UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10‑K

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Commission File No. 001‑36719

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ANTERO MIDSTREAM PARTNERS LP

(Exact name of registrant as specified in its charter)

 

(303) 357‑7310

(Registrant’s telephone number, including area code)

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

 

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S‑T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ☒ Yes  ☐ No

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

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

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑2 of the Act). ☐ Yes  ☒ No

As of June 30, 2014, the last business day of the registrant’s most recently completed second quarter, the registrant’s equity was not listed on a domestic exchange or over-the-counter market.  The registrant’s common units began trading on the New York Stock Exchange on November 5, 2014. 

The registrant had 151,881,914 common units representing limited partner interests outstanding as of February 19, 2015.

Documents incorporated by reference: None.

 

 

 

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EXPLANATORY NOTE 

 

This Annual Report on Form 10-K includes the results of operations of Antero Resources Corporation’s (“Antero”) gathering and compression assets and related operations on a carve-out basis, the predecessor for accounting purposes of Antero Midstream Partners LP (the “Partnership”) for periods prior to November 10, 2014, when the Partnership completed the initial public offering (“IPO”).

 

In connection with the completion of the IPO, Antero contributed its gathering and compression assets to the Partnership.  The historical results of the predecessor operations are not indicative of future results of the Partnership.    

 

References in this report to “Predecessor,” “we,” “our,” “us” or like terms, when referring to periods prior to November 10, 2014, refer to Antero’s gathering and compression assets, our predecessor for accounting purposes.  References to “the Partnership,” “we,” “our,” “us” or like terms, when referring to periods after November 10, 2014, refer to Antero Midstream Partners LP.

The Partnership’s common units are listed on the New York Stock Exchange under the symbol “AM.”

 

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TABLE OF CONTENTS

 

 

 

 

 

 

 

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS 

Some of the information in this Annual Report on Form 10-K may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Annual Report on Form 10-K. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

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

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

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report on Form 10-K.

 

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GLOSSARY OF TERMS 

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in our industry:

Bbl or barrel:  One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs or other liquid hydrocarbons.

Bbl/d:  Bbl per day.

Bcfe:  One billion cubic feet of natural gas equivalent with one barrel of oil, condensate or NGLs converted to six thousand cubic feet of natural gas.

Bcfe/d:  Bcfe per day.

Btu:  British thermal units.

DOT:  Department of Transportation.

dry gas:  A natural gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.

EPA:  Environmental Protection Agency.

expansion capital expenditures:  Cash expenditures to construct new midstream infrastructure and those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system throughput.

FERC:  Federal Energy Regulatory Commission.

field:  The general area encompassed by one or more oil or gas reservoirs or pools that are located on a single geologic feature, that are otherwise closely related to the same geologic feature (either structural or stratigraphic).

high pressure pipelines:  Pipelines gathering or transporting natural gas that has been dehydrated and compressed to the pressure of the downstream pipelines or processing plants.

hydrocarbon:  An organic compound containing only carbon and hydrogen.

low pressure pipelines:  Pipelines gathering natural gas at or near wellhead pressure that has yet to be compressed (other than by well pad gas lift compression or dedicated well pad compressors) and dehydrated.

maintenance capital expenditures:  Cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity or revenue.

MBbl:  One thousand Bbls.

MBbl/d:  One thousand Bbls per day.

Mcf:  One thousand cubic feet of natural gas.

MMBtu:  One million British thermal units.

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MMcf:  One million cubic feet of natural gas.

MMcfe:  One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbls of crude oil, condensate or natural gas liquids.

MMcf/d:  One million cubic feet per day.

MMcfe/d:  One million cubic feet equivalent per day.

natural gas:  Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.

NGLs:  Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane and natural gasoline.

oil:  Crude oil and condensate.

SEC:  United States Securities and Exchange Commission.

Tcfe:  One Tcf equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

throughput:  The volume of product transported or passing through a pipeline, plant, terminal or other facility.

WTI: West Texas Intermediate

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PART I

 

Items 1 and 2.  Business and Properties 

Our Partnership

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

Pursuant to our long‑term contract with Antero, we have secured a 20‑year dedication covering substantially all of Antero’s current and future acreage for gathering and compression services. All of Antero’s 543,000 net acre leasehold is dedicated to us for gathering and compression services except for the third‑party commitments in place prior to our formation, which includes 131,000 Marcellus Shale net leasehold acres characterized by dry gas and liquids‑rich production that have been previously dedicated to third‑party gatherers. Please read “—Antero’s Existing Third‑Party Commitments.” Net of the excluded acreage, our contract covers approximately 412,000 net leasehold acres held by Antero as of December 31, 2014 for gathering and compression services. In addition to Antero’s existing acreage dedication, our agreement provides that any acreage Antero acquires in the future will be dedicated to us for gathering and compression services. We also provide condensate gathering services to Antero under the gathering and compression agreement.

In addition, we have an option for two years to purchase Antero’s fresh water distribution systems at fair market value, with a right of first offer thereafter. Further, we have a right to participate for up to a 15% non‑operating equity interest in an unnamed 50‑mile regional gathering pipeline extension (the “Regional Gathering System”) that will expire six months following the date on which the Regional Gathering System is placed into service, which is currently scheduled to occur during the fourth quarter of 2015. In addition, we have entered into a right‑of‑first‑offer agreement with Antero to allow for us to provide Antero with gas processing or NGLs fractionation, transportation or marketing services in the future. 

 

Developments and Highlights

 

Energy Industry Environment

 

The gathering and compression agreement with Antero provides for fixed fee structures, and we intend to continue to pursue additional fixed fee opportunities with Antero and third parties in order to avoid direct commodity price exposure. However, to the extent that our future contractual arrangements with Antero or third parties do not provide for fixed fee structures, we may become subject to commodity price risk. We are subject to commodity price risks to the extent that they impact Antero’s development plan and therefore our gathering volumes. Recently, global energy commodity prices have declined precipitously as a result of several factors including increased worldwide supplies, a stronger U.S. dollar, relatively mild weather in the U.S., and strong competition among oil producing countries for market share.  Specifically, prices for WTI have declined from approximately $106.00 per Bbl in June 2014 to less than $50.00 per Bbl in January 2015.  Prices for Henry Hub natural gas in January 2015 have traded around $3.00 per MMBtu compared to prices a year ago in January 2014 of around $4.40 per MMBtu. In response to these market conditions and concerns about access to capital markets, U.S. exploration and development companies have significantly reduced capital spending plans. Antero’s capital budget for 2015 is projected to be $1.8 billion, a 41% reduction from 2014.  Antero plans to operate an average of 14 drilling rigs in 2015, down from 21 at December 31, 2014, and to complete 130 horizontal Marcellus and Utica wells in 2015, down from 177 in 2014. 

 

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Initial Public Offering 

 

On November 10, 2014, we completed our IPO of 46,000,000 common units representing limited partnership interests at a price of $25.00 per common unit.  We were originally formed as Antero Resources Midstream LLC and converted to a limited partnership in connection with the completion of the IPO.  At the closing of the IPO, Antero contributed its gathering and compression assets to Antero Midstream LLC (“Midstream Operating”), and the ownership of Midstream Operating was contributed to us. Net proceeds received by us from the IPO were approximately $1.1 billion, after deducting underwriting discounts, structuring fees and expenses.  We used $843 million to repay indebtedness assumed from Antero, to reimburse Antero for certain capital expenditures incurred, and to redeem 6,000,000 common units held by Antero. The Partnership retained $250 million of the net proceeds for general partnership purposes.

 

2015 Capital Budget

During 2015, we plan to expand our existing Marcellus and Utica Shale gathering and compression systems to accommodate Antero’s development plans. We expect to invest $415 to $435 million and $10 to $15 million in expansion and maintenance capital, respectively, resulting in a total capital budget of $425 to $450 million in 2015. This capital budget includes $250 to $260 million on gathering infrastructure, which will result in 44 miles and 20 miles of additional low pressure and high pressure gathering pipelines, respectively, in both the Marcellus and Utica Shale plays combined. Additionally, the budget includes the construction or expansion of five compressor stations, which will add 545 MMcf/d of additional compression capacity in 2015. At year-end 2015, we expect to have 180 miles of low pressure gathering lines, 117 miles of high pressure gathering lines, and 920 MMcf/d of compression capacity in service.

 

Our Assets

The following table provides information regarding our gathering and compression systems as of December 31, 2013 and 2014.

 

 

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

As of December 31, 2014, our Marcellus and Utica Shale gathering systems include 153 miles and 96 miles of pipelines, respectively, and our year‑end daily Marcellus compression capacity is 375 MMcf/d.

Our Relationship with Antero

Antero is our only current customer and is one of the largest producers of natural gas and NGLs in the Appalachian Basin, where it produced on average over 1 Bcfe/d net (14% liquids) during 2014, an increase of 93% as compared to 2013. As of December 31, 2014, Antero’s estimated net proved reserves were 12.7 Tcfe, which were comprised of 83% natural gas, 16% NGLs, and 1% oil. As of December 31, 2014, Antero’s drilling inventory consisted of 5,331 identified potential horizontal well locations (3,502 of which were located on acreage dedicated to us) for

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gathering and compression services, which provides us with significant opportunities for growth as Antero’s robust drilling program continues and its production increases. On January 20, 2015, Antero announced an expected 2015 drilling and completion budget of $1.6 billion. In 2015, Antero plans to operate an average of 14 drilling rigs, including nine operated rigs in the Marcellus Shale, and five  operated rigs in the Utica Shale. Antero also announced guidance for 2015 including projected production of 1.4 Bcfe/d, a 40% increase over 2014. Antero relies substantially on us to deliver the midstream infrastructure necessary to accommodate its continuing production growth. For additional information regarding our contracts with Antero, please read “—Contractual Arrangements with Antero.”

We are highly dependent on Antero as our only current customer, and we expect to derive most of our revenues from Antero for the foreseeable future. Accordingly, we are indirectly subject to the business risks of Antero. For additional information, please read “Risk Factors—Risks Related to Our Business.” Because 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 adverse impact on us.

Contractual Arrangements with Antero

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 third‑party commitments in place prior to our formation). For a discussion of Antero’s existing third‑party commitments, please read “—Antero’s Existing Third‑Party Commitments.” We also have an option to gather and compress natural gas produced by Antero on any acreage it acquires in the future outside of West Virginia, Ohio and Pennsylvania on the same terms and conditions. Under the gathering and compression agreement, we receive a low pressure gathering fee of $0.30 per Mcf, a high pressure gathering fee of $0.18 per Mcf, a compression fee of $0.18 per Mcf, and a condensate gathering fee of $4.00 per Bbl, in each case subject to CPI‑based adjustments. If and to the extent Antero requests that we construct new high pressure lines and compressor stations, the gathering and compression agreement contains minimum volume commitments that require Antero to utilize or pay for 75% and 70%, respectively, of the capacity of such new construction for 10 years. Additional high pressure lines and compressor stations installed on our own initiative are not subject to such volume commitments. These minimum volume commitments on new infrastructure are intended to support the stability of our cash flows. For additional information, please read “Item 13. Certain Relationships and Related Transactions.”

Option to Acquire Antero’s Fresh Water Distribution Business

In addition to the gathering and compression agreement, Antero has also granted us an option to purchase its fresh water distribution systems at fair market value. Antero owns and operates two independent fresh water distribution systems that distribute fresh water from the Ohio River and several other regional water sources for producers’ well completion operations in the Marcellus and Utica Shales. These systems consist of a combination of permanent buried pipelines, moveable surface pipelines and fresh water storage facilities, as well as pumping stations to transport the fresh water throughout the pipeline networks.

Gas Processing and NGL Fractionation

Although we do not currently have any gas processing, NGL fractionation, transportation or marketing infrastructure, we have entered into a right‑of‑first‑offer agreement with Antero for gas processing services, pursuant to which Antero has agreed, subject to certain exceptions, not to procure any gas processing, NGL fractionation, transportation or marketing services with respect to its production (other than production subject to a pre‑existing dedication) without first offering us the right to provide such services. For additional information, please read “—Antero’s Existing Third‑Party Commitments” and “Item 13. Certain Relationships and Related Transactions.”

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Option to Participate in Regional Gathering System

We have the option to participate for up to a 15% non‑operated equity interest in the Regional Gathering System. The Regional Gathering System is expected to connect a portion of Antero’s Marcellus Shale operating areas with the delivery point for some of its downstream firm transportation commitments. Our option will expire six months following the date on which the Regional Gathering System is placed into service, which is currently scheduled to occur during the fourth quarter of 2015. We have not yet determined to what extent, if any, we would exercise such option.

Antero’s Existing Third‑Party Commitments

Excluded Acreage

Antero previously dedicated a portion of its acreage in the Marcellus Shale to certain third parties’ gathering and compression services. We refer to this acreage dedication as the “excluded acreage.” As of December 31, 2014, the excluded acreage consisted of approximately 131,000 of Antero’s existing net leasehold acreage. At that same date, 1,829 of Antero’s 5,331 potential horizontal well locations were located within the excluded acreage.

Other Commitments

In addition to the excluded acreage, Antero has entered into take‑or‑pay contracts with volume commitments for certain third parties’ high pressure gathering and compression services. Specifically, those volume commitments consist of up to an aggregate of 750 MMcf/d on four high pressure gathering pipelines and 1,020 MMcf/d on nine compressor stations. 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.

Title to Properties

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

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.

Seasonality

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

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Competition

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

Regulation of Operations

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

Gathering Pipeline Regulation

Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission, or FERC, under the NGA. Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests the FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC‑regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case‑by‑case basis, so the classification and regulation of some our gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by the FERC, the courts, or Congress. If the FERC were to consider the status of an individual facility and determine that the facility is not a gathering pipeline and the pipeline provides interstate transmission service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the Natural Gas Policy Act of 1978, or NGPA. Such FERC-regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by the FERC.

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.

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The Energy Policy Act of 2005, or EPAct 2005, amended the NGA and NGPA to prohibit fraud and manipulation in natural gas markets.  The FERC subsequently issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud.  The FERC’s anti-manipulation rules apply to intrastate sales and gathering activities only to the extent that there is a “nexus” to FERC-jurisdictional transactions.  EPAct 2005 also provided the FERC with the authority to impose civil penalties of up to $1,000,000 per day per violation.

Pipeline Safety Regulation

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

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

The 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote‑controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. Consistent with the act, PHMSA finalized rules that increased the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to $200,000 per violation per day, with a maximum of $2,000,000 for a series of violations. The PHMSA has also issued a final rule applying safety regulations to certain rural low‑stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. 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.

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

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compliance costs, based on the intensification of the regulatory environment and upcoming changes to regulations as outlined above. In addition to regulatory changes, costs may be incurred when there is an accidental release of a commodity transported by our system, or a regulatory inspection identifies a deficiency in our required programs.

Regulation of Environmental and Occupational Safety and Health Matters

General

Our natural gas gathering and compression 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. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations, or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the

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surrounding rock and stimulate production. Our only customer, Antero, uses hydraulic fracturing as part of its completion operations as does most of the U.S. onshore oil and natural gas industry. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority over the process and published permitting guidance in February 2014 restricting the use of diesel fuels in fracturing fluids. In May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its intent to develop and issue regulations under the Toxic Substances Control Act regarding the disclosure of information related to the chemicals used in hydraulic fracturing. 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 the first half of 2015. Also, rules promulgated by the EPA under the Clean Air Act require that certain wells employ “green completion” technology after January 1, 2015 to address emissions of volatile organic compounds, including methane, a highly‑potent greenhouse gas, or 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.  The rule will likely be finalized in the first half of 2015.

In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act, or 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.

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, and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources is expected to be available for public comment and peer review sometime in the first half of 2015. 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.  Moreover, the Obama Administration is expected to release a series of new regulations on the oil and gas industry in 2015, including federal standards limiting methane emissions. 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.

Hazardous Waste

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

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Site Remediation

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

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

Air Emissions

The federal Clean Air Act, and comparable state laws, regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and also impose various emission limits, operational limits and monitoring, reporting and record keeping requirements on air emission sources. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, 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.

Water Discharges

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

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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.

Occupational Safety and Health Act

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

Endangered Species

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

Climate Change

The EPA has determined that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, EPA has adopted regulations under existing provisions of the federal Clean Air Act, that establish Prevention of Significant Deterioration, or PSD, pre‑construction permits, and Title V operating permits for GHG emissions from certain large stationary sources. Under these regulations, facilities required to obtain PSD permits must meet BACT standards for their GHG emissions established by the states or, in some cases, by the EPA, on a case‑by‑case basis. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities. 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.

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 2014, nor do we anticipate that such expenditures will be material in 2015.

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Employees

We do not have any employees. The officers of our general partner, who are also officers of Antero manage our operations and activities. As of December 31, 2014, Antero employed approximately 444 people who provide direct, full-time support to our operations. All of the employees required to conduct and support our operations are employed by Antero and all of our direct, full‑time personnel are subject to the services agreement with our general partner and Antero. Antero considers its relations with its employees to be satisfactory.

Legal Proceedings

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

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

Address, Website and Availability of Public Filings

Our principal executive offices are at 1615 Wynkoop Street, Denver, Colorado 80202.  Our telephone number is (303) 357-7310. Our website is located at www.anteromidstream.com.

We will make available our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, and our Current Reports on Form 8-K.  These documents are located www.anteromidstream.com under the “Investors Relations” link.

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

 

Item 1A.  Risk Factors 

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

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

Risks Related to Our Business

Because substantially all of our revenue is derived from Antero, any development that materially and adversely affects Antero’s operations, financial condition or market reputation could have a material and adverse impact on us.

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

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and cash available for distribution. Accordingly, we are indirectly subject to the business risks of Antero, including, among others:

Recently, global energy prices have declined precipitously as a result of several factors, including increased worldwide supplies, a stronger U.S. dollar, relatively mild weather in the U.S., and strong competition among oil producing countries for market share. Specifically, prices for West Texas Intermediate light sweet crude oil declined from approximately $106.00 per Bbl in June 2014 to less than $50.00 per Bbl in January 2015 and Henry Hub natural gas has traded around $3.00 per MMBtu in January 2015 compared to prices a year ago in January 2014 of around $4.40 per MMBtu.

Changes in commodity prices can significantly affect our capital resources, liquidity and expected operating results. Please see “—Because of the natural decline in production from existing wells, our success depends, in part, on Antero’s ability to replace declining production and our ability to secure new sources of natural gas from Antero or third parties. Any decrease in volumes of natural gas that Antero produces or any decrease in the number of wells that Antero completes, could adversely affect our business and operating results.”

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

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

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.

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

In order to make our minimum quarterly distribution of $0.17 per common unit and subordinated unit per quarter, or $0.68 per unit per year, we will require available cash of approximately $26 million per quarter, or approximately $105 million per year based on the common units and subordinated units outstanding at December 31, 2014, as well as grants made under the Antero Midstream Partners LP Long-term Incentive Plan. We may not generate sufficient cash flow each quarter to support the payment of the minimum quarterly distribution or to increase our quarterly distributions in the future.

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

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

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Because of the natural decline in production from existing wells, our success depends, in part, on Antero’s ability to replace declining production and our ability to secure new sources of natural gas from Antero or third parties. Any decrease in volumes of natural gas that Antero produces or any decrease in the number of wells that Antero completes, could adversely affect our business and operating results.

The natural gas volumes that support our gathering business depend on the level of production from natural gas wells connected to our systems, which may be less than expected and will naturally decline over time. To the extent Antero reduces its activity or otherwise ceases to drill and complete wells, revenues for our gathering and compression services will be directly and adversely affected. In addition, natural gas volumes from completed wells will naturally decline and our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering systems, we must obtain new sources of natural gas from Antero or third parties. The primary factors affecting our ability to obtain additional sources of natural gas include (i) the success of Antero’s drilling activity in our areas of operation, (ii) Antero’s acquisition of additional acreage and (iii) our ability to obtain dedications of acreage from third parties.

We have no control over Antero’s or other producers’ levels of development and completion activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. We have no control over Antero or other producers or their development plan decisions, which are affected by, among other things:

Fluctuations in energy prices can also greatly affect the development of reserves. Recently, global energy prices have declined precipitously as a result of several factors, including increased worldwide supplies, a stronger U.S. dollar, relatively mild weather in the U.S., and strong competition among oil producing countries for market share. Specifically, prices for West Texas Intermediate light sweet crude oil declined from approximately $106.00 per Bbl in June 2014 to less than $50.00 per Bbl in January 2015 and Henry Hub natural gas has traded around $3.00 per MMBtu in January 2015 compared to prices a year ago in January 2014 of around $4.40 per MMBtu. These lower prices have compelled most natural gas and oil producers, including Antero, to reduce the level of exploration, drilling and production activity. This will have a significant effect on our capital resources, liquidity and expected operating results. Any sustained reductions in natural gas and oil prices will directly affect Antero’s production, which would reduce our revenues and ability to pay distributions. Sustained reductions in development or production activity in our areas of operation could lead to reduced utilization of our services.

Due to these and other factors, even if reserves are known to exist in areas served by our assets, producers haven chosen, and may choose in the future, not to develop those reserves. If reductions in development activity result in

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our inability to maintain the current levels of throughput on our systems, those reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

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

The gathering and compression agreement includes minimum volume commitments only on new high pressure pipelines and compressor stations that we construct at Antero’s request. Our existing compressor stations and gathering pipelines are not supported by minimum volume commitments from Antero. Any decrease in the current levels of throughput on our gathering and compression systems could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

We may not be able to attract third‑party gathering and compression volumes, which could limit our ability to grow and increase our dependence on Antero.

Part of our long‑term growth strategy includes diversifying our customer base by identifying opportunities to offer services to third-parties. To date, substantially all of our revenues were earned from Antero. Our ability to increase throughput on our gathering and compression systems and any related revenue from third parties is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when requested by third parties. To the extent that we lack available capacity on our systems for third‑party volumes, we may not be able to compete effectively with third‑party systems for additional oil and natural gas production in our areas of operation. In addition, some of our natural gas and NGLs marketing competitors for third‑party volumes have greater financial resources and access to larger supplies of natural gas than those available to us, which could allow those competitors to price their services more aggressively than we do.

Our efforts to attract new unaffiliated customers may be adversely affected by (i) our relationship with Antero and the fact that a substantial majority of the capacity of our gathering and compression systems 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.

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

Antero has granted us an option to purchase its fresh water distribution systems at fair market value. In addition, pursuant to our right‑of‑first‑offer agreement, Antero has agreed, subject to certain exceptions, not to procure any gas processing or NGLs fractionation, transportation or marketing services with respect to its production (other than production subject to a pre‑existing dedication) without first offering us the right to provide such services. The development of gas processing infrastructure in connection with the exercise of our right‑of‑first‑offer will depend upon, among other things, our ability to obtain financing on acceptable terms for the construction of such facilities and our ability to provide such services on the same or better terms than third parties. We can offer no assurance that we will be able to successfully develop processing infrastructure pursuant to these rights. 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.

We have a right to participate for up to a 15% non‑operating equity interest in the Regional Gathering System that will expire six months following the date on which the Regional Gathering System is placed into service, which is currently scheduled to occur during the fourth quarter of 2015. We have not determined to what extent, if any, we would exercise this option. We can offer no assurance that our participation in the Regional Gathering System, if we exercise the option, will enhance our cash flows or ability to pay distributions.

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

We rely primarily on revenues generated from gathering and compression systems that we own, which are located in the Marcellus and Utica Shales. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, market limitations or interruption of the processing or transportation of natural gas, NGLs or oil.

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

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

Our construction or purchase of new gathering and compression, processing or other assets may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our cash flows, results of operations and financial condition and, as a result, our ability to distribute cash to our unitholders.

The construction of additions or modifications to our existing systems and the construction or purchase of new assets involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If we undertake these projects, we may not be able to complete them on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a processing facility, the construction may occur over an extended period of time, and we may not receive any material increases in revenues until the project is completed. Moreover, we may construct facilities to capture anticipated future production growth in an area in which such growth does not materialize. As a result, new gathering and compression, processing or other assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition,

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the construction of additions to our existing assets may require us to obtain new rights‑of‑way prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights‑of‑way to connect new natural gas supplies to our existing gathering pipelines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights‑of‑way or to expand or renew existing rights‑of‑way. If the cost of renewing or obtaining new rights‑of‑way increases, our cash flows could be adversely affected.

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

Gathering and compression services require special equipment and laborers skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. If we experience shortages of necessary equipment or skilled labor in the future, our labor and equipment costs and overall productivity could be materially and adversely affected. If our equipment or labor prices increase or if we experience materially increased health and benefit costs for employees, our results of operations could be materially and adversely affected.

If third‑party pipelines or other midstream facilities interconnected to our gathering and compression systems become partially or fully unavailable, our operating margin, cash flow and ability to make cash distributions to our unitholders could be adversely affected.

Our gathering and compression assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of third‑party pipelines, compressor stations and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if the costs to us to access and transport on these third‑party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurs or if any of these pipelines or other midstream facilities become unable to receive or transport natural gas, our operating margin, cash flow and ability to make cash distributions to our unitholders could be adversely affected.

Our exposure to commodity price risk may change over time.

We currently generate all of our revenues pursuant to fee‑based contracts under which we are paid based on the volumes that we gather and compress, rather than the underlying value of the commodity. Consequently, our existing operations and cash flows have little direct exposure to commodity price risk. Although we intend to enter into similar fee‑based contracts with new customers in the future, our efforts to negotiate such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of natural gas, NGL and oil prices, especially in light of the recent declines, could have a material adverse effect on our business, results of operations and financial condition and, as a result, our ability to make cash distributions to our unitholders.

Restrictions in our revolving credit facility could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

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

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Our revolving credit facility also contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet any such ratios and tests. Additionally, we may not be able to borrow the full amount of commitments under our revolving credit facility if doing so would cause us to not meet a financial covenant.

The provisions of our revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

If our assets become subject to FERC regulation or federal, state or local regulations or policies change , or if we fail to comply with market behavior rules, our financial condition, results of operations and cash flows could be materially and adversely affected.

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

State regulation of natural gas gathering facilities and intrastate transportation pipelines generally includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser requirements, as well as complaint‑based rate regulation. Other state regulations may not directly apply to our business, but may nonetheless affect the availability of natural gas for purchase, compression and sale.

Moreover, FERC regulations indirectly impact our businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, gas quality, capacity release and market center promotion, indirectly affect the intrastate natural gas market. Should we fail to comply with any applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines, which could have a material adverse effect on our results of operations and cash flows. The FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations of up to $1,000,000 per day for each violation and disgorgement of profits associated with any violation.

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

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Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas, NGLs and oil production by our customers, which could reduce the throughput on our gathering and compression systems, which could adversely impact our revenues.

All of Antero’s natural gas, NGLs and oil production is being developed from unconventional sources, such as shale formations. These reservoirs require hydraulic fracturing completion processes to release the liquids and natural gas from the rock so it can flow through casing to the surface. Hydraulic fracturing is a well stimulation process that utilizes large volumes of water and sand (or other proppant) combined with fracturing chemical additives that are pumped at high pressure to crack open previously impenetrable rock to release hydrocarbons. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies. Some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. In addition, various studies are currently underway by the U.S. Environmental Protection Agency, or the EPA, and other federal agencies concerning the potential environmental impacts of hydraulic fracturing activities. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of Congress to provide for such regulation. We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of liquids and natural gas that move through our gathering systems, which in turn could materially adversely affect our revenues and results of operations.

Antero or any third‑party customers may incur significant liability under, or costs and expenditures to comply with, environmental and worker health and safety regulations, which are complex and subject to frequent change.

As an owner, lessee or operator of gathering pipelines and compressor stations, we are subject to various stringent federal, state, provincial and local laws and regulations relating to the discharge of materials into, and protection of, the environment. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly response actions. These laws and regulations may impose various obligations that are applicable to our and our customer’s operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customer’s operations. Failure to comply with these laws, regulations and permits may result in joint and several, strict liability and the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our gathering systems pass and facilities where wastes resulting from our operations are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non‑compliance, with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause it to lose potential and current customers, interrupt its operations and limit its growth and revenues, which in turn could affect our profitability. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability.

Our operations also pose risks of environmental liability due to leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons, or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of

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more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. Please read “Business—Regulation of Environmental and Occupational Safety and Health Matters” for more information.

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

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources that are already potential sources of conventional pollutants. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case‑by‑case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the U.S. on an annual basis. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. In any event, the Obama administration announced its Climate Action Plan in 2013, which, among other things, directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and gas industry. As part of the Climate Action Plan, the Obama Administration also announced that it intends to adopt additional regulations to reduce emissions of methane and other GHGs and also rules to encourage greater use of low carbon technologies sometime in 2015. 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:

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The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, or the 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote‑controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. Consistent with the 2011 Pipeline Safety Act,, the Pipelines and Hazardous Materials Safety Administration, or PHMSA, finalized rules consistent with the signed act that increased the maximum administrative civil penalties for violations of the pipeline safety laws and regulations to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. 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, including:

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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 under policies we are covered under, and neither we nor Antero Investment on our behalf have obtained pollution insurance. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights‑of‑way or if such rights‑of‑way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right‑of‑way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

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

We depend on the services of a relatively small group of our general partner’s senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our general partner’s senior management or technical personnel, including Paul M. Rady, Chairman and Chief Executive Officer, and Glen C. Warren, Jr., President and Chief Financial Officer, could have a material adverse effect on our business, financial condition and results of operations.

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

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

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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.

Terrorist attacks or cyber‑attacks could have a material adverse effect on our business, financial condition or results of operations.

Terrorist attacks or cyber‑attacks may significantly affect the energy industry, including our operations and those of our customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy‑related assets, may be at greater risk of future attacks than other targets in the United States. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

Risks Inherent in an Investment in Us

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

Antero Investment indirectly owns and controls our general partner and appoints all of the officers and directors of our general partner. All of the officers and a majority of the directors of our general partner are officers or directors of Antero Investment. Similarly, all of the officers and a majority of the directors of our general partner are also officers or directors of Antero. Although our general partner has a duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owner, Antero Investment. Further, our general partner’s directors and officers who are also directors and officers of Antero have a fiduciary duty to manage Antero in a manner that is beneficial to Antero. Conflicts of interest will arise between Antero, Antero Investment and our general partner, on the one hand, and us and our common unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own

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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:

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

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

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.

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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:

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

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

Our partnership agreement provides that, with certain limited exceptions, the Court of Chancery of the State of Delaware will be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners, (4) asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) or (5) asserting a claim against us governed by the internal affairs doctrine. In addition, if any unitholder brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. Limited partners who own common units irrevocably consent to these limitations, provisions and potential reimbursement obligations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers.

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

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

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

Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or 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.

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The incentive distribution rights held by our general partner may be transferred to a third party without unitholder consent.

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

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

If interest rates rise, the interest rates on our 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.

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

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

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

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

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

As of February 19, 2015, Antero holds 29,940,957 common units and all 75,940,957 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier. Additionally, we have agreed to provide Antero with certain registration rights, pursuant to which we may be required to register the common units they hold under the Securities Act and applicable state securities laws. Pursuant to the registration rights agreement and our partnership agreement, we may be required to undertake a future public or private offering of common units and use the net proceeds from such offering to redeem an equal number of common units held by Antero.

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

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

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

If at any time our general partner and its affiliates (including Antero) own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (i) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest per‑unit price paid by our general partner or any of its affiliates for common units during the 90‑day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, or the Exchange Act. Our general partner and its affiliates (including Antero) own an aggregate of 19.7% 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 69.7% of our common units.

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

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

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

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

The price of our common units may fluctuate significantly, which could cause you to lose all or part of your investment.

The market price of our common units is influenced by many factors, some of which are beyond our control, including:

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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.

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

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

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

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

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

We had no history operating as a publicly‑traded partnership prior to our IPO. As a publicly‑traded partnership, we incur significant legal, accounting and other expenses that we did not incur prior to our IPO. In addition, the Sarbanes‑Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly‑traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay or reserve cash for our expenses, including the costs of being a publicly‑traded partnership. As a result, the amount of cash we have available for distribution to our unitholders is affected by the costs associated with being a publicly‑traded partnership.

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As a result of our IPO, we became subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time‑consuming and costly. For example, as a result of becoming a publicly‑traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we incur additional costs associated with our SEC reporting requirements.

We also incur significant expense in order to maintain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on our board or as executive officers.

Tax Risks to Common Unitholders

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

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

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

If we were treated as a corporation for federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after‑tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

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

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could

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eliminate 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.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

 

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

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

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

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Tax‑exempt entities and non‑U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax‑exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non‑U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Allocations and/or distributions to non‑U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non‑U.S. persons, and each non‑U.S. person will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax‑exempt entity or a non‑ U.S. person, you should consult your tax advisor before investing in our common units.

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

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

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

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The 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.

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

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

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

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

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

 

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The sale or exchange of 50% or more of our capital and profits interests during any twelve‑month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve‑month period. As of December 31, 2014, Antero owned 69.7% of the total interests in our capital and profits. Therefore, a transfer by Antero of all or a portion of its interests in us could, in conjunction with the trading of common units held by the public, result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once.

Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year 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.

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

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

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

Item 1B.  Unresolved Staff Comments

Not applicable.

Item 3.  Legal Proceedings 

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

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Item 4.  Mine Safety Disclosures

Not applicable.

 

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PART II

 

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

Common Units

Our common units are listed on the New York Stock Exchange and traded under the symbol “AM”. On February 19, 2015, our common units were held by 3 holders of record.  The number of holders does not include the holders for whom units are held in a “nominee” or “street” name. In addition, as of February 19, 2015, Antero and its affiliates owned 29,940,957 of our common units and 75,940,957 of our subordinated units, which together represent a 69.7% limited partner interest in us.

 

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

 

 

 

No distributions were made to unitholders during the year ended December 31, 2014. On February 2, 2015, we announced the board of directors of our general partner had declared a cash distribution of $0.0943 per common unit for the partial quarter ended December 31, 2014. The distribution is payable on February 27, 2015, to unitholders of record on February 13, 2015. This amount represents the prorated minimum quarterly distribution of $0.17 per unit, or $0.68 per unit on an annualized basis.

 

Use of Proceeds 

On November 10, 2014, we completed our IPO of 46,000,000 common units representing limited partnership interests at a price of $25.00 per common unit.  

The public currently owns 30.3% of the 151,881,914 outstanding common and subordinated units, and Antero and its affiliates currently own the remaining 69.7% of the limited partner interests in the Partnership.

Net proceeds received by us from the offering were approximately $1.1 billion, after deducting underwriting discounts, structuring fees and expenses.  We used $843 million to repay indebtedness assumed from Antero, to reimburse Antero for certain capital expenditures incurred, and to redeem 6,000,000 common units held by Antero. We retained $250 million of the net proceeds for general partnership purposes.

Issuer Purchases of Equity Securities

None.  

Sales of Unregistered Units

 

On November 10, 2014, pursuant to the Amended and Restated Contribution Agreement (the “A&R Contribution Agreement”) between us and Antero, Antero contributed to us 100% of the membership interest in an entity that owned Antero’s gathering and compression assets.  Under the terms of the A&R Contribution Agreement, Antero granted us an option for two years to purchase Antero’s fresh water distribution systems at fair market value, with a right of first offer thereafter.  In addition, Antero assigned to us (i) its option to participate for up to a 20% non-operating equity interest in the 800-mile Energy Transfer LLC Rover Pipeline Project and (ii) its right to participate for up to a 15% non-operating equity interest in an unnamed 50-mile regional gathering pipeline extension. We elected not to exercise the option to participate in the Rover Pipeline project. As consideration for the contributed assets, we issued

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35,940,957 common units and 75,940,957 subordinated units to Antero. 

 

The foregoing transactions were undertaken in reliance upon the exemption from the registration requirements of the Securities Act pursuant to Section 4(a)(2) thereof.

 

Securities Authorized for Issuance Under Equity Compensation Plans

 

In connection with the completion of our IPO, our general partner adopted the Midstream LTIP, which permits the issuance of up to 10,000,000 common units.  Phantom unit grants have been made to each of the independent directors of our general partner under the Midstream LTIP.  Please read the information under “Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” of this report.

 

Our Minimum Quarterly Distribution

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

Within 60 days after the end of each quarter, we expect to make a minimum quarterly distribution of $0.17 per common unit and subordinated unit ($0.68 per common unit and subordinated unit on an annualized basis) to unitholders of record on the applicable record date. On February 2, 2015, we announced the board of directors of our general partner had declared a cash distribution of $0.0943 per common unit for the partial quarter ended December 31, 2014. This amount represents the prorated minimum quarterly distribution of $0.17 per unit, or $0.68 per unit on an annualized basis.

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

Our partnership agreement generally provides that we distribute cash each quarter during the subordination period in the following manner:

If cash distributions to our unitholders exceed $0.1955 per common unit and subordinated unit in any quarter, our unitholders and our general partner, as the holder of our incentive distribution rights (“IDRs”), will receive distributions according to the following percentage allocations:

 

 

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

 

Subordinated Units

 

Antero owns all of our subordinated units. The principal difference between our common units and subordinated units is that, for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. When the subordination period ends, all of the subordinated units will convert into an equal number of common units.

 

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.

 

Item 6.  Selected Financial Data 

The following table presents our selected historical financial data, for the periods and as of the dates indicated, for Antero Midstream Partners LP (the “Partnership”) and our Predecessor. Our Predecessor for accounting purposes consisted of Antero Resources Corporation’s (“Antero”) gathering and compression assets and related operations on a carve-out basis. The Partnership was originally formed as Antero Resources Midstream LLC and converted into a limited partnership in connection with the completion of the Partnership’s initial public offering (the “IPO”) of common units representing limited partner interests in the Partnership on November 10, 2014.

 

The selected statement of operations and statement of cash flow data for the years ended December 31 2012, 2013, and 2014 and the balance sheet data as of December 31, 2013 and 2014 are derived from our audited consolidated financial statements included in Item 8 of this Annual Report on Form 10-K. The selected statement of operations and statement of cash flow data for the year ended December 31 2011, and the balance sheet data as of December 31, 2012 are derived from our audited financial statements not included in Item 8 of this Annual Report on Form 10-K.

 

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

 

 

 

 

 

 

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Non‑GAAP Financial Measure

We use Adjusted EBITDA and Distributable Cash Flow as performance measures to assess the ability of our assets to generate cash sufficient to pay interest costs, support indebtedness and make cash distributions. Adjusted EBITDA is a financial measure reported to our lenders and used as a gauge for compliance with some of the financial covenants included in our revolving credit facility. We define Adjusted EBITDA as net income (loss) before equity-based compensation expense, interest expense, interest income, income taxes and depreciation and amortization expense. We define Distributable Cash Flow as Adjusted EBITDA less cash interest paid and ongoing maintenance capital expenditures paid. Distributable cash flow should not be viewed as indicative of the actual amount of cash that the Partnership has available for distributions from operating surplus or that the Partnership plans to distribute.

We use Adjusted EBITDA and Distributable Cash Flow to assess:

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

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

 

 

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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our condensed consolidated financial statements and related notes included elsewhere in this report. The information provided below supplements, but does not form part of, our financial statements. This discussion contains forward‑looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward‑looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact our future operating performance or financial condition, please read see “Item 1A. Risk Factors.” and the section entitled “Cautionary Statement Regarding Forward‑Looking Statements.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. 

References in this report to “Predecessor,” “we,” “our,” “us” or like terms, when referring to periods prior to November 10, 2014, refer to Antero’s gathering and compression assets, our predecessor for accounting purposes.  References to “the Partnership,” “we,” “our,” “us” or like terms, when referring to periods after November 10, 2014, refer to Antero Midstream Partners LP.

Overview

We are a growth‑oriented limited partnership formed by Antero to own, operate and develop midstream energy assets to service Antero’s rapidly increasing production. Our assets consist of gathering pipelines and compressor stations, through which we provide midstream services to Antero under a long‑term, fixed‑fee contract. Our assets are located in the rapidly developing liquids‑rich southwestern core of the Marcellus Shale in northwest West Virginia and the liquids‑rich core of the Utica Shale in southern Ohio, two of the premier North American shale plays. We believe that our strategically located assets and our relationship with Antero position us to become a leading midstream energy company serving the Marcellus and Utica Shales.

Initial Public Offering

 

On November 10, 2014, we completed our IPO of 46,000,000 common units representing limited partnership interests at a price of $25.00 per common unit. At the closing of the IPO, Antero contributed its gathering and compression assets to Antero Midstream LLC (“Midstream Operating”), and the ownership of Midstream Operating was contributed to us.

The public currently owns 46,000,000 common units, representing a 30.3% limited partner interest in the Partnership. Antero and its affiliates currently own the remaining 29,940,957 common units and all 75,940,957 subordinated units, representing an aggregate 69.7% of the limited partner interest in the Partnership.

Net proceeds received by us from the IPO were approximately $1.1 billion, after deducting underwriting discounts, structuring fees and expenses.  We used $843 million to repay indebtedness assumed from Antero, to reimburse Antero for certain capital expenditures incurred, and to redeem 6,000,000 common units held by Antero. We retained $250 million of the net proceeds for general partnership purposes.

Revolving Credit Facility

 

On November 10, 2014, in connection with the IPO, we entered into a revolving credit facility that will mature on November 10, 2019 (“revolving credit facility”). Our revolving credit facility provides for lender commitments $1.0 billion, subject to maintenance of the required financial ratios. See “—Capital Resources and Liquidity.”

 

Recent Trends and Uncertainties

 

The gathering and compression agreement with Antero provides for fixed fee structures, and we intend to continue to pursue additional fixed fee opportunities with Antero and third parties in order to avoid direct commodity

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price exposure. However, to the extent that our future contractual arrangements with Antero or third parties do not provide for fixed fee structures, we may become subject to commodity price risk. We are subject to commodity price risks to the extent that they impact Antero’s development plan and therefore our gathering volumes. Recently, global energy commodity prices have declined precipitously as a result of several factors including increased worldwide supplies, a stronger U.S. dollar, relatively mild weather in the U.S., and strong competition among oil producing countries for market share.  Specifically, prices for WTI have declined from approximately $106.00 per Bbl in June 2014 to less than $50.00 per Bbl in January 2015.  Henry Hub natural gas has traded around $3.00 per MMBtu in January 2015 compared to prices a year ago in January 2014 of around $4.40 per MMBtu. In response to these market conditions and concerns about access to capital markets, U.S. exploration and development companies have significantly reduced capital spending plans. Antero’s capital budget for 2015 is projected to be $1.8 billion, a 41% reduction from 2014.  Antero plans to operate an average of 14 drilling rigs in 2015 down from 21 at December 31, 2014 and to complete 130 horizontal Marcellus and Utica wells in 2015, down from 177 in 2014.  A further or extended decline in commodity prices could cause some of the development and production projects of Antero or third parties to be uneconomic or less profitable, which could reduce gathering volumes in our current and future potential areas of operation. Those reductions in gathering volumes could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

 

Sources of Our Revenues

Our revenues are driven by the volumes of natural gas and condensate we gather and compress. Pursuant to our long‑term contracts with Antero, we have secured 20‑year dedications covering a significant portion of Antero’s current and future acreage for gathering and compression services. All of Antero’s existing acreage is dedicated to us for gathering and compression services except for the existing third‑party commitments, which includes 131,000 Marcellus Shale net leasehold acres characterized by dry gas and liquids‑rich production that have been previously dedicated to third‑party gatherers.

Our gathering and compression operations are substantially dependent upon natural gas and oil and condensate production from Antero’s upstream activity in its areas of operation. In addition, there is a natural decline in production from existing wells that are connected to our gathering systems. Although we expect that Antero will continue to devote substantial resources to the development of oil and gas reserves, we have no control over this activity and Antero has the ability to reduce or curtail such development at its discretion.

How We Evaluate Our Operations

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

Adjusted EBITDA and Distributable Cash Flow

We use Adjusted EBITDA and Distributable Cash Flow as performance measures to assess the ability of our assets to generate cash sufficient to pay interest costs, support indebtedness and make cash distributions. Adjusted EBITDA and Distributable Cash flow are non-GAAP financial measures. See “Item 6. Selected Financial Data—Non-GAAP Financial Measure,” for more information regarding these financial measures, including a reconciliation of Adjusted EBITDA and Distributable Cash Flow to the most directly comparable GAAP measures.

Natural Gas and Oil and Condensate Throughput

We must continually obtain additional supplies of natural gas and oil and condensate to maintain or increase throughput on our systems. Our ability to maintain existing supplies of natural gas and oil and condensate and obtain additional supplies is primarily impacted by our acreage dedication and the level of successful drilling activity by Antero and, to a lesser extent in the future, the potential for acreage dedications with and successful drilling by third party producers. Any increase in our throughput volumes over the near term will likely be driven by Antero continuing its robust drilling and development activities in its Marcellus and Utica Shale acreage. In the short term, we expect increases

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in high pressure gathering and compression throughput volumes to be less than that for low pressure gathering revenues, in part because a percentage of Antero’s high pressure gathering and compression needs will be met by existing third‑party providers.

Principal Components of Our Cost Structure

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

Direct Operating Expense

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

General and Administrative Expenses

Our general and administrative expenses include direct charges for operations of our assets and costs allocated by Antero. These costs relate to: (i) various business services, including payroll processing, accounts payable processing and facilities management, (ii) various corporate services, including legal, accounting, treasury, information technology and human resources and (iii) compensation, including equity-based compensation costs. These costs are charged to us based on the nature of the expenses and are allocated based on a combination of our proportionate share of Antero’s gross property and equipment, capital expenditures and direct labor costs as applicable. Management believes these allocation methodologies are reasonable.

Our general and administrative expenses include equity-based compensation costs allocated by Antero to us for: (i) grants made pursuant to Antero’s Long‑Term Incentive Plan (the “Antero LTIP”), (ii) profits interests awards valued in connection with the Antero reorganization pursuant to its initial public offering of common stock, which closed on October 16, 2013, and (iii) grants made to Antero employees under our own plan.

In connection with the IPO, our general partner adopted the Antero Midstream Partners Long-Term Incentive Plan (“Midstream LTIP”), and on November 12, 2014, the Partnership granted 20,000 restricted units and 2,361,440 phantom units under the plan. For accounting purposes, these units are treated as if they are distributed from us to Antero. During the year ended December 31, 2014, Antero recognized approximately $2 million in equity-based compensation related to these awards, $0.4 million of which was allocated to us and included in our general and administrative expenses. We will be allocated a portion of approximately $66.7 million of unrecognized equity-based compensation expense related to the Midstream LTIP over the remaining service period of the awards.

 

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Depreciation Expense

Depreciation expense consists of our estimate of the decrease in value of the assets capitalized in property and equipment as a result of using the assets throughout the applicable year. Depreciation is computed over the asset’s estimated useful life using the straight‑line basis. Gathering pipelines and compressor stations are depreciated over a 20 year useful life.

Interest Expense

Interest expense in 2014 represents interest related to: (i)  borrowings under a credit facility agreement between Antero Midstream LLC (“Midstream Operating”), then a wholly owned subsidiary of Antero and now a wholly owned subsidiary of the Partnership, and the lenders under Antero’s credit facility that were incurred for the acquisition of our gathering and compression assets (the “midstream credit facility”), (ii) capital leases and  (iii) commitment fees and amortization of deferred financing costs incurred under our revolving credit facility that we entered into in connection with the closing of the IPO. In 2013, interest expense related to capital leases.

Items Affecting Comparability of Our Financial Results

The historical financial results of our Predecessor discussed below may not be comparable to our future financial results primarily as a result of the significant increase in the scope of our operations over the last several years. Our gathering and compression 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.

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Results of Operations

Year Ended December 31, 2013 Compared to Year Ended December 31, 2014

The following table sets forth selected operating data for the year ended December 31, 2013 compared to the year ended December 31, 2014:

 

 

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*Not meaningful or applicable.

Gathering and compression revenue—affiliate.  Revenues from gathering of natural gas and condensate and compression of natural gas increased from $22.3 million for the year ended December 31, 2013 to $95.7 million for the year ended December 31, 2014, an increase of $73.4 million. Specifically:

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Direct operating expenses.  Total direct operating expenses increased from $2.1 million for the year ended December 31, 2013 to $15.5 million for the year ended December 31, 2014, an increase of $13.4 million. The increase was primarily due to an increase in the number of gathering pipelines and compressor stations, as well as an increase in ad valorem tax expense related to the gathering and compression assets in West Virginia.

General and administrative expenses.  General and administrative expenses (before equity-based compensation expense) increased from $7.2 million for the year ended December 31, 2013 to $13.4 million for the year ended December 31, 2014, an increase of $6.2 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 us by Antero. The increase was also attributable to an increase in staff required to support our additional capital projects.

Equity-based compensation expense decreased from $15.9 million for the year ended December 31, 2013 to $8.6 million for the year ended December 31, 2014, a decrease of $7.3 million. This decrease is due to a decrease in the allocation of Antero’s equity-based compensation expense to us related to Antero’s profits interests awards. This decrease is offset by an increase in equity-based compensation expense allocated to us by Antero related to (i) awards made under the Antero LTIP and (ii) awards made to Antero employees under the Midstream LTIP.

Depreciation expense.  Total depreciation expense increased from $11.3 million for the year ended December 31, 2013 to $36.8 million for the year ended December 31, 2014, an increase of $25.5 million. The increase was primarily due to gathering and compression assets placed in service and depreciated in 2014 as well as a full period of depreciation for the assets places in service during 2013.

Interest expense.  Interest expense increased from $0.1 million for the year ended December 31, 2013 to $4.6 million for the year ended December 31, 2014, an increase of $4.5 million. The increase is primarily due to interest incurred on $510 million in borrowings under the midstream credit facility, as well as commitment fees incurred on our revolving credit facility.  Upon completion of the IPO, on November 10, 2014 we repaid $510 million of the facility related to gathering and compression expenditures and the remainder of the midstream credit facility was assumed by Antero. We had no outstanding balance under our revolving credit facility at December 31, 2014.

 

Adjusted EBITDA.  Adjusted EBITDA increased from $13.1 million for the year ended December 31, 2013 to $66.9 million for the year ended December 31, 2014, an increase of $53.8 million. The increase was primarily due to an increase in gathering and compression throughput volumes in 2014. For a discussion of the non-GAAP financial measure Adjusted EBITDA, including a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Item 6.  Selected Financial Data—Non-GAAP Financial Measure.”

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Year Ended December 31, 2012 Compared to Year Ended December 31, 2013

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