2014
A N N U A L R E P O R T
H i g H l i g H t s
A ntero Mids tre am
Antero Midstream Partners LP is a limited partnership that owns, operates and develops midstream gathering,
compression and pipeline assets that service Antero Resources’ production located in the Appalachian Basin in
West Virginia, Ohio and Pennsylvania. All of Antero Resources’ 543,000 net acre leasehold is dedicated to us for
gathering and compression services except for 131,000 Marcellus Shale net leasehold acres characterized
by dry gas and liquids-rich production that have been previously dedicated to third-party gatherers. We have
approximately 136 miles of low pressure gathering pipelines, 97 miles of high pressure gathering pipelines, 16
miles of condensate gathering pipelines and 375 MMcf/d of compression capacity.
Antero Resources formed Antero Midstream to support its growing Appalachian Basin production and to
create a seamless and highly effective system of gathering pipelines and compressor stations. We successfully
executed Antero Midstream’s $1.15 billion IPO during 2014 and generated significant throughput, cash flows and
distributable cash flow. We are a 70% owned MLP subsidiary of Antero Resources.
2 014 T H ROUG H PU T ( M M c f /d )
907
738
K E Y
L o w P r e s s u r e G a t h e r i n g
H i g h P r e s s u r e G a t h e r i n g
C o m p r e s s i o n
531
531
222
386
266
331
116
41
Q4
Q3
Q2
2 014 C A PI TA L E X PE N DI T U R E S ($ M M )
2 014 E B I T DA ($ M M )
126
Q1
36
Q4
Q3
Q2
Q1
$104
76 %
2 4%
M a r c e l l u s
U t i c a
$126
$28
$162
$162
Q4
Q3
Q2
Q1
C A P E X ( $ M M )
$19
$12
$8
M a r c e l l u s
6 9 %
31 %
U t i c a
PARTNERSHIP STRENGTHS
1
D r i ve n b y A R ’s
“ B e s t in C l a s s”
U p s tr e a m G r o w th
2
Str a te gic a l ly
L o c a te d A s s e t B a s e
in L o w C o s t
Re s o ur ce P l ay s
3
F in a n c i a l F l ex ib il i t y
a n d Str o n g
C a p i t a l Str u c tur e
4
Hi gh G r o w th
C a s h F l o w s
U n d e r p in n e d b y
L o n g -Te r m , F i xe d -
Fe e C o n tr a c t s
5
M ulti - P a y
B a s in w i th
A d di tio n al P l ay
D e vel o p m e nt
U p s i d e
Utica Shale
148,000 net acres dedicated to AM
45 miles of low pressure gathering pipelines
35 miles of high pressure gathering pipelines
16 miles of condensate gathering pipelines
Marcellus Shale
264,000 net acres dedicated to AM
91 miles of low pressure gathering pipelines
62 miles of high pressure gathering pipelines
375 MMcf/d of compression capacity
Utica Shale
DEAR FELLOW UNITHOLDERS,
2014 was a year of continued momentum and success for the Antero family. Just 13 months after
Antero Resources (“Antero”) completed the largest E&P IPO in U.S. history, Antero Midstream
Partners LP (“Antero Midstream”) completed the largest and lowest yielding Master Limited
Partnership (“MLP”) IPO in U.S. history, raising $1.15 billion. Our role as the primary midstream
provider to Antero, who continues to successfully develop its leading Appalachian liquids-rich
acreage position, enabled us to generate volumetric, revenue, and cash flow records in 2014. Our
low pressure gathering, high pressure gathering, and compression volumes grew over 200 percent;
revenues and EBITDA grew 328 percent and 411 percent, respectively. The Company’s growth and
the achievements of our employees to date have positioned Antero Midstream for continued
momentum and success, with the best years yet to come.
SUCCESS OF ANTERO RESOURCES BUILDS OUR FOUNDATION
In 2008, Antero identified the Appalachian Basin as one of the lowest cost, unconventional
resource plays in North America. The focus driving Antero’s strategy was to become the lowest cost
producer in the lowest cost plays, thereby generating attractive rates of return and a sustainable
development program that will weather any commodity price environment. This enterprising
approach and foresight led to the development of the Marcellus and Utica Shales, and to the
subsequent infrastructure capital investment opportunity that became Antero Midstream. Going
forward, the resources of Antero and the successful development of the Company’s Appalachian
acreage position will continue to contribute significantly to the success of Antero Midstream.
LARGEST AND LOWEST YIELDING MLP IPO IN U.S. HISTORY
Despite a declining and volatile commodity price environment in the second half of 2014, Antero
Midstream successfully executed a 46 million common unit initial public offering at $25 per unit
in November 2014. The IPO was priced $5.00 above the midpoint of the original pricing range and
the offering size was upsized by 20 percent to accommodate the tremendous demand for Antero
Midstream units. The transaction marked the largest MLP IPO in U.S. history to date, as well as
the lowest-yielding MLP IPO on record at a 2.7 percent yield. Approximately 30 percent of the
units outstanding were offered to the public, with the remaining 70 percent owned by Antero, thus
aligning and incentivizing Antero to maximize the value for our unitholders. This highly successful
offering, in spite of commodity headwinds, was a true testament to the underlying quality of the
assets served by our operations in the world-class Marcellus and Utica Shales.
WORLD-CLASS SPONSOR
In 2014, Antero once again reached several milestones on multiple fronts. Net proved reserves
grew 66 percent to 12.7 Tcfe; production grew 93 percent to 1,007 MMcfe/d; and EBITDAX grew
79 percent to $1.2 billion. In the Marcellus Shale, Antero added 50,000 net acres through
acquisitions and basehold leasing, and dedicated the entire acreage to Antero Midstream. The
Company further increased well recoveries by drilling longer laterals and utilizing shorter stage
length (SSL) completions in 100 percent of the Marcellus wells drilled in 2014. The successful
combination led to the growth of proved and 3P reserves to 11.9 Tcfe and 28.4 Tcfe, respectively. In
addition to the full scale development of the Marcellus Shale, the Utica Shale made a significant
contribution to total production in 2014 for the first time in Antero’s history. Targeting the highest
Antero M i dstr e AM AM 2014- p g. 1/2
liquids-rich areas in the southern core part of the play, Antero turned 41 Utica wells to sales,
achieving net production of 134 MMcfe/d, including 36 percent liquids. This represented a 433
percent increase over average 2013 production. Antero’s Utica Shale wells exhibit some of the
highest production rates of any North American shale play. As Antero Midstream is the primary
midstream service provider for Antero, the ongoing improvement and growth in Antero’s
development program ultimately benefits our unitholders.
SIGNIFICANT INVESTMENT IN CORE FOOTPRINT
In 2014, we invested nearly $600 million in gathering and compression infrastructure. We successfully
placed three compressor stations into service in the Marcellus Shale, adding incremental capacity
of 275 MMcf/d, and built 97 miles of combined low pressure, high pressure, and condensate gathering
lines. To date we have invested $1.2 billion in midstream infrastructure in the largest U.S. basin by
natural gas production; approximately 80 percent of that investment is associated with rich gas
production. Our mutually interdependent relationship with Antero is a key competitive asset and a
factor in our success. The relationship allows us to prudently deploy capital in a responsible, timely,
and cost-effective manner. By eliminating the need to use speculative capital, our relationship with
Antero facilitates the investment of “ just in time” capital, resulting in lower-risk projects. This is a
tremendous, albeit underappreciated, benefit in the low commodity price cycle our industry faces
as we head into 2015.
FUTURE READY
Antero enters 2015 as the most active operator in the Appalachian Basin. By targeting high rate of
return, core, liquids-rich drilling, the Company expects to report peer-leading production growth
of 40 percent. To accommodate the most active operator in Appalachia, Antero Midstream anticipates
investing more than $425 million in associated gathering and compression infrastructure in 2015.
At year-end 2014, Antero Midstream held in excess of $1.2 billion in liquidity and zero leverage,
allowing us to pursue these attractive, organic growth opportunities. Our unique combination of
fixed-fee contracts to mitigate direct commodity price exposure, financial flexibility, and an industry-
leading E&P sponsor in Antero will enable us to achieve top-tier, consistent distribution growth in
2015 and beyond.
THE PEOPLE OF ANTERO
The hard work and dedication of our talented employees generated the value creation and
momentum that this Company exhibited in 2014. The skills and expertise of our people in
assembling and executing world-class projects represent Antero Midstream’s true strength and
competitive advantage. We’re grateful for the guidance and support of our Board of Directors. We
thank you for investing in our partnership and look forward to even greater value creation in 2015,
and for years to come.
Paul M. Rady
Chairman & CEO
Glen C. Warren, Jr.
President & CFO
Antero M i dstr e AM AM 2014- p g. 2/2
2014FORM 10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File No. 001-36719
ANTERO MIDSTREAM PARTNERS LP
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
1615 Wynkoop Street
Denver Colorado
(Address of principal executive offices)
46-4109058
(IRS Employer
Identification No.)
80202
(Zip Code)
(303) 357-7310
(Registrant’s telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class
Common Units Representing Limited Partner Interests
Securities Registered Pursuant to Section 12(g) of the Act: None.
Name of Each Exchange on which Registered
New York Stock Exchange
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject
to such filing requirements for the past 90 days. Yes No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or
for such shorter period that the registrant was required to submit and post such files). Yes No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filer
(Do not check if a
smaller reporting company)
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes No
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.
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.”
2
TABLE OF CONTENTS
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
PART I
Items 1 and 2.
Item 1A.
Item 1B.
Item 3.
Item 4.
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV
Item 15.
Business and Properties
Risk Factors
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosures
Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer
Purchases of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Directors, Executive Officers, and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Certain Relationships and Related Transactions and Director Independence
Principal Accountant Fees and Services
Exhibits and Financial Statement Schedules
Page
4
7
7
17
41
41
42
43
43
45
49
60
61
61
61
62
64
64
69
76
78
85
86
86
3
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Some of the information in this Annual Report on Form 10-K may contain forward-looking statements.
Forward-looking statements give our current expectations, contain projections of results of operations or of financial
condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,”
“expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and
similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by
known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When
considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements
in this Annual Report on Form 10-K. Actual results may vary materially. You are cautioned not to place undue reliance
on any forward-looking statements. You should also understand that it is not possible to predict or identify all such
factors and should not consider the following list to be a complete statement of all potential risks and uncertainties.
Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking
statements include:
• Antero’s inability to meet its drilling and development plan;
•
•
natural gas, natural gas liquids (“NGLs”) and oil prices;
business strategy;
•
•
•
•
•
•
•
•
•
competition and government regulations;
actions taken by third-party producers, operators, processors and transporters;
pending legal or environmental matters;
costs of conducting our gathering and compression operations;
general economic conditions;
credit markets;
operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our
control;
uncertainty regarding our future operating results; and
plans, objectives, expectations and intentions contained in this report that are not historical.
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of
which are difficult to predict and many of which are beyond our control, incident to the gathering and compression
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.
4
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.
5
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
6
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.
7
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.
Gathering and Compression System:
Marcellus
Utica
Total
Low-
Pressure
Pipeline
(miles)
High-
Pressure
Pipeline
(miles)
Condensate
Pipeline
(miles)
Compression
Capacity
(MMcf/d)
As of December 31,
2013 2014 2013 2014 2013 2014 2013 2014
Average Daily
Throughput
for the Year
Ended
December 31,
2014
(Mmcfe/d)
54
26
80
91
45
136
39
23
62
62
35
97
—
10
10
—
16
16
100
—
100
375
—
375
393
153
546
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
gathering and compression services, which provides us with significant opportunities for growth as Antero’s robust
8
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:
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perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a HCA;
improve data collection, integration and analysis;
repair and remediate pipelines as necessary; and
implement preventive and mitigating actions.
The 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety
violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity
management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system
installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength
in high consequence areas. Consistent with the act, PHMSA finalized rules that increased the maximum administrative
civil penalties for violation of the pipeline safety laws and regulations to $200,000 per violation per day, with a
maximum of $2,000,000 for a series of violations. The PHMSA has also issued a final rule applying safety regulations to
certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. 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:
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requiring the installation of pollution-control equipment, imposing emission or discharge limits or
otherwise restricting the way we operate resulting in additional costs to our operations;
limiting or prohibiting construction activities in areas, such as air quality nonattainment areas, wetlands,
coastal regions or areas inhabited by endangered or threatened species;
delaying system modification or upgrades during review of permit applications and revisions;
requiring investigatory and remedial actions to mitigate discharges, releases or pollution conditions
associated with our operations or attributable to former operations; and
enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to or
regulatory requirements imposed by such environmental laws and regulations.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal
enforcement measures, including the assessment of monetary penalties and natural resource damages. Certain
environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where
hazardous substances, hydrocarbons or solid wastes have been disposed or otherwise released. Moreover, neighboring
landowners and other third parties may file common law claims for personal injury and property damage allegedly
caused by the release of hazardous substances, hydrocarbons or solid waste into the environment.
The trend in environmental regulation 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:
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a reduction in or slowing of Antero’s development program, which would directly and adversely impact
demand for our gathering and compression services;
the volatility of natural gas, NGLs and oil prices, which could have a negative effect on the value of Antero’s
properties, its drilling programs or its ability to finance its operations;
the availability of capital on an economic basis to fund Antero’s exploration and development activities;
• Antero’s ability to replace reserves;
• Antero’s drilling and operating risks, including potential environmental liabilities;
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transportation capacity constraints and interruptions;
adverse effects of governmental and environmental regulation; and
losses from pending or future litigation.
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:
•
•
•
the volume of natural gas we gather and compress;
the volume of condensate we gather;
the rates we charge third parties, if any, for our gathering and compression services;
• market prices of natural gas, NGLs and oil and their effect on Antero’s drilling schedule as well as
produced volumes;
• Antero’s ability to fund its drilling program;
•
•
•
•
adverse weather conditions;
the level of our operating, maintenance and general and administrative costs;
regulatory action affecting the supply of, or demand for, natural gas, the rates we can charge for our
services, how we contract for services, our existing contract, our operating costs or our operating
flexibility; and
prevailing economic conditions.
In addition, the actual amount of cash we will have available for distribution will depend on other factors,
including:
•
•
•
•
•
•
•
the level and timing of maintenance and expansion capital expenditures we make;
our debt service requirements and other liabilities;
our ability to borrow under our debt agreements to pay distributions;
fluctuations in our working capital needs;
restrictions on distributions contained in any of our debt agreements;
the cost of acquisitions, if any;
fees and expenses of our general partner and its affiliates (including Antero) we are required to reimburse;
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•
•
the amount of cash reserves established by our general partner; and
other business risks affecting our cash levels.
Because of the natural decline in production from existing wells, our success depends, in part, on Antero’s ability
to replace declining production and our ability to secure new sources of natural gas from Antero or third parties.
Any decrease in volumes of natural gas that Antero produces or any decrease in the number of wells that Antero
completes, could adversely affect our business and operating results.
The natural gas volumes that support our gathering business depend on the level of production from natural gas
wells connected to our systems, which may be less than expected and will naturally decline over time. To the extent
Antero reduces its activity or otherwise ceases to drill and complete wells, revenues for our gathering and compression
services will be directly and adversely affected. In addition, natural gas volumes from completed wells will naturally
decline and our cash flows associated with these wells will also decline over time. In order to maintain or increase
throughput levels on our gathering systems, we must obtain new sources of natural gas from Antero or third parties. The
primary factors affecting our ability to obtain additional sources of natural gas include (i) the success of Antero’s drilling
activity in our areas of operation, (ii) Antero’s acquisition of additional acreage and (iii) our ability to obtain dedications
of acreage from third parties.
We have no control over Antero’s or other producers’ levels of development and completion activity in our
areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production
from a well declines. We have no control over Antero or other producers or their development plan decisions, which are
affected by, among other things:
•
•
•
•
•
•
•
the availability and cost of capital;
prevailing and projected natural gas, NGLs and oil prices;
demand for natural gas, NGLs and oil;
levels of reserves;
geologic considerations;
environmental or other governmental regulations, including the availability of drilling permits and the
regulation of hydraulic fracturing; and
the costs of producing the gas and the availability and costs of drilling rigs and other equipment.
Fluctuations in energy prices can also greatly affect the development of reserves. 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:
•
•
incur or guarantee additional debt;
redeem or repurchase units or make distributions under certain circumstances;
• make certain investments and acquisitions;
•
incur certain liens or permit them to exist;
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•
enter into certain types of transactions with affiliates;
• merge or consolidate with another company; and
•
transfer, sell or otherwise dispose of assets.
Our revolving credit facility also contains covenants requiring us to maintain certain financial ratios. Our ability
to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we
will meet any such ratios and tests. Additionally, we may not be able to borrow the full amount of commitments under
our revolving credit facility if doing so would cause us to not meet a financial covenant.
The provisions of our revolving credit facility may affect our ability to obtain future financing and pursue
attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In
addition, a failure to comply with the provisions of our revolving credit facility could result in a default or an event of
default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid
interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to
repay such debt in full, and our unitholders could experience a partial or total loss of their investment. Please read
“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital
Resources.”
If our assets become subject to FERC regulation or federal, state or local regulations or policies change , or if we
fail to comply with market behavior rules, our financial condition, results of operations and cash flows could be
materially and adversely affected.
Our gathering and transportation operations are exempt from regulation by the FERC, under the NGA.
Section 1(b) of the NGA, exempts natural gas gathering facilities from regulation by the FERC under the NGA.
Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that the
natural gas pipelines in our gathering systems meet the traditional tests the FERC has used to establish whether a
pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission
services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the
FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of
our gathering facilities may be subject to change based on future determinations by the FERC, the courts, or Congress. If
the FERC were to consider the status of an individual facility and determine that the facility or services provided by it
are not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by
such facility would be subject to regulation by the FERC under the NGA or the NGPA. Such regulation could decrease
revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of
operations and cash flows.
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:
•
•
•
•
•
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventive and mitigating actions.
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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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•
unintended breach of impoundment and downstream flooding, release of invasive species or aquatic
pathogens, hazardous spills near intake points, trucking collision, vandalism, excessive road damage or
bridge collapse and unauthorized access or use of automation controls;
damage to pipelines, compressor stations, pump stations, impoundments, related equipment and
surrounding properties caused by natural disasters, acts of terrorism and acts of third parties;
damage from construction, farm and utility equipment as well as other subsurface activity (for example,
mine subsidence);
leaks of natural gas, NGLs or oil or losses of natural gas, NGLs or oil as a result of the malfunction of
equipment or facilities;
fires, ruptures and explosions;
other hazards that could also result in personal injury and loss of life, pollution and suspension of
operations; and
hazards experienced by other operators that may affect our operations by instigating increased regulations
and oversight.
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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:
•
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•
•
•
•
injury or loss of life;
damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage;
regulatory investigations and penalties;
suspension of our operations; and
repair and remediation costs.
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available
insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not
fully insurable under policies we are covered under, and neither we nor Antero 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 obtain additional financing, if necessary, for working capital, capital expenditures (including
required drilling pad connections and well connections pursuant to our gathering and compression
agreements as well as acquisitions) or other purposes may be impaired or such financing may not be
available on favorable terms;
our funds available for operations, future business opportunities and distributions to unitholders will be
reduced by that portion of our cash flow required to make interest payments on our debt;
• we may be more vulnerable to competitive pressures or a downturn in our business or the economy
generally; and
•
our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our debt will depend upon, among other things, our future financial and operating
performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other
factors, some of which are beyond our control. If our operating results are not sufficient to service any future
indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business
activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to effect any of these
actions on satisfactory terms or at all.
Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or
results of operations.
Terrorist attacks or cyber-attacks may significantly affect the energy industry, including our operations and
those of our customers, as well as general economic conditions, consumer confidence and spending and market liquidity.
Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United
States. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these
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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•
•
actions taken by our general partner may affect the amount of cash available to pay distributions to
unitholders or accelerate the right to convert subordinated units;
the directors and officers of Antero Investment have a fiduciary duty to make decisions in the best interests
of the owners of Antero Investment, which may be contrary to our interests;
the directors and officers of Antero have a fiduciary duty to make decisions in the best interests of the
owners of Antero, which may be contrary to our interests;
our general partner is allowed to take into account the interests of parties other than us, such as Antero
Investment, in exercising certain rights under our partnership agreement;
except in limited circumstances, our general partner has the power and authority to conduct our business
without unitholder approval;
our general partner may cause us to borrow funds in order to permit the payment of cash distributions,
our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances
of additional partnership securities and the level of reserves, each of which can affect the amount of cash
that is distributed to our unitholders;
our general partner determines the amount and timing of any capital expenditure and whether a capital
expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an
expansion capital expenditure, which does not reduce operating surplus, and this determination can affect
the amount of cash from operating surplus that is distributed to our unitholders which, in turn, may affect
the ability of the subordinated units owned by Antero to convert;
our partnership agreement limits the liability of, and replaces the duties owed by, our general partner and
also restricts the remedies available to our unitholders for actions that, without the limitations, might
constitute breaches of fiduciary duty;
common unitholders have no right to enforce obligations of our general partner and its affiliates under
agreements with us;
contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not and
will not be the result of arm’s-length negotiations;
except in limited circumstances, our general partner has the power and authority to conduct our business
without unitholder approval;
our partnership agreement permits us to distribute up to $75.0 million as operating surplus, even if it is
generated from asset sales, non-working capital borrowings or other sources that would otherwise
constitute capital surplus, which may be used to fund distributions on our subordinated units or the
incentive distribution rights;
our general partner determines which costs incurred by it and its affiliates (including Antero) are
reimbursable by us;
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•
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•
•
our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for
any services rendered to us or entering into additional contractual arrangements with its affiliates on our
behalf;
our general partner intends to limit its liability regarding our contractual and other obligations;
our general partner may exercise its right to call and purchase common units if it and its affiliates
(including Antero) own more than 80% of the common units;
our general partner controls the enforcement of obligations that it and its affiliates (including Antero) owe
to us;
• we may not choose to retain separate counsel for ourselves or for the holders of common units;
•
•
our general partner’s affiliates may compete with us, and neither our general partner nor its affiliates have
any obligation to present business opportunities to us; and
the holder or holders of our incentive distribution rights may elect to cause us to issue common units to it in
connection with a resetting of incentive distribution levels without the approval of our unitholders, which
may result in lower distributions to our common unitholders in certain situations.
Ongoing cost reimbursements due to our general partner and its affiliates for services provided, which are
determined by our general partner, will be substantial and will reduce our cash available for distribution to our
unitholders.
Prior to making distributions on our common units, we reimburse our general partner and its affiliates for all
expenses they incur on our behalf. These expenses include all costs incurred by our general partner and its affiliates in
managing and operating us, including costs for rendering administrative staff and support services to us and
reimbursements paid by our general partner to Antero for customary management and general administrative services.
There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed under the
services agreement. Our partnership agreement provides that our general partner determines the expenses that are
allocable to us in good faith. In addition, under Delaware partnership law, our general partner has unlimited liability for
our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly
made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are
obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our
general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments
could reduce the amount of cash otherwise available for distribution to our unitholders.
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:
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how to allocate business opportunities among us and its other affiliates;
• whether to exercise its limited call right;
•
how to exercise its voting rights with respect to the units it owns;
• whether to exercise its registration rights;
• whether to elect to reset target distribution levels; and
• whether or not to consent to any merger or consolidation of the partnership or amendment to the
partnership agreement.
Unitholders are treated as having consented to the provisions in the partnership agreement, including the
provisions discussed above.
Our partnership agreement 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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each unitholder’s proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each unit may decrease;
because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in
the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
the ratio of taxable income to distributions may increase;
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•
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the relative voting strength of each previously outstanding unit may be diminished; and
the market price of the common units may decline.
There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common
units.
In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional
partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by
us of units of senior rank may, among other adverse effects: (i) reduce or eliminate the amount of cash available for
distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding
as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.
Future sales of common units in the public markets or otherwise, which sales could have an adverse impact on the
trading price of the common units.
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:
•
•
a court or government agency determined that we were conducting business in a state but had not complied
with that particular state’s partnership statute; or
your right to act with other unitholders to remove or replace the general partner, to approve some
amendments to our partnership agreement or to take other actions under our partnership agreement
constitute “control” of our business.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to
them. Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution
would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years
from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time
of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount.
Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are
known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the
liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership
interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a
distribution is permitted.
The 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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our quarterly distributions;
our quarterly or annual earnings or those of other companies in our industry;
events affecting Antero;
announcements by us or our competitors of significant contracts or acquisitions;
changes in accounting standards, policies, guidance, interpretations or principles;
general economic conditions;
the failure of securities analysts to cover our common units or changes in financial estimates by analysts;
future sales of our common units; and
other factors described in these “Risk Factors.”
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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.
37
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
38
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.
39
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.
40
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.
41
Item 4. Mine Safety Disclosures
Not applicable.
42
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:
2014:
For the period from November 5, 2014 through December 31, 2014
$ 30.77 $ 22.80
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.
Common Unit
High
Low
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
43
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:
•
•
•
first, to the holders of common units, until each common unit has received the minimum quarterly distribution
of $0.1700 plus any arrearages from prior quarters;
second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly
distribution of $0.1700; and
third, to the holders of common units and subordinated units pro rata until each has received a distribution of
$0.1955.
If cash distributions to our unitholders exceed $0.1955 per common unit and subordinated unit in any quarter,
our unitholders and our general partner, as the holder of our incentive distribution rights (“IDRs”), will receive
distributions according to the following percentage allocations:
Marginal Percentage
Interest in
Distributions
General Partner
(as holder of
IDRs)
Unitholders
85 %
75 %
50 %
15 %
25 %
50 %
Total Quarterly Distribution
Target Amount
above $0.1955 up to $0.2125
above $0.2125 up to $0.2550
above $0.2550
44
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.
45
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.
(in thousands except per unit amounts)
Statement of operations data:
Revenue:
Gathering and compression—affiliate
Operating expenses:
Direct operating
General and administrative (including $15,931 and $8,619 of
equity-based compensation in 2013 and 2014, respectively)
Depreciation
Total operating expenses
Operating income (loss)
Interest expense
Net income (loss)
Net income attributable to Antero Midstream Partners LP subsequent
to IPO
Net income attributable to Antero Midstream Partners LP subsequent
to IPO per limited partner unit (basic and diluted) (1)
Common units
Subordinated units
Year ended December 31,
2011
2012
2013
2014
$
441
$
647
$ 22,363
$ 95,746
802
652
2,079
15,470
397
997
2,196
(1,755)
2
$ (1,757)
2,894
1,679
5,225
(4,578)
8
22,035
36,789
74,294
21,452
4,620
$ (4,586) $ (14,332) $ 16,832
23,124
11,346
36,549
(14,186)
146
7,422
$ 0.05
$ 0.05
Year ended December 31,
2011
2012
2013
2014
(in thousands)
Balance sheet data (at period end):
Cash and cash equivalents
Property and equipment, net
Total assets
Long-term indebtedness
Total capital
Cash flow data:
Net cash provided by (used in) operating activities
Net cash used in investing activities
Net cash provided by financing activities
Other financial data:
Adjusted EBITDA (2)
Adjusted EBITDA attributable to Antero Midstream Partners LP
Predecessor
Adjusted EBITDA attributable to Antero Midstream Partners LP
subsequent to the IPO
— $
$
173,351
173,510
320
142,862
—
566,476
578,089
4,864
532,520
$ 230,192
1,129,597
1,395,121
—
1,342,459
$
(618)
(15,795)
16,413
$
(115,267)
118,419
(3,152) $ 10,613
(397,921)
387,308
$
48,887
(597,389)
778,694
$
(758)
$
(2,899) $ 13,091
$
66,860
—
—
—
—
—
—
50,181
16,679
(1) Earnings per unit is not provided for historical periods prior to the contribution of Midstream Operating to us because the nature
of our Predecessor makes the presentation of earnings per unit not relevant, or comparable on a prospective basis, for investors.
(2) For a discussion of the non-GAAP financial measure Adjusted EBITDA, including a reconciliation of Adjusted EBITDA to its
most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Non-GAAP
Financial Measure” below.
46
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:
•
•
•
•
the financial performance of our assets, without regard to financing methods in the case of adjusted
EDITDA, capital structure or historical cost basis;
the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions;
our operating performance and return on capital as compared to other publicly traded partnerships in the
midstream energy sector, without regard to financing or capital structure; and
the viability of acquisitions and other capital expenditure projects.
Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. The GAAP measures most
directly comparable to Adjusted EBITDA and Distributable Cash Flow are net income and net cash provided by (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.
47
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:
(in thousands)
Reconciliation of Net Income (loss) to Adjusted EBITDA and
Distributable Cash Flow attributable to Antero Midstream
Partners LP:
Net income (loss)
Add:
Interest expense
Depreciation expense
Equity-based compensation expense
Adjusted EBITDA
Adjusted EBITDA attributable to Antero Midstream Partners LP
subsequent to IPO
Less:
Cash interest paid
Maintenance capital expenditures ⁽¹⁾
Distributable cash flow attributable to Antero Midstream Partners
LP
Reconciliation of Adjusted EBITDA to Cash Provided by (Used
in) Operating Activities:
Adjusted EBITDA
Less:
Interest expense
Changes in operating assets and liabilities which provided (used)
cash
Plus:
Amortization of deferred financing costs
Net cash provided by (used in) operating activities
Year Ended
December 31,
2013
2012
2011
2014
$ (1,757) $ (4,586) $ (14,332) $ 16,832
2
997
—
4,620
36,789
8,619
$ (758) $ (2,899) $ 13,091 $ 66,860
146
11,346
15,931
8
1,679
—
16,679
(331)
(1,157)
$ 15,191
$ (758) $ (2,899) $ 13,091 $ 66,860
(2)
(8)
(146)
(4,620)
142
(245)
(2,332)
(13,488)
135
$ (618) $ (3,152) $ 10,613 $ 48,887
—
—
—
(1) Maintenance capital expenditures represent that portion of our estimated capital expenditures associated with the connection of
new wells to our gathering and compression systems that we believe will be necessary to offset the natural production declines
Antero will experience on all of its wells over time.
48
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
49
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
50
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:
•
gathering and compression throughput in the Marcellus and Utica Shales;
• maintenance and contract service costs;
•
•
regulatory and compliance costs; and
operating costs associated with our internal growth projects, including:
•
•
increases in miles of pipeline; and
additional compressor stations.
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.
51
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.
52
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:
Revenue:
Gathering and compression—affiliate
$ 22,363 $ 95,746
$ 73,383
328 %
Year ended December 31,
Amount of
2013
Increase
2014
($ in thousands, except average realized fees)
Percentage
Change
Operating expenses:
Direct operating
General and administrative (including $15,931 and $8,619 of
equity-based compensation in 2013 and 2014, respectively)
Depreciation
Total operating expenses
Operating income (loss)
Interest expense
Net income (loss)
Adjusted EBITDA(1)
Operating Data:
Gathering—low pressure (MMcf)
Gathering—high pressure (MMcf)
Compression (MMcf)
Condensate gathering (MBbl)
Gathering—low pressure (MMcf/d)
Gathering—high pressure (MMcf/d)
Compression (MMcf/d)
Condensate gathering (MBbl/d)
Average realized fees:
2,079
15,470
13,391
644 %
23,124
11,346
36,549
(14,186)
146
22,035
36,789
74,294
21,452
4,620
$ 16,832 $
$ 13,091 $ 66,860 $
$ (14,332)
(1,089)
25,443
37,745
35,638
4,474
31,164
53,769
(5)%
224 %
103 %
* %
3,064 %
* %
411 %
61,406
11,736
9,900
181,727
167,935
38,104
621
498
460
104
2
—
168
32
27
—
120,321
156,199
28,204
621
330
428
77
2
196 %
1,331 %
285 %
*
196 %
1,338 %
285 %
*
Average gathering—low pressure fee ($/Mcf)
Average gathering—high pressure fee ($/Mcf)
Average compression fee ($/Mcf)
Average gathering—condensate fee ($/Bbl)
$
$
$
$
0.30
0.18
0.18
$
$
$
— $
0.31 $
0.18 $
0.18 $
4.08
0.01
—
—
*
3 %
— %
— %
*
* Not meaningful or applicable.
(1) For a discussion of the non-GAAP financial measure Adjusted EBITDA, including a reconciliation of Adjusted EBITDA to its
most directly comparable financial measures calculated and presented in accordance with GAAP, please “Item 6. Selected
Financial Data—Non-GAAP Financial Measure”.
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:
•
•
low pressure gathering revenue increased $37.0 million period over period primarily due to an increase of
throughput volumes of 120 Bcf, or 330 MMcf/d, which was primarily due to 126 new wells added in
2014, the expansion of our low pressure gathering system by 56 miles in 2014, and an increase in the
average realized fees of $0.01 per Mcf resulting from a consumer price index-based rate adjustment;
high pressure gathering revenue increased $28.6 million due to an increase of throughput volumes of 156
Bcf, or 428 MMcf/d, primarily as a result of the addition of twelve new high pressure gathering lines
placed in service in 2014 and the expansion of our high pressure gathering system by 35 miles in 2014;
53
•
•
compressor revenue increased $5.3 million period over period due to an increase of throughput
volumes of 28 Bcf, or 77 MMcf/d, primarily as a result of the addition of three new compressor
stations that were placed in service during 2014; and
condensate gathering revenue increased $2.5 million due to an increase of throughput volumes of 621
MBbl, or 2 MBbl/d, primarily as a result of the addition of condensate gathering lines that were placed
in service in 2014.
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 $53.8 million. The increase was primarily due to an
increase in gathering and compression throughput volumes in 2014. For a discussion of the non-GAAP financial measure
Adjusted EBITDA, including a reconciliation of Adjusted EBITDA to its most directly comparable financial measures
calculated and presented in accordance with GAAP, please read “Item 6. Selected Financial Data—Non-GAAP
Financial Measure.”
54
Year Ended December 31, 2012 Compared to Year Ended December 31, 2013
The following table sets forth selected operating data for the year ended December 31, 2012 compared to the
year ended December 31, 2013:
Year ended December 31,
Amount of
Increase
2013
($ in thousands, except average realized fees)
2012
Percentage
Change
Revenue:
Gathering and compression—affiliate
$
647 $ 22,363
$ 21,716
3,356 %
Operating expenses:
Direct operating
General and administrative (including $15,931 of equity-based
652
2,079
1,427
219 %
compensation in 2013)
Depreciation
Total operating expenses
Operating loss
Interest expense
Net loss
Adjusted EBITDA(1)
Operating Data:
Gathering—low pressure (MMcf)
Gathering—high pressure (MMcf)
Compression (MMcf)
Gathering—low pressure (MMcf/d)
Gathering—high pressure (MMcf/d)
Compression (MMcf/d)
Average realized fees:
23,124
11,346
36,549
(14,186)
146
2,894
1,679
5,225
(4,578)
8
20,230
9,667
31,324
(9,608)
138
$ (14,332) $ (9,746)
$ (2,899) $ 13,091 $ 15,990
$ (4,586)
699 %
576 %
600 %
*%
1,725 %
*%
(552)%
2,320
—
—
6
—
—
61,406
11,736
9,900
168
32
27
59,086
11,736
9,900
162
32
27
2,547 %
*%
*%
2,700 %
*%
*%
Average gathering—low pressure fee ($/Mcf)
Average gathering—high pressure fee ($/Mcf)
Average compression fee ($/Mcf)
$
$
$
0.28 $
* $
* $
0.30 $
0.18 $
0.18 $
0.02
*
*
7 %
— %
— %
* Not meaningful or applicable.
(1) For a discussion of the non-GAAP financial measure Adjusted EBITDA, including a reconciliation of Adjusted EBITDA to its
most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Item 6. Selected
Financial Data—Non-GAAP Financial Measure”.
Gathering and compression revenue—affiliate. Revenues from gathering and compression of natural gas
increased from $0.6 million for the year ended December 31, 2012 to $22.3 million for the year ended December 31,
2013, an increase of $21.7 million. Specifically:
•
•
•
low pressure gathering revenue increased $17.8 million period over period primarily due to an increase of
throughput volumes of 59 Bcf, or 162 MMcf/d, which was primarily due to the addition of low pressure
gathering volumes from 62 new wells in 2013 and an increase in the average realized fees of $0.02 per
Mcf;
high pressure gathering revenue increased $2.1 million due to an increase of throughput volumes of 12 Bcf,
or 32 MMcf/d, primarily as a result of the addition of compressor discharge volumes from two new
compressor stations placed in service in 2013; and
compressor revenue increased $1.8 million period over period due to an increase of throughput volumes of
10 Bcf, or 27 MMcf/d, primarily as a result of the addition of compressor volumes from two new
compressor stations placed in service in 2013.
55
Direct operating expenses. Total direct operating expenses increased from $0.7 million for the year ended
December 31, 2012 to $2.1 million for the year ended December 31, 2013, an increase of $1.4 million. The increase was
primarily due to an increase in the number of gathering pipelines and compressor stations.
General and administrative expenses. General and administrative expenses (before equity-based compensation
expense) increased from $2.9 million for the year ended December 31, 2012 to $7.2 million for the year ended
December 31, 2013, an increase of $4.3 million. The increase was primarily as a result of increased staffing levels and
related salary and benefits expenses and increases in legal and other general corporate expenses and the related allocation
of direct and indirect costs to our Predecessor. The increase was also attributable to an increase in staff required to
support our increase in capital expenditure activity.
Equity-based compensation expense increased from zero for the year ended December 31, 2012 to
$15.9 million for the year ended December 31, 2013, an increase of $15.9 million. The increase was due to an allocation
of Antero’s equity-based compensation expense to us related to 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.
Depreciation expense. Total depreciation expense increased from $1.7 million for the year ended December 31,
2012 to $11.3 million for the year ended December 31, 2013, an increase of $9.6 million. The increase was primarily due
to approximately $297 million in gathering and compression assets placed in service and depreciated in 2013 and a full
period of depreciation for the assets places in service during 2012.
Interest expense. Interest expense increased from less than $0.1 million for the year ended December 31, 2012
to $0.1 million for the year ended December 31, 2013, primarily due to the addition of $6.1 million in borrowings related
to additional capital leases in 2013.
Adjusted EBITDA. Adjusted EBITDA increased from $(2.9) million for the year ended December 31, 2012 to
$13.1 million for the year ended December 31, 2013, an increase of $16.0 million. The increase was primarily due to an
increase in gathering and compression throughput volumes in 2013. For a discussion of the non-GAAP financial measure
Adjusted EBITDA, including a reconciliation of Adjusted EBITDA to its most directly comparable financial measures
calculated and presented in accordance with GAAP, please read “Item 6. Selected Financial Data—Non-GAAP
Financial Measure.”
Capital Resources and Liquidity
Sources and Uses of Cash
Historically, our sources of liquidity included cash generated from operations and funding from Antero. We
historically participated in Antero’s centralized cash management program for all periods presented, whereby excess
cash from most of its subsidiaries was swept into a centralized account. Sales and purchases related to our Predecessor
third-party transactions were received or paid in cash by Antero within the centralized cash management system.
Subsequent to the closing of the IPO, we began maintaining our own bank accounts and sources of liquidity, but
continue to utilize Antero’s cash management system and expertise.
Capital and liquidity is provided by operating cash flow, cash on our balance sheet, and borrowings under our
revolving credit facility, discussed below. We expect cash flow from operations to continue to contribute to our liquidity
in the future. Sources of liquidity include borrowing capacity under our new $1.0 billion revolving credit facility. We
expect the combination of these capital resources will be adequate to meet our working capital requirements, capital
expenditures program and expected quarterly cash distributions for at least the next 12 months.
The board of directors of our general partner has adopted a cash distribution policy pursuant to which we intend
to distribute at least the minimum quarterly distribution of $0.17 per unit ($0.68 per unit on an annualized basis) on all of
our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses,
including payments to our general partner and its affiliates. On February 2, 2015, we announced the board of directors of
our general partner had declared a prorated quarterly cash distribution of $0.0943 per common unit for the quarter ended
December 31, 2014. The distribution is payable on February 27, 2015, to unit holders of record on February 13, 2015.
56
This amount represents the prorated minimum quarterly distribution of $0.17 per unit, or $0.68 per unit on an annual
basis.
We expect our future cash requirements relating to working capital, maintenance capital expenditures and
quarterly cash distributions to our partners will be funded from cash flows internally generated from our operations. Our
expansion capital expenditures will be funded by borrowings under our revolving credit facility or from potential capital
market transactions.
The following table and discussion presents a summary of our combined net cash provided by or used in
operating activities, investing activities and financing activities for the periods indicated.
2012
Year ended December 31,
2013
(in thousands)
2014
Operating activities
Investing activities
Financing activities
Net increase in cash and cash equivalents
Cash Flow Provided by Operating Activities
$ (3,152) $ 10,613 $ 48,887
(597,389)
778,694
— $ 230,192
(115,267)
118,419
(397,921)
387,308
— $
$
Net cash provided by operating activities was $48.9 million for the year ended December 31, 2014 and net cash
provided by operating activities was $10.6 million for the year ended December 31, 2013. The increase in cash flow
from operations for the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily
the result of increased throughput volumes and revenues attributable to the addition of new gathering and compression
systems placed in service in 2014.
Net cash provided by operating activities was $10.6 million for the year ended December 31, 2013 and net cash
used in operating activities was $3.2 million for the year ended December 31, 2012. The increase in cash flow from
operations for the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily the
result of increased throughput volumes and revenues attributable to the addition of new high pressure gathering and
compression capacity in 2013.
Cash Flow Used in Investing Activities
Our Predecessor’s historical capital expenditures were funded by Antero.
During the year ended December 31, 2014, we used cash flows in investing activities totaling $597.4 million for
expenditures and deposits for gathering systems and compressor stations.
During the year ended December 31, 2013, we used cash flows in investing activities totaling $397.9 million for
expenditures and deposits for gathering systems and compressor stations.
During the year ended December 31, 2012, we used cash flows in investing activities totaling $115.3 million for
expenditures for gathering systems and compressor stations.
Our board of directors has approved a capital budget of from $425 million to $450 million for 2015 to expand
our existing gathering and compression systems to accommodate Antero Resources’ development plans. Our capital
budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is
largely discretionary and within our control. If natural gas, NGLs, and oil prices decline to levels below acceptable levels
or costs increase to levels above acceptable levels, Antero could choose to defer a significant portion of its budgeted
capital expenditures until later periods. As a result, we may also defer a significant portion of our budgeted capital
expenditures to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we
believe have the highest expected returns and potential to generate near-term cash flow. We routinely monitor and adjust
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our capital expenditures in response to changes in Antero’s development plans, changes in prices, availability of
financing, acquisition costs, industry conditions, the timing of regulatory approvals, success or lack of success in
Antero’s drilling activities, contractual obligations, internally generated cash flow and other factors both within and
outside our control.
Cash Flow Provided by Financing Activities
Net cash provided by financing activities for the year ended December 31, 2014 of $778.7 million is the result
of $1.1 billion in net proceeds from our IPO, $510.0 million in borrowings under the midstream credit facility, and $29.8
million parent contributions offset by $510.0 million in repayments on the midstream credit facility, $332.5 million
distributions to Antero, $4.9 million payments of deferred financing costs, and $0.9 million principal payments on
capital leases.
Net cash provided by financing activities for the year ended December 31, 2013 of $387.3 million is the result
of $388.1 million in parent contributions, offset by $0.8 million for principal payments on capital leases.
Net cash provided by financing activities for the year ended December 31, 2012 of $118.4 million is the result
of $118.4 million in parent contributions, offset by less than $0.1 million for principal payments on capital leases.
Debt Agreements
Revolving Credit Facility
On November 10, 2014, in connection with the closing of the IPO, the Partnership entered into a revolving
credit facility with a syndicate of lenders. The revolving credit facility provides for lender commitments of $1.0 billion
and for a letter of credit sublimit of $150 million. At December 31, 2014, we had no borrowings and no letters of credit
outstanding under the revolving credit facility. The revolving credit facility will mature on November 10, 2019.
Principal amounts borrowed are payable on the maturity date with such borrowings bearing interest that is
payable quarterly. The Partnership has a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear
interest at a rate per annum equal to the LIBOR Rate administered by the ICE Benchmark Administration for one, two,
three, six or twelve months plus an applicable margin ranging from 150 to 225 basis points, depending on the leverage
ratio then in effect. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference
rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100
basis points, plus an applicable margin ranging from 50 to 125 basis points, depending on the leverage ratio then in
effect.
The revolving credit facility is secured by mortgages on substantially all of our and our restricted subsidiaries’
properties and guarantees from our restricted subsidiaries. The revolving credit facility contains restrictive covenants that
may limit our ability to, among other things:
• incur additional indebtedness;
• sell assets;
• make loans to others;
• make investments;
• enter into mergers;
• make certain restricted payments;
• incur liens; and
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• engage in certain other transactions without the prior consent of the lenders.
Borrowings under the revolving credit facility also require the Partnership to maintain the following financial
ratios:
• an interest coverage ratio, which is the ratio of the Partnership’s consolidated EBITDA to its
consolidated current interest charges of at least 2.5 to 1.0 at the end of each fiscal quarter; provided
that upon obtaining an investment grade rating, the borrower may elect not to be subject to such ratio;
• a consolidated total leverage ratio, which is the ratio of consolidated debt to consolidated EBITDA, of
not more than 5.0 to 1.0; provided that after electing to issue unsecured high yield notes, the
consolidated total leverage ratio will not be more than 5.25 to 1.0, or, following the election of the
borrower for two fiscal quarters after a material acquisition, 5.50 to 1.0; and
• if the Partnership elects to issue unsecured high yield notes, a consolidated senior secured leverage
ratio, which is the ratio of consolidated senior secured debt to consolidated EBITDA, of not more than
3.75 to 1.0.
Contractual Obligations
At December 31, 2014, we had no borrowings and no letters of credit outstanding under the revolving credit
facility. Under the terms of our revolving credit facility, we are required to pay a commitment fee of 0.250% on any
unused portion of the credit facility.
Critical Accounting Policies and Estimates
The following discussion relates to the critical accounting policies and estimates for both the Partnership and
our Predecessor. The discussion and analysis of our financial condition and results of operations are based upon our
financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of our consolidated
financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities,
revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve
judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could
have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and
assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are
believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the
carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from
these estimates and assumptions used in preparation of our financial statements. We provide expanded discussion of our
more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our
more significant estimates and assumptions used in preparation of our financial statements. See Note 2—Summary of
Significant Accounting Policies to the financial statements for a discussion of additional accounting policies and
estimates made by management.
Property and Equipment
Property and equipment primarily consists of gathering pipelines and compressor stations and are stated at the
lower of historical cost less accumulated depreciation, or fair value, if impaired. We capitalize construction-related direct
labor and material costs. Maintenance and repair costs are expensed as incurred.
Depreciation is computed over the asset’s estimated useful life using the straight-line method, based on
estimated useful lives and salvage values of assets. Gathering pipelines and compressor stations are depreciated over a
20 year useful life. The depreciation of fixed assets recorded under capital lease agreements is included in depreciation
expense. Uncertainties that may impact these estimates include, among others, changes in laws and regulations relating
to environmental matters, including air and water quality, restoration and abandonment requirements, economic
59
conditions and supply and demand in the area. When assets are placed into service, management makes estimates with
respect to useful lives and salvage values that management believes are reasonable. However, subsequent events could
cause a change in estimates, thereby impacting future depreciation amounts.
General and Administrative Costs
General and administrative costs are charged or allocated to us based on the nature of the expenses and are
allocated based on our proportionate share of Antero’s gross property and equipment, capital expenditures and direct
labor costs, as applicable. These allocations are based on estimates and assumptions that management believes are
reasonable.
Equity-based compensation grants are measured at their grant date fair value and related compensation cost is
recognized over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is
recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award.
Estimating the fair value of each award, the number of awards that will ultimately vest, and the forfeiture rate requires
management to apply judgment to estimate the tenure of our employees.
Equity-based compensation expenses are allocated to us based on our proportionate share of Antero’s direct
labor costs. These allocations are based on estimates and assumptions that management believes are reasonable.
New Accounting Pronouncements
On May 28, 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from
Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled
for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition
guidance in GAAP when it becomes effective. The new standard is effective for the Partnership on January 1, 2017.
Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition
method. We are evaluating the effect that ASU 2014-09 will have on our financial statements and related disclosures. We
have not yet selected a transition method nor have we determined the effect of the standard on our ongoing financial
reporting.
Off-Balance Sheet Arrangements
As of December 31, 2014, we did not have any off-balance sheet arrangements other than immaterial operating
leases.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative
information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from
adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of
expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides
indicators of how we view and manage our ongoing market risk exposures.
Commodity Price Risk
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 program and production and therefore our gathering volumes.
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Interest Rate Risk
Our primary exposure to interest rate risk results from outstanding borrowings under our revolving credit
facility, which has a floating interest rate. We do not currently, but may in the future, hedge the interest on portions of
our borrowings under our revolving credit facility from time-to-time in order to manage risks associated with floating
interest rates. At December 31, 2014, we had no borrowings and no letters of credit outstanding under the revolving
credit facility.
Prior to our IPO, we incurred interest on indebtedness under the midstream credit facility. The average annual
interest rate incurred on our indebtedness under the midstream credit facility for the year ended December 31, 2014 was
approximately 2.08%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the year ended
December 31, 2014 would have resulted in an estimated $6.9 million increase in interest expense for that period.
Credit Risk
We are dependent on Antero as our only customer, and we expect to derive a substantial majority of our
revenues from Antero for the foreseeable future. As a result, any event, whether in our area of operations or otherwise,
that adversely affects Antero’s production, drilling schedule, financial condition, leverage, market reputation, liquidity,
results of operations or cash flows may adversely affect our revenues and cash available for distribution.
Further, we are subject to the risk of non-payment or non-performance by Antero, including with respect to our
gathering and compression agreement. We cannot predict the extent to which Antero’s business would be impacted if
conditions in the energy industry were to deteriorate further, nor can we estimate the impact such conditions would have
on Antero’s ability to execute its drilling and development program or to perform under our agreement. Any material
non-payment or non-performance by Antero could reduce our ability to make distributions to our unitholders.
Item 8. Financial Statements and Supplementary Data
The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and
supplementary financial data required for this Item are set forth beginning on page F-1 of this report and are incorporated
herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”),
we have evaluated, under the supervision and with the participation of our management, including our principal
executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls
and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period
covered by this annual report. Our disclosure controls and procedures are designed to ensure that information required to
be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and
reported, within the time periods specified in the SEC’s rules and forms. Based upon that evaluation, our principal
executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as
of December 31, 2014.
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Internal Control Over Financial Reporting
This annual report is not required to include a report of management’s assessment regarding internal control
over financial reporting or an attestation report of our independent registered public accounting firm due to a transition
period established by rules of the SEC for newly public companies.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and
15d-15(f) under the Exchange Act) during the fourth quarter of 2014 that has materially affected, or is reasonably likely
to materially affect, our internal control over financial reporting.
Item 9B. Other Information
Pursuant to Section 13(r) of the Securities Exchange Act of 1934, we, Antero Midstream Partners LP, may be
required to disclose in our annual and quarterly reports to the Securities and Exchange Commission (the “SEC”),
whether we or any of our “affiliates” knowingly engaged in certain activities, transactions or dealings relating to Iran or
with certain individuals or entities targeted by US economic sanctions. Disclosure is generally required even where the
activities, transactions or dealings were conducted in compliance with applicable law. Because the SEC defines the term
“affiliate” broadly, it includes any entity under common “control” with us (and the term “control” is also construed
broadly by the SEC).
The description of the activities below has been provided to us by Warburg Pincus LLC (“WP”), affiliates of
which: (i) beneficially own more than 10% of our outstanding common units and/or are members of our general partner’s
board of directors and (ii) beneficially own more than 10% of the equity interests of, and have the right to designate
members of the board of directors of Endurance International Group (“EIG”) and Santander Asset Management
Investment Holdings Limited (“SAMIH”). EIG and SAMIH may therefore be deemed to be under common “control”
with Antero Midstream Partner LP; however, this statement is not meant to be an admission that common control exists.
The disclosure below relates solely to activities conducted by EIG and SAMIH and its non-U.S. affiliates that
may be deemed to be under common “control” with Antero Midstream Partner LP. The disclosure does not relate to any
activities conducted by us or by WP and does not involve our or WP’s management. Neither we nor WP has had any
involvement in or control over the disclosed activities of SAMIH, and neither we nor WP has independently verified or
participated in the preparation of the disclosure. Neither we nor WP is representing as to the accuracy or completeness
of the disclosure nor do we or WP undertake any obligation to correct or update it.
As to EIG:
We understand that EIG’s affiliates intend to disclose in their next annual or quarterly SEC report that: “On
July 2, 2013, the billing information for a subscriber account, or the Subscriber Account was updated to include Seyed
Mahmoud Mohaddes, or Mohaddes. On September 16, 2013, the Office of Foreign Assets Control, or OFAC, designated
Mohaddes as a Specially Designated National, or SDN, pursuant to 31 C.F.R. Part 560.304. On or around September 26,
2014, during a routine compliance scan of new and existing subscriber accounts, EIG discovered that Mohaddes, a SDN,
was named as an account contact for the Subscriber Account. EIG promptly suspended the Subscriber Account, locked
the domain name IOCUKLTD.COM, which was registered to the Subscriber Account, and reported the domain name to
OFAC as potentially the property of a SDN subject to blocking pursuant to Executive Order 13599. Since September 16,
2013, when Mohaddes was added to the SDN list, charges in the total amount of $120.35 were made to the Subscriber
Account for web hosting and domain privacy services. EIG has ceased billing for the Subscriber Account. To date, EIG
has not received any correspondence from OFAC regarding this matter.”
“On July 10, 2014, OFAC designated each of Stars Group Holding, or Stars, and Teleserve Plus SAL, or
Teleserve, as SDNs under Executive Order 13224, and their property became subject to blocking pursuant to the Global
Terrorism Sanctions Regulations, 31 C.F.R. Part 594. On July 15, 2014, as part of EIG’s compliance review processes,
EIG discovered that the domain names associated with each of Stars, STARSCOM.NET, and Teleserve,
TELESERVEPLUS.COM, or collectively, the Stars/Teleserve Domain Names, were registered through EIG’s platform.
EIG immediately took steps to suspend and lock the Stars/Teleserve Domain Names to prevent them from being
62
transferred or resolving to a website, and EIG promptly reported the Domain Names as potentially blocked property to
OFAC. EIG did not generate any revenue from the Stars/Teleserve Domain Names between when they were added to the
SDN list on July 10, 2014 and when EIG discovered that they were registered through EIG’s platform on July 15, 2014.
To date, EIG has not received any correspondence from OFAC regarding the matter.”
“On July 15, 2014 during a compliance scan of all domain names on one of our platforms, EIG identified the
domain name KAHANETZADAK.COM, or the Domain Name, which was listed as an ‘also known as,’ or AKA, of the
entity Kahane Chai which operates as the American Friends of the United Yeshiva. Kahane Chai was designated as a
SDN on November 2, 2001 pursuant to Executive Order 13224. Because the Domain Name was transferred into a
customer account of one of EIG’s resellers, there was no direct financial transaction between EIG and the registered
owner of the Domain Name. The Domain Name was suspended upon EIG’s discovering it on EIG’s platform, and EIG
reported the Domain Name to OFAC as potentially the property of a SDN. To date, EIG have not received any
correspondence from OFAC regarding the matter.”
As to SAMIH:
We understand that SAMIH’s affiliates intend to disclose in their next annual or quarterly SEC report that
“Santander UK holds frozen savings and current accounts for three customers resident in the U.K. who are currently
designated by the U.S. for terrorism. The accounts held by each customer were blocked after the customer’s designation
and remained blocked and dormant throughout 2014. No revenue has been generated by Santander UK on these
accounts. The bank account held for one of these customers was closed in the fourth quarter of 2014.”
“An Iranian national, resident in the U.K., who is currently designated by the U.S. under the Iranian Financial
Sanctions Regulations and the Weapons of Mass Destruction Proliferators Sanctions Regulations (“NPWMD sanctions
program”), holds a mortgage with Santander UK that was issued prior to any such designation. No further drawdown
has been made (or would be permitted) under this mortgage although Santander UK continues to receive repayment
installments. In 2014, total revenue in connection with the mortgage was approximately £2,580 and net profits were
negligible relative to the overall profits of Santander UK. The same Iranian national also holds two investment accounts
with Santander Asset Management UK Limited. The accounts have remained frozen during 2014. The investment
returns are being automatically reinvested, and no disbursements have been made to the customer. Total revenue for the
Santander Group in connection with the investment accounts was £250 and net profits in 2014 were negligible relative to
the overall profits of Banco Santander, S.A.”
“In addition, during the third quarter 2014, Santander UK identified two additional customers: a UK national
designated by the U.S. under the NPWMD sanctions program held a business account. No transactions were made and
the account was closed in the fourth quarter of 2014. No revenue or profit has been generated. A second UK national
designated by the US for reasons of terrorism held a personal current account and a personal credit card account, both of
which were closed in the third quarter of 2014. Although transactions took place on the current account during the third
quarter of 2014, revenue and profits generated were negligible. No transactions took place on the credit card.”
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Item 10. Directors, Executive Officers, and Corporate Governance
Management of Antero Midstream Partners LP
PART III
We are managed and operated by the board of directors and executive officers of our general partner, Antero
Midstream Management LLC (“Midstream Management”). Our general partner is controlled by Antero Investment. All
of the officers and certain of the directors of our general partner are also officers and directors of Antero. Neither our
general partner nor its board of directors is elected by our unitholders. Antero Investment is the sole member of our
general partner and has the right to appoint our general partner’s entire board of directors, including at least three
independent directors meeting the independence standards established by the NYSE. Our unitholders are not entitled to
directly participate in our management or operations. Our general partner owes certain contractual duties to our
unitholders as well as a fiduciary duty to its owners.
Our general partner has 7 directors. The NYSE does not require a listed publicly traded partnership, such as
ours, to have a majority of independent directors on the board of directors of our general partner or to establish a
compensation committee or a nominating committee. However, our general partner is required to have an audit
committee of at least three members, and all its members are required to meet the independence and experience
standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the year following
this offering.
All of the executive officers of our general partner listed below allocate their time between managing our
business and affairs and the business and affairs of Antero. The amount of time that our general partner’s executive
officers devote to our business and the business of Antero will vary in any given year based on a variety of factors. Our
general partner’s executive officers intend, however, to devote as much time to the management of our business and
affairs as is necessary for the proper conduct of our business and affairs.
Antero provides customary management and general administrative services to us pursuant to a services
agreement. Our general partner reimburses Antero at cost for its direct expenses incurred on behalf of us and a
proportionate amount of its indirect expenses incurred on behalf of us, including, but not limited to, compensation
expenses. Neither our general partner nor Antero receives any management fee or other compensation. Under a services
agreement, Antero charges us a general and administrative fee for services it provides us. Our partnership agreement
does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These
expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us
or on our behalf and expenses allocated to our general partner by its affiliates. Please read “Item 13. Certain
Relationships and Related Transactions and Director Independence.”
Board Leadership Structure
The Board does not have a formal policy addressing whether or not the roles of Chairman and Chief Executive
Officer should be separate or combined. The directors serving on the Board possess considerable professional and
industry experience, significant experience as directors of both public and private companies and a unique knowledge of
the challenges and opportunities that the Partnership faces. As such, the Board believes that it is in the best position to
evaluate the needs of the Partnership and to determine how best to organize Midstream Management’s leadership
structure to meet those needs.
At present, Midstream Management’s Board has chosen to combine the positions of Chairman and Chief
Executive Officer. While the Board believes it is important to retain the flexibility to determine whether the roles of
Chairman and Chief Executive Officer should be separated or combined in one individual, the Board believes that the
current Chief Executive Officer is the individual with the necessary experience, commitment and support of the other
members of the Board to effectively carry out the role of Chairman.
The Board believes this structure promotes better alignment of strategic development and execution, more
effective implementation of strategic initiatives and clearer accountability for the Partnership's success or failure.
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Moreover, the Board believes that combining the Chairman and Chief Executive Officer positions does not impede
independent oversight of the Partnership. Five of the seven members of the Board are independent under NYSE rules.
Board’s Role in Risk Oversight
In the normal course of its business, the Partnership is exposed to a variety of risks, including market risks
relating to changes in commodity prices, interest rates, technical risks affecting the Partnership’s facilities, political risks
and credit and investment risk. The Board oversees the strategic direction of the Partnership, and in doing so considers
the potential rewards and risks of the Partnership’s business opportunities and challenges, and monitors the development
and management of risks that impact the Partnership's strategic goals.
Executive Sessions
To facilitate candid discussion among our directors, the non-management directors meet in regularly scheduled
executive sessions.
Interested Party Communications
Unitholders and other interested parties may communicate by writing to: Antero Midstream Partners LP, 1615
Wynkoop Street, Denver, Colorado 80202. Unitholders may submit their communications to the Board, any committee
of the Board or individual directors on a confidential or anonymous basis by sending the communication in a sealed
envelope marked "Unitholder Communication with Directors" and clearly identify the intended recipient(s) of the
communication.
Our Chief Administrative Officer will review each communication and other interested parties and will forward
the communication, as expeditiously as reasonably practicable, to the addressees if: (1) the communication complies
with the requirements of any applicable policy adopted by the Board relating to the subject matter of the communication;
and (2) the communication falls within the scope of matters generally considered by the Board. To the extent the subject
matter of a communication relates to matters that have been delegated by the Board to a committee or to an executive
officer of the general partner, then the general partner’s Chief Administrative Officer may forward the communication to
the executive officer or chairman of the committee to which the matter has been delegated. The acceptance and
forwarding of communications to the members of the Board or an executive officer does not imply or create any
fiduciary duty of the Board members or executive officer to the person submitting the communications.
Information may be submitted confidentially and anonymously, although the Partnership may be obligated by
law to disclose the information or identity of the person providing the information in connection with government or
private legal actions and in other circumstances. The Partnership’s policy is not to take any adverse action, and not to
tolerate any retaliation, against any person for asking questions or making good faith reports of possible violations of
law, the Partnership’s policies or its Corporate Code of Business Conduct and Ethics.
Available Governance Materials
The following materials are available on the Partnership’s website at www.anteromidstream.com:
• Charter of the Audit Committee of the Board;
• Corporate Code of Business Conduct and Ethics;
• Financial Code of Ethics; and
• Corporate Governance Guidelines.
Unitholders may obtain a copy, free of charge, of each of these documents by sending a written request to
Antero Midstream Partners LP, 1615 Wynkoop Street, Denver, Colorado, 80202.
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Directors and Executive Officers
The following table shows information for our general partner’s executive officers and directors. Directors hold
office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or
disqualification. Executive officers serve at the discretion of the board. There are no family relationships among any of
the directors or executive officers. Some of the directors and all of the executive officers also serve as executive officers
of Antero.
Name
Paul M. Rady
Glen C. Warren, Jr.
Kevin J. Kilstrom
Alvyn A. Schopp
Ward D. McNeilly
Richard W. Connor
Peter R. Kagan
W. Howard Keenan, Jr.
Christopher R. Manning
David A. Peters
Age
Position With Our General Partner
61 Chairman and Chief Executive Officer
58 Director, President, Chief Financial Officer and Secretary
60 Vice President—Production
56 Chief Administrative Officer and Regional Vice President
64 Vice President—Reserves, Planning and Midstream
65 Director
46 Director
64 Director
47 Director
56 Director
Paul M. Rady has served as Chief Executive Officer and Chairman of the Board of Directors of Midstream
Management since February 2014. Mr. Rady also served as Chief Executive Officer and Chairman of the Board of
Directors of Antero since May 2004 and of its predecessor company from its founding in 2002 to its ultimate sale to
XTO Energy, Inc. in April 2005. Prior to Antero, Mr. Rady served as President, CEO and Chairman of Pennaco Energy
from 1998 until its sale to Marathon in early 2001. Prior to Pennaco, Mr. Rady was with Barrett Resources from 1990
until 1998 where he initially was recruited as Chief Geologist in 1990, then served as Exploration Manager, EVP
Exploration, President, COO and Director and ultimately CEO. Mr. Rady began his career with Amoco where he served
10 years as a geologist focused on the Rockies and Mid-Continent. Mr. Rady holds a B.A. in Geology from Western
State College of Colorado and M.Sc. in Geology from Western Washington University.
Mr. Rady’s significant experience as a chief executive of oil and gas companies, together with his training as a
geologist and broad industry knowledge, enable Mr. Rady to provide the board with executive counsel on a full range of
business, strategic and professional matters.
Glen C. Warren, Jr. has served as President, Chief Financial Officer and Secretary and as a director of
Midstream Management since February 2014. Mr. Warren also served as President, Chief Financial Officer and
Secretary and as a director of Antero since May 2004 and of its predecessor company from its founding in 2002 to its
ultimate sale to XTO Energy, Inc. in April 2005. Prior to Antero, Mr. Warren served as EVP, CFO and Director of
Pennaco Energy from 1998 until its sale to Marathon in early 2001. Mr. Warren spent 10 years as a natural resources
investment banker focused on equity and debt financing and M&A advisory with Lehman Brothers, Dillons
Read & Co. Inc. and Kidder, Peabody & Co. Mr. Warren began his career as a landman in the Gulf Coast region with
Amoco, where he spent six years. Mr. Warren holds a B.A. from the University of Mississippi, a J.D. from the
University of Mississippi School of Law and an M.B.A. from the Anderson School of Management at U.C.L.A.
Mr. Warren’s significant experience as a chief financial officer of oil and gas companies, together with his
experience as an investment banker and broad industry knowledge, enable Mr. Warren to provide the board with
executive counsel on a full range of business, strategic, financial and professional matters.
Kevin J. Kilstrom has served as Vice President of Production of Midstream Management since February 2014.
Mr. Kilstrom also has served as Vice President of Production of Antero since June 2007. Mr. Kilstrom was a Manager of
Petroleum Engineering with AGL Energy of Sydney, Australia from 2006 to 2007. Prior to AGL, Mr. Kilstrom was with
Marathon Oil as an Engineering Consultant and Asset Manager from 2003 to 2006 and as a Business Unit Manager for
Marathon’s Powder River coal bed methane assets from 2001 to 2003. Mr. Kilstrom also served as a member of the
board of directors of three Marathon subsidiaries from October 2003 through May 2005. Mr. Kilstrom was an Operations
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Manager and reserve engineer at Pennaco Energy from 1999 to 2001. Mr. Kilstrom was at Amoco for more than 22 years
prior to 1999. Mr. Kilstrom holds a B.S. in Engineering from Iowa State University and an M.B.A. from DePaul
University.
Alvyn A. Schopp has served as Chief Administrative Officer, Regional Vice President, and Treasurer of
Midstream Management since February 2014. Mr. Schopp has also served as Chief Administrative Officer, Regional
Vice President, and Treasurer of Antero since September 2013, as Vice President of Accounting and Administration and
Treasurer from January 2005 to September 2013, as Controller and Treasurer from 2003 to 2005 and as Vice President of
Accounting and Administration and Treasurer of Antero’s predecessor company, Antero Resources Corporation, from
January 2005 until its ultimate sale to XTO Energy, Inc. in April 2005. From 1993 to 2000, Mr. Schopp was CFO,
Director and ultimately CEO of T-Netix. From 1980 to 1993 Mr. Schopp was with KPMG LLP, most recently as a
Senior Manager. Mr. Schopp holds a B.B.A. from Drake University.
Ward D. McNeilly has served as Vice President of Reserves, Planning and Midstream of Midstream
Management since February 2014. Mr. McNeilly also has served as Vice President of Reserves, Planning & Midstream
of Antero since October 2010. Mr. McNeilly has 34 years of experience in oil and gas asset management, operations, and
reservoir management. From 2007 to October 2010, Mr. McNeilly was BHP Billiton’s Gulf of Mexico Operations
Manager. From 1996 through 2007, Mr. McNeilly served in various North Sea and Gulf of Mexico Deepwater
operations and asset management positions with Amoco and then BP. Mr. McNeilly served in a number of different
domestic and international positions with Amoco from 1979 to 1996. Mr. McNeilly holds a B.S. in Geological
Engineering from the Mackay School of Mines at the University of Nevada.
Richard W. Connor joined the board of Midstream Management in connection with our listing on the NYSE,
and serves as the Chairman of the audit committee. Mr. Connor has served as a director and Chairman of the audit
committee of Antero since September 1, 2013. Prior to his retirement in September 2009, Mr. Connor was an audit
partner with KPMG LLP, or KPMG, where he principally served publicly traded clients in the energy, mining,
telecommunications, and media industries for 38 years. Mr. Connor was elected to the partnership in 1980 and was
appointed to KPMG’s SEC Reviewing Partners Committee in 1987 where he served until his retirement. From 1996 to
September 2008, he served as the Managing Partner of KPMG’s Denver office. Mr. Connor earned his B.S. degree in
accounting from the University of Colorado. Mr. Connor is a member of the board of directors of Zayo Group
Holdings, Inc. (NYSE: ZAYO), a provider of bandwidth infrastructure and colocation services, and the chairman of its
audit committee. Mr. Connor is also a director of Centerra Gold, Inc. (TSX: CG.T), a Toronto-based gold mining
company listed on the Toronto Stock Exchange.
Mr. Connor has experience in technical accounting and auditing matters, knowledge of SEC filing requirements
and experience with a variety of energy clients. We believe his background and skill set make Mr. Connor well-suited to
serve as a member of our board of directors and as Chairman of the audit committee.
Peter R. Kagan has served as a director of Midstream Management since February 2014. Mr. Kagan also has
served as a director of Antero since 2004. Mr. Kagan has been with Warburg Pincus since 1997 where he leads the
firm’s investment activities in energy and natural resources. He is a Partner of Warburg Pincus & Co. and a Managing
Director of Warburg Pincus LLC. He is also a member of Warburg Pincus LLC’s Executive Management Group.
Mr. Kagan received a B.A. degree cum laude from Harvard College and J.D. and M.B.A. degrees with honors from the
University of Chicago. Prior to joining Warburg Pincus, he worked in investment banking at Salomon Brothers in both
New York and Hong Kong. Mr. Kagan currently also serves on the boards of directors of the following public
companies: Laredo Petroleum Holdings, Inc., MEG Energy Corp. and Targa Resources Corp., as well as the boards of
several private companies. In addition, he is a director of Resources for the Future and a trustee of Milton Academy.
Mr. Kagan has significant experience with energy companies and investments and broad knowledge of the oil
and gas industry. We believe his background and skill set make Mr. Kagan well-suited to serve as a member of our board
of directors.
W. Howard Keenan, Jr. has served as a director of Midstream Management since February 2014. Mr. Keenan
also has served as a director of Antero since 2004. Mr. Keenan has over thirty-five years of experience in the financial
67
and energy businesses. Since 1997, he has been a Member of Yorktown Partners LLC, a private investment manager
focused on the energy industry. From 1975 to 1997, he was in the Corporate Finance Department of Dillon,
Read & Co. Inc. and active in the private equity and energy areas, including the founding of the first Yorktown Partners
fund in 1991. He is serving or has served as a director of multiple Yorktown Partners portfolio companies. Mr. Keenan
holds an B.A. degree cum laude from Harvard College and an M.B.A. degree from Harvard University.
Mr. Keenan has significant experience with energy companies and investments and broad knowledge of the oil
and gas industry. We believe his background and skill set make Mr. Keenan well-suited to serve as a member of our
board of directors.
Christopher R. Manning has served as a director of Midstream Management since February 2014. Mr. Manning
also has served as a director of Antero since 2005. Mr. Manning has been a Partner with Trilantic Capital Partners since
its formation and spin out from Lehman Brothers Merchant Banking in April 2009, and is currently a member of its
Executive Committee and Chairman of Trilantic Energy Partners. His primary focus is on investments in the energy
sector. Mr. Manning joined Lehman Brothers Merchant Banking in 2000 and was concurrently the Head of Lehman
Brothers’ Investment Management Division, including both the Asset Management and Private Equity businesses, in
Asia-Pacific from 2006 to 2008. He was also a member of the Global Investment Management Division Executive
Committee and the Private Equity Division Operating Committee. Prior to Lehman Brothers, Mr. Manning was the chief
financial officer of The Wing Group, a developer of international power projects. Prior to The Wing Group, he was in
the investment banking department of Kidder, Peabody & Co., where he worked on M&A and corporate finance
transactions in the energy sector. Mr. Manning currently serves on the boards of The Cross Group, Enduring
Resources, LLC, Fluid Delivery Systems, Templar Energy LLC, and Trail Ridge Energy Partners II LLC, Velvet
Energy, Ltd., and Ward Energy Partners. Mr. Manning was previously Chairman of the Board of LB Pacific and TLP
Energy and a director of Mediterranean Resources and VantaCore Partners. Mr. Manning holds an M.B.A. from The
Wharton School of the University of Pennsylvania and a B.B.A. from the University of Texas at Austin.
Mr. Manning has significant experience with energy companies and investments and broad knowledge of the oil
and gas industry. We believe his background and skill set make Mr. Manning well-suited to serve as a member of our
board of directors.
David A. Peters joined the board of Midstream Management in connection with our listing on the NYSE, and
serves as a member of the audit committee. Mr. Peters served as a director of TransMontaigne GP L.L.C., the general
partner of TransMontaigne Partners L.P. (NYSE: TLP), from May 2005 to August 2014, and served as a member of the
audit and compensation committees and as the chair of the conflicts committee. Since 1999, Mr. Peters has been a
business consultant with a primary client focus in the energy sector. In addition, Mr. Peters also served as a member of
the board of directors of QDOBA Restaurant Corporation from 1998 to 2003. From 1997 to 1999, Mr. Peters was a
managing director of a private investment fund, and from 1995 to 1997 he served as an executive vice president at Duke
Energy Field Services/PanEnergy Field Services Inc., responsible for natural gas gathering, processing and storage
operations. Prior to joining Duke Energy Field Services/PanEnergy Field Services Inc., Mr. Peters held various positions
with Associated Natural Gas Corporation, and from 1980 to 1984, he worked in the audit department of Peat Marwick
Mitchell & Co. Mr. Peters holds a B.B.A. from the University of Michigan.
Mr. Peters has extensive knowledge of the energy industry as a business consultant and a former director of the
general partner of a master limited partnership and significant financial and accounting knowledge. We believe his
background and skill set make Mr. Peters well-suited to serve as a member of our board of directors and of the audit
committee.
Committees of the Board of Directors
The board of directors of our general partner has an audit committee. We do not have a compensation
committee, but rather the board of directors of our general partner approves equity grants to directors and Antero
employees. The board of directors of our general partner may establish a conflicts committee to review specific matters
that the board believes may involve conflicts of interest.
68
Audit Committee
Our general partner established an audit committee prior to the completion of our IPO. Rules implemented by
the NYSE and SEC require us to have an audit committee comprised of at least three directors who meet the
independence and experience standards established by the NYSE and the Exchange Act, subject to transitional relief
during the year following our IPO. Messrs. Connor and Peters serve on our audit committee, and Mr. Connor serves as
the Chairman of the committee. As required by the rules of the SEC and listing standards of the NYSE, the audit
committee will consist solely of independent directors, subject to transitional relief. SEC rules also require that a public
company disclose whether or not its audit committee has an “audit committee financial expert” as a member. An “audit
committee financial expert” is defined as a person who, based on his or her experience, possesses the attributes outlined
in such rules. Our board of directors believes that Mr. Connor possesses substantial financial experience based on his
extensive experience in technical accounting and auditing matters as a former audit partner of KPMG, LLP. As a result
of these qualifications, we believe Mr. Connor satisfies the definition of “audit committee financial expert.”
This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board
of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the
independent accountants, the performance of our independent accountants and our accounting practices. In addition, the
audit committee oversees our compliance programs relating to legal and regulatory requirements. We adopted an audit
committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE.
Conflicts Committee
Our general partner may, from time to time, have a conflicts committee to which the board will appoint at least
two independent directors and which may be asked to review specific matters that the board believes may involve
conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee will
determine if the resolution of the conflict of interest is adverse to the interest of the partnership. The members of the
conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its
affiliates, including Antero Investment and Antero, and must meet the independence standards established by the NYSE
and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our
partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be approved by
us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires executive officers and managing board members
of our general partner and persons who beneficially own more than 10% of a registered class of our equity securities to
file reports of ownership and changes in ownership with the Securities and Exchange Commission and to furnish us with
copies of all such reports.
Based solely upon our review of reports received by us, or representations from certain reporting persons that
no filings were required, we believe that all of the officers and managing board members of our general partner and
persons who beneficially owned more than 10% of our common units complied with all applicable filing requirements
during fiscal year 2014.
Item 11. Executive Compensation
Neither we nor our general partner have any employees. All of the executive officers of our general partner and
other personnel who provide services to our business are employed by Antero. The named executive officers of our
69
general partner (which we refer to below as our “Named Executive Officers”) are listed below along with their respective
principal positions with our general partner and Antero:
Name
Paul M. Rady
Glen C. Warren, Jr.
Alvyn A. Schopp
Chairman of the Board of Directors and Chief Executive Officer
Director, President, Chief Financial Officer and Secretary
Chief Administrative Officer and Regional Vice President
Principal Position
Aside from certain equity awards granted to our Named Executive Officers under the Antero Midstream
Partners LP Long-Term Incentive Plan (the “Midstream LTIP”), our Named Executive Officers currently receive all of
their compensation and benefits for services provided to our business from Antero. Although we bear an allocated
portion of Antero’s costs of providing such compensation and benefits to the employees who serve as our Named
Executive Officers, we have no control over such costs and do not establish or direct the compensation policies or
practices of Antero. Pursuant to the services agreement that we have entered into with Antero and our general partner,
we are required to reimburse Antero for a proportionate amount of compensation expenses incurred on our behalf.
Summary Compensation Table
Name and Principal Position
Paul M. Rady
(Chairman of the Board and Chief
Executive Officer)
Glen C. Warren, Jr.
(Director, President and Chief
Financial Officer and Secretary)
Salary
($)
Bonus
($) (1)
Year
2014 $ 800,000 $ 960,000 $ 25,567,995 $ —(3) $
— $ — $
2013 $ 650,000 $ 1,200,000 $
($)
Stock
Awards
($) (2)
Option
Awards
All Other
Compensation
($) (4)
Total
($)
6,677 $ 27,334,672
— $ 1,850,000
2014 $ 600,000 $ 600,000 $ 17,051,968 $ —(3) $
2013 $ 525,000 $ 950,000 $
— $ — $
10,400 $ 18,262,368
— $ 1,475,000
Alvyn A. Schopp
(Chief Administrative Officer and
2014 $ 400,000 $ 340,000 $ 9,392,024 $ —(3) $
2013 $ 350,000 $ 500,000 $
— $ — $
10,400 $ 10,142,424
850,000
— $
Regional Vice President)
(1) Represents the aggregate amount of the annual discretionary cash bonuses paid to each Named Executive Officer.
(2) The amounts reflected in this column represent the grant date fair value of (i) restricted stock unit awards granted to the Named
Executive Officers pursuant to the AR LTIP (as defined below) and (ii) phantom units (which include tandem distribution
equivalent rights) granted to the Named Executive Officers pursuant to the Midstream LTIP, computed in accordance with
Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) Topic 718. See Note 5 to our
consolidated financial statements for additional detail regarding assumptions underlying the value of these equity awards.
(3) In May 2013, Messrs. Rady, Warren, and Schopp were each granted additional units in Employee Holdings (as defined below).
As indicated below under the heading “—Narrative Disclosure to the Summary Compensation Table—Employee Holdings Unit
Awards,” the units in Employee Holdings are intended to constitute “profits interests” for federal tax purposes. Accordingly, if
Employee Holdings had been liquidated as of the date these units were granted, Messrs. Rady, Warren, and Schopp would not
have been entitled to receive a distribution with respect to such units.
(4) The amounts reflected in this column represent the amount of Antero’s 401(k) match for fiscal 2014 for each participating
Named Executive Officer.
Narrative Disclosure to the Summary Compensation Table
The following is a discussion of material factors necessary to an understanding of the information disclosed in
the Summary Compensation Table.
Phantom Unit Awards
On November 12, 2014, the board of directors of our general partner granted phantom units under the
Midstream LTIP to each of our Named Executive Officers in connection with our IPO. 25% of the phantom units
70
granted to each of our Named Executive Officers will become vested on each of the first four anniversaries of the grant
date so long as the applicable Named Executive Officer remains continuously employed by Antero from the grant date
through the applicable vesting date. All of the phantom units granted to each Named Executive Officer will also become
fully vested immediately if such Named Executive Officer’s employment terminates due to his death or disability.
Vested phantom units (less any phantom units withheld to satisfy applicable tax withholding obligations) will be settled
through the issuance of common units within 30 days following the applicable vesting date. While a Named Executive
Officer holds unvested phantom units, he is entitled to receive distribution equivalent right credits (the “Midstream
DERs”) equal to cash distributions paid in respect of a common unit. The Midstream DERs will be paid in cash within
30 days following the vesting of the associated phantom units (and will be forfeited at the same time the associated
phantom units are forfeited). The potential acceleration and forfeiture events relating to these phantom units are
described in greater detail under the heading “Potential Payments Upon Termination or a Change in Control” below.
Antero Restricted Stock Unit Awards
On April 1, 2014, the board of directors of our general partner granted restricted stock unit awards under
Antero’s Long-Term Incentive Plan (the “AR LTIP”) to each of our Named Executive Officers in connection with a
retention program adopted by the board of directors of our general partner in fiscal 2014. The retention program was
intended to provide our Named Executive Officers with a direct link to the performance of Antero’s common stock while
encouraging their continued service to Antero and us. With respect to Messrs. Rady and Warren, 50% of the restricted
stock unit awards granted pursuant to the retention program will vest on October 22 of each of 2016 and 2017, so long as
Mr. Rady or Warren, as applicable, remains continuously employed by Antero from the grant date through the applicable
vesting date. With respect to Mr. Schopp, 25% of the restricted stock unit awards granted pursuant to the retention
program will vest on April 1 of each of 2015, 2016, 2017 and 2018, so long as Mr. Schopp remains continuously
employed by Antero from the grant date through the applicable vesting date. All of the restricted stock units granted to
each Named Executive Officer will also become fully vested immediately if such Named Executive Officer’s
employment terminates due to his death or disability. Vested restricted stock units (less any restricted stock units
withheld to satisfy applicable tax withholding obligations) will be settled through the issuance of Antero common stock
within 30 days following the applicable vesting date. While a Named Executive Officer holds unvested restricted stock
units, he is entitled to receive distribution equivalent right credits (the “AR DERs”) equal to cash distributions paid in
respect of a share of Antero common stock. The AR DERs will be paid in cash within 30 days following the vesting of
the associated restricted stock units (and will be forfeited at the same time the associated restricted stock units are
forfeited).The potential acceleration and forfeiture events relating to these restricted stock units are described in greater
detail under the heading “Potential Payments Upon Termination or a Change in Control” below. As of December 31,
2014, no restricted stock unit awards granted pursuant to the retention program had vested.
Employee Holdings Unit Awards
Historically, Antero’s long-term equity-based incentive awards have consisted of profits interests in Antero
Resources Employee Holdings LLC (“Employee Holdings”), which holds as a portion of the membership interests in
Antero Resources Investment LLC (“ARI”), which in turn, owns approximately 79% of the outstanding shares of
Antero’s common stock. These awards entitle Antero’s employees, including our Named Executive Officers, to receive,
subject to the terms and provisions of the limited liability company agreement of Employee Holdings (the “Employee
Holdings LLC Agreement”) and the restricted unit agreements pursuant to which the awards were granted, a portion of
any future profits of Employee Holdings that result from any distributions on the ARI units that are held by Employee
Holdings once certain return thresholds have been achieved. This structure enabled Antero to provide its employees with
long-term equity incentive compensation in an affiliated entity that may directly profit from any success Antero
achieves. The numbers and classes of units in Employee Holdings that were granted to each Named Executive Officer
were determined based on each executive’s contribution to the growth of Antero.
Other than the Employee Holdings units granted to Messrs. Rady, Warren, and Schopp in May 2013, all of the
Employee Holdings units held by our Named Executive Officers were fully vested as of December 31, 2014. The
unvested portion of the Employee Holdings units held by Messrs. Rady, Warren, and Schopp will become vested in
accordance with the schedule as described in footnote 4 to the Outstanding Equity Awards at 2014 Fiscal Year-End table
below.
71
Outstanding Equity Awards at 2014 Fiscal Year-End
The following table provides information concerning equity awards that have not vested for our Named
Executive Officers as of December 31, 2014.
Option Awards(1)
Stock Awards(6)
Number of
Securities
Underlying
Unexercised
Options
Unexercisable
(#) (2)
Number of
Securities
Underlying
Unexercised Option
Exercise
Price
($) (5)
Exercisable
Options
(#) (3)
Option
Expiration
Date
($) (5)
Number of
Units That
Have Not
Vested
(#) (7)
—
—
1,875,000
113,670
500,000
625,000
N/A
N/A
N/A
—
—
1,250,000
75,780
333,333
416,667
N/A
N/A
N/A
—
—
318,750
50,000
125,000
106,250
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Market
Value of
Units That
Have Not
Vested
($) (8)
N/A
N/A
N/A
307,314 $ 12,470,802
5,280,000
192,000 $
N/A
N/A
N/A
8,318,007
3,520,000
N/A
N/A
N/A
4,988,337
1,320,000
204,978 $
128,000 $
122,926 $
48,000 $
Name
Paul M. Rady
Class A-2 Units
Class B-2 Units
Class B-4 Units(4)
Restricted Stock Units
Phantom Units
Glen C. Warren, Jr.
Class A-2 Units
Class B-2 Units
Class B-4 Units(4)
Restricted Stock Units
Phantom Units
Alvyn A. Schopp
Class A-2 Units
Class B-2 Units
Class B-4 Units(4)
Restricted Stock Units
Phantom Units
(1) The equity awards that are disclosed in this Outstanding Equity Awards at 2014 Fiscal Year-End table under Option Awards are
units in Employee Holdings that are intended to constitute profits interests for federal tax purposes rather than traditional option
awards.
(2) Awards reflected as “Unexercisable” are Employee Holdings units that have not yet become vested.
(3) Awards reflected as “Exercisable” are Employee Holdings units that have become vested, but have not yet been settled.
(4) One-third of the unvested Employee Holdings units reflected in this row will become vested on each of May 7, 2015, May 7,
2016 and May 7, 2017 so long as the applicable Named Executive Officer remains continuously employed by Antero or one of its
affiliates through each such date.
(5) These equity awards are not traditional options and, therefore, there is no exercise price or expiration date associated with them.
(6) The equity awards that are disclosed in this Outstanding Equity Awards at 2014 Fiscal Year-End table under Stock Awards are
restricted stock units granted under the AR LTIP and phantom units granted under the Midstream LTIP.
(7) Except as otherwise provided in the applicable award agreement, (i) (A) with respect to Messrs. Rady and Warren, 50% of the
restricted stock units will vest on October 22 of each of 2016 and 2017, so long as Mr. Rady or Warren, as applicable, remains
continuously employed by Antero from the grant date through the applicable vesting date, and (B) with respect to Mr. Schopp,
25% of the restricted stock units will vest on April 1 of each of 2015, 2016, 2017 and 2018, so long as Mr. Schopp remains
continuously employed by Antero from the grant date through the applicable vesting date, and (ii) 25% of the phantom units
granted to each of our Named Executive Officers will become vested on November 12, 2015, 2016, 2017 and 2018, in each case,
so long as the applicable Named Executive Officer remains continuously employed by Antero from the grant date through the
applicable vesting date.
(8) The amounts reflected in this column represent the market value of (i) common stock underlying the restricted stock unit awards
granted to the Named Executive Officers, computed based on the closing price of Antero’s common stock on December 31,
2014, which was $40.58 per share, and (ii) our common units underlying the phantom unit awards granted to the Named
Executive Officers, computed based on the closing price of our common units on December 31, 2014, which was $27.50 per unit.
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Additional Narrative Disclosure
Retirement Benefits
Antero has not maintained, and does not currently maintain, a defined benefit pension plan or a nonqualified
deferred compensation plan providing for retirement benefits. Antero maintains an employee retirement savings plan
through which employees may save for retirement or future events on a tax-advantaged basis. Participation in the 401(k)
plan is at the discretion of each individual employee, and our Named Executive Officers participate in the plan on the
same basis as all other employees. While the plan permits Antero to make discretionary matching and non-elective
contributions, Antero has not made any employer contributions in recent years apart from safe harbor matching
contributions equal to 100% of employees’ pre-tax contributions under the plan, but not as to pre-tax contributions
exceeding 4% of their eligible compensation (up to IRS limitations).
Potential Payments Upon Termination or a Change in Control
Antero does not maintain any employment, severance or change in control agreements with any of our Named
Executive Officers. However, the unvested units in Employee Holdings granted to Messrs. Rady, Warren and Schopp
could be affected by the termination of their employment or the occurrence of certain corporate events. The impact of
such a termination or corporate event upon the units is governed by the terms of both the restricted unit agreements
issued to them in connection with the grant of their unit awards, as well as the Employee Holdings LLC Agreement.
The Employee Holdings LLC Agreement provides that upon the termination of a Named Executive Officer’s
employment with Antero by reason of death or “disability” (as defined below) or upon the occurrence of an “exit event”
(as defined below) while the Named Executive Officer is employed by Antero, any unvested portion of the Employee
Holdings units granted to the Named Executive Officer will become vested; Antero’s termination of the Named
Executive Officer’s employment with or without “cause,” as well as the officer’s voluntary termination of employment,
generally results in the forfeiture of all unvested Employee Holdings units. In addition, a termination for “cause” results
in a forfeiture of all vested units. Any unvested portion of the Employee Holdings units granted to a Named Executive
Officer may also become immediately vested under such circumstances and at such times as the board of directors of
Employee Holdings determines to be appropriate in its discretion.
The Employee Holdings LLC Agreement also provides that upon the voluntary resignation of a Named
Executive Officer or the occurrence of an exit event, any portion of the Employee Holdings units granted to the officer
that have vested as of the time of the applicable event are subject to repurchase, at Employee Holdings’ option, at a
purchase price equal to the “fair market value” of such units, as determined by the unanimous resolution of the board of
directors of Employee Holdings. Such amount may be paid by Employee Holdings in cash or by promissory note. In
addition, in lieu of electing to repurchase all or any portion of a Named Executive Officer’s vested units in Employee
Holdings, the board of directors of Employee Holdings has the right to modify such units so that the aggregate amount
that may potentially be distributed with respect to such units is “capped” at the lesser of (a) the aggregate amount that the
Named Executive Officer is entitled to receive with respect to such units under the Employee Holdings LLC Agreement
or (b) an amount equal to the sum of (x) the fair market value of such units as of the date the Named Executive Officer’s
employment terminates (the “Termination Value”) and (y) an accretion amount with respect to the Termination Value
calculated based upon a rate equal to 5% per annum, compounding annually in arrears as of the Termination Date.
Under the Employee Holdings LLC Agreement, a Named Executive Officer will be considered to have incurred
a “disability” if the officer becomes incapacitated by accident, sickness or other circumstance that renders the officer
mentally or physically incapable of performing the officer’s duties with Antero on a full time basis for a period of at least
120 days during any 12 month period. A termination for “cause” will occur following an employee’s (1) gross
negligence or willful misconduct, (2) conviction of a felony or a crime involving theft, fraud or moral turpitude,
(3) refusal to perform material duties or responsibilities, (4) willful and material breach of a corporate policy or code of
conduct or (5) willful engagement in conduct that damages the integrity, reputation or financial success of Antero or any
of its affiliates. Further, an “exit event” generally includes the sale of Antero Investment, in one transaction or a series of
related transactions, whether structured as (a) a sale or other transfer of all or substantially all of Antero Investment
(including by way of merger, consolidation, share exchange, or similar transaction), (b) a sale or other transfer of all or
73
substantially all of our assets promptly followed by a dissolution and liquidation of our company or (c) a combination of
the transactions described in clauses (a) and (b).
As noted above, any unvested phantom units or restricted stock units granted to our Named Executive Officers
will become immediately fully vested if the applicable Named Executive Officer’s employment with Antero terminates
due to his death or “disability.” For purposes of these awards, a Named Executive Officer will be considered to have
incurred a “disability” if he is unable to engage in any substantial gainful activity by reason of any medically
determinable physical or mental impairment that can be expected to result in death or which has lasted or can be
expected to last for a continuous period of not less than 12 months.
Potential Payments Upon Termination or Change in Control Table for Fiscal 2014
Because the right to repurchase vested Employee Holdings units is optional rather than mandatory, none of our
Named Executive Officers would have had a right to receive any amounts in respect of their Employee Holdings units on
or after a termination of their employment or the occurrence of an exit event as of December 31, 2014. However, if
Messrs. Rady, Warren, or Schopp’s employment with Antero would have terminated due to the Named Executive
Officers’ death or disability or if an exit event occurred, the unvested portion of his Employee Holdings units would have
become vested. The Employee Holdings units effectively represent an indirect interest in certain shares of Antero’s
common stock. The closing price of Antero’s common stock on December 31, 2014 was $40.58 per share.
Similarly, if any of our Named Executive Officers’ employment with Antero would have terminated due to the
Named Executive Officers’ death or disability, the unvested portion of his restricted stock units and phantom units, as
applicable, would have become vested. The restricted stock units represent a direct interest in shares of Antero’s
common stock, and the closing price of Antero’s common stock on December 31, 2014 was $40.58 per share. The
phantom units represent a direct interest in our common units, and the closing price of our common units on December
31, 2014 was $27.50 per unit.
The amounts that each of our Named Executive Officers would receive in connection with the accelerated
vesting of their equity awards upon a termination due to their death or disability (assuming such termination occurred on
December 31, 2014) is included in the last column of the Outstanding Equity Awards at 2014 Fiscal Year-End table
above.
Compensation of Directors
Generally
Each director of our general partner who is not an officer or employee of Antero receives the following
compensation for serving as a director:
•
•
•
an annual retainer fee of $60,000 per year;
an additional retainer of $7,500 per year if such director is a member of the audit committee (or an additional
retainer of $20,000 per year if such director serves as the chairperson of the audit committee); and
an additional retainer of $5,000 per year if such director is a member of the conflicts committee (or an
additional retainer of $15,000 per year if such director serves as the chairperson of the conflicts committee).
In addition to cash compensation, our non-employee directors receive annual equity-based compensation
consisting of restricted units under the Midstream LTIP with an aggregate grant date value equal to $100,000, subject to
the terms and conditions of the Midstream LTIP and the award agreements pursuant to which such awards are granted.
All retainers are paid in cash on a quarterly basis in arrears, but directors have the option to elect to receive their
retainers in the form of common units pursuant to the Midstream LTIP rather than in cash. Our non-employee directors
do not receive any meeting fees, but each director is reimbursed for (i) travel and miscellaneous expenses to attend
meetings and activities of the board of directors of our general partner or its committees and (ii) travel and miscellaneous
expenses related to participation in general education and orientation programs for directors.
74
Each director is fully indemnified by us for actions associated with serving as a director to the fullest extent
permitted under Delaware law.
Director Compensation Table
Officers or employees of Antero who also serve as directors of our general partner do not receive additional
compensation for such service. The following table provides information concerning the compensation of our non-
employee directors for the fiscal year ended December 31, 2014.
Name
Peter Kegan
W Howard Keenan, Jr.
Christopher R. Manning
Richard W. Connor
David Peters
Fee Earned or
Paid in Cash
($)⁽¹⁾
15,000 $
15,000 $
15,000 $
20,000 $
20,625 $
$
$
$
$
$
Unit Awards
($)⁽²⁾
116,000 $
116,000 $
116,000 $
116,000 $
116,000 $
Total
($)
131,000
131,000
131,000
136,000
136,625
(1) Includes annual cash retainer fee and committee chair fees for each non-employee director during fiscal 2014, as described
above.
(2) The amounts reflected in this column represent the grant date fair value of restricted unit awards granted to the non-employee
directors of our general partner, computed in accordance with FASB ASC Topic 718. See Note 5 to our consolidated financial
statements for additional detail regarding assumptions underlying the value of these equity awards. As of December 31, 2014,
Messrs. Kagan, Keenan, Manning, Connor, and Peters each held a total of 4,000 restricted units, which will become fully vested
on November 12, 2015 so long as the applicable non-employee director continues to serve on our general partner’s board of
directors through such date.
Equity Compensation Plan Information
The following table sets forth information about our securities that may be issued under all existing equity
compensation plans of the Partnership and Antero as of December 31, 2014.
Plan Category
Equity compensation plans approved by
security holders
Antero Resources Corporation Long-
Term Incentive Plan(1)
Antero Midstream Partners LP Long-
Term Incentive Plan(2)
Equity compensation plans not approved by
security holders
Total
Number of securities to be
Number of securities
remaining available for
future issuance under
issued upon exercise of Weighted-average exercise
equity compensation plans
outstanding options,
warrants and rights
(a) ('2)
price of outstanding options,
(excluding securities
warrants and rights
(b)
reflected in column (a))
(c)
1,970,587 $
52.44 (3)
14,819,823
2,361,440
—
4,332,027
N/A(4)
7,618,560
—
—
22,438,383
(1) The Antero Resources Corporation Long-Term Incentive Plan (the “AR LTIP”) was approved by our sole stockholder prior to
our IPO.
(2) The Antero Midstream Partners LP Long Term Incentive Plan (the “Midstream LTIP”) was approved by the general partner of
the Partnership prior to its IPO.
(3) The calculation of the weighted-average exercise price of outstanding options, warrants and rights excludes restricted stock unit
awards granted under the AR LTIP.
(4) Only phantom unit awards are granted under the Midstream LTIP, therefore there is no weighted average exercise price.
75
Item 12. Security Ownership of Certain Beneficial Owners and Management
The following table sets forth the beneficial ownership of common units and subordinated units of Antero
Midstream Partners LP that will be issued and outstanding as of February 19, 2015 held by:
•
•
•
•
our general partner;
beneficial owners of 5% or more of our common units;
each director and named executive officer; and
all of our general partner’s directors and executive officers as a group.
Unless otherwise noted, the address for each beneficial owner listed below is 1615 Wynkoop Street, Denver,
Colorado 80202.
Percentage of
Common Units Common Units
Beneficially
Beneficially
Subordinated
Units
Beneficially
Owned
Owned
Percentage of
Percentage of
Subordinated Subordinated
Common
and
Units
Beneficially
Owned
Units
Beneficially
Owned
Name of Beneficial Owner
Antero Resources Corporation(¹)
Antero Resources Midstream
Management LLC(²)
Richard W. Connor
Peter R. Kagan
W. Howard Keenan, Jr.
Christopher R. Manning
David A. Peters
Paul M. Rady
Glen C. Warren, Jr.
Kevin J. Kilstrom
Alvyn A. Schopp
Ward D. McNeilly
All directors and executive officers as a
group (10 persons)
Owned
29,940,957
—
9,000
4,000
4,000
14,000
10,000
60,000
40,000
—
6,000
—
147,000
39.4 % 75,940,957
100 %
69.7 %
—%
*%
*%
*%
*%
*%
*%
*%
*%
*%
*%
*%
—
—
—
—
—
—
—
—
—
—
—
—
— %
— %
— %
— %
— %
— %
— %
— %
— %
— %
— %
— %
—%
*%
*%
*%
*%
*%
*%
*%
*%
*%
*%
*%
Less than 1%.
*
(1) Under Antero’s amended and restated certificate of incorporation and bylaws, the voting and disposition of any of our common
or subordinated units held by Antero will be controlled by the board of directors of Antero. The board of directors of Antero,
which acts by majority approval, comprises Peter R. Kagan, W. Howard Keenan, Jr., Christopher R. Manning, Robert J. Clark,
Richard W. Connor, Benjamin A. Hardesty, James R. Levy, Paul M. Rady and Glen C. Warren, Jr. Each of the members of
Antero’s board of directors disclaims beneficial ownership of any of our units held by Antero.
(2) Under our general partner’s amended and restated limited liability company agreement, the voting and disposition of any of our
common or subordinated units or the incentive distribution rights held by our general partner will be controlled by its sole
member, Antero Resources Investment LLC (“Antero Investment”). The board of directors of Antero Investment, which acts by
majority approval, comprises Peter R. Kagan, W. Howard Keenan, Jr., Christopher R. Manning, Paul M. Rady and Glen C.
Warren, Jr. Each of the members of Antero Investment’s board of directors disclaims beneficial ownership of any of our
securities held by our general partner.
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The following table sets forth the number of shares of common stock of Antero owned by each of the named
executive officers and directors of our general partner and all directors and executive officers of our general partner as a
group as of February 19, 2015:
Name of Beneficial Owner
Richard W. Connor(1)(2)(3)
Peter R. Kagan(1)(2)
W. Howard Keenan, Jr.(1)(2)
Christopher R. Manning(1)(2)(4)
David A. Peters
Paul M. Rady
Glen C. Warren, Jr.(5)
Kevin J. Kilstrom
Alvyn A. Schopp
All directors and executive officers as a group (9 persons)
Percentage of
Shares
Shares
Beneficially Beneficially
Owned
Owned
4,861
6,036
4,821
40,571
—
307,314
204,985
122,926
122,926
814,440
*
*
*
*
—
*
*
*
*
*
Less than 1%.
*
(1) Includes 1,477 shares of common stock of Antero issuable upon exercise of outstanding options.
(2) Includes 1,526 shares of restricted stock that will vest on October 16, 2015.
(3) Mr. Connor indirectly own 40 shares of common stock of Antero purchased by a family member, and these shares are included
because of his relation to the purchaser. Mr. Connor disclaims beneficial ownership of all shares reported except to the extent of
his pecuniary interest therein.
(4) Mr. Manning is a partner of Trilantic Capital Partners. Mr. Manning indirectly owns 35,750 shares of common stock of Antero
purchased by TCP Antero Principals LLC, a Trilantic Capital Partners entity, and these shares are included because of his
affiliation with Trilantic Capital Partners. Mr. Manning disclaims beneficial ownership of all shares reported except to the extent
of his pecuniary interest therein.
(5) Mr. Warren indirectly owns 7 shares of common stock of Antero purchased by a family member, and these shares are included
because of his relation to the purchaser. Mr. Warren disclaims beneficial ownership of all shares reported except to the extent of
his pecuniary interest therein.
Securities Authorized for Issuance Under Equity Compensation Plan
The following table sets forth information with respect to the securities that may be issued under the Midstream
LTIP as of February 19, 2015. The Midstream LTIP was adopted by our general partner in connection with the closing
of our IPO and provides for the making of certain awards. For information about the Midstream LTIP, that did not
require approval by our limited partners, please read “Item 11. Executive Compensation—Additional Narrative
Disclosure—Midstream Long-Term Incentive Plan” in this Form 10-K.
Number of securities to be Weighted average
exercise price of
issued upon exercise of
outstanding options,
outstanding options,
Number of securities remaining
available for future issuance under
equity compensation plans,
Plan Category
Equity compensation plans approved
by security holders
warrants and rights (1) warrants and rights (2) excluding securities reflected in column
2,381,440
—
7,618,560
(1) Amounts in this column reflect phantom units and restricted units that have been granted under the Midstream LTIP. No awards
(as defined under the LTIP) have been made other than the phantom units and restricted units. These phantom units and restricted
units vest subject to the satisfaction of service requirements, upon the completion of which common units in the Partnership are
delivered to the holder of the restricted units or phantom units.
(2) This column is not applicable because phantom units do not have an exercise price.
77
Item 13. Certain Relationships and Related Transactions and Director Independence
Antero owns 29,940,957 common units and 75,940,957 subordinated units representing an aggregate
approximately 69.7% limited partner interest in us. Antero Investment owns and controls (and appoints all the directors
of) our general partner, which owns a non-economic general partner interest in us and the incentive distribution rights.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its
affiliates in connection with the conversion, ongoing operation and any liquidation of us.
Conversion of Antero Resources Midstream LLC to Antero Midstream Partners LP
The aggregate consideration received by
our general partner in connection with
the conversion of its special
membership interest pursuant to the
limited liability company agreement of
Antero Resources Midstream LLC
The aggregate consideration received by
Antero in connection with the
conversion of its common economic
interest pursuant to the limited liability
company agreement of Antero
Resources Midstream LLC
• the non-economic general partner interest; and
• the incentive distribution rights.
• 35,940,957 common units;
• 75,940,957 subordinated units;
• a distribution of $332.5 million to reimburse it for certain capital
expenditures it incurred in connection with the Predecessor prior to
Midstream Operating being contributed to us;
• our assumption of $510 million of indebtedness incurred in connection
with the Predecessor prior to Midstream Operating being contributed
to us; and
• we will also undertake a public or private offering of common units in
the future upon request by Antero and use the proceeds thereof (net of
underwriting or placement agency discounts and commissions, as
applicable) to redeem an equal number of common units from Antero
as a distribution to reimburse Antero for certain capital expenditures
incurred in connection with the Predecessor prior to Midstream
Operating being contributed to us.
Option units or proceeds from option
In connection with the completion of the IPO, the underwriters exercises
units
Operational Stage
Distributions of cash available for
distribution to our general partner and
its affiliates
their option to purchase additional common units. We used the net
proceeds resulting from the issuance of 6,000,000 common units upon
such exercise to acquire an equivalent number of common units from
Antero, which common units were cancelled, to reimburse Antero for
capital expenditures incurred in connection with the Predecessor prior to
Midstream Operating being contributed to us.
We will generally make cash distributions 100% to our unitholders,
including affiliates of our general partner. In addition, if distributions
exceed the minimum quarterly distribution and other higher target
distribution levels, our general partner will be entitled to increasing
percentages of the distributions, up to 50% of the distributions above the
highest target distribution level.
78
Assuming we have sufficient cash available for distribution to pay the full
minimum quarterly distribution on all of our outstanding common units
and subordinated units for four quarters, our general partner and its
affiliates (including Antero) would receive an annual distribution of
approximately $76.1 million on their units.
Antero provides customary management and general administrative
services to us. Our general partner reimburses Antero at cost for its direct
expenses incurred on behalf of us and a proportionate amount of its
indirect expenses incurred on behalf of us, including, but not limited to,
compensation expenses. Our general partner does not receive a
management fee or other compensation for its management of our
partnership, but we reimburse our general partner and its affiliates for all
direct and indirect expenses they incur and payments they make on our
behalf, including payments made to Antero for customary management
and general administrative services. Our partnership agreement does not
set a limit on the amount of expenses for which our general partner and
its affiliates may be reimbursed. These expenses include salary, bonus,
incentive compensation and other amounts paid to persons who perform
services for us or on our behalf and expenses allocated to our general
partner by its affiliates. Our partnership agreement provides that our
general partner will determine the expenses that are allocable to us.
If our general partner withdraws or is removed, its non-economic general
partner interest and its incentive distribution rights will either be sold to
the new general partner for cash or converted into common units, in each
case for an amount equal to the fair market value of those interests.
Please read “The Partnership Agreement—Withdrawal or Removal of
Our General Partner.”
Upon our liquidation, the partners, including our general partner,will be
entitled to receive liquidating distributions according to their respective
capital account balances.
Payments to our general partner and its
affiliates
Withdrawal or removal of our general
partner
Liquidation Stage
Liquidation
Agreements with Antero
In connection with our IPO, we entered into certain agreements with Antero, as described in more detail below.
Registration Rights Agreement
Pursuant to the registration rights agreement, we may be required to register the sale of Antero’s (i) common
units issued (or issuable) to it pursuant to the contribution agreement, (ii) subordinated units and (iii) common units
issuable upon conversion of subordinated units pursuant to the terms of the partnership agreement (together, the
“Registrable Securities”) in certain circumstances.
Demand Registration Rights
Antero has the right to require us by written notice to register the sale of a number of their Registrable
Securities in an underwritten offering. We are required to provide notice of the request within 10 days following the
receipt of such demand request to all additional holders of Registrable Securities, if any, who may, in certain
circumstances, participate in the registration. We are not obligated to effect any demand registration in which the
anticipated aggregate offering price included in such offering is less than $50,000,000. Once we are eligible to effect a
registration on Form S-3, any such demand registration may be for a shelf registration statement.
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Piggy-back Registration Rights
If, at any time, we propose to register an offering of our securities (subject to certain exceptions) for our own
account, then we must give to Antero securities to allow it to include a specified number of Registrable Securities in that
registration statement.
Redemptive Offerings
We may be required pursuant to the registration rights agreement to undertake a future public or private offering
and use the proceeds (net of underwriting or placement agency discounts, fees and commissions, as applicable) to
redeem an equal number of common units from Antero.
Conditions and Limitations; Expenses
The registration rights are subject to certain conditions and limitations, including the right of the underwriters to
limit the number of Registrable Securities to be included in a registration and our right to delay or withdraw a
registration statement under certain circumstances. We will generally pay all registration expenses in connection with our
obligations under the registration rights agreement, regardless of whether a registration statement is filed or becomes
effective. The obligations to register Registrable Securities under the registration rights agreement will terminate when
no Registrable Securities remain outstanding. Registrable Securities shall cease to be covered by the registration rights
agreement when they have (i) been sold pursuant to an effective registration statement under the Securities Act, (ii) been
sold in a transaction exempt from registration under the Securities Act (including transactions pursuant to Rule 144),
(iii) ceased to be outstanding, (iv) been sold in a private transaction in which Antero’s rights under the registration rights
agreement are not assigned to the transferee or (v) become eligible for resale pursuant to Rule 144(b) (or any similar rule
then in effect under the Securities Act).
Services Agreement
Pursuant to the services agreement, Antero has agreed to provide customary operational and management
services for us in exchange for reimbursement of its direct expenses and an allocation of its indirect expenses attributable
to the provision of such services to us. For the year ended December 31, 2014, we incurred $15.5 million of operating
and maintenance expenses and $22.0 million of general and administrative expenses. To the extent that these expenses
are incurred by Antero on our behalf, we would reimburse Antero for such expenses under the services agreement.
Gathering and Compression
Pursuant to our 20-year gas gathering and compression agreement with Antero, Antero has agreed to dedicate
all of its current and future acreage in West Virginia, Ohio and Pennsylvania to us (other than the existing third-party
commitments), so long as such production is not otherwise subject to a pre-existing dedication to third-party gathering
systems. Antero’s production subject to a pre-existing dedication will be dedicated to us at the expiration of such
pre-existing dedication. In addition, if Antero acquires any gathering facilities, it is required to offer such gathering
facilities to us at its cost.
Under the gathering and compression agreement, we receive a low pressure gathering fee of $0.30 per Mcf, a
high pressure gathering fee of $0.18 per Mcf, a compression fee of $0.18 per Mcf, and a condensate gathering fee of
$4.00 per Bbl, in each case subject to CPI-based adjustments. If and to the extent Antero requests that we construct new
high pressure lines and compressor stations requested by Antero, the gathering and compression agreement contains
minimum volume commitments that require Antero to utilize or pay for 75% and 70%, respectively, of the capacity of
such new construction. Additional high pressure lines and compressor stations installed on our own initiative are not
subject to such volume commitments. These minimum volume commitments on new infrastructure, as well as price
adjustment mechanisms, are intended to support the stability of our cash flows.
We also have an option to gather and compress natural gas produced by Antero on any acreage it acquires in the
future outside of West Virginia, Ohio and Pennsylvania on the same terms and conditions. In the event that we do not
80
exercise this option, Antero will be entitled to obtain gathering and compression services and dedicate production from
limited areas to such third-party agreements from third parties.
In return for Antero’s acreage dedication, we have agreed to gather, compress, dehydrate and redeliver all of
Antero’s dedicated natural gas on a firm commitment, first-priority basis. We may perform all services under the
gathering and compression agreement or we may perform such services through third parties. In the event that we do not
perform our obligations under the gathering and compression agreement, Antero will be entitled to certain rights and
procedural remedies thereunder.
Pursuant to the gathering and compression agreement, we have also agreed to build to and connect all of
Antero’s wells producing dedicated natural gas, subject to certain exceptions, upon 180 days’ notice by Antero. In the
event of late connections, Antero’s natural gas will temporarily not be subject to the dedication. We are entitled to
compensation under the gathering and compression agreement for capital costs incurred if a well does not commence
production within 30 days following the target completion date for the well set forth in the notice from Antero.
We have agreed to install compressor stations at Antero’s direction, but will not be responsible for inlet
pressures or for pressuring natural gas to enter downstream facilities if Antero has not directed us to install sufficient
compression. Additionally, we will provide high pressure gathering pursuant to the gathering and compression
agreement.
Upon completion of the initial 20-year term, the gathering and compression agreement will continue in effect
from year to year until such time as the agreement is terminated, effective upon an anniversary of the effective date of
the agreement, by either us or Antero on or before the 180th day prior to the anniversary of such effective date.
Fresh Water Distribution
In addition to the gathering and compression agreement, Antero has also granted us an option for a period of
two years to purchase its fresh water distribution systems at fair market value, with a right of first offer thereafter. Antero
owns 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. As of December 31, 2014, Antero
expanded its fresh water distribution system to include 103 miles and 49 miles of buried water pipelines in the Marcellus
and Utica operating areas, respectively, as well as 22 and 8 fresh water storage impoundments, respectively.
If we elect to exercise the option, we must provide written notice to Antero stating our intention to exercise.
Within 30 days after we deliver an exercise notice, Antero must propose to us, in writing, a purchase price for the fresh
water distribution systems. The conflicts committee of our general partner will determine, with the assistance of
independent advisors, whether to accept the proposed purchase price. If we cannot agree with Antero on a mutually
acceptable purchase price after good faith negotiations by both parties, Antero will nominate three investment banking
firms and we will select one of those firms to determine the fair market value of the fresh water distribution systems.
Once the selected investment bank submits its valuation, we will have the right, but not the obligation, to purchase the
fresh water distribution systems at the price determined by the investment bank. Our exercise of the option will require
the approval of the conflicts committee of the board of directors of our general partner. We will have the option to pay
the purchase price using our common units, which will be valued at a 5% discount to the volume-weighted average price
of our common units during the ten trading days prior to the date of the agreement pursuant to which we would acquire
the fresh water distribution systems. Following the term of the option, if the option is not exercised, we will have a right
of first offer to acquire the fresh water gathering systems if Antero ever decides to dispose of such systems.
If we purchase Antero’s fresh water distribution systems, we will enter into a 20-year fresh water distribution
agreement with Antero, pursuant to which a service area encompassing all of Antero’s areas of operation in West
Virginia, Ohio and Pennsylvania will be dedicated to us. If Antero requires fresh water distribution services outside of
the initial service area, we will have the option to provide those services on the same terms and conditions. In the event
we do not exercise this option, Antero will be entitled to obtain proposals for fresh water distribution from third parties.
81
We will then have the right to match any proposal received by Antero from a third-party. Under the fresh water
distribution agreement, we will receive a fee of $3.50 per barrel for fresh water deliveries to well sites by pipe or $3.00
per barrel if Antero accesses the water by truck directly from our fresh water storage facilities, in each case subject to
CPI-based adjustments. Similar to the gathering and compression agreement, the price adjustment mechanisms in the
fresh water distribution agreement will be intended to support the stability of our cash flows. In addition, if Antero
acquires any facilities for providing water for hydraulic fracturing, it will be required to offer such facilities to us at its
cost.
The water pipeline system by which we would distribute fresh water includes facilities for receiving fresh water
at designated sources. Pursuant to the fresh water distribution agreement, we transport and store such fresh water at
specific areas of operation. The water pipeline system also includes permanent and temporary water lines for delivering
Antero’s fresh water from the transportation system to its well sites for hydraulic fracturing operations.
In return for Antero’s acreage dedication, we will agree to receive Antero’s fresh water and deliver such fresh
water to the water pipeline system storage facilities or to particular well sites for hydraulic fracturing up to the available
capacity of the water pipeline system. Antero will retain the risk of acquiring water in sufficient quantities. We may
perform all services under the fresh water distribution agreement or we may perform such services through third parties.
In the event that we do not perform our obligations under the fresh water distribution agreement, Antero will be entitled
to certain rights and procedural remedies thereunder.
We will have the right to use excess water pipeline system capacity and water from Antero’s fresh water
sources to provide to third parties, provided that we pay the cost, if any, of such excess water.
Further, we will be required to build out and expand the water pipeline system in order to deliver fresh water to
all of Antero’s wells being drilled, subject to certain exceptions. We will be obligated to connect the water system and
commence water deliveries to particular wells with the central portions of the initial service area upon 180 days’ notice
from Antero. Our obligation to connect and commence water deliveries in the outlying areas of the initial service area
will be phased in over time, but the 180-day notice period will eventually become applicable to all areas in the initial
service area. If we do not connect to a particular well for water deliveries, Antero may transport water from our water
storage sites for delivery to its well sites.
Upon completion of the initial 20-year term, the fresh water distribution agreement will continue in effect from
year to year until such time as the agreement is terminated, effective upon an anniversary of the effective date of the
agreement, by either us or Antero on or before the 180th day prior to the anniversary of such effective date.
Processing
Although we do not currently have any processing or NGLs fractionation, transportation or marketing
infrastructure, we have entered into a right-of-first-offer agreement with Antero for gas processing services, pursuant to
which Antero has agreed, subject to certain exceptions, not to procure any gas processing or NGLs fractionation,
transportation or marketing services with respect to its production (other than production subject to a pre-existing
dedication) without first offering us the right to provide such services.
Antero’s request for offer will describe the production that will be dedicated under the resulting agreement and
the capacities of the facilities it desires and, if applicable, details of the facility Antero has acquired or proposes to
acquire. Antero is permitted concurrently to seek offers from third parties for the same services on the same terms and
conditions, but we have a right to match the fees offered by any third-party. Antero will only be permitted to obtain these
services from third parties if we either do not make an offer or do not match a competing third-party offer. The process
could result in Antero obtaining certain of the required services from us (for example, gas processing) and certain of such
services (for example, NGLs fractionation and related services) from a third-party. Our right of first offer does not apply
to production that is subject to a pre-existing dedication. The right of first offer agreement has a 20-year term.
Pursuant to the procedures provided for in the right of first offer agreement, if our offer prevails, Antero will
enter into a gas processing agreement or other appropriate services agreement with us and, if applicable, transfer the
82
acquired facility to us for the price for which Antero acquired it. Relevant production will be dedicated under such
agreement. We will provide the relevant services for the offered fees, subject to price adjustments based on the consumer
price index, or CPI, and Antero will be obligated to deliver minimum daily volumes or pay fees for any deficiencies in
deliveries. We may perform all services under the gas processing or other services agreement or may perform such
services through third parties. In the event that we do not perform our obligations under the agreement, Antero will be
entitled to certain rights and procedural remedies thereunder.
If pursuant to the foregoing procedures Antero enters into a gas processing agreement with us, we will agree to
construct or cause to be constructed a processing plant to process the dedicated natural gas, except to the extent rendered
unnecessary if Antero is transferring an acquired facility to us. If Antero requires additional capacity in the future at the
plant at which we are providing the services, we will have the option to provide such additional capacity on the same
terms and conditions. In the event that we do not exercise this option, Antero will be entitled to obtain proposals from
third parties to process such production.
License
Pursuant to a license agreement with Antero, we will have the right to use certain Antero-related names and
trademarks in connection with our operation of the midstream business.
Procedures for Review, Approval and Ratification of Transactions with Related Persons
The board has adopted a written code of business conduct and ethics, under which a director would be expected
to bring to the attention of our chief executive officer or the board any conflict or potential conflict of interest that may
arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The
resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be
determined by a majority of the disinterested directors.
If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand,
and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed
by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the
discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by
the conflicts committee.
Pursuant to our code of business conduct, our general partner’s executive officers are required to avoid conflicts
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner
and its directors, officers, affiliates (including Antero) and owners, on the one hand, and us and our limited partners, on
the other hand. Conflicts may arise as a result of the duties of our general partner and its directors and officers to act for
the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. We are
managed and operated by the board of directors and officers of our general partner, Midstream Management, which is
owned by Antero Investment. All of our initial officers and a majority of our initial directors will also be officers or
directors of Antero Investment. Similarly, all of the officers and a majority of the directors of our general partner are also
officers or directors of Antero. Although our general partner has a contractual duty to manage us in a manner that it
believes is not adverse to our interests, the directors and officers of our general partner have a fiduciary duty to manage
our general partner in a manner that is beneficial to Antero Investment. Our general partner’s directors and officers who
are also directors and officers of Antero have a fiduciary duty to manage Antero in a manner that is beneficial to Antero
and its shareholders. Our partnership agreement specifically defines the remedies available to unitholders for actions
taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable
Delaware law. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements,
expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the
partnership.
83
Whenever a conflict arises between our general partner or its owners and affiliates (including Antero), on the
one hand, and us or our limited partners, on the other hand, the resolution or course of action in respect of such conflict
of interest shall be permitted and deemed approved by us and all our limited partners and shall not constitute a breach of
our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in
respect of such conflict of interest is:
•
•
approved by the conflicts committee of our general partner, although our general partner is not obligated to
seek such approval; or
approved by the holders of a majority of the outstanding common units, excluding any such units owned by
our general partner or any of its affiliates.
Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from
the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as
described above. If our general partner does not seek approval from the conflicts committee or from holders of common
units as described above and the board of directors of our general partner approves the resolution or course of action
taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors
of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders,
the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving
that such decision was not in good faith. Unless the resolution of a conflict is specifically provided for in our partnership
agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our
general partner may consider any factors they determine in good faith to consider when resolving a conflict. An
independent third party is not required to evaluate the resolution. Under our partnership agreement, a determination,
other action or failure to act by our general partner, the board of directors of our general partner or any committee thereof
(including the conflicts committee) will be deemed to be “in good faith” unless our general partner, the board of directors
of our general partner or any committee thereof (including the conflicts committee) believed such determination, other
action or failure to act was adverse to the interest of the partnership. Please read “Management—Committees of the
Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board
of directors.
Director Independence
Rather than adopting categorical standards, the Board assesses director independence on a case-by-case basis, in
each case consistent with applicable legal requirements and the listing standards of the NYSE. After reviewing all
relationships each director has with the Partnership, including the nature and extent of any business relationships
between the Partnership and each director, as well as any significant charitable contributions the Partnership makes to
organizations where its directors serve as board members or executive officers, the Board has affirmatively determined
that the following directors have no material relationships with the Partnership and are independent as defined by the
current listing standards of the NYSE: Messrs. Kagan, Keenan, Manning, Connor and Peters. Neither Mr. Rady, the
Chairman and Chief Executive Officer of our general partner, nor Mr. Warren, the President, Chief Financial Officer and
Secretary of our general partner, is considered by the Board to be an independent director because of his employment
with Antero.
84
Item 14. Principal Accountant Fees and Services
The table below sets forth the aggregate fees and expenses billed by KPMG LLP, the Partnership's independent
registered public accounting firm, for the Partnership and its Predecessor for the year ended December 31, 2014:
(in thousands)
Audit Fees ⁽¹⁾:
Audit and Quarterly Reviews
Other Filings
Subtotal
Tax Fees ⁽²⁾:
Total
For the Years Ended
December 31,
2014
$
$
242
276
518
46
564
(1) Includes audit of the Predecessor’s annual financial statements for the years ended December 31, 2012 and 2013, the audit of the
Partnership’s annual consolidated financial statements for the year ended December 31, 2014 included in this Annual Report on
form 10-K, review of the Partnership's quarterly financial statements included in its Quarterly Reports on Form 10-Q and review
of the Partnership’s other filings with the SEC, including work performed in conjunction with S-1 filings, consents and other
research work necessary to comply with generally accepted auditing standards for the years ended December 31, 2012, 2013, and
2014.
(2) Consultation on tax matters.
The charter of the Audit Committee and its pre-approval policy require that the Audit Committee review and pre-
approve the Partnership’s independent registered public accounting firm's fees for audit, audit-related, tax and other
services. The Chairman of the Audit Committee has the authority to grant pre-approvals, provided such approvals are
within the pre-approval policy and are presented to the Audit Committee at a subsequent meeting. For the year ended
December 31, 2014, the audit committee of our predecessor approved 100% of the services described above under the
captions "Audit Fees" and "Tax Fees."
85
Item 15. Exhibits and Financial Statement Schedules
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
PART IV
The consolidated financial statements are listed on the Index to Financial Statements to this report beginning on
page F-1.
(a)(3) Exhibits.
Exhibit
Number
3.1
3.2
3.3
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
Description of Exhibit
Certificate of Conversion of Antero Resources Midstream LLC, dated November 5, 2014
(incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (Commission File No.
001-36719) filed on November 7, 2014).
Certificate of Limited Partnership of Antero Midstream Partners LP, dated November 5, 2014
(incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K (Commission File No.
001-36719) filed on November 7, 2014).
Agreement of Limited Partnership, dated as of November 10, 2014, by and between Antero
Resources Midstream Management LLC, as the General Partner, and Antero Resources
Corporation, as the Organizational Limited Partner (incorporated by reference to Exhibit 3.1 to
Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014).
Amended and Restated Contribution Agreement, dated as of November 10, 2014, by and between
Antero Resources Corporation and Antero Midstream Partners LP (incorporated by reference to
Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 001-36719) filed on November
17, 2014).
Gathering and Compression Agreement, dated as of November 10, 2014, by and between Antero
Resources Corporation and Antero Midstream LLC (incorporated by reference to Exhibit 10.2 to
Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014).
Right of First Offer Agreement, dated as of November 10, 2014, by and between Antero Resources
Corporation and Antero Midstream LLC (incorporated by reference to Exhibit 10.3 to Current
Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014).
License Agreement, dated as of November 10, 2014, by and between Antero Resources Corporation
and Antero Midstream Partners LP (incorporated by reference to Exhibit 10.4 to Current Report on
Form 8-K (Commission File No. 001-36719) filed on November 17, 2014).
Registration Rights Agreement, dated as of November 10, 2014, by and among Antero Midstream
Partners LP and Antero Resources Corporation (incorporated by reference to Exhibit 10.5 to Current
Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014).
Credit Agreement, dated as of November 10, 2014, among Antero Midstream Partners LP and certain
of its subsidiaries, certain lenders party thereto, Wells Fargo Bank, National Association, as
administrative agent, l/c issuer and swingline lender and the other parties thereto (incorporated by
reference to Exhibit 10.6 to Current Report on Form 8-K (Commission File No. 001-36719) filed on
November 17, 2014).
Services Agreement, dated as of November 10, 2014, by and among Antero Midstream Partners LP
and Antero Resources Corporation (incorporated by reference to Exhibit 10.7 to Current Report on
Form 8-K (Commission File No. 001-36719) filed on November 17, 2014).
Form of Antero Midstream Partners LP Long-Term Incentive Plan (incorporated by reference to
86
10.9
21.1*
23.1*
31.1*
31.2*
32.1*
32.2*
101*
Exhibit 10.11 to Amendment No. 4 to Antero Resources Midstream LLC’s Registration Statement on
Form S-1, filed on July 11, 2014, File No. 333-193798).
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.12 to Amendment No.
4 to Antero Resources Midstream LLC’s Registration Statement on Form S-1, filed on July 11, 2014,
File No. 333-193798).
Subsidiaries of Antero Midstream Partners LP.
Consent of KPMG, LLP.
Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of
2002 (18 U.S.C. Section 7241).
Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of
2002 (18 U.S.C. Section 7241).
Certification of the Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of
2002 (18 U.S.C. Section 1350).
Certification of the Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of
2002 (18 U.S.C. Section 1350).
The following financial information from this Form 10-K of Antero Midstream Partners LP for the
year ended December 31, 2014, formatted in XBRL (eXtensible Business Reporting Language): (i)
Consolidated Balance Sheets, (ii) Consolidated Statements of Operations and Comprehensive Income
(Loss), (iii) Consolidated Statements of Equity, (iv) Consolidated Statements of Cash Flows, and (v)
Notes to the Consolidated Financial Statements, tagged as blocks of text.
The exhibits marked with the asterisk symbol (*) are filed or furnished (in the case of Exhibits 32.1 and 32.2) with this
Annual Report on Form 10-K.
87
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
ANTERO MIDSTREAM PARTNERS LP
By:
By:
ANTERO RESOURCES MIDSTREAM
MANAGEMENT LLC, its general partner
/s/ Glen C. Warren, Jr.
Glen C. Warren, Jr.
President, Chief Financial Officer and Secretary
Date: February 25, 2015
88
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the
following persons on behalf of the registrant in the capacities and on the dates indicated.
Signature
Title (Position with Antero Resources Midstream
Management LLC)
Date
/s/ PAUL M. RADY
Chairman of the Board,
Director and Chief Executive officer
Paul M. Rady
(principal executive officer)
/s/ GLEN C. WARREN, JR.
President, Director,
Chief Financial Officer and Secretary
Glen C. Warren, Jr.
(principal financial officer)
/s/ K. PHIL YOO
Chief Accounting Officer
and Corporate Controller
K. Phil Yoo
(principal accounting officer)
/s/ RICHARD W. CONNOR
Director
Richard W. Connor
/s/ W. HOWARD KEENAN,
JR.
Director
W. Howard Keenan, Jr.
/s/ PETER R. KAGAN
Peter R. Kagan
Director
/s/ DAVID A. PETERS
Director
David A. Peters
/s/ CHRISTOPHER R.
MANNING
Christopher R. Manning
Director
February 25, 2015
February 25, 2015
February 25, 2015
February 25, 2015
February 25, 2015
February 25, 2015
February 25, 2015
February 25, 2015
89
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Introductory Note to Consolidated Financial Statements
Audited Historical Consolidated Financial Statements as of December 31, 2013 and 2014 and for the
Years Ended December 31, 2012, 2013 and 2014
Reports of Independent Registered Public Accounting Firm
Balance Sheets
Statements of Operations and Comprehensive Income (Loss)
Statements of Partners’ Capital
Statements of Cash Flows
Notes to Consolidated Financial Statements
Page
F-2
F-3
F-4
F-5
F-6
F-7
F-8
F-1
Introductory Note to Consolidated Financial Statements
The information in this report includes periods prior to the completion of Antero Midstream Partners LP initial
public offering (“IPO”) on November 10, 2014. Consequently, the consolidated financial statements and related
discussion of financial condition and results of operations contained in this report include periods that pertain to the
gathering and compression assets of Antero Resources Corporation (“Antero”), our predecessor for accounting
purposes.
References in these financial statements to “Predecessor,” “we,” “our,” “us” or like terms, when referring to periods
prior to November 10, 2014, refer to Antero’s gathering and compression assets, our predecessor for accounting
purposes. References to “the Partnership,” “we,” “our,” “us” or like terms, when referring to periods since November
10, 2014 or when used in the present tense or prospectively, refer to Antero Midstream Partners LP.
F-2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Unitholders
Antero Midstream Partners LP:
We have audited the accompanying consolidated balance sheets of Antero Midstream Partners LP (“the Partnership”) and
its accounting predecessor as of December 31, 2013 and 2014 and the related consolidated statements of operations and
comprehensive income (loss), partners’ capital, and cash flows for each of the years in the three-year period ended
December 31, 2014. These consolidated financial statements are the responsibility of the Partnership’s management. Our
responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of Antero Midstream Partners LP and its accounting predecessor as of December 31, 2013 and 2014, and the
results of their operations and their cash flows for the years then ended in conformity with U.S. generally accepted
accounting principles.
/s/ KPMG LLP
Denver, Colorado
February 25, 2015
F-3
ANTERO MIDSTREAM PARTNERS LP
Consolidated Balance Sheets
December 31, 2013, and 2014
(In thousands, except unit counts)
Assets
Current assets:
Cash and cash equivalents
Accounts receivable–affiliate
Prepaid
Total current assets
Property and equipment:
Gathering and compressions systems
Less accumulated depreciation
Property and equipment, net
Other assets, net
Total assets
Current liabilities:
Accounts payable
Accounts payable–affiliate
Accrued capital expenditures
Accrued liabilities
Other current liabilities
Total current liabilities
Long-term liabilities
Other
Total liabilities
Liabilities and Partners' capital
Commitments and contingencies (Note 8)
Partners' capital:
Common unitholders - public (46,000,000 units issued and outstanding)
Common unitholder - Antero (29,940,957 units issued and outstanding)
Subordinated unitholder - Antero (75,940,957 units issued and outstanding)
Total partners' capital
Parent net investment
Total capital
Total liabilities and partners' capital
See accompanying notes to consolidated financial statements.
2013
2014
$
— $
3,032
—
3,032
230,192
17,646
518
248,356
$
$
580,800
(14,324)
566,476
8,581
1,180,707
(51,110)
1,129,597
17,168
578,089 $ 1,395,121
5,804 $
—
33,343
648
910
40,705
4,864
45,569
8,728
1,380
37,208
5,346
—
52,662
—
52,662
1,090,037
—
71,665
—
180,757
—
1,342,459
—
—
532,520
532,520
1,342,459
578,089 $ 1,395,121
$
F-4
ANTERO MIDSTREAM PARTNERS LP
Consolidated Statements of Operations and Comprehensive Income (Loss)
Years Ended December 31, 2012, 2013, and 2014
(In thousands, except unit counts and per unit amounts)
Year ended
December 31,
2013
2014
2012
$
647 $
22,363 $
95,746
652
2,079
15,470
2,894
1,679
5,225
(4,578)
8
(4,586) $
23,124
11,346
36,549
(14,186)
146
(14,332) $
$
$
$
22,035
36,789
74,294
21,452
4,620
16,832
7,422
—
7,422
0.05
0.05
46,000,000
29,940,957
75,940,957
Revenue–affiliate
Operating expenses:
Direct operating
General and administrative (including $15,931 and $8,619 of equity-
based compensation in 2013 and 2014, respectively)
Depreciation
Total operating expenses
Operating income (loss)
Interest expense
Net income (loss) and comprehensive income (loss)
$
Net income attributable to Antero Midstream Partners LP
subsequent to IPO
Less: General partner's interest in net income subsequent to
IPO
Limited partners' interest in net income subsequent to IPO
Net income attributable to Antero Midstream Partners LP
subsequent to IPO per limited partner unit (basic and diluted)
Common units
Subordinated units
Weighted average number of limited partner units outstanding
(basic and diluted):
Common units–public
Common units–Antero
Subordinated units–Antero
See accompanying notes to consolidated financial statements.
F-5
Parent Net
Investment
— $
29,002 $
(4,586)
118,446
— 142,862
(14,332)
—
388,059
—
15,931
—
532,520
—
9,410
—
29,764
—
6,351
—
578,045
—
— (578,045)
—
—
—
—
— $
Total
29,002
(4,586)
118,446
142,862
(14,332)
388,059
15,931
532,520
9,410
29,764
6,351
578,045
—
— 1,087,224
(332,500)
—
7,422
—
2,268
—
$ 1,342,459
—
ANTERO MIDSTREAM PARTNERS LP
Consolidated Statements of Partners’ Capital
Years Ended December 31, 2012, 2013, and 2014
(In thousands)
Partnership
Common
Unitholders
Public
Common
Unitholder
Antero
Subordinated
Unitholder
Antero
General
Partner
Antero
Balance at December 31, 2011
Net loss and comprehensive loss
Deemed contribution from parent, net
Balance at December 31, 2012
Net loss and comprehensive loss
Deemed contribution from parent, net
Equity-based compensation
Balance at December 31, 2013
Net income and comprehensive income
Deemed contribution from parent, net
Equity-based compensation
Balance at November 10, 2014 (prior to IPO)
Allocation of net investment to unitholders
Net proceeds from IPO
Distribution to Antero
Net income and comprehensive income
Equity-based compensation
Balance at December 31, 2014
$
— $
— $
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 163,458
—
— (94,023)
1,463
767
1,087,224
2,248
565
—
—
—
—
—
—
—
—
—
414,587
—
(238,477)
3,711
936
$ 1,090,037 $ 71,665 $ 180,757 $
See accompanying notes to consolidated financial statements.
F-6
ANTERO MIDSTREAM PARTNERS LP
Consolidated Statements of Cash Flows
Years Ended December 31, 2012, 2013, and 2014
(In thousands)
Cash flows provided by (used in) operating activities:
Net income (loss)
Adjustment to reconcile net income (loss) to net cash provided by operating
activities:
Depreciation
Equity-based compensation
Amortization of deferred financing costs
Changes in assets and liabilities:
Accounts receivable–affiliate
Prepaid
Accounts payable
Accounts payable–affiliate
Accrued liabilities
Net cash provided by (used in) operating activities
Cash flows used in investing activities:
Additions to property and equipment
Change in working capital of affiliate related to property and equipment
Change in other assets
Net cash used in investing activities
Cash flows provided by financing activities:
Deemed contribution from parent, net
Net proceeds from initial public offering
Distribution to Antero
Borrowings on bank credit facility
Repayments on bank credit facility
Payments of deferred financing costs
Payments on capital lease obligations
Net cash provided by financing activities
Net increase in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
Supplemental disclosure of cash flow information:
Cash paid during the period for interest
2012
2013
2014
$
(4,586) $ (14,332) $
16,832
1,679
—
—
(126)
—
—
—
(119)
(3,152)
11,346
15,931
—
(2,873)
—
—
—
541
10,613
36,789
8,619
135
(19,465)
(518)
738
1,059
4,698
48,887
(115,267)
—
—
(115,267)
(389,340)
—
(8,581)
(397,921)
(553,582)
(40,277)
(3,530)
(597,389)
118,446
—
—
—
—
—
(27)
118,419
—
—
— $
29,764
388,059
1,087,224
—
(332,500)
—
510,000
—
(510,000)
—
(4,871)
—
(923)
(751)
778,694
387,308
230,192
—
—
—
— $ 230,192
8 $
146 $
4,485
$
$
Supplemental disclosure of noncash investing activities:
Increase in accrued capital expenditures and accounts payable for property
and equipment
$ 27,721 $
9,003 $
46,327
See accompanying notes to consolidated financial statements.
F-7
ANTERO MIDSTREAM PARTNERS LP
Notes to Consolidated Financial Statements
Years Ended December 31, 2012, 2013, and 2014
(1) Organization
(a) Organization
Antero Midstream Partners LP (the “Partnership”) is a growth-oriented limited partnership formed by
Antero Resources Corporation (“Antero”) to own, operate and develop midstream assets to service Antero’s natural
gas and oil and condensate production. On November 10, 2014, the Partnership completed its initial public offering
(the “IPO”) of 46,000,000 common units representing limited partnership interests at a price of $25.00 per common
unit. The Partnership was 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
substantially all of its high and low pressure gathering and compression assets to Antero Midstream LLC
(“Midstream Operating”), and the equity interests of Midstream Operating were contributed to the Partnership.
Our consolidated financial statements as of December 31, 2014, include the accounts of Antero Midstream
Partners LP and Antero Midstream LLC.
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 the Partnership from the IPO were approximately $1.1 billion, after deducting
underwriting discounts, structuring fees and expenses. The Partnership 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.
(b) Description of the Business
Our assets consist of 8-, 12-, 16-, and 20-inch high and low pressure gathering pipelines and compressor
stations that collect natural gas and oil and condensate from Antero’s wells in the Marcellus Shale in West Virginia
and the Utica Shale in Ohio.
We have agreements with Antero pursuant to which we will provide gathering and compression services
for a 20 year period and a services agreement whereby Antero provides operational and management services to us.
See Note 3—Transactions with Affiliates.
(2) Summary of Significant Accounting Policies
(a) Basis of Presentation
Our consolidated financial statements have been prepared in accordance with accounting principles
generally accepted in the United States (“GAAP”). In the opinion of management, the accompanying consolidated
financial statements include all adjustments considered necessary to present fairly our financial position as of
December 31, 2013 and 2014, and the results of our operations and our cash flows for the years ended December 31,
2012, 2013, and 2014. We have no items of other comprehensive income or loss; therefore, net income or loss is
identical to comprehensive income or loss.
The accompanying consolidated financial statements represent the assets, liabilities, and results of
F-8
ANTERO MIDSTREAM PARTNERS LP
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2012, 2013, and 2014
operations of Antero’s gathering and compression assets as the accounting predecessor (the “Predecessor”) to the
Partnership, presented on a carve-out basis of Antero’s historical ownership of the Predecessor. The Predecessor
financial statements have been prepared from the separate records maintained by Antero and may not necessarily be
indicative of the actual results of operations that might have occurred if the Predecessor had been operated
separately during the periods reported. The parent net investment in the Predecessor is shown as parent net equity.
Our costs of doing business incurred by Antero on our behalf have been reflected in the accompanying
consolidated financial statements. These costs include general and administrative expenses allocated by Antero to us
in exchange for:
•
•
•
business services, such as payroll, accounts payable and facilities management;
corporate services, such as finance and accounting, legal, human resources, investor relations and
public and regulatory policy; and
employee compensation, including equity-based compensation.
Transactions between us and Antero have been identified in the consolidated financial statements as
transactions between affiliates (see Note 3).
As of the date these consolidated financial statements were filed with the Securities and Exchange
Commission, the Partnership completed its evaluation of potential subsequent events for disclosure and no items
requiring disclosure were identified, except on February 2, 2015 we declared a cash distribution of $0.0943 per unit,
as described in Note 6—Partnership Equity and Distributions, and Note 7—Net Income Per Limited Partner Unit.
(b) Revenue Recognition
We provide gathering and compression services under fee-based contracts based on throughput. Under
these arrangements, we receive a fee or fees for gathering oil and gas products and compression services. The
revenue we earn from these arrangements is directly related to (1) in the case of natural gas gathering and
compression, the volumes of metered natural gas that we gather, compress and deliver to natural gas compression
sites or other transmission delivery points or (2) in the case of oil and condensate gathering, the volumes of metered
oil and condensate that we gather and deliver to other transmission delivery points. We recognize revenue when all
of the following criteria are met: (1) services have been rendered, (2) the prices are fixed or determinable, and
(3) collectability is reasonable assured.
(c) Use of Estimates
The preparation of the consolidated financial statements and notes in conformity with GAAP requires that
management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the
disclosure of contingent assets and liabilities. Items subject to estimates and assumptions include the useful lives of
property and equipment, valuation of accrued liabilities, and obligations related to employee benefits, among others.
Although management believes these estimates are reasonable, actual results could differ from these estimates.
(d) Cash and Cash Equivalents
Historically, the majority of the Predecessor’s operations were funded by Antero and managed under
Antero’s cash management program. Net amounts funded by Antero are reflected as net contributions from or
F-9
ANTERO MIDSTREAM PARTNERS LP
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2012, 2013, and 2014
distributions to parent on the accompanying Statements of Partners’ Capital and Cash Flows.
We consider all liquid investments purchased with an initial maturity of three months or less to be cash
equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of
these instruments.
(e) Property and Equipment
Property and equipment primarily consists of gathering pipelines and compressor stations and are stated at
the lower of historical cost less accumulated depreciation, or fair value, if impaired. We capitalize
construction-related direct labor and material costs. Maintenance and repair costs are expensed as incurred.
Depreciation is computed over the asset’s estimated useful life using the straight-line method, based on
estimated useful lives and salvage values of assets. Gathering pipelines and compressor stations are depreciated over
a 20 year useful life. The depreciation of fixed assets recorded under capital lease agreements is included in
depreciation expense. Uncertainties that may impact these estimates include, among others, changes in laws and
regulations relating to environmental matters, including air and water quality, restoration and abandonment
requirements, economic conditions and supply and demand in the area. When assets are placed into service,
management makes estimates with respect to useful lives and salvage values that management believes are
reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation
amounts.
Property and equipment included assets under construction of $211 million and $318 million at
December 31, 2013 and 2014, respectively.
(f) Impairment of Long-Lived Assets
We evaluate the ability to recover the carrying amount of long-lived assets and determine whether such
long-lived assets have been impaired. Impairment exists when the carrying amount of an asset exceeds estimates of
the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative
courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future
undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying
amount of the long-lived asset is not recoverable, based on the estimated future undiscounted cash flows, the
impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the
asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense.
Fair value represents the estimated price between market participants to sell an asset in the principal or
most advantageous market for the asset, based on assumptions a market participant would make. When warranted,
management assesses the fair value of long-lived assets using commonly accepted techniques and may use more
than one source in making such assessments. Sources used to determine fair value include, but are not limited to,
recent third party comparable sales, internally developed discounted cash flow analyses and analyses from outside
advisors. Significant changes, such as changes in contract rates or terms, the condition of an asset, or management’s
intent to utilize the asset, generally require management to reassess the cash flows related to long-lived assets. A
reduction of carrying value of fixed assets would represent a Level 3 fair value measure under GAAP. No
impairments for such assets have been recorded through December 31, 2014.
F-10
ANTERO MIDSTREAM PARTNERS LP
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2012, 2013, and 2014
(g) Asset Retirement Obligations
Certain of our assets have an indeterminate life. There is no requirement to record the fair value of the
retirement obligations associated with such assets. These assets include our gathering pipelines and compressor
stations. A liability for these asset retirement obligations will be recorded only if and when a future retirement
obligation with a determinable life can be estimated. These assets have an indeterminate life because they will
operate for an indeterminate period when properly maintained. As such, we are not able to make a reasonable
estimate of when future dismantlement and removal dates of such assets will occur and therefore have not recorded
asset retirement obligations at December 31, 2013 or 2014.
(h) Litigation and Other Contingencies
An accrual is recorded for a loss contingency when its occurrence is probable and damages can be
reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of
possible outcomes. We regularly review contingencies to determine the adequacy of our accruals and related
disclosures. The amount of ultimate loss may differ from these estimates.
We accrue losses associated with environmental obligations when such losses are probable and can be
reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time the
remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as
additional information becomes available or as circumstances change. Future environmental expenditures are not
discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as
assets at their undiscounted value when receipt of such recoveries is probable.
We have not recorded any accruals for loss contingencies or environmental obligations at December 31,
2013 or 2014.
(i) Equity-Based Compensation
Our financial statements reflect various equity-based compensation awards granted by Antero, as well as
compensation expense associated with our own plans. These awards include profits interests awards, restricted
stock, stock options, restricted units, and phantom units. For purposes of these consolidated financial statements, we
recognized as expense in each period the required allocation from Antero, with the offset included in parent net
investment. See Note 3—Transactions with Affiliates.
In connection with the IPO, our general partner adopted the Antero Midstream Partners LP Long-Term
Incentive Plan (“Midstream LTIP”), pursuant to which certain non-employee directors of our general partner and
certain officers, employees and consultants of our general partner and its affiliates are eligible to receive awards. An
aggregate of 10,000,000 common units may be delivered pursuant to awards under the Midstream LTIP, subject to
customary adjustments. On November 12, 2014, we granted approximately 20,000 restricted units and 2,361,440
phantom units under the Midstream LTIP. For accounting purposes, these units are treated as if they are distributed
from us to Antero. Antero recognizes compensation expense for the units awarded to its employees and a portion of
that expense is allocated to us. See Note 5—Equity-based Compensation.
(j) Income Taxes
Our consolidated financial statements do not include income tax as we are treated as a partnership for
federal and state income tax purposes, with each partner being separately taxed on its share of the taxable income.
F-11
ANTERO MIDSTREAM PARTNERS LP
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2012, 2013, and 2014
(k) Fair Value Measures
The Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification Topic 820,
Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for
measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all
nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial
recognition of asset retirement obligations and impairments of long-lived assets). The fair value is the price that we
estimate would be received to sell an asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date. A fair value hierarchy is used to prioritize input to valuation techniques used to
estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy
based on the lowest level of input that is significant to the fair value measurement. Our assessment of the
significance of a particular input to the fair value measurement in its entirety requires judgment and considers
factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in
active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs.
Level 2 inputs are data, other than quoted prices included within Level 1 that are observable for the asset or liability,
either directly or indirectly.
The carrying values on our balance sheet of our cash and cash equivalents, accounts receivable—affiliate,
prepaid, other assets, accounts payable, accounts payable—affiliate, accrued liabilities, accrued capital expenditures,
and the revolving credit facility approximate fair values due to their short maturities.
(3) Transactions with Affiliates
(a) Revenues
All revenues during the year ended December 31, 2012, 2013, and 2014 were earned from Antero.
(b) Accounts receivable—affiliate, and Accounts payable—affiliate
Accounts receivable—affiliate represents amounts due from Antero, primarily related to gathering and
compression services and other costs. Accounts payable—affiliate represents amounts due to Antero for general and
administrative and other costs.
(c) Accounts Payable, Accrued Expenses, and Accrued Capital Expenditures
All accounts payable, accrued liabilities and accrued capital expenditures balances are due to unaffiliated
parties. Prior to the IPO, all operating and capital expenditures were funded through capital contributions from
Antero and borrowings under its midstream credit facility. See Note 4 – Long-term Debt. These balances were
managed and paid under Antero’s cash management program. Following the IPO, we maintain our own bank
accounts and sources of liquidity and continue to utilize Antero's cash management expertise.
(d) Allocation of Costs
The employees supporting our operations are employees of Antero. Direct operating expenses related to
employees who support our operations are included in direct operating expense. Direct operating expense includes
direct labor expenses from Antero of $1.5 million for the year ended December 31, 2014. General and
administrative expense charged or allocated to us was $2.9 million, $23.1 million and $22.0 million during the year
F-12
ANTERO MIDSTREAM PARTNERS LP
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2012, 2013, and 2014
ended December 31, 2012, 2013 and 2014, respectively. These costs relate to: (i) various business services,
including payroll processing, accounts payable processing and facilities management, (ii) various corporate services,
including legal, accounting, treasury, information technology and human resources and (iii) compensation, including
equity-based compensation. These expenses are charged or allocated to us based on the nature of the expenses and
are allocated based on a combination of our proportionate share of Antero’s gross property and equipment, capital
expenditures and direct labor costs, as applicable.
Our general and administrative expenses include equity-based compensation costs allocated by Antero. See
Note 5—Equity-based Compensation for more information.
(e) Agreements
The Partnership has entered into various agreements with Antero, as summarized below.
Gathering and Compression
Pursuant to our 20-year gathering and compression agreement, Antero has agreed to dedicate all of its
current and future acreage in West Virginia, Ohio and Pennsylvania to us (other than the existing third-party
commitments). We also have an option to gather and compress natural gas produced by Antero on any acreage it
acquires in the future outside of West Virginia, Ohio and Pennsylvania on the same terms and conditions. Under the
gathering and compression agreement, we receive a low pressure gathering fee of $0.30 per Mcf, a high pressure
gathering fee of $0.18 per Mcf, a compression fee of $0.18 per Mcf, and a condensate gathering fee of $4.00 per
Bbl, in each case subject to CPI-based adjustments. If and to the extent Antero requests that we construct new high
pressure lines and compressor stations, the gathering and compression agreement contains minimum volume
commitments that require Antero to utilize or pay for 75% and 70%, respectively, of the capacity of such new
construction. Additional high pressure lines and compressor stations installed on our own initiative are not subject to
such volume commitments. These minimum volume commitments on new infrastructure are intended to support the
stability of our cash flows.
Services Agreement
Upon the closing of the IPO, we entered into a services agreement with Antero, pursuant to which Antero
agrees to provide customary operational and management services for us in exchange for reimbursement of its direct
expenses and an allocation of its indirect expenses attributable to the provision of such services to us. To the extent
that these expenses are incurred by Antero on our behalf, we reimburse Antero for such expenses under the services
agreement.
(4) Long-term Debt
(a) Midstream Credit Facility
Prior to the IPO on November 10, 2014, long-term debt represented amounts outstanding under a credit
facility agreement between Midstream Operating, then a wholly owned subsidiary of Antero and now a wholly
owned subsidiary of the Partnership, and the lenders under Antero’s credit facility that were incurred for the
acquisition of the Predecessor’s gathering and compression assets (the “midstream credit facility”). The facilities
were ratably secured by mortgages on substantially all of Antero’s and Midstream Operating’s properties and
guarantees from Antero and its restricted subsidiaries. Commitments under this facility were allocated from the
borrowing base and commitment levels under the Antero facility. Interest on the facility was payable at a variable
F-13
ANTERO MIDSTREAM PARTNERS LP
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2012, 2013, and 2014
rate based on LIBOR plus a margin ranging from 1.50% to 2.50% or the prime rate plus a margin ranging from
0.50% to 1.50%, based on an election at the time of borrowing and on the borrowing base usage. Commitment fees
on the unused portion of the credit facility were due quarterly at rates from 0.375% to 0.50% of the unused facility.
On November 10, 2014, in connection with the completion of the IPO, the outstanding balance of $510
million that related to gathering and compression assets was repaid out of the proceeds of the IPO, and this facility
was assumed by Antero.
(b) Revolving Credit Facility
On November 10, 2014, in connection with the closing of the IPO, the Partnership entered into a revolving
credit facility with a syndicate of lenders. The revolving credit facility provides for lender commitments of $1.0
billion and for a letter of credit sublimit of $150 million. At December 31, 2014, we had no of borrowings and no
letters of credit outstanding under the revolving credit facility. The revolving credit facility will mature on
November 10, 2019.
Principal amounts borrowed are payable on the maturity date with such borrowings bearing interest that is
payable quarterly. The Partnership has a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans
bear interest at a rate per annum equal to the LIBOR Rate administered by the Intercontinental Exchange (“ICE”)
Benchmark Administration for one, two, three, six or twelve months plus an applicable margin ranging from 150 to
225 basis points, depending on the leverage ratio then in effect. Base rate loans bear interest at a rate per annum
equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points
and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 50 to
125 basis points, depending on the leverage ratio then in effect.
The revolving credit facility is secured by mortgages on substantially all of our and our restricted
subsidiaries’ properties and guarantees from our restricted subsidiaries. The revolving credit facility contains
restrictive covenants that may limit our ability to, among other things:
•
•
incur additional indebtedness;
sell assets;
• make loans to others;
• make investments;
•
enter into mergers;
• make certain restricted payments;
•
•
incur liens; and
engage in certain other transactions without the prior consent of the lenders.
F-14
ANTERO MIDSTREAM PARTNERS LP
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2012, 2013, and 2014
Borrowings under the revolving credit facility also require the Partnership to maintain the following financial ratios:
•
•
•
an interest coverage ratio, which is the ratio of the Partnership’s consolidated EBITDA to its
consolidated current interest charges of at least 2.5 to 1.0 at the end of each fiscal quarter; provided
that upon obtaining an investment grade rating, the borrower may elect not to be subject to such ratio;
a consolidated total leverage ratio, which is the ratio of consolidated debt to consolidated EBITDA, of
not more than 5.0 to 1.0; provided that after electing to issue unsecured high yield notes, the
consolidated total leverage ratio will not be more than 5.25 to 1.0, or, following the election of the
borrower for two fiscal quarters after a material acquisition, 5.50 to 1.0; and
if the Partnership elects to issue unsecured high yield notes, a consolidated senior secured leverage
ratio, which is the ratio of consolidated senior secured debt to consolidated EBITDA, of not more than
3.75 to 1.0.
(5) Equity-Based Compensation
Our general and administrative expenses include equity-based compensation costs allocated by Antero to us
for grants made pursuant to: (i) the Antero Resources Corporation Long-Term Incentive Plan (the “Antero LTIP”)
(ii) profits interests awards valued in connection with the Antero reorganization pursuant to its initial public offering
of common stock, which closed on October 16, 2013, and (iii) the Midstream LTIP. Equity-based compensation
expense allocated to us was $15.9 million and $8.6 million for the year ended December 31, 2013 and 2014,
respectively. These expenses were allocated to us based on our proportionate share of Antero’s direct labor costs.
We will be allocated a portion of approximately $104.8 million of unrecognized equity-based compensation expense
related to the Antero LTIP as of December 31, 2014, approximately $37 million of unrecognized equity-based
compensation expense related to profits interest awards as of December 31, 2014, and approximately $66.7 million
of unrecognized equity-based compensation related to the Midstream LTIP as of December 31, 2014 that will be
recognized by Antero over the remaining service periods of the awards.
Midstream LTIP
Our general partner manages our operations and activities and employs the personnel who provide support
to our operations. In connection with the IPO, our general partner adopted the Midstream LTIP, pursuant to which
non-employee directors of our general partner and certain officers, employees and consultants of our general partner
and its affiliates are eligible to receive awards. On November 12, 2014, the Partnership granted approximately
20,000 restricted units and 2,361,440 phantom units under the Midstream LTIP to Antero’s employees and officers.
The restricted units and phantom units vest subject to the satisfaction of service requirements, upon the completion
of which common units in the Partnership are delivered to the holder of the restricted units or phantom units.
Compensation related to each restricted unit and phantom unit award is recognized on a straight-line basis over the
requisite service period of the entire award. The grant date fair values of these awards are determined based on the
closing price of the Partnership’s common units on the date of grant. These units are accounted for as if they are
distributed from us to Antero. Antero recognizes compensation expense for the units awarded to its employees and a
portion of that expense is allocated to us. Antero allocates equity-based compensation expense to us based our
proportionate share of Antero’s direct labor costs. Our portion of the equity-based compensation expense is included
in general administrative expenses.
F-15
ANTERO MIDSTREAM PARTNERS LP
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2012, 2013, and 2014
A summary of restricted unit and phantom unit awards activity during the year ended December 31, 2014 is
as follows:
Total awarded and unvested, December 31, 2013
Granted
Vested
Forfeited
Total awarded and unvested—December 31, 2014
Number of
units
— $
2,381,440 $
— $
— $
2,381,440 $
Weighted
average
grant date
fair value
Aggregate
intrinsic value
(in thousands)
—
—
—
—
65,490
— $
29.00 $
— $
— $
29.00 $
Intrinsic values are based on the closing price of the Partnership’s common units on the referenced dates.
Unamortized expense of $66.7 million at December 31, 2014 is expected to be recognized over a weighted average
period of approximately 3.8 years and our proportionate share will be allocated to us as it is recognized.
(6) Partnership Equity and Distributions
Our Minimum Quarterly Distribution
Our partnership agreement provides for a minimum quarterly distribution of $0.17 per unit for each whole
quarter, or $0.68 per unit on an annualized basis. The payment of the full minimum quarterly distribution on all of
the common units and subordinated units to be outstanding require us to have cash available for distribution of
approximately $26 million per quarter, or $105 million per year.
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 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:
•
•
•
first, to the holders of common units, until each common unit has received the minimum quarterly
distribution of $0.1700 plus any arrearages from prior quarters;
second, to the holders of subordinated units, until each subordinated unit has received the minimum
quarterly distribution of $0.1700; and
third, to the holders of common units and subordinated units pro rata until each has received a distribution
of $0.1955.
F-16
ANTERO MIDSTREAM PARTNERS LP
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2012, 2013, and 2014
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:
Total Quarterly Distribution
Target Amount
above $0.1955 up to $0.2125
above $0.2125 up to $0.2550
above $0.2550
Subordinated Units
Marginal Percentage
Interest in
Distributions
Unitholders
85 %
75 %
50 %
General Partner
(as holder of
IDRs)
15 %
25 %
50 %
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.
(7) Net Income Per Limited Partner Unit
Net Income Per Limited Partner Unit
The Partnership’s net income is allocated to the general partner and limited partners, including
subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving
effect to incentive distributions paid to the general partner. Basic and diluted net income per limited partner unit is
calculated by dividing limited partners’ interest in net income, less general partner incentive distributions, by the
weighted average number of outstanding limited partner units during the period.
We compute earnings per unit using the two-class method for master limited partnerships. The two-class
method requires that securities that meet the definition of a participating security be considered for inclusion in the
computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the
earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the
general partner has discretion over the amount of distributions to be made in any particular period, whether those
earnings would actually be distributed during a particular period from an economic or practical perspective, or
F-17
ANTERO MIDSTREAM PARTNERS LP
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2012, 2013, and 2014
whether the general partner has other legal or contractual limitations on its ability to pay distributions that would
prevent it from distributing all of the earnings for a particular period.
We calculate net income available to limited partners based on the distributions pertaining to the current
period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings
or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance
with the contractual terms of the partnership agreement under the two-class method.
Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted
average number of units outstanding during each period. However, because our IPO was completed on November
10, 2014, the number of units issued following the IPO is utilized for the 2014 periods presented. Diluted net income
per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common
units, such as awards under the long-term incentive plan, were exercised, settled or converted into common units.
When it is determined that potential common units resulting from an award subject to performance or market
conditions should be included in the diluted net income per limited partner unit calculation, the impact is reflected
by applying the treasury stock method. Diluted earnings per unit reflects the potential dilution of common equivalent
units that could occur if equity participation units are converted into common units.
The following table illustrates the Partnership’s calculation of net income per common and subordinated
unit for the periods indicated:
In thousands except per unit amounts
Basic and diluted earnings per unit:
Earnings:
Distribution declared ⁽¹⁾
Distributions in excess of earnings
Total earnings
Weighted average units outstanding:
Basic and diluted
Net income attributable to Antero Midstream Partners
LP subsequent to IPO per limited partner unit
Basic and diluted:
Total earnings per unit
November 10, 2014 to December 31, 2014
Limited
partners'
General partner
common units
Limited
partner's
subordinated
units
Total
$
$
$
— $
—
— $
7,161 $
(3,450)
3,711 $
7,161 $
(3,450)
3,711 $
14,322
(6,900)
7,422
—
75,941
75,941
151,882
— $
0.05 $
0.05
(1) On February 2, 2015, we announced the board of directors of our general partner had declared a quarterly cash distribution of
$0.0943 per unit, totaling approximately $14 million. The quarterly cash distribution for the period November 10, 2014 to
December 31, 2014 was calculated as a minimum quarterly distribution of $0.1700 per unit prorated for the period subsequent to
the IPO. The distribution is payable on February 27, 2015 to unitholders of record on February 13, 2015.
F-18
ANTERO MIDSTREAM PARTNERS LP
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2012, 2013, and 2014
(8) Commitments and Contingencies
Environmental Obligations
We are subject to federal, state and local regulations regarding air and water quality, hazardous and solid
waste disposal and other environmental matters. We believe there are currently no such matters that will have a
material adverse effect on our results of operations, cash flows or financial position.
(9) Quarterly Financial Information (Unaudited)
Our quarterly financial information for the years ended December 31, 2013 and 2014 is as follows:
Year ended December 31, 2013
Total operating revenues
Total operating expenses
Operating income (loss)
Net income (loss)
Year ended December 31, 2014
Total operating revenues
Total operating expenses
Operating income (loss)
Net income (loss)
(1
First
quarter
Second
quarter
Third
quarter
Forth
quarter
$
$
1,953 $
2,984
(1,031)
(1,050)
3,539 $
4,300
(761)
(805)
7,138 $
5,726
1,412
1,369
9,733
23,539
(13,806)
(13,846)
11,773
10,825
948
774
16,923 $
16,632
291
(735)
26,282 $
19,270
7,012
5,079
40,768
27,567
13,201
11,714
F-19
Partnership Information
INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
KPMG LLP
Denver, Colorado
LEGAL COUNSEL
Vinson & Elkins LLP
Houston, Texas
UNITHOLDER INFORMATION
Our common units are publicly
traded on the NYSE under the
symbol “AM”
PARTNERSHIP HEADQUARTERS
Antero Midstream Partners LP
1615 Wynkoop Street
Denver, Colorado 80202
K. PHIL YOO
Vice President—Accounting,
Chief Accounting Officer and
Corporate Controller
JONATHAN L. GRANNIS
Co-Head of Geology
ROBERT S. TUCKER
Co-Head of Geology
INVESTOR RELATIONS
Antero Midstream Partners LP
1615 Wynkoop Street
Denver, Colorado 80202
(303) 357-7310 extension 6782
www.anteromidstream.com
TRANSFER AGENT
AND REGISTRAR
American Stock Transfer and
Trust Company, LLC
6201 15th Avenue
Brooklyn, New York 11219
(800) 937-5449
FORWARD-LOOKING STATEMENTS
The 2014 Annual Report may contain forward-looking statements. Forward-looking statements
give our current expectations, contain projections of results of operations or of financial condi-
tion, or forecasts of future events. Such forward-looking statements are subject to a number of
risks and uncertainties, many of which are beyond Antero Midstream’s control. All forward-looking
statements speak only as of the date of this annual report. Although Antero Midstream believes
that the plans, intentions and expectations reflected in or suggested by the forward-looking
statements are reasonable, there is no assurance that these plans, intentions or expectations
will be achieved. Therefore, actual outcomes and results could materially differ from what is
expressed, implied or forecast in such statements.
We caution you that these forward-looking statements are subject to all of the risks and uncer-
tainties, 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 the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year-ended
December 31, 2014.
DIRECTORS
RICHARD W. CONNOR
Audit Committee
Director
PETER R. KAGAN
Director
W. HOWARD KEENAN, JR.
Director
BROOKS J. KLIMLEY
Director
CHRISTOPHER R. MANNING
Director
DAVID A. PETERS
Audit Committee
Director
MANAGEMENT
PAUL M. RADY
Chief Executive Officer
and Chairman
GLEN C. WARREN, JR.
Director, President, Chief Financial
Officer and Secretary
ALVYN A. SCHOPP
Chief Administrative Officer,
Regional Vice President
and Treasurer
MICHAEL N. KENNEDY
Vice President—Finance
KEVIN J. KILSTROM
Vice President—Production
BRIAN A. KUHN
Vice President—Land
MARK D. MAUZ
Vice President—Gathering,
Marketing and Transportation
WARD D. MCNEILLY
Vice President—Reserves, Planning
and Midstream
TROY R. ROACH
Vice President—Employee Health
and Safety
STEVEN M. WOODWARD
Vice President—Business
Development