Jan updated

1. Partnership Overview
January 2015

2. FORWARD-LOOKING STATEMENTS
This presentation contains forward-looking statements. All statements, other than statements of historical facts, included in this
presentation that address activities, events or developments that Antero Midstream Partners LP, and its subsidiaries (collectively,
the “Partnership”) expect, believe or anticipate will or may occur in the future are forward-looking statements. The words “believe,”
“expect,” “anticipate,” “plan,” “intend,” “estimate,” “project,” “foresee,” “should,” “would,” “could,” or other similar expressions are
intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not
forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation
specifically include expectations of plans, strategies, objectives, and anticipated financial and operating results of the Partnership
and Antero Resources Corporation (“Antero”). These statements are based on certain assumptions made by the Partnership and
Antero based on management’s experience and perception of historical trends, current conditions, anticipated future developments
and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties,
many of which are beyond the control of the Partnership, which may cause actual results to differ materially from those implied or
expressed by the forward-looking statements.
The Partnership cautions you that these forward-looking statements are subject to risks and uncertainties that may cause these
statements to be inaccurate, and readers are cautioned not to place undue reliance on such statements. These risks include, but
are not limited to, Antero’s ability to meet its drilling and development plan, 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 discussed in the
registration statement on Form S-1 (No. 333-193798) filed by the Partnership under the heading “Risk Factors.”
Any forward-looking statement speaks only as of the date on which such statement is made, and the Partnership undertakes no
obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise,
except as required by applicable law.
1

3. ANTERO MIDSTREAM – A GROWTH FOCUSED MLP
2
• AM sponsor is the most active operator in Appalachia
• Highest recycle ratio and low F&D cost supports sponsor production growth expectations
• Sponsor maintains strong liquidity and significant hedging position
• Highly incentivized to maximize value of AM to support AR growth
• Midstream assets located in lowest cost per Mcfe rich gas plays in North America
• ~80% of midstream “footprint” is associated with rich gas production
• Substantial AR and third-party future infrastructure required
• Gathering and compression provide core asset portfolio with additional option to
expand into freshwater distribution and regional pipelines
• Pure play, fee-based midstream MLP with top tier growth rate
• Cash flows are supported by 20-year, fee-based agreements with AR
• “Best in class” anchor tenant with 92% net production growth in 2014 and 40%
growth projected for 2015
• Growth not dependent on drop-downs, 3rd party business or acquisitions for growth
• Consolidated Marcellus and Utica rich gas acreage dedications
• Multiple gathering and compression, processing, pipeline and other expansion
opportunities
• Option to acquire AR Fresh Water Distribution system
• Antero Midstream MLP had no leverage at IPO closing plus $250 million cash
• $1 billion of undrawn borrowing capacity commitments and $230 million of cash at
12/31/2014
• Good high yield access with “Ba3/BB” rated parent (corporate ratings)
• Structured to pursue organic growth opportunities
Premier
E&P Sponsorship
1
“Pure Play”
Marcellus/Utica
Midstream MLP
2
Top Tier MLP
Organic Growth3
Appalachian
Midstream Value
Chain Opportunity
4
Stacked-Pay Basin
Potential Upside5
Financial Flexibility
& Strong Capital
Structure
6
• Stacked-pay opportunities – Utica, Marcellus, Upper Devonian
• Opportunity to develop Utica Shale dry gas pipeline and compression systems in
West Virginia
• Future Upper Devonian development will require existing water resource for
completions and gathering and compression systems

4. ANTERO MIDSTREAM – 2015 GUIDANCE
Key Variable 2015 Guidance Range
Adjusted EBITDA ($MM) $150 - $160
Distributable Cash Flow ($MM) $135 - $145
Year-over-Year Distribution Growth 28% - 30%
Low Pressure Pipelines Added (Miles) 46
High Pressure Pipelines Added (Miles) 18
Compression Capacity Added (MMcf/d) 545
Capital Expenditures ($MM)
Low Pressure Gathering $165 - $170
High Pressure Gathering $85 - $90
Compression $160 - $165
Condensate Gathering $5 - $10
Maintenance Capital $10 - $15
Total Capital Expenditures ($MM) $425 - $450
1. Financial assumptions per Partnership press release dated 1/20/2015.
Key Operating & Financial Assumptions
3

5. Antero
Midstream Management
ANTERO MIDSTREAM OWNERSHIP STRUCTURE
4
Antero Resources
Corporation (NYSE: AR)
$13.0 Billion Enterprise Value(1)
Ba3/BB Corporate Rating
Antero Midstream
Partners LP (NYSE: AM)
$3.4 Billion Market Cap.(1)
Public
$1 Billion
Credit Facility
Midstream Entity
Partnership
Corporation
Marcellus
Gathering
& Compression
Utica
Gathering &
Compression
Option(3)
Antero Fresh Water
Distribution System
Option
69.7% Limited
Partner Interest
1. As of 1/16/2015. AR enterprise value excludes AM minority interest and cash.
2. Option to acquire up to a 15% non-operating equity interest in a new build Regional Gathering Pipeline.
3. Option to acquire 100% interest at fair market value.
100% 100% 100%
Option(2)
Regional Gathering
Pipeline
15%
Midstream Option

6. 1. Represents inception to date actuals as of 6/30/2014 and 2015 midpoint guidance.
2. Includes $12.5 million of maintenance capex at 2015 midpoint guidance.
5
• Gathering and compression assets in core of rapidly
growing Marcellus and Utica Shale plays
– Acreage dedication of ~412,000 net leasehold
acres for gathering and compression services
– 100% fixed fee long term contracts
Utica
Shale
Marcellus
Shale
Projected Midstream Infrastructure(1)
Marcellus
Shale
Utica
Shale Total
YE 2014E Cumulative Gathering/
Compression Capex ($MM) $850 $350 $1,200
Gathering Pipelines
(Miles) 153 80 233
Compression Capacity
(MMcf/d) 375 - 375
Condensate Gathering Pipelines
(Miles) - 16 16
YE 2015E Gathering/
Compression Capex ($MM)(2) $256 $182 $438
Gathering Pipelines
(Miles) 46 18 64
Compression Capacity
(MMcf/d) 425 120 545
Condensate Gathering Pipelines
(Miles) - 4 4
Midstream Assets
ANTERO MIDSTREAM PARTNERS OVERVIEW

7. ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS
6
• Provides Marcellus gathering and compression
services
− Liquids-rich gas is delivered to MWE’s Sherwood
Complex for processing
• Significant growth projected over the next twelve
months as set out below:
• Antero sold the Harrison County portion of its gathering
system to a 3rd party midstream company in 2012,
which is now recognized as the 3rd Party Gathering and
Compression Dedication area
• Development upside as AR continues to drill, step-out
and add acreage
Marcellus Gathering & Compression
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
YE 2014 YE 2015
Gathering Pipelines (Miles) 153 199
Compression Capacity (MMcf/d) 375 800
WV/PA Utica Dry Gas Gathering & Compression
• Further development upside in 170,000 net acres of
Utica deep rights beneath the Marcellus Shale
− Will require a separate dry gas gathering system

8. 7
• Provides Utica natural gas and condensate gathering
services
− Liquids-rich gas delivered into MWE’s Seneca
Complex for processing
− Condensate delivered to centralized stabilization
and truck loading facilities
• Significant growth projected over the next twelve
months as set out below:
• Development upside as AR continues to drill, step-out
and add acreage
Utica Gathering
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
ANTERO MIDSTREAM ASSETS – RICH & DRY GAS UTICA
YE 2014 YE 2015
Gathering Pipelines (Miles) 80 98
Condensate Pipelines (Miles) 16 20
Compression (MMcf/d) 0 120
Utica Compression
• Opportunity to build up to ten new compressor stations
that are planned to support AR development over the
next several years

9. 108
216
281
331
386
531
964
0
200
400
600
800
1,000
2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q'14 NTM
9/30/15
Utica Marcellus
$1.4
$5.0 $6.8 $8.4
$11.4 $18.8
$136.2
0
20
40
60
80
100
120
140
160
2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM
9/30/15
EBITDA
HIGH GROWTH THROUGHPUT
Low Pressure Gathering (MMcf/d) Compression (MMcf/d)
High Pressure Gathering (MMcf/d) Antero Midstream Partners EBITDA ($MM)
1. Midstream EBITDA does not include EBITDA contribution from fresh water distribution
(1)
8
26 31
40 36 41
116
249
0
50
100
150
200
250
2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM
9/30/15
Marcellus
10
38
80
126
266
531
773
0
200
400
600
800
2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM
9/30/15
Utica Marcellus

10. ORGANIC GROWTH STRATEGY: “BUILD VS. BUY”
9
• Organic growth strategy provides attractive
returns and project economics, while
avoiding the competitive acquisition market
• Industry leading organic growth story
– ~$1.04 billion in estimated capital spent
through 9/30/2014
– $425 million in additional growth capital
forecast for the twelve-month period
ending 12/31/15 (excludes $12.5 million of
maintenance capital)
Note: Precedent data per IHS Herold’s research and public filings.
1. Antero organic multiple calculated as estimated gathering and compression capital expended through Q3 2014 divided by 12/31/15 projected gathering and compression EBITDA assuming 12-15
month lag between capital incurred and full system utilization.
2. Selected gathering and compression drop down acquisitions since 1/1/2011. Drop down multiples are based on NTM EBITDA. Source: Barclays.
6.3x
11.9x
10.7x
10.0x
9.3x
9.0x 9.0x 9.0x 8.9x 8.9x 8.8x
8.6x
8.0x 7.9x
7.0x 6.9x
5.5x
0.0x
1.0x
2.0x
3.0x
4.0x
5.0x
6.0x
7.0x
8.0x
9.0x
10.0x
11.0x
12.0x
Drop Down Multiple(2)
Organic EBITDA Multiple vs. Precedent Drop Down Multiples
Median: 8.9x
Value creation for the AM unit holder =
Build at 4-6x EBITDA
vs.
Drop-Down / Buy at 8-12x EBITDA

11. Fresh Water
Distribution(1)
Regional Gas Pipelines
Miles Capacity In-Service
Unnamed Regional
Pipeline
50 1.4 Bcf/d 4Q 2015
101. Currently owned by AR; AM holds option to purchase 100% of assets at fair market value.
End
Users
End
Users
Gas Processing
Y-Grade Pipeline
Long-Haul Interstate
Pipeline
Inter
Connect
NGL Product Pipelines
Fractionation
Compression
Low Pressure Gathering
Well Pad
Terminals
and
Storage
(Miles) YE 2014 YE 2015
Marcellus 91 118
Utica 45 62
Total 136 180
AM has option to participate
in processing, fractionation,
terminaling and storage
projects offered to AR
FULL MIDSTREAM VALUE CHAIN POTENTIAL
(Miles) YE 2014 YE 2015
Marcellus 62 81
Utica 35 36
Total 97 117
(MMcf/d) YE 2014 YE 2015
Marcellus 375 800
Utica 0 120
Total 375 920
AM Owned Assets
Condensate Gathering
Stabilization
(Miles) YE 2014 YE 2015
Utica 16 20
End
Users
AM Option Assets
(Ethane, Propane,
Butane, etc.)
(De-ethanization)

12. AM OPTION – FRESH WATER DISTRIBUTION SYSTEMS
11
Marcellus Fresh Water Distribution System
• Provides fresh water to support ongoing Marcellus completion
activity
• Year-round water supply sources: Ohio River and local rivers
• Significant growth projected over the next twelve months as
summarized below:
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
1. Estimated fee of $3.50 per barrel at an average of 200,000 Bbls of water per well.
Utica Fresh Water Distribution System
• Provides fresh water to support ongoing Utica completion activity
• Year-round water supply sources: local reservoirs and rivers
• Significant growth projected over the next twelve months as
summarized below:
• Currently owned by AR – AM holds option to purchase 100% of assets at fair market value
Marcellus Water System YE 2014 YE 2015
Water Pipeline (Miles) 177 49
Fresh Water Storage Impoundments 22 24
YE 2015 Projected Wells 80
Water Fees per Well ($)(1) $600K -
$800K
Utica Water System YE 2014 YE 2015
Water Pipeline (Miles) 61 29
Fresh Water Storage
Impoundments
8 14
YE 2015 Projected Wells 50
Water Fees per Well ($)(1) $600K -
$800K
OHIO

13. 25%
15%
10%
25%
30%
15% 15%
35%
25%
20%
35%
25%
20%
40%
0%
10%
20%
30%
40%
InternalRateofReturn
12
DRY GAS LOCATIONS RICH GAS LOCATIONS
HIGHLY
RICH GAS
LOCATIONS
Project Economics by Segment(1)
ESTIMATED PROJECT ECONOMICS BY SEGMENT
LP
Gathering
HP
Gathering Compression
Condensate
Gathering
Water
Distribution
Regional
Pipeline
Processing/
Fractionation
Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 25% - 35% 30% - 40% 15% - 25% 15% - 20%
Payout (Years): 2.5 - 4.0 3.5 - 4.5 4.0 - 6.5 2.0 - 3.5 2.0 – 3.0 3.5 - 7.0 5.0 - 6.0
Minimum Volume Commitments: N/A 75% 70% N/A N/A 100% 60%
12/31/2015 Capex(2) Total
Marcellus $248.4 $72.6 $73.3 $102.5 -
Utica 176.5 104.1 12.1 55.1 5.2
Expansion Capex $424.9 $176.7 $85.4 $157.6 $5.2
% of Capex 100% 42% 20% 37% 1%
Included in NTM Period: Marcellus &
Utica
Marcellus &
Utica
Marcellus Utica Not Included Not Included Not Included
Additional Opportunities: Dry Utica Dry Utica Rich & Dry
Utica
Utica
Stabilization
Drop-Down
of Water
Distribution
System
Regional
Gathering
Pipeline
Marcellus
Processing/
Fractionation
1. Based on management capex, operating cost and throughput assumptions by project.
2. Excludes $12.5 million of maintenance capex.
Wtd. Avg. 23% IRR
AM Option Opportunities

14. SIGNIFICANT FINANCIAL FLEXIBILITY
13
• Unfunded $1 billion revolver in place at time of IPO to fund
future growth capital (5x Debt/EBITDA Cap)
• No leverage and $250 million of cash “post-IPO” provides
significant financial flexibility
• $230 million of cash at 12/31/2014
• Sponsor (NYSE: AR) has Ba3/BB corporate ratings
AM Liquidity
AM Peer Leverage Comparison(2)
($ in millions) At IPO(1)
Revolver Capacity $1,000
Less: Borrowings -
Plus: Cash 250
Liquidity $1,250
0.0x 0.0x 0.1x
1.1x 1.3x
1.5x
2.2x
2.4x
3.1x 3.1x 3.3x 3.3x
4.0x 4.1x
0.0x
2.0x
4.0x
6.0x
Debt/LTMEBITDA
1. IPO completed on 11/10/2014.
2. Peers include ACMP, EQM, MPLX, MWE, OILT, PSXP, QEPM, RRMS, SXL, TEP, TLLP, VLP and WES.
Sources ($ in millions)
Primary IPO Proceeds $1,150
Total Sources $1,150
Uses
Proceeds to AR $843
Proceeds retained by AM 250
Fees & Expenses 57
Total Uses $1,150
Sources & Uses (11/10/2014)
Financial Flexibility

15. 14
ANTERO MIDSTREAM MLP INVESTMENT HIGHLIGHTS
Premier E&P
Sponsorship
“Pure Play”
Marcellus/Utica
Midstream MLP
Top Tier MLP
Organic Growth
Full Midstream Value
Chain Potential
Financial Flexibility
& Strong Capital
Structure “Best in Class”
Distribution Growth
Expected

16. 15
Antero Resources (NYSE: AR)
Overview

17. 16
Most Active Operator
in Appalachia
Most Active
Land Organization
in Appalachia
Largest Firm Transport
and Processing
Portfolio in Appalachia
Largest Gas Hedge
Position in U.S. E&P +
Strong Financial
Liquidity
Highest Growth
Large Cap E&P
Largest Liquids-Rich
Core Position in
Appalachia
Highest Realizations
and Margins Among
Large Cap
Appalachian Peers
Growth Land
Liquidity
Midstream
Drilling
LEADING UNCONVENTIONAL BUSINESS MODEL
MLP (NYSE: AM)
Highlights
Substantial Value in
Midstream Business
Realizations
Takeaway
Liquids-Rich
1
2 3
4
5
67
8
Premier Appalachian
E&P Company
Run by Co-Founders

18. DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA
1. All net acres allocated to the WV/PA Utica Shale Dry Gas and Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as they are stacked pay formations attributable
to the same leasehold.
2. Antero and industry rig locations and rig count as of 1/23/2015 per RigData.
17
COMBINED TOTAL – 12/31/14 RESERVES
Assumes Ethane Rejection
Net Proved Reserves 12.7 Tcfe
Net 3P Reserves 40.7 Tcfe
Pre-Tax 3P PV-10 $22.8 Bn
Net 3P Reserves & Resource 51.8 Tcfe
Net 3P Liquids 1,026 MMBbls
% Liquids – Net 3P 15%
4Q 2014E Net Production 1,265 MMcfe/d
- 4Q 2014E Net Liquids 30,400 Bbl/d
Net Acres(1) 543,000
Undrilled 3P Locations 5,331
UTICA SHALE CORE
Net Proved Reserves 758 Bcfe
Net 3P Reserves 7.6 Tcfe
Pre-Tax 3P PV-10 $6.1 Bn
Net Acres 148,000
Undrilled 3P Locations 1,024
MARCELLUS SHALE CORE
Net Proved Reserves 11.9 Tcfe
Net 3P Reserves 28.4 Tcfe
Pre-Tax 3P PV-10 $16.8 Bn
Net Acres 395,000
Undrilled 3P Locations 3,191
UPPER DEVONIAN SHALE
Net Proved Reserves 8 Bcfe
Net 3P Reserves 4.6 Tcfe
Pre-Tax 3P PV-10 NM
Undrilled 3P Locations 1,116
WV/PA UTICA SHALE DRY GAS
Net Resource 11.1 Tcf
Net Acres 170,000
Undrilled Locations 1,616
0
5
10
15
20
25
RigCount
Operators
SW Marcellus & Utica(2)

19. 0
600
1,200
1,800
2010 2011 2012 2013 2014 2015E
Marcellus Utica Guidance
30
124
239
522
1,400
1,007
1. 2012, 2013 and 2014 proved reserves assuming ethane rejection.
2. Per current First Call median estimate from Bloomberg.
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
2010 2011 2012 2013 2014
Marcellus Utica
677
2,844
4,283
7,632
(1) (1) (1)
12,683
18
AVERAGE NET DAILY PRODUCTION (MMcfe/d)NET PROVED SEC RESERVES (Bcfe)
0
25
50
75
100
125
150
175
200
2010 2011 2012 2013 2014 2015E
Marcellus Utica Deferred Completions
19
38
60
114
177 180
130
GROWTH – STRONG TRACK RECORD
OPERATED GROSS WELLS COMPLETED EBITDAX ($MM)
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
2010 2011 2012 2013 2014E
$28
$160
$285
$649
$1,144
(2)
40% Growth
Guidance
92% Growth

20.  Assembled a 543,000 net acre position in the core of the Marcellus and Utica shale plays over the past 6 years
December 2008
Net Acreage 118,000
Net Production (MMcfe/d) NM
3P Reserves (Bcfe) NM
3P PV-10 ($MM) NM
Rigs Running NM
Dec 2008 Dec 2011 Dec 2014
December 2011(1)
Net Acreage 213,000
Net Production (MMcfe/d) 167
3P Reserves (Bcfe) 18,400
3P PV-10 ($MM) $9,000
Rigs Running 5
December 2014(1)
Net Acreage 543,000
Net Production (MMcfe/d) 1,265
3P Reserves (Bcfe) 40,700
3P PV-10 ($MM) $22,800
Rigs Running 21
1. Net daily production for December 2011 and December 2014 is for the fourth quarter, respectively.
LAND – MOST ACTIVE LAND ORGANIZATION
IN APPALACHIA
19
118,000 118,000 118,000
162,000
189,000
213,000
285,000
371,000
420,000
450,000
486,000
543,000
0
100,000
200,000
300,000
400,000
500,000
600,000
12/2008 12/2009 6/2010 12/2010 6/2011 12/2011 6/2012 12/2012 6/2013 12/2013 6/2014 12/2014
Antero Net Acreage
Utica Marcellus

21. 20
LIQUIDS-RICH – LARGEST CORE POSITION
Source: Core outlines and peer net acreage positions based on peer presentations, news releases and 10-K/10-Qs.
 Antero has the largest liquids-rich core position in Appalachia ≈371,000 net acres

22. TAKEAWAY – LARGEST FIRM TRANSPORTATION AND
PROCESSING PORTFOLIO IN APPALACHIA
Odebrecht / Braskem
30 MBbl/d Commitment
Ascent Cracker
(Pending Final
Investment Decision)
Antero Long Term Firm Processing & Takeaway Position (2018) – Accessing Favorable Markets
Mariner East II
62 MBbl/d Commitment(2)
Marcus Hook Export
Shell
25 MBbl/d Commitment
Beaver County Cracker
(Pending Final
Investment Decision)
Sabine Pass (Trains 1-4)
50 MMcf/d per Train
1. February 2015 and full year 2016 futures basis, respectively, provided by Wells Fargo dated 12/31/2014. Favorable gas markets shaded in green.
2. As an anchor shipper on Mariner East II, Antero has the right to expand its NGL commitment with notice to operator.
Chicago(1)
+$0.23 /
$(0.08)
CGTLA(1)
$(0.08) /
$(0.09)
Dom South(1)
$(1.38) /
$(1.11)
TCO(1)
$(0.13) /
$(0.41)
21
4 Bcf/d
Firm Gas
Takeaway
By 2018
Cove Point

23. 1,316 943 780 1,073 818 40
$4.42 $4.47 $4.34 $4.50 $4.41 $4.41
$3.09
$3.48 $3.77 $3.95 $4.08 $4.21
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
0
200
400
600
800
1,000
1,200
1,400
2015 2016 2017 2018 2019 2020
BBtu/d $/MMBtu
22
Average Index Hedge Price(1)Hedged Volume Current NYMEX Strip(2)
COMMODITY HEDGE POSITION
1. Reflects weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio. Antero has hedged 3,000 Bbl/d of oil and 23,000 Bbl/d of propane for 2015.
2. As of 12/31/2014.
3. Percentage of net gas equivalent production target hedged for respective years.
 ~$1.6 billion mark-to-market unrealized gain based on 12/31/2014 prices
 1.8 Tcfe hedged from January 1, 2015 through year-end 2020 and 262 Bcf of TCO basis hedges from 2015 to 2017
$689 MM $464 MM $176 MM $214 MM $98 MM $3 MM
Mark-to-Market Value(2)
LIQUIDITY – LARGEST GAS HEDGE POSITION IN U.S. E&P
+ STRONG FINANCIAL LIQUIDITY
$3,000
$2,012
($1,505)
($332) $6 $843
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
Credit Facility
9/30/2014
Bank Debt
9/30/2014
L/Cs
Outstanding
9/30/2014
Cash
9/30/2014
AM IPO
Proceeds
to AR
Pro Forma
Liquidity
9/30/2014
AR LIQUIDITY POSITION ($MM) AM LIQUIDITY POSITION ($MM)
$1,000
$1,250
$0 $0 $0
$250
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
Credit Facility
9/30/2014
Bank Debt
9/30/2014
L/Cs
Outstanding
9/30/2014
Cash
9/30/2014
AM IPO
Proceeds
to AM
Pro Forma
Liquidity
9/30/2014
≈ 94% of 2015E
Target
Production(3)
 Over $3 billion of combined AR and AM financial liquidity as of 9/30/2014, pro forma for AM IPO closed on 11/10/2014

24. 1. Includes firm sales.
2. Price realization includes $0.05 of midstream revenues in 3Q, 2014.
3. Includes natural gas hedges.
4. Source: Public data from 3Q 2014 10-Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp. and Range Resources.
5. Includes realized hedge gains and losses. Operating costs include lease operating expenses, production taxes, gathering, processing and firm transport costs and general and administrative costs. 4-year
proved reserve average all-in F&D from 2010-2013. Calculation = (Development costs + exploration costs + leasehold costs) / Total reserves added (2013 ending reserves – 2010 beginning reserves + 4-year
reserve sales – 4-year reserve purchases + 4-year accumulated production). AR price realization includes $0.04 of midstream revenues.
$4.16 $3.97
$0.58
$0.95
$0.74 $0.77 $0.81
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
Antero Peer 1 Peer 2 Peer 3 Peer 4
$/Mcfe
LOE Production Taxes GPT G&A EBITDAX 4-year Avg. All-in F&D ($/Mcfe)
$4.96
$3.25
$4.48
$2.93
$2.40
$2.64
$2.11 $2.09
23
REALIZATIONS – HIGHEST REALIZATIONS & MARGINS
AMONG LARGE-CAP APPALACHIAN PEERS
3Q & 4Q 2014 Natural Gas Realizations ($/Mcf)
3Q 2014 Natural Gas Realizations(3) 3Q 2014 Price Realization & EBITDAX Margin vs F&D(2)(4)
$4.31
$4.12
$3.66 $3.62 $3.60
$2.98 $2.87 $2.75
$0.00
$2.00
$4.00
$6.00
AR EQT GPOR RRC CNX RICE ECR COG
$/Mcf
3Q 2014 NYMEX = $4.06/Mcf
AR Peer 1 Peer 2 Peer 3 Peer 4
Average
NYMEX
Price
($/Mcf)
Average
Differential(1)
($/Mcf)
Average
BTU Upgrade
($/Mcf)
Discount to
NYMEX
($/Mcf)
Gas
Hedge
Effect
($/Mcf)
Average
Realized
Gas Price
($/Mcf)
Average
Realized Gas
Premium/
Discount
($/Mcf)
Liquids
Upgrade
($/Mcfe)
Realized
Equivalent
Price
($/Mcfe)
Equivalent
Premium
($/Mcfe)
3Q 2014 $4.06 $(0.84) $0.41 $(0.43) $0.68 $4.31 $0.25 $0.60 $4.91 $0.85
4Q 2014 $4.00 $(0.71) $0.37 $(0.34) $0.73 $4.39 $0.39 $0.29 $4.68 $0.68

25. DOM S
22%
DOM S - 9% DOM S - 6%
TETCO M2 - 7%
TETCO M2 - 6%
TCO
24%
TCO
16%
TCO - 9%
NYMEX
8%
NYMEX
11%
NYMEX
10%
Gulf Coast
18%
Gulf Coast
38%
Gulf Coast
56%
Chicago
21%
Chicago
20%
Chicago
19%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
($/Mcf) 2015E
NYMEX Strip Price(1) $3.09
Basis Differential to NYMEX(1) $(0.46)
BTU Upgrade(6) $0.26
Estimated Realized Hedge Gains $1.35
Realized Gas Price with Hedges $4.24
Premium to NYMEX +$1.15
Liquids Impact +$0.39
Premium to NYMEX w/ Liquids +$1.54
Realized Gas-Equivalent Price $4.63
4. Represents 60,000 MMBtu/d of TCO index hedges and 270,000 MMBtu/d of TCO
basis hedges that are matched with NYMEX hedges for presentation purposes.
5. Represents 107,500 MMBtu/d of TCO basis hedges matched with NYMEX hedges.
6. Assumes ethane rejection resulting in 1100 BTU residue sales gas.
REALIZATIONS – REALIZED PRICE “ROAD MAP”
1. Based on 12/31/14 strip pricing.
2. Differential represents contractual deduct to NYMEX-based firm sales contract.
3. Represents 120,000 MMBtu/d of TCO index hedges and 390,000 MMBtu/d of TCO basis hedges that are
matched with NYMEX hedges for presentation purposes.
2015
Basis(1)
2016
Basis(1)
2017
Basis(1)
2015
Hedges
2016
Hedges
2017
Hedges
Marketed%ofTargetResidueGasProduction
+$0.05/MMBtu
$(0.25)/MMBtu(2)
$(1.28)/MMBtu
$(0.24)/MMBtu
$(0.07)/MMBtu
$(0.25)/MMBtu(2)
$(1.11)/MMBtu
$(0.41)/MMBtu
$(0.20)/MMBtu
$(0.25)/MMBtu(2)
$(0.83)/MMBtu
$(0.50)/MMBtu
$(0.09)/MMBtu
$(0.07)/MMBtu
182,500 MMBtu/d
@ $4.38/MMBtu
107,500 MMBtu/d
@ $3.88/MMBtu (5)
40,000 MMBtu/d
@ $4.00/MMBtu
230,000 MMBtu/d
@ $5.60/MMBtu
510,000 MMBtu/d
@ $3.87/MMBtu(3)
170,000 MMBtu/d
@ $4.09/MMBtu
272,500 MMBtu/d
@ $5.35/MMBtu
330,000 MMBtu/d
@ $3.82/MMBtu(4)
85% exposure to favorable price indices
$1.35/Mcfe in estimated hedge gains(1)
71% exposure to favorable price indices
94% exposure to favorable price indices
 Antero is forecasting realized gas prices including hedges at a premium to NYMEX for 2015, assuming current strip pricing,(1)
current basis differentials, existing firm transportation and hedges
$(1.35)/MMBtu
$(1.26)/MMBtu
Wtd. Avg.
Basis ($0.46)
Wtd. Avg.
Basis $(0.32)
1,160,000 MMBtu/d
@ $4.34/MMBtu
Wtd. Avg.
Basis $(0.18)
942,500 MMBtu/d
@ $4.47/MMBtu
420,000 MMBtu/d
@ $4.27/MMBtu
2015E 2016E 2017E
24
380,000 MMBtu/d
@ $3.88/MMBtu
170,000 MMBtu/d
@ $3.35/MMBtu
70,000 MMBtu/d
@ $4.57/MMBtu
780,000 MMBtu/d
@ $4.34/MMBtu
$(0.10)/MMBtu

26. 0%
10%
20%
30%
40%
248
139
94
254
289
10%
31%
46%
33% 30%
0
100
200
300
0%
20%
40%
60%
Condensate Highly-Rich
Gas/
Condensate
Highly-Rich
Gas
Rich Gas Dry Gas
Total3PLocations
ROR
Locations ROR
MARCELLUS SSL WELL ECONOMICS(1)
664
1,010
628
88942%
28%
12% 11%
0
300
600
900
1,200
0%
15%
30%
45%
60%
Highly-Rich
Gas/
Condensate
Highly-Rich
Gas
Rich Gas Dry Gas
Total3PLlocations
ROR
Locations ROR
MULTI-YEAR DRILLING INVENTORY SUPPORTS
LOW RISK, HIGH RETURN GROWTH PROFILE
Large 3P Drilling Inventory of High Return Projects(2)
1. Pre-tax well economics based on 12/31/2014 natural gas and WTI strip pricing for 2015-2020, flat thereafter, NGLs at 55% of oil price and applicable firm transportation costs; 8,000’ lateral.
2. Source: Credit Suisse report dated December 2014 – After-tax internal rate of return based on 12/31/2014 strip pricing.
26% 26%
31%
15%
InternalRateofReturn(%)
20%
25
UTICA WELL ECONOMICS(1)
 72% of Marcellus locations are processable (1100-plus Btu)  72% of Utica locations are processable (1100-plus Btu)
3,037 Antero Liquids-Rich Locations
16%
2015
Drilling Plan
Antero Projects
 Antero is well positioned in the core of the highest return shale projects in the U.S. in the current commodity price environment

27. WORLD CLASS MARCELLUS SHALE
DEVELOPMENT PROJECT
100% operated
Operating 13 drilling rigs
including 5 intermediate rigs
395,000 net acres in
Southwestern Core (73%
includes processable rich gas
assuming an 1100 Btu cutoff)
– 50% HBP with additional 27%
not expiring for 5+ years
362 horizontal wells completed
and online
– Laterals average 7,400’
– 100% drilling success rate
5 plants in-service at Sherwood
Processing Complex capable of
processing 1 Bcf/d of rich gas
− Over 800 MMcf/d being
processed currently
Net production of 937 MMcfe/d in
3Q 2014, including 17,300 Bbl/d
of liquids
3,191 future drilling locations in
the Marcellus (2,302 or 72% are
processable rich gas)
28.4 Tcfe of net 3P (17% liquids),
includes 11.9 Tcfe of proved
reserves (assuming ethane
rejection) Highly-Rich Gas
130,000 Net Acres
1,010 Gross Locations
Rich Gas
91,000 Net Acres
628 Gross Locations
Dry Gas
105,000 Net Acres
889 Gross Locations
Highly-Rich/Condensate
69,000 Net Acres
664 Gross Locations
HEFLIN UNIT
30-Day Rate
2H: 21.4 MMcfe/d
(21% liquids)
CONSTABLE UNIT
30-Day Rate
1H: 14.3 MMcfe/d
(26% liquids)
142 Horizontals Completed
30-Day Rate
8.1 MMcf/d
6,915’ average lateral length
Sherwood
Processing
Complex
Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held. Note: Rates in ethane rejection.
NERO UNIT
30-Day Rate
1H: 18.2 MMcfe/d
(27% liquids)
BEE LEWIS PAD
30-Day Rate
4-well combined
30-Day Rate of
67 MMcfe/d
(26% liquids)
RJ SMITH PAD
30-Day Rate
4-well combined
30-Day Rate of
56 MMcfe/d
(21% liquids)
26
MHR COLLINS UNIT
30-Day Rate
4-well average
9.3 MMcfe/d
(26% liquids)
HENDERSHOT UNIT
30-Day Rate
1H: 16.3 MMcfe/d
2H: 18.1 MMcfe/d
(29% liquids)
HORNET UNIT
30-Day Rate
1H: 21.5 MMcfe/d
2H: 17.2 MMcfe/d
(26% liquids)
CARR UNIT
30-Day Rate
2H: 20.6 MMcfe/d
(20% liquids)
WAGNER PAD
30-Day Rate
4-well combined
30-Day Rate of
59 MMcfe/d
(14% liquids)

28. Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held.
Note: Third party peak rates assume ethane recovery; Antero 30-day rates in ethane rejection.
1. For non-Antero wells, Antero has converted rich gas rates where BTU has been disclosed to NGLs, assuming ethane recovery. Where BTU has not been disclosed, Antero has estimated BTU and gas
composition.
2. 30-day rate reflects restricted choke regime.
• 100% operated
• Operating 8 rigs including 3 intermediate rigs
• 148,000 net acres in the core rich gas/
condensate window (72% includes processable
rich gas assuming an 1100 Btu cutoff)
– 20% HBP with additional 79% not expiring
for 5+ years
• 52 operated horizontal wells completed and
online in Antero core areas
− 100% drilling success rate
• 3 plants at Seneca Processing Complex capable
of processing 600 MMcf/d of rich gas
− Over 500 MMcf/d being processed currently,
including third party production
• Net production of 143 MMcfe/d in 3Q 2014
including 7,700 Bbl/d of liquids
− Seneca 3 processing plant online in July
2014
− Fourth third party compressor station in-
service December 2014 with a capacity of
120 MMcf/d
• 1,024 future gross drilling locations (735 or 72%
are processable gas)
• 7.6 Tcfe of net 3P (15% liquids), includes
758 Bcfe of proved reserves (assuming ethane
rejection)
LEADING UTICA SHALE CORE POSITION DELIVERS
CONDENSATE AND NGLS
27
Utica Shale Industry Activity(1)
Cadiz
Processing
Plant
NORMAN UNIT
30-Day Rate
2 wells average
20.3 MMcfe/d
(17% liquids)
RUBEL UNIT
30-Day Rate
3 wells average
21.1 MMcfe/d
(24% liquids)
GULFPORT
24-Hour IP
McCort1-28H, 2-28H,
Stutzman 1-14H
Average 13.1 MMcf/d
+ 922 Bbl/d NGL
+ 21 Bbl/d Oil
GULFPORT
24-Hour IP
Wagner 1-28H,
Shugert 1-1H, 1-12H
Average 21.0 MMcf/d
+ 2,270 Bbl/d NGL
+ 292 Bbl/d Oil
Utica
Core
Area
GARY UNIT
30-Day Rate
3 wells average
29.8 MMcfe/d
(22% liquids)
Highly-Rich/Cond
26,000 Net Acres
139 Gross Locations
Highly-Rich Gas
15,000 Net Acres
94 Gross Locations
Rich Gas
33,000 Net Acres
254 Gross Locations
Dry Gas
42,000 Net Acres
289 Gross Locations
NEUHART UNIT 3H
30-Day Rate
18.7 MMcfe/d
(58% liquids)
Condensate
32,000 Net Acres
248 Gross Locations
DOLLISON UNIT 1H
30-Day Rate
23.3 MMcfe/d
(44% liquids)
MYRON UNIT 1H
30-Day Rate
30.4 MMcfe/d
(49% liquids)
Seneca
Processing
Complex
LAW UNIT
30-Day Rate
2 wells average
18.4 MMcfe/d
(50% liquids)
SCHAFER UNIT
30-Day Rate(2)
2 wells average
16.2 MMcfe/d
(49% liquids)
URBAN PAD
30-Day Rate
4-well combined
30-Day Rate of
74 MMcfe/d
(16% liquids)

29. APPENDIX
28

30. LTM Production
NTM Production Forecast
Average LTM Production
MAINTENANCE CAPITAL METHODOLOGY
• Maintenance Capital Calculation Methodology
– Estimate the number of new well connections needed during the forecast period in order to offset the natural
production decline and maintain the average throughput volume on our system over the LTM period
– (1) Compare this number of well connections to the total number of well connections estimated to be made during
such period and
– (2) Designate an equal percentage of our estimated gathering capital expenditures as maintenance capital
expenditures
29
Maintenance capital expenditures are cash expenditures (including expenditures for the
construction or development of new capital assets or the replacement, improvement or expansion
of existing capital assets) made to maintain, over the long term, our operating capacity or revenue
• Illustrative Example
LTM Forecast Period
Decline of LTM
average throughput
to be replaced with
production volume
from new well
connections

31. CONTRACTUAL ARRANGEMENTS WITH ANTERO
PROVIDE SIGNIFICANT GROWTH OPPORTUNITIES
30
• Gathering and Compression
– 20-year agreement
– Dedication of all current and future AR acreage in West Virginia, Ohio, and Pennsylvania, outside of current
third-party commitments
– Option to gather and compress natural gas produced by Antero on any future acquired acreage outside of the
aforementioned areas
– Low-pressure gathering fee of $0.30/Mcf(1)
– High-pressure gathering fee of $0.18/Mcf(1)
– Compression fee of $0.18/Mcf(1)
– Minimum volume commitments on newly constructed high-pressure lines and compressor stations, respectively
– Compression minimum volume commitments of 70% of design capacity
– High-pressure gathering minimum volume commitments of 75% of design capacity
• Processing (“ROFO”)
– Right of first offer on future processing services
– Agreement stipulates that AR has agreed not to procure any gas processing or NGLs fractionation,
transportation or marketing services (other than production subject to a pre-existing dedication) without first
offering AM the right to provide such services
1. All subject to CPI-based adjustments.

32. FORECASTED CASH FLOW AVAILABLE
FOR DISTRIBUTIONS
31
12 Months Ending
($ in millions) December 31, 2015
Antero Midstream Adjusted EBITDA(1) $150 – $160
Less:
Cash interest, net ($2.5)
Expansion capital expenditures ($425 – $450)
Ongoing maintenance capital expenditures ($10 – $15)
Add:
Borrowings and cash to fund expansion capital expenditures $425 – $450
Minimum estimated cash available for distribution $135 – $145
Distributable Cash Flow Coverage Ratio 1.1x – 1.2x
Year-over-Year Distribution Growth(2) 28% – 30%
1. Includes incremental public company expenses.
2. Year-over-year distribution growth reflects the expected distribution in the fourth quarter of 2015 vs. the minimum quarterly distribution (“MQD”) of $0.17/unit (not full year 2015
distributions vs. the annualized MQD).

33. AM OPPORTUNITY SET
32
ACTIVITY CURRENTLY DEDICATED TO AM
Gas Gathering and Compression
(High-Pressure and Low-Pressure)
Condensate and
Liquids Gathering
Fresh Water Distribution System
Processing, Fractionation,
Transportation, Marketing
and Other Services
• Existing dedication of ≈412,000 acres
• Option to expand outside dedicated area, including ROFR
• Minimum Volume Commitments on newly constructed
compression (70%) and high pressure gathering (75%)
Regional Pipeline Project
• Option to participate up to 15% in another regional pipeline
project
• Relevant liquids production can be
added to the existing dedication; AR must request AM to
provide a fee proposal
• Option to acquire at fair market value 100% of AR’s fresh
water distribution assets covering 543,000 net acres,
including ROFO on future services
• AR must request a bid from AM and can only reject if third
party service fees are lower. AM has right to match
lower fee offer.

34. 0%
20%
40%
60%
80%
100%
$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00
Pre-TaxROR(%)
Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas
MARCELLUS ROR% AND GAS PRICE SENSITIVITY
331. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 8,000’ lateral.
• Large portfolio of Highly-Rich Gas/Condensate to Dry Gas locations
• Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime
• Assumes 12/31/2014 WTI strip pricing for 2015-2020, flat thereafter; NGL price 55% of WTI
NYMEX Flat Price Sensitivity(1)
ROR% at Flat 2015-2020 Strip Price
Highly-Rich Gas/Condensate: 44%
Highly-Rich Gas: 30%
Rich Gas: 12%
Dry Gas: 11%
664 Locations
1,010 Locations
628 Locations
889 Locations
Antero Rigs Employed
2015
Drilling Plan

35. 0%
20%
40%
60%
80%
100%
120%
140%
160%
180%
200%
$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00
Pre-TaxROR(%)
Condensate Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas
UTICA ROR% AND GAS PRICE SENSITIVITY
34
NYMEX Flat Price Sensitivity(1)
94 Locations
ROR% at Flat 2015-2020 Strip Price
Condensate: 13%
Highly-Rich Gas/Condensate: 41%
Highly-Rich Gas: 63%
Rich Gas: 47%
Dry Gas: 44%
• Large portfolio of Condensate to Dry Gas locations
• Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime
• Assumes 12/31/2014 WTI strip pricing for 2015-2020, flat thereafter; NGL price 55% of WTI
1. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 8,000’ lateral.
254 Locations
139 Locations
289 Locations
248 Locations
2015
Drilling Plan

36. LARGE UTICA SHALE DRY GAS POSITION
35
 Antero has 212,000 net acres of exposure to Utica dry gas play
− 42,000 net acres in Ohio with net 3P reserves of 2.4 Tcf as of
12/31/2014
− 170,000 net acres in West Virginia and Pennsylvania with net
resource of 11.1 Tcf as of 12/31/2014 (not included in 40.7
Tcfe of net 3P reserves)
− 1,616 locations underlying current Marcellus Shale leasehold
in West Virginia and Pennsylvania as of 12/31/2014
 Other operators have reported strong Utica Shale dry gas
results including the following wells:
Chesapeake
Hubbard BRK #3H
3,550’ Lateral
IP 11.1 MMcf/d
Hess
Porterfield 1H-17
5,000’ Lateral
IP 17.2 MMcf/d
Gulfport
Irons #1-4H
5,714’ Lateral
IP 30.3 MMcf/d
Eclipse
Tippens #6H
5,858’ Lateral
IP 23.2 MMcf/d
Magnum Hunter
Stalder #3UH
5,050’ Lateral
IP 32.5 MMcf/d
Antero
Planned
Utica Well
2015
Well Operator
IP
(MMcf/d)
Lateral
Length (Ft)
Claysville SC #1 Range 59.0 5,420
Stewart Winland 1300U Magnum Hunter 46.5 5,289
Bigfoot 9H Rice Energy 41.7 6,957
Stalder #3UH Magnum Hunter 32.5 5,050
Irons #1-4H Gulfport 30.3 5,714
Pribble 6HU Stone Energy 30.0 3,605
Simms U-5H Gastar 29.4 4,447
Conner 6H Chevron 25.0 6,451
Tippens #6H Eclipse 23.2 5,858
Porterfield 1H-17 Hess 17.2 5,000
Hubbard BRK #3H Chesapeake 11.1 3,550
1. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA.
Magnum Hunter
Stewart Winland 1300U
5,289’ Lateral
IP 46.5 MMcf/d
Range
Claysville SC #1
5,420’ Lateral
IP 59.0 MMcf/d
Chevron
Conner 6H
6,451’ Lateral
IP 25.0 MMcf/d
Gastar
Simms U-5H
4,447’ Lateral
IP 29.4 MMcf/d
Utica Shale Dry Gas Acreage in OH/WV/PA(1)
Rice
Bigfoot 9H
6,957’ Lateral
IP 41.7 MMcf/d
Utica Shale Dry Gas
WV/PA
Net Resource
11.1 Tcf
1,616 Gross Locations
170,000 Net Acres
Utica Shale Dry Gas
Ohio
3P Reserves
2.4 Tcf
289 Gross Locations
42,000 Net Acres
Utica Shale Dry Gas
Total OH/WV/PA
Net Resource
13.5 Tcf
1,905 Gross Locations
212,000 Net Acres
Stone Energy
Pribble 6HU
3,605’ Lateral
IP 30.0 MMcf/d
Chesapeake
Utica Well
Drilling
Rice
Blue Thunder
10H, 12H
≈9,000’ Lateral

37. Needed to make up
for base declines in
conventional and
GOM production
? ??
3,000 Antero
Drilling Locations
Permian
Niobrara
GraniteWash
Barnett
Haynesville
U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE(1)
36
 Low cost, liquids-rich Utica and Marcellus Shales will remain attractive in most commodity price environments
Utica
Shale
SW (Rich)
Marcellus
Shale
1. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI
NE (Dry)
Marcellus
Shale
Eagle Ford
Shale
MARCELLUS & UTICA – ADVANTAGED ECONOMICS

38. CAUTIONARY NOTE
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates
(collectively, “3P”). Antero has provided internally generated estimates for proved, probable and possible reserves in this presentation in
accordance with SEC guidelines and definitions, which have been audited by Antero’s third-party engineers. Unless otherwise noted,
reserve estimates as of December 31, 2014 assume ethane rejection and strip pricing.
Actual quantities that may be ultimately recovered from Antero’s interests may differ substantially from the estimates in this presentation.
Factors affecting ultimate recovery include the scope of Antero’s ongoing drilling program, which will be directly affected by commodity
prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease
expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and
mechanical factors affecting recovery rates.
In this presentation:
• “3P reserves” refer to Antero’s estimated aggregate proved, probable and possible reserves as of December 31, 2014. The SEC
prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of
certainty associated with each reserve category.
• “EUR,” or “Estimated Ultimate Recovery,” refers to Antero’s internal estimates of per well hydrocarbon quantities that may be
potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily
constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management
System or the SEC’s oil and natural gas disclosure rules.
• “Condensate” refers to gas having a heat content between 1250 BTU and 1300 BTU in the Utica Shale.
• “Highly-rich gas/condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1225
BTU and 1250 BTU in the Utica Shale.
• “Highly-rich gas” refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and
1225 BTU in the Utica Shale.
• “Rich gas” refers to gas having a heat content of between 1100 BTU and 1200 BTU.
• “Dry gas” refers to 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.
37
Regarding Hydrocarbon Quantities