349
Depreciation expense	$	11,346		$	2,773		$	14,119

The Predecessor is subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. We believe there are currently no such matters that will have a material adverse effect on our results of operations, cash flows or financial position.

Antero has a senior secured revolving bank credit facility ("Credit Facility") that has maximum borrowing amount of $2.5 billion. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of Antero's proved properties and commodity hedge positions and are subject to regular semiannual redeterminations. At December 31, 2013, the borrowing base was $2.0 billion and lender commitments were $1.5 billion. The Credit Facility is secured by mortgages on substantially all of Antero's properties and guarantees from Antero's operating subsidiaries. The assets of the Predecessor and are included in these mortgages on Antero's properties. Antero Midstream is a guarantor under the Credit Facility.

As of December 31, 2013, Antero had an outstanding balance under the Credit Facility of $288 million and outstanding letters of credit of approximately $32 million. As of December 31, 2012, Antero had an outstanding balance under the Credit Facility of $217 million and outstanding letters of credit of approximately $43 million.

We have evaluated subsequent events that occurred after December 31, 2013 through the filing of this Form S-1. Any material subsequent events that occurred during this time have been properly recognized or disclosed in these financial statements or the notes to the financial statements.

On February 28, 2014, Midstream Operating entered into a credit facility agreement with the lenders of Antero's credit facility. The facility is guaranteed by Antero and each of its restricted subsidiaries and secured by (i) a security interest in substantially all personal property of Antero and each of its Restricted Subsidiaries (as defined in the credit facility agreement) and (ii) mortgages on substantially all of oil and gas properties of Antero and its restricted subsidiaries, in each case shared on a pari passu basis with the obligations under Antero's credit facility. The maximum amount of the facility is $500 million. Midstream Operating currently may borrow up to $300 million, the aggregate commitment amount. Commitments under the facility may be increased to the maximum facility amount by Midstream Operating upon consent of the Administrative Agent (as defined in the credit facility agreement). Commitments under Midstream Operating's credit facility constitute an allocation of the borrowing base and aggregate commitment amount under Antero's credit facility. The credit facility matures on the earlier of May 12, 2016 or the consummation of a Qualified IPO (as defined in the credit facility agreement) by Midstream Operating or any entity in which Antero Resources Midstream Management LLC owns any equity interest. Interest is payable at a variable rate based on LIBOR plus a margin ranging from 1.50% to 2.50% or the prime rate plus a margin ranging from 0.50% to 1.50%, in each case based on Midstream Operating's election at the time of borrowing and on its borrowing base usage. Commitment fees on the unused portion of the credit facility are due quarterly at rates ranging from 0.375% to 0.50% of the unused facility based on utilization.

We have audited the accompanying balance sheet of Antero Resources Midstream LLC (the Partnership) as of December 31, 2013. This balance sheet is the responsibility of the Partnership's management. Our responsibility is to express an opinion on this balance sheet based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Antero Resources Midstream LLC as of December 31, 2013, in conformity with U.S. generally accepted accounting principles.

Antero Resources Midstream LLC (the "Company") is a Delaware limited liability company formed on September 23, 2013.

Antero Resources Corporation contributed $1,000, all in the form of a note receivable to the Company on October 1, 2013. There have been no other transactions involving the Company as of December 31, 2013.

In connection with the completion of this offering, the Company intends to convert to a limited partnership (upon such conversion, the "Partnership") and to offer common units, representing limited partner interests, pursuant to a public offering and to concurrently issue common units and subordinated units, representing additional limited partner interests in the Partnership to Antero Resources Corporation, and a non-economic general partner interest in the Partnership to Antero Resources Midstream Management LLC, an indirect wholly-owned subsidiary of Antero Resources Investment LLC.

In connection with the completion of this offering, Antero Resources Corporation will contribute its midstream business and assets to the Company.

FORM OF AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP
OF
ANTERO MIDSTREAM PARTNERS LP

100% success rate: Antero defines the term "100% success rate" to mean that all wells were completed and produce in commercially viable quantities.

Bbl or barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs or other liquid hydrocarbons.

Bcfe: One billion cubic feet of natural gas equivalent with one barrel of oil, condensate or NGLs converted to six thousand cubic feet of natural gas.

condensate: Similar to crude oil and produced in association with natural gas gathering and processing.

dry gas: A natural gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.

field: The general area encompassed by one or more oil or gas reservoirs or pools that are located on a single geologic feature, that are otherwise closely related to the same geologic feature (either structural or stratigraphic).

highly rich gas/condensate: Gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1250 BTU and 1300 BTU in the Utica Shale.

highly rich gas: Gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and 1250 BTU in the Utica Shale.

high-pressure pipelines: Pipelines gathering or transporting natural gas that has been dehydrated and compressed to the pressure of the downstream pipelines or processing plants.

low-pressure pipelines: Pipelines gathering natural gas at or near wellhead pressure that has yet to be compressed (other than by well pad gas lift compression or dedicated well pad compressors) and dehydrated.

MMcfe: One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbls of crude oil, condensate or natural gas liquids.

natural gas: Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.

NGLs: Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane and natural gasoline.

Tcfe: One Tcf equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

throughput: The volume of product transported or passing through a pipeline, plant, terminal or other facility.

Through and including , 2014 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

Set forth below are the expenses (other than underwriting discounts) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever. The section of the prospectus entitled "The Partnership Agreement—Indemnification" discloses that we will generally indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference.

Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of the general partner or any of its direct or indirect subsidiaries.

The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of Antero Resources Corporation and our general partner, their officers and directors, and any person who controls Antero Resources Corporation and our general partner, including indemnification for liabilities under the Securities Act.

In connection with the contribution of Midstream Operating to us at the completion of this offering, Antero Resources Midstream LLC will convert into Antero Midstream Partners LP, and we expect to issue (i) the non-economic general partner interest in us to Antero Resources Midstream Management LLC for no consideration and (ii) the 100% limited partner interest in us to Antero Resources Corporation for $1,000.00. On October 1, 2013, in connection with its formation, Antero Resources Midstream LLC issued 100% of its common economic interests to Antero Resources Corporation and all of its special membership interests to Antero Resources Midstream Management LLC for no consideration. Both issuances were exempt from registration under

Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

(a) The following documents are filed as exhibits to this Registration Statement.

Exhibit Number			Description

1.1	**	—	Form of Underwriting Agreement
3.1	**	—	Form of Certificate of Limited Partnership of Antero Midstream Partners LP
3.2	**	—	Agreement of Limited Partnership of Antero Midstream Partners LP (included as Appendix A in the prospectus included in this Registration Statement)
3.3	***	—	Certificate of Formation of Antero Resources Midstream LLC
3.4		—	Limited Liability Company Agreement of Antero Resources Midstream LLC (incorporated by reference to Exhibit 10.4 to Antero Resource Corporation's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013)
5.1	**	—	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
8.1	**	—	Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1		—	Contribution Agreement, dated as of October 16, 2013, by and between Antero Resources Corporation and Antero Resources Midstream LLC (incorporated by reference to Exhibit 10.2 to Antero Resources Corporation's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013)
10.2		—	Form of Right of First Offer Agreement (incorporated by reference to Exhibit D to Exhibit 10.2 to Antero Resource Corporation's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013)
10.3		—	Form of Gathering Agreement (incorporated by reference to Exhibit C to Exhibit 10.2 to Antero Resource Corporation's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013)
10.4		—	Form of Water Services Agreement (incorporated by reference to Exhibit E to Exhibit 10.2 to Antero Resource Corporation's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013)
10.5		—	Form of License Agreement (incorporated by reference to Exhibit F to Exhibit 10.2 to Antero Resource Corporation's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013)
10.6	*	—	Credit Agreement, dated as of February 28, 2014, among Antero Resources Midstream Operating LLC, certain subsidiaries of the borrower, as Guarantors, the Lenders party hereto, JPMorgan Chase Bank, N. A., as Administrative Agent, Wells Fargo Bank, N. A., as Syndication Agent, and Union Bank, N. A., and Credit Agricole Corporate and Investment Bank, as Co-Documentation Agents
10.7	**	—	Form of Registration Rights Agreement
10.8	**	—	Form of New Revolving Credit Facility
21.1	***	—	List of Subsidiaries of Antero Midstream Partners LP
23.1	*	—	Consent of KPMG LLP

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

The undersigned registrant undertakes that, for the purposes of determining liability under the Securities Act to any purchaser, if the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with its general partner or its general partner's affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to its general partner or its general partner's affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on March 20, 2014.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

			Description

1.1	**	—	Form of Underwriting Agreement
3.1	**	—	Form of Certificate of Limited Partnership of Antero Midstream Partners LP
3.2	**	—	Agreement of Limited Partnership of Antero Midstream Partners LP (included as Appendix A in the prospectus included in this Registration Statement)
3.3	***	—	Certificate of Formation of Antero Resources Midstream LLC
3.4		—	Limited Liability Company Agreement of Antero Resources Midstream LLC (incorporated by reference to Exhibit 10.4 to Antero Resource Corporation's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013)
5.1	**	—	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
8.1	**	—	Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1		—	Contribution Agreement, dated as of October 16, 2013, by and between Antero Resources Corporation and Antero Resources Midstream LLC (incorporated by reference to Exhibit 10.2 to Antero Resources Corporation's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013)
10.2		—	Form of Right of First Offer Agreement (incorporated by reference to Exhibit D to Exhibit 10.2 to Antero Resource Corporation's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013)
10.3		—	Form of Gathering Agreement (incorporated by reference to Exhibit C to Exhibit 10.2 to Antero Resource Corporation's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013)
10.4		—	Form of Water Services Agreement (incorporated by reference to Exhibit E to Exhibit 10.2 to Antero Resource Corporation's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013)
10.5		—	Form of License Agreement (incorporated by reference to Exhibit F to Exhibit 10.2 to Antero Resource Corporation's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013)
10.6	*	—	Credit Agreement, dated as of February 28, 2014, among Antero Resources Midstream Operating LLC, certain subsidiaries of the borrower, as Guarantors, the Lenders party hereto, JPMorgan Chase Bank, N. A., as Administrative Agent, Wells Fargo Bank, N. A., as Syndication Agent, and Union Bank, N. A., and Credit Agricole Corporate and Investment Bank, as Co-Documentation Agents
10.7	**	—	Form of Registration Rights Agreement
10.8	**	—	Form of New Revolving Credit Facility
21.1	***	—	List of Subsidiaries of Antero Midstream Partners LP
23.1	*	—	Consent of KPMG LLP
23.2	*	—	Consent of KPMG LLP
23.3	**	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
23.4	**	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)


Delaware	4922	46-4109058
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(IRS Employer Identification Number)
1625 17^th Street Denver, Colorado 80202 (303) 357-7310 (Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant's Principal Executive Offices)
Glen C. Warren, Jr. 1625 17^th Street Denver, Colorado 80202 (303) 357-7310 (Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)


Large accelerated filer o		Accelerated filer o
Non-accelerated filer ý (Do not check if a smaller reporting company)		Smaller reporting company o

	Per Common Unit	Total

Offering price to the public	$	$
Underwriting discounts and commissions	$	$
Proceeds to us (before expenses)⁽¹⁾	$	$


Administrative Matters			179
State, Local and Other Tax Considerations			181
INVESTMENT IN ANTERO MIDSTREAM PARTNERS LP BY EMPLOYEE BENEFIT PLANS			182
General Fiduciary Matters			182
Prohibited Transaction Issues			182
Plan Asset Issues			183
UNDERWRITING			184
Commissions and Expenses			184
Option to Purchase Additional Common Units			185
Lock-Up Agreements			185
Offering Price Determination			186
Indemnification			186
Directed Unit Program			186
Stabilization, Short Positions and Penalty Bids			186
Electronic Distribution			187
New York Stock Exchange			187
Discretionary Sales			187
Stamp Taxes			188
Other Relationships			188
Direct Participation Program Requirements			188
Selling Restrictions			189
VALIDITY OF OUR COMMON UNITS			192
EXPERTS			192
WHERE YOU CAN FIND MORE INFORMATION			192
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


Assumed initial public offering price per common unit		$
Pro forma net tangible book value per common unit before the offering⁽¹⁾	$
Increase in net tangible book value per common unit attributable to purchasers in the offering


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


Immediate dilution in net tangible book value per common unit to purchasers in the offering⁽³⁾⁽⁴⁾		$


David P. Oelman Matthew R. Pacey Vinson & Elkins L.L.P. 1001 Fannin, Suite 2500 Houston, Texas 77002 (713) 758-2222		Ryan J. Maierson Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, Texas 77002 (713) 546-5400


SUMMARY			1
Overview			1
Our Contractual Arrangements with Antero			4
Our Existing Assets and Growth Projects			5
Business Strategies			6
Competitive Strengths			7
Our Relationship with Antero and Antero Investment			8
Our Management			9
Partnership Structure			9
Emerging Growth Company Status			11
Risk Factors			11
Partnership Information			12
The Offering			13
Summary Historical and Pro Forma Financial and Operating Data			18
Non-GAAP Financial Measure			20
RISK FACTORS			21
Risks Related to Our Business			21
Risks Inherent in an Investment in Us			34
Tax Risks to Common Unitholders			44
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			49
USE OF PROCEEDS			50
CAPITALIZATION			51
DILUTION			52
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			54
General			54
Our Minimum Quarterly Distribution			56
Subordinated Units			56
Unaudited Pro Forma Cash Available for Distribution for the Twelve-Month Period Ended December 31, 2013			57
Estimated Cash Available for Distribution for the Twelve-Month Period Ending March 31, 2015			60
Assumptions and Considerations			63
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			78
General Partner's Right to Reset Incentive Distribution Levels			78
Distributions From Capital Surplus			81
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			87
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			89
Overview			89
Sources of Our Revenues			89
Segments			90
How We Evaluate Our Operations			91
Items Affecting Comparability of Our Financial Results			92
Principal Components of Our Cost Structure			92
Results of Operations			94
Liquidity and Capital Resources			98
Our Critical Accounting Policies and Estimates			101
Off-Balance Sheet Arrangements			102
Quantitative and Qualitative Disclosures About Market Risk			102
INDUSTRY			104
Midstream Natural Gas Industry			104
Overview of the Water Services Industry			105
BUSINESS			109
Our Company			109
Our Areas of Operation			111
Our Relationship with Antero			113
Our Existing Assets and Growth Projects			114
Business Strategies			116
Competitive Strengths			116
Antero's Existing Third-Party Commitments			118
Title to Properties			118
Seasonality			119
Competition			119
Regulation of Operations			119
Pipeline Safety Regulation			120
Regulation of Environmental and Occupational Safety and Health Matters			121
Employees			126
Legal Proceedings			126
MANAGEMENT			127
Management of Antero Midstream Partners LP			127
Executive Officers and Directors of Our General Partner			127
Committees of the Board of Directors			130
EXECUTIVE COMPENSATION			131
Summary Compensation Table			131
Salary and Cash Incentive Awards in Proportion to Total Compensation			131
Outstanding Equity Awards at 2013 Fiscal Year-End			132
Additional Narrative Disclosure			132
Compensation of Directors			133
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			138
Procedures for Review, Approval and Ratification of Transactions with Related Persons			141
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			142
Conflicts of Interest			142
Duties			147
DESCRIPTION OF THE COMMON UNITS			150
The Units			150
Transfer Agent and Registrar			150
Transfer of Common Units			150
THE PARTNERSHIP AGREEMENT			152
Organization and Duration			152
Purpose			152
Cash Distributions			152
Capital Contributions			152
Voting Rights			153
Applicable Law; Forum, Venue and Jurisdiction			154
Limited Liability			154
Issuance of Additional Interests			155
Amendment of the Partnership Agreement			156
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets			158
Dissolution			158
Liquidation and Distribution of Proceeds			159
Withdrawal or Removal of Our General Partner			159
Transfer of General Partner Interest			160
Transfer of Ownership Interests in the General Partner			160
Transfer of Subordinated Units and Incentive Distribution Rights			160
Change of Management Provisions			161
Limited Call Right			161
Non-Taxpaying Holders; Redemption			161
Non-Citizen Assignees; Redemption			162
Meetings; Voting			162
Voting Rights of Incentive Distribution Rights			163
Status as Limited Partner			163
Indemnification			163
Reimbursement of Expenses			164
Books and Reports			164
Right to Inspect Our Books and Records			165
Registration Rights			165
UNITS ELIGIBLE FOR FUTURE SALE			166
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES			168
Taxation of the Partnership			168
Tax Consequences of Unit Ownership			170
Tax Treatment of Operations			175
Disposition of Units			175
Uniformity of Units			178
Tax-Exempt Organizations and Other Investors			178

	Units				Total Consideration

	Number	Percent			Amount	Percent
Antero^(1)(2)(3)				%				%
Purchasers in the offering				%				%


Total			100	%			100	%

		Minimum Quarterly Distributions

	Number of Units	One Quarter	Annualized
Common units held by the public⁽¹⁾		$	$
Common units held by Antero⁽¹⁾
Subordinated units held by Antero


Total		$	$

		Marginal Percentage Interest in Distributions

	Total Quarterly Distribution Per Unit	Unitholders			IDR Holders
Minimum Quarterly Distribution	$		100	%		—	%
First Target Distribution	above $ up to $		100	%		—	%
Second Target Distribution	above $ up to $		85	%		15	%
Third Target Distribution	above $ up to $		75	%		25	%
Thereafter	above $		50	%		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 $		100	%		—	%	up to $ ⁽¹⁾
First Target Distribution	above $ up to $		100	%		—	%	above $ up to $ ⁽²⁾
Second Target Distribution	above $ up to $		85	%		15	%	above $ up to $ ⁽³⁾
Third Target Distribution	above $ up to $		75	%		25	%	above $ up to $ ⁽⁴⁾
Thereafter	above $		50	%		50	%	above $

		Cash Distributions to Common Unitholders Prior to Reset		Cash Distributions to Holders of IDRs After Reset

	Quarterly Distributions per Unit	Cash Distributions to Common Unitholders Prior to Reset		Common Units⁽¹⁾		IDRs		Total		Total Distributions
Minimum Quarterly Distribution	up to $	$		$		$	—	$		$
First Target Distribution	above $ up to $		—		—		—		—		—
Second Target Distribution	above $ up to $		—		—		—		—		—
Third Target Distribution	above $ up to $		—		—		—		—		—
Thereafter	above $		—		—		—		—		—


		$		$		$	—	$		$

	Payments Due by Period

	Total		Less Than 1 Year		1 - 3 Years		3 - 5 Years		More Than 5 Years
	(in thousands)
Long-term debt and capital lease obligations⁽¹⁾	$	7,282	$	1,219	$	2,541	$	2,424	$	1,098
Interest payments⁽¹⁾		592		188		266		120		18


Total	$	7,874	$	1,407	$	2,807	$	2,544	$	1,116


Barclays		Citigroup		Wells Fargo Securities

	Low- Pressure Pipeline (miles)				High- Pressure Pipeline (miles)

									Oil Pipeline (miles)				Compression Capacity (MMcf/d)
									Oil Pipeline (miles)				Compression Capacity (MMcf/d)				Average Daily Throughput for the Three Months Ended December 31, 2013 (MMcf/d)
	As of December 31,
	2013		2014E		2013		2014E		2013		2014E		2013		2014E
Gathering and Compression System:
Marcellus		54		125		38		67		—		—		105		410		232
Utica		26		55		23		37		10		20		—		120		61


Total		80		180		61		104		10		20		105		530		293

Name		Position With Our General Partner

Paul M. Rady	60	Chairman and Chief Executive Officer
Glen C. Warren, Jr.	58	Director, President, Chief Financial Officer and Secretary
Kevin J. Kilstrom	59	Vice President—Production
Alvyn A. Schopp	55	Chief Administrative Officer and Regional Vice President
Ward D. McNeilly	63	Vice President—Reserves, Planning and Midstream
Peter R. Kagan	45	Director
W. Howard Keenan, Jr.	63	Director
Christopher R. Manning	46	Director

Name		Principal Position

Paul M. Rady		Chairman of the Board of Directors and Chief Executive Officer
Glen C. Warren, Jr.		Director, President, Chief Financial Officer and Secretary
Alvyn A. Schopp		Chief Administrative Officer and Regional Vice President
Kevin J. Kilstrom		Vice President—Production

	Option Awards

Name	Number of Securities Underlying Unexercised Options Unexercisable (#)	Number of Securities Underlying Unexercised Options Exercisable (#)	Option Exercise Price ($)	Option Expiration Date
Paul M. Rady
Glen C. Warren, Jr.
Alvyn A. Schopp
Kevin J. Kilstrom


State law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.

Underwriters		Number of Common Units

Barclays Capital Inc.
Citigroup Global Markets Inc.
Wells Fargo Securities, LLC


Total


Unaudited Pro Forma Financial Statements of Antero Midstream Partners LP
Introduction			F-2
Pro Forma Statement of Operations for the Year Ended December 31, 2013			F-4
Pro Forma Balance Sheet as of December 31, 2013			F-5
Notes to Unaudited Pro Forma Financial Statements			F-6
Audited Financial Statements of Antero Resources Midstream LLC Predecessor
Report of Independent Registered Public Accounting Firm			F-9
Balance Sheets as of December 31, 2012 and 2013			F-10
Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 2011, 2012 and 2013			F-11
Statements of Equity for the years ended December 31, 2011, 2012 and 2013			F-12
Statements of Cash Flows for the years ended December 31, 2011, 2012 and 2013			F-13
Notes to Financial Statements			F-14
Audited Balance Sheet of Antero Resources Midstream LLC as of December 31, 2013
Report of Independent Registered Public Accounting Firm			F-25
Balance Sheet			F-26
Notes to the Balance Sheet			F-27

	December 31, 2012			December 31, 2013

Compressor stations	$	429		$	6,557
Pumping equipment		—			1,625


		429			8,182
Less accumulated amortization		(54	)		(326	)


Total	$	375		$	7,856


2014		1,407
2015		1,407
2016		1,400
2017		1,372
2018		1,172
Thereafter		1,116


Total minimum lease payments		7,874
Less amount representing interest (at rates ranging from 2.5% to 6.6%)		(592	)


Present value of net minimum capital lease payments	$	7,282


Profits interest awards	$	364,957
Restricted stock		219
Stock options		104


Total expense	$	365,280

		Weighted average grant date fair value		Aggregate intrinsic value (in thousands)

Total granted and unvested, January 1, 2013	—		—		—
Granted	45,093	$	54.27
Vested	—
Forfeited	—


Total awarded and unvested—December 31, 2013	45,093	$	54.27	$	2,861

		Weighted average exercise price			Intrinsic Value (in thousands)

Outstanding at January 31, 2013	—		—	—		—
Options granted	70,339	$	54.15
Options exercised	—		—
Options cancelled	—		—
Options expired	—		—
Outstanding at December 31, 2013	70,339	$	54.15
Vested or expected to vest as of December 31, 2013	70,339	$	54.15	9.79	$	653
Exercisable at December 31, 2013	—			9.79	$	653


Dividend yield		—	%
Volatility		35	%
Risk-free interest rate		1.48	%
Expected life (years)		6.17
Weighted average fair value of options granted	$	20.20


ASSETS
Current assets:
Receivable from affiliate	$	1,000


Total Assets	$	1,000




LIABILITIES AND EQUITY
Equity:
Member's equity	$	1,000


Total liabilities and equity	$	1,000


SEC registration fee	$	64,400
FINRA filing fee		75,500
NYSE listing fee			*
Accountants' fees and expenses			*
Legal fees and expenses			*
Printing and engraving expenses			*
Transfer agent and registrar fees			*
Miscellaneous			*


Total			*

Signature		Title	Date


* Paul M. Rady		Chairman of the Board, Director and Chief Executive Officer (principal executive officer)	March 20, 2014
/s/ GLEN C. WARREN, JR. Glen C. Warren, Jr.		Director, President, Chief Financial Officer and Secretary (principal financial officer)	March 20, 2014
* K. Phil Yoo		Chief Accounting Officer and Corporate Controller (principal accounting officer)	March 20, 2014
* Peter R. Kagan		Director	March 20, 2014
* W. Howard Keenan, Jr.		Director	March 20, 2014
* Christopher R. Manning		Director	March 20, 2014
*By:	/s/ GLEN C. WARREN, JR. Glen C. Warren, Jr. Attorney-in-Fact

Exhibit Number					Description

	24.1	***	—		Powers of Attorney (included on the signature page of this registration statement)

Antero Resources Midstream LLC

Antero Midstream Management LLC, its sole member

/s/ GLEN C. WARREN, JR.

Glen C. Warren, Jr.

President, Chief Financial Officer and Secretary