Dec. overview

1. Partnership Overview
December 2014

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
• 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 90% expected net production growth in 2014 and
45-50% growth in both 2015 and 2016
• 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
2
• Antero Midstream MLP had no leverage at IPO closing plus $250 million cash
• $1 billion of undrawn borrowing capacity commitments at IPO
• Good high yield access with “Ba3/BB” rated parent (corporate ratings)
• Structured to pursue organic growth opportunities
Premier
1 E&P Sponsorship
“Pure Play”
Marcellus/Utica
Midstream MLP
2
Top Tier MLP
3 Organic Growth
Appalachian
Midstream Value
Chain Opportunity
4
Stacked-Pay Basin
5 Potential Upside
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
ANTERO MIDSTREAM OWNERSHIP STRUCTURE
Midstream Management
3
Antero Resources
Corporation (NYSE: AR)
$13.4 Billion Enterprise Value(1)
Ba3/BB Corporate Rating
Antero Midstream
Partners LP (NYSE: AM)
$3.9 Billion Market Cap.(1)
Public
$1 Billion
Credit Facility
Midstream Entity
Midstream Option
Corporation
Partnership
100% 100% 100%
Marcellus
Gathering
& Compression
Utica
Gathering &
Compression
Option(3)
Antero Fresh Water
Distribution System
Option
69.7% Limited
Partner Interest
15%
Option(2)
Regional Gathering
Pipeline
1. As of 12/8/2014. 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.

5. ANTERO MIDSTREAM PARTNERS OVERVIEW
Midstream Assets
• Gathering and compression assets in core of rapidly
growing Marcellus and Utica Shale plays
– Acreage dedication of ~390,000 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 $1,200
Gathering Pipelines
(Miles) 180 85 265
Compression Capacity
(MMcf/d) 370 - 370
Condensate Gathering Pipelines
(Miles) - 20 20
NTM (9/30/2015) Gathering/
Compression Capex ($MM)(2) $473 $129 $602
Gathering Pipelines
(Miles) 219 108 327
Compression Capacity
(MMcf/d) 835 - 835
Condensate Gathering Pipelines
(Miles) - 27 27
1. Represents inception to date actuals as of 9/30/2014 and 4Q 2014 and next twelve months (NTM) guidance.
2. Includes $14.7 million of maintenance capex. 4

6. ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS
5
Marcellus Gathering & Compression
• 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:
YE 2014 9/30/2015
Gathering Pipelines (Miles) 180 219
Compression Capacity (MMcf/d) 370 835
• 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
WV/PA Utica Dry Gas Gathering & Compression
• Further development upside in 167,000 net acres of
Utica deep rights beneath the Marcellus Shale
− Will require a separate dry gas gathering system
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.

7. 6
ANTERO MIDSTREAM ASSETS – RICH & DRY GAS UTICA
Utica Gathering
• 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:
YE 2014 9/30/2015
Gathering Pipelines (Miles) 85 108
Condensate Pipelines (Miles) 20 27
• Development upside as AR continues to drill, step-out
and add acreage
Utica Compression
• Opportunity to build up to ten new compressor stations
that are planned to support AR development over the
next several years
− Compressor stations are not included in AM NTM
forecast
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.

8. 108
216
281 331
386
531
964
1,000
800
600
400
200
0
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
$136.2
250
200
150
100
50
160
140
120
100
80
60
40
20
0
2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM
9/30/15
EBITDA
HIGH GROWTH THROUGHPUT
Low Pressure Gathering (MMcf/d) Compression (MMcf/d)
High Pressure Gathering (MMcf/d) Antero Midstream Partners EBITDA ($MM)
800
600
400
200
1. Midstream EBITDA does not include EBITDA contribution from fresh water distribution
(1)
7
26 31
40 36 41
116
249
0
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
2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM
9/30/15
Utica Marcellus

9. ORGANIC GROWTH STRATEGY: “BUILD VS. BUY”
8
• Organic growth strategy provides attractive
returns and project economics, while
avoiding the competitive acquisition market
• Industry leading organic growth story
– ~$875 million in estimated capital spent
through 6/30/2014
– $587 million in additional growth capital
forecast for the twelve-month period
ending 9/30/15 (excludes $15 million of
maintenance capital)
Organic EBITDA Multiple vs. Precedent Drop Down Multiples
6.4x
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
12.0x
11.0x
10.0x
9.0x
8.0x
7.0x
6.0x
5.0x
4.0x
3.0x
2.0x
1.0x
Note: Precedent data per IHS Herold’s research and public filings.
1. Antero organic multiple calculated as estimated gathering and compression capital expended through Q2 2014 divided by NTM 9/30/15 projected gathering and compression EBITDA.
2. Selected gathering and compression drop down acquisitions since 1/1/2011. Drop down multiples are based on NTM EBITDA. Source: Barclays.
7.0x 6.9x
5.5x
0.0x
Drop Down Multiple(2)
Median: 8.9x
Value creation for the AM unit holder =
Build at 4-6x EBITDA
vs.
Drop-Down / Buy at 8-12x EBITDA

10. FULL MIDSTREAM VALUE CHAIN POTENTIAL
Fresh Water
Distribution(1)
(Miles) YE 2014 9/30/2015
Marcellus 70 89
Utica 34 36
Total 104 125
Gas Processing
Stabilization
Compression
End
Users
(MMcf/d) YE 2014 9/30/2015
Marcellus 370 835
Utica 0 0
Total 370 835
Y-Grade Pipeline
Regional Gas Pipelines
Miles Capacity In-Service
Unnamed Regional
Pipeline
50 1.4 Bcf/d 4Q 2015
End
Users
End
Users
Condensate Gathering
(Miles) YE 2014 9/30/2015
Utica 20 27
Low Pressure Gathering
Well Pad
(Miles) YE 2014 9/30/2015
Marcellus 110 130
Utica 51 72
Total 161 202
NGL Product Pipelines
(Ethane, Propane,
Butane, etc.)
AM has option to participate
in processing, fractionation,
terminaling and storage
projects offered to AR
Long-Haul Interstate
Pipeline
Fractionation
(De-ethanization)
Inter
Connect
Terminals
and
Storage
AM Owned Assets
AM Option Assets
1. Currently owned by AR; AM holds option to purchase 100% of assets at fair market value. 9

11. AM OPTION – FRESH WATER DISTRIBUTION SYSTEMS
10
• Currently owned by AR – AM holds option to purchase 100% of assets at fair market value
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:
Marcellus Water System YE 2014 9/30/2015
Buried Water Pipeline (Miles) 107 127
Fresh Water Storage Impoundments 26 32
NTM 9/30/2015 Projected Wells 162
Water Fees per Well ($)(1) $600K -
Utica Fresh Water Distribution System
$800K
• Provides fresh water to support ongoing Utica completion activity
• Year-round water supply sources: local reservoirs and rivers
• Significant growth projected over the next twelve months as
summarized below:
Utica Water System YE 2014 9/30/2015
Buried Water Pipeline (Miles) 48 63
Fresh Water Storage
8 13
Impoundments
NTM 9/30/2015 Projected Wells 56
Water Fees per Well ($)(1) $600K -
$800K
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.
OHIO

12. ESTIMATED PROJECT ECONOMICS BY SEGMENT
25%
15%
10%
25%
30%
10%
15%
35%
25%
20%
35%
25%
20%
40%
40%
30%
20%
10%
0%
Internal Rate of Return
11
DRY GAS LOCATIONS RICH GAS LOCATIONS
HIGHLY
RICH GAS
LOCATIONS
Project Economics by Segment(1)
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% 10% - 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%
9/30/15 NTM Capex(2) Total
Marcellus $473.3 $155.9 $131.8 $185.6 -
Utica 114.0 89.8 15.9 - 8.3
Expansion Capex $587.3 $245.7 $147.7 $185.6 $8.3
% of Capex 100% 42% 25% 32% 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 $14.7 million of maintenance capex.
Wtd. Avg. 23% IRR
AM Option Opportunities

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

14. 13
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

15. 14
Antero Resources (NYSE: AR)
Overview

16. 15
LEADING UNCONVENTIONAL BUSINESS MODEL
Most Active Operator
in Appalachia
Most Active
Land Organization
in Appalachia
Largest Firm Transport
and Processing
Portfolio in Appalachia
Highest Growth
Large Cap E&P
Largest Gas Hedge
Position in U.S. E&P +
Strong Financial
Liquidity
Largest Liquids-Rich
Core Position in
Appalachia
Highest Realizations
and Margins Among
Large Cap
Appalachian Peers
Growth Land
Liquidity
Midstream
Drilling
MLP (NYSE: AM)
Highlights
Substantial Value in
Midstream Business
Realizations
Takeaway
Liquids-Rich
1
2 3
4
5
7 6
8
Premier Appalachian
E&P Company
Run by Co-Founders

17. DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA
25
20
15
10
5
SW Marcellus + Utica Rigs(3)
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. Locations as of 9/30/2014 adjusted for additional 130 locations acquired through 11/3/2014.
3. Antero and industry rig locations and rig count as of 11/28/2014 per RigData.
16
COMBINED TOTAL – 6/30/14 RESERVES
Assumes Ethane Rejection
Net Proved Reserves 9.1 Tcfe
Net 3P Reserves 37.5 Tcfe
Pre-Tax 3P PV-10 $25.9 Bn
Net 3P Reserves & Resource 47.0 Tcfe
Net 3P Liquids 966 MMBbls
% Liquids – Net 3P 15%
3Q 2014 Net Production 1,080 MMcfe/d
- 3Q 2014 Net Liquids 25,000 Bbl/d
Net Acres(1) 524,000
Undrilled 3P Locations(2) 5,244
UTICA SHALE CORE
Net Proved Reserves 537 Bcfe
Net 3P Reserves 6.4 Tcfe
Pre-Tax 3P PV-10 $6.5 Bn
Net Acres 135,000
Undrilled 3P Locations(2) 997
MARCELLUS SHALE CORE
Net Proved Reserves 8.5 Tcfe
Net 3P Reserves 26.4 Tcfe
Pre-Tax 3P PV-10 $19.4 Bn
Net Acres 389,000
Undrilled 3P Locations 3,131
UPPER DEVONIAN SHALE
Net Proved Reserves 40 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 9.5 Tcf
Net Acres 167,000
Undrilled Locations 1,390
0
Rig Count
Operators

18. GROWTH – STRONG TRACK RECORD
10,000
8,000
6,000
4,000
2,000
Marcellus Utica
677
2,844
4,283
9,107
(1) (1) (1)
OPERATED GROSS WELLS SPUD EBITDAX ($MM)
225
200
175
150
125
100
75
50
25
Marcellus Utica
29 36
86
1. 2012, 2013 and 6/30/2014 proved reserves assuming ethane rejection.
2. Midpoint of production guidance of 990-1,010 MMcfe/d for 2014.
3. Based on 45-50% production growth targets for 2015 and 2016.
4. Per current First Call median estimate from Bloomberg.
2,400
1,800
1,200
600
0
2010 2011 2012 2013 1H 2014 3Q
2014
1,237
4Q
2014
2015E 2016E
Marcellus Utica Guidance
30 124 239
522
(2)
838
1,500
2,200
(3) (3)
1,080
0
7,632
2010 2011 2012 2013 6/30/2014
45-50% Annual
Growth Target
$1,145
17
NET PROVED SEC RESERVES (Bcfe) AVERAGE NET DAILY PRODUCTION (MMcfe/d)
0
162
215
2010 2011 2012 2013 2014E
$1,400
$1,200
$1,000
$800
$600
$400
$200
$0
$28
$160
$285
$649
2010 2011 2012 2013 2014E
(4)
92% Growth –
Guidance of
1,000 MMcfe/d
for 2014E

19. LAND – MOST ACTIVE LAND ORGANIZATION
IN APPALACHIA
 Assembled a 524,000 net acre position in the core of the Marcellus and Utica shale plays over the past 6 years
Dec 2008 Dec 2011 Dec 2014
December 2008
Net Acreage 118,000
Net Production (MMcfe/d) NM
3P Reserves (Bcfe) NM
3P PV-10 ($MM) NM
Rigs Running NM
December 2011(1)
Net Acreage 214,000
Net Production (MMcfe/d) 167
3P Reserves (Bcfe) 18,400
3P PV-10 ($MM) $9,000
Rigs Running 5
December 2014(1)
Net Acreage 524,000
Net Production (MMcfe/d) 1,080
6/30/14 3P Reserves (Bcfe) 37,500
6/30/14 3P PV-10 ($MM) $25,900
Rigs Running 21
600,000
500,000
400,000
300,000
200,000
100,000
Antero Net Acreage
1. Reserves and PV-10 data for December 2014 reflect data as of 6/30/2014 and for December 2011 reflects data as of 12/31/2011. Daily net production for December 2011 and December 2014 is for
third quarter respectively.
18
118,000 118,000 118,000
162,000 189,000 213,000
285,000
371,000
420,000 450,000
486,000
524,000
0
12/2008 12/2009 6/2010 12/2010 6/2011 12/2011 6/2012 12/2012 6/2013 12/2013 6/2014 12/2014
Utica Marcellus

20. 19
LIQUIDS-RICH – LARGEST CORE POSITION
 Antero has the largest liquids-rich core position in Appalachia ≈366,000 net acres
(1)
Source: Core outlines and peer net acreage positions based on peer presentations, news releases and 10-K/10-Qs.
1. Pending Southwestern Energy acquisition of Chesapeake southern Marcellus acreage position.

21. TAKEAWAY – LARGEST FIRM TRANSPORTATION AND
PROCESSING PORTFOLIO IN APPALACHIA
Antero Long Term Firm Processing & Takeaway Position (2018) – Accessing Favorable Markets
Dom South(1)
$(1.32) /
$(1.16)
Odebrecht / Braskem
30 MBbl/d Commitment
Ascent Cracker
(Pending Final
Investment Decision)
Mariner East II
62 MBbl/d Commitment(2)
Marcus Hook Export
Shell
25 MBbl/d Commitment
Beaver County Cracker
(Pending Final
Investment Decision)
Chicago(1)
+$0.18 /
$(0.04)
Sabine Pass (Trains 1-4)
50 MMcf/d per Train
CGTLA(1)
$(0.10) /
$(0.09)
1. 2015 and 2016 futures basis, respectively, provided by Wells Fargo dated 11/28/2014. 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.
TCO(1)
$(0.29) /
$(0.47)
20
4 Bcf/d
Firm Gas
Takeaway
By 2018
Cove Point

22. LIQUIDITY – LARGEST GAS HEDGE POSITION IN U.S. E&P
+ STRONG FINANCIAL LIQUIDITY
 ~$1,109 million mark-to-market unrealized gain based on current prices
 1.8 Tcfe hedged from October 1, 2014 through year-end 2019 and 256 Bcf of TCO basis hedges from 2015 to 2017
COMMODITY HEDGE POSITION
BBtu/d $/MMBtu
$4.97
Mark-to-Market Value(2)
$4.38 $4.46 $4.34 $4.50 $4.41
$4.07 $3.82 $3.83 $3.96 $4.09 $4.21
$72 MM $345 MM $349 MM $123 MM $160 MM $60 MM
788 1,168 943 780 1,073 818
$7.00
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
$0.00
1,200
1,000
800
600
400
200
0
4Q 2014 2015 2016 2017 2018 2019
21
Hedged Volume Average Index Hedge Price(1) Current NYMEX Strip(2)
AR LIQUIDITY POSITION ($MM) AM LIQUIDITY POSITION ($MM)
$3,000
$2,012
($1,505)
($332) $6 $843
$3,000
$2,500
$2,000
$1,500
$1,000
$500
$0
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
$1,000
$3,000
$2,500
$2,000
$1,500
$1,000
$500
1. Reflects weighted average index price per annum based on volumes hedged and 6:1 gas to oil ratio. Antero has hedged 3,000 Bbl/d of oil for 2014 and 2,000 Bbl/d of propane for 2015.
2. As of 11/28/2014.
3. Percentage of net gas equivalent production target hedged for respective years.
$1,250
$0 $0 $0
$250
$0
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
≈ 78% of 2015E
Target
Production(3)
≈ 43% 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

23. REALIZATIONS – HIGHEST REALIZATIONS & MARGINS
AMONG LARGE-CAP APPALACHIAN PEERS
3Q 2014 Natural Gas Realizations ($/Mcf)
Average 3Q 2014
Realized Gas Price(3)
TCO 39% $4.06 $(0.12) $0.48 $0.58 $5.00 $0.94
Dom South/TETCO 41% $4.06 $(1.83) $0.32 $1.10 $3.65 $(0.41)
Gulf Coast(1) 10% $4.06 $(0.25) $0.39 $0.01 $4.21 $0.15
Chicago 10% $4.06 $(0.07) $0.52 - $4.51 $0.45
Total Wtd. Avg. 100% $4.06 $(0.84) $0.41 $0.68 $4.31 $0.25
3Q 2014 Natural Gas Realizations(3) 3Q 2014 Price Realization & EBITDAX Margin vs F&D(4)
$4.16 $3.97
Average
BTU Upgrade
$4.96
$2.93
$0.58
Average
Premium/
Discount
$3.25
Hedge
Effect
$4.48
$2.40
$2.64
$2.11 $2.09
$0.95 $0.74 $0.77 $0.81
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
$0.00
Antero Peer 1 Peer 2 Peer 3 Peer 4
$/Mcfe
Region
3Q 2014
% Sales
Average
NYMEX Price
Average
Differential(2)
$4.31
$4.12
$3.66 $3.62 $3.60
$2.98 $2.87 $2.75
$6.00
$4.00
$2.00
$0.00
AR EQT GPOR RRC CNX RICE ECR COG
1. Gulf Coast differential represents contractual deduct to NYMEX-based sales.
2. Includes firm sales.
3. Includes natural gas hedges.
4. Source: Public data from 3Q 2014 10-Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp. and Range Resources.
5. Includes realized hedge gains and losses. Operating costs include lease operating expenses, production taxes, gathering, processing and firm transport costs and general and administrative costs. 4-year
LOE Production Taxes GPT G&A EBITDAX 4-year Avg. All-in F&D ($/Mcfe)
22
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.
$/Mcf
3Q 2014 NYMEX = $4.06/Mcf
AR Peer 1 Peer 2 3

24. REALIZATIONS – REALIZED PRICE “ROAD MAP”
 Antero is forecasting realized gas prices including hedges at a premium to NYMEX strip prices for Q4 2014 through 2016, assuming
current strip prices and basis, existing firm transportation and hedges, and targeted 2015 and 2016 production figures
4Q 2014E 2015E 2016E
$(0.29)/MMBtu
210,000 MMBtu/d
@ $5.24/MMBtu
DOM S
28% DOM S
$(0.46)/MMBtu
510,000 MMBtu/d
@ $3.87/MMBtu(3)
22% DOM S
8%
TETCO M2
4% TETCO M2
8%
TETCO M2
10%
TCO
43%
TCO
23%
TCO
15%
NYMEX
9%
NYMEX
7%
NYMEX
10%
Gulf Coast
18% Gulf Coast
47%
Chicago
16% Chicago
22%
Chicago
10%
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
4Q 2014
Basis(1)
$(0.07)/MMBtu
($/Mcf) 4Q 2014E 2015E 2016E
NYMEX Strip Price(1) $4.00 $3.82 $3.83
Basis Differential to NYMEX(1) $(0.52) $(0.45) $(0.35)
BTU Upgrade(5) $0.35 $0.34 $0.35
Estimated Realized Hedge Gains $0.67 $0.63 $0.45
Realized Gas Price with Hedges $4.50 $4.34 $4.28
Premium to NYMEX +$0.50 +$0.52 +$0.45
Liquids Impact(6) +$0.54 +$0.50 +$0.58
Premium to NYMEX w/ Liquids +$1.04 +$1.02 +$1.03
Realized Gas-Equivalent Price $5.04 $4.84 $4.86
265,000 MMBtu/d
@ $3.89/MMBtu(4)
4. Represents 60,000 MMBtu/d of TCO index hedges and 205,000 MMBtu/d of TCO basis
hedges that are matched with NYMEX hedges for presentation purposes.
5. Assumes ethane rejection resulting in 1100 BTU residue sales gas.
6. Represents equivalent price upgrade associated with NGL (C3+) and oil production.
1. Based on 11/28/2014 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)
4Q 2014
Hedges
2015
Hedges
2016
Hedges
Marketed % of Target Residue Gas Production
+$0.33/MMBtu
$(0.25)/MMBtu(2)
$(1.63)/MMBtu
+$0.18/MMBtu
$(0.25)/MMBtu(2)
$(1.32)/MMBtu
$(0.04)/MMBtu
$(0.25)/MMBtu(2)
$(1.16)/MMBtu
$(0.10)/MMBtu
$(0.09)/MMBtu
340,000 MMBtu/d
@ $4.18/MMBtu
160,000 MMBtu/d
@ $5.27/MMBtu
40,000 MMBtu/d
@ $4.00/MMBtu
230,000 MMBtu/d
@ $5.60/MMBtu
170,000 MMBtu/d
@ $4.09/MMBtu
272,500 MMBtu/d
@ $5.35/MMBtu
$0.56/Mcfe in estimated hedge gains(1)
70% exposure to favorable price indices
$0.67/Mcfe in estimated hedge gains(1)
68% exposure to favorable price indices
$0.43/Mcfe in estimated hedge gains(1)
82% exposure to favorable price indices
$(1.57)/MMBtu
$(1.18)/MMBtu
$(1.05)/MMBtu
Wtd. Avg.
Basis ($0.52)
770,000 MMBtu/d
@ $4.97/MMBtu
Wtd. Avg.
Basis $(0.45)
1,160,000 MMBtu/d
@ $4.34/MMBtu
Wtd. Avg.
Basis $(0.35)
942,500 MMBtu/d
@ $4.46/MMBtu
10,000 MMBtu/d
@ $3.98/MMBtu
23
380,000 MMBtu/d
@ $3.88/MMBtu
235,000 MMBtu/d
@ $4.00/MMBtu
50,000 MMBtu/d
@ $4.72/MMBtu

25. MULTI-YEAR DRILLING INVENTORY SUPPORTS
LOW RISK, HIGH RETURN GROWTH PROFILE
100%
75%
50%
25%
80%
60%
40%
20%
0%
248
143 87
265 254
14%
57%
76%
50% 45%
300
250
200
150
100
50
0
100%
75%
50%
25%
0%
Condensate Highly-Rich
Gas/
Condensate
Highly-Rich
Gas
Rich Gas Dry Gas
Total 3P Locations
ROR
Locations ROR
MARCELLUS SSL WELL ECONOMICS(1)
727
896
633
875
55%
37%
17% 16%
1000
800
600
400
200
0
0%
Highly-Rich
Gas/
Condensate
Highly-Rich
Gas
Rich Gas Dry Gas
Total 3PLlocations
ROR
Locations ROR
Large 3P Drilling Inventory of High Return Projects(3)
71%
59%
57%
21%
Internal Rate of Return (%)
37%
1. Pre-tax well economics based on 11/28/2014 natural gas and WTI strip pricing for 2014-2019, flat thereafter, NGLs at 55% of oil price and applicable firm transportation costs.
2. Adjusted for additional 130 gross locations acquired as of 11/3/2014.
3. Source: Credit Suisse report dated October 2014 – After-tax internal rate of return based on 10/27/2014 strip pricing.
24
UTICA WELL ECONOMICS(1)(2)
1,000
 72% of Marcellus locations are processable (1100-plus Btu)  75% of Utica locations are processable (1100-plus Btu)
3,000 Antero Liquids-Rich Locations
37%
2H 2014 / 2015
Drilling Plan
1,129 Antero Dry Gas Locations

26. WORLD CLASS MARCELLUS SHALE
DEVELOPMENT PROJECT
100% operated
Operating 14 drilling rigs
including 5 intermediate rigs
389,000 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
339 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
BEE LEWIS PAD
30-Day Rate
4-well combined
30-Day Rate of
67 MMcfe/d
(26% liquids)
Net production of 937 MMcfe/d in
3Q 2014, including 17,300 Bbl/d
of liquids
3,131 future drilling locations in
the Marcellus (2,256 or 72% are
processable rich gas)
26.4 Tcfe of net 3P (18% liquids),
includes 8.5 Tcfe of proved
reserves (assuming ethane
rejection) Highly-Rich Gas
119,000 Net Acres
896 Gross Locations
RJ SMITH PAD
30-Day Rate
4-well combined
30-Day Rate of
56 MMcfe/d
(21% liquids)
NERO UNIT
30-Day Rate
1H: 18.2 MMcfe/d
(27% liquids)
Rich Gas
91,000 Net Acres
633 Gross Locations
Dry Gas
104,000 Net Acres
875 Gross Locations
Highly-Rich/Condensate
75,000 Net Acres
727 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.
25
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: 21.8 MMcfe/d
(26% liquids)
HINTERER UNIT
30-Day Rate
1H: 12.9 MMcfe/d
(20% liquids)

27. LEADING UTICA SHALE CORE POSITION DELIVERS
CONDENSATE AND NGLS
• 100% operated
• Operating 7 rigs including 2 intermediate rigs
• 135,000 net acres in the core rich gas/
condensate window (76% includes processable
rich gas assuming an 1100 Btu cutoff)
– 20% HBP with additional 79% not expiring
for 5+ years
• 44 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
expected in-service December 2014 with a
capacity of 120 MMcf/d
• 997 future gross drilling locations (743 or 75%
are processable gas)
• 6.4 Tcfe of net 3P (13% liquids), includes
537 Bcfe of proved reserves (assuming ethane
rejection)
GULFPORT
24-Hour IP
McCort1-28H, 2-28H,
Stutzman 1-14H
Average 13.1 MMcf/d
+ 922 Bbl/d NGL
+ 21 Bbl/d Oil
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.
26
Utica Shale Industry Activity(1)
Cadiz
Processing
Plant
NORMAN UNIT
30-Day Rate
2 wells average
17.2 MMcfe/d
(17% liquids)
RUBEL UNIT
30-Day Rate
3 wells average
17.3 MMcfe/d
(22% liquids)
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
24.3 MMcfe/d
(22% liquids)
Highly-Rich/Cond
19,000 Net Acres
143 Gross Locations
Highly-Rich Gas
20,000 Net Acres
87 Gross Locations
Rich Gas
31,000 Net Acres
265 Gross Locations
Dry Gas
32,000 Net Acres
254 Gross Locations
NEUHART UNIT 3H
30-Day Rate
16.4 MMcfe/d
(56% liquids)
Condensate
33,000 Net Acres
248 Gross Locations
DOLLISON UNIT 1H
30-Day Rate
19.0 MMcfe/d
(36% liquids)
MYRON UNIT 1H
30-Day Rate
26.0 MMcfe/d
(50% liquids)
Seneca
Processing
Complex
LAW UNIT
30-Day Rate
2 wells average
15.7 MMcfe/d
(48% liquids)
SCHAFER UNIT
30-Day Rate(2)
2 wells average
13.7 MMcfe/d
(46% liquids)
McDOUGAL UNIT
30-Day Rate
2 wells average
20.6 MMcfe/d
(14% liquids)

28. APPENDIX
27

29. 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
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
average throughput
to be replaced with
production volume
LTM Production
NTM Production Forecast
Average LTM Production
LTM Forecast Period
Decline of LTM
from new well
connections
• NTM Maintenance Capital ($ in millions)
NTM Wells to be placed online 183
Wells required to maintain LTM throughput 10.3
% of total wells to be placed online 5.6%
NTM Low-Pressure Gathering Capital $260.4
Forecasted NTM Maintenance Capital $14.7
Source: Antero Midstream S-1; maintenance capital calculation per management estimates. 28

30. CONTRACTUAL ARRANGEMENTS WITH ANTERO
PROVIDE SIGNIFICANT GROWTH OPPORTUNITIES
29
• 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.

31. FORECASTED CASH FLOW AVAILABLE
FOR DISTRIBUTIONS
30
Next 12 Months Ending
($ in millions) September 30, 2015
Antero Midstream Adjusted EBITDA(1) $136.2
Less:
Cash interest, net ($2.7)
Expansion capital expenditures ($587.3)
Ongoing maintenance capital expenditures ($14.7)
Add:
Borrowings and cash to fund expansion capital expenditures $587.3
Minimum estimated cash available for distribution $118.8
Assumed Coverage 1.15x
Distributed Cash Flow $103.3
Distribution per Unit(2) $0.68
1. Includes incremental public company expenses.
2. Based on 151.9 million units outstanding.

32. AM OPPORTUNITY SET
31
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 ≈390,000 acres
• Option to expand outside dedicated area, including ROFR
• Minimum Volume Commitments on newly constructed
compression (70%) and high pressure gathering (75%)
• 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 524,000 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.
Regional Pipeline Projects • Option to participate up to 15% in another regional pipeline
project

33. MARCELLUS ROR% AND GAS PRICE SENSITIVITY
• 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 11/28/2014 WTI strip pricing for 2014-2019, flat thereafter; NGL price of 55% of WTI
NYMEX Price Sensitivity(1)
150.0%
125.0%
100.0%
75.0%
50.0%
25.0%
0.0%
ROR% at 5-Year Strip
Highly-Rich Gas/Condensate: 55%
Highly-Rich Gas: 37%
Rich Gas: 17%
Dry Gas: 16%
2H 2014 / 2015
Drilling Plan
$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00
Pre-Tax ROR (%)
Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas
727 Locations
896 Locations
633 Locations
875 Locations
Antero Rigs Employed
32 1. Assumes 11/28/2014 strip pricing, market differentials and relevant transportation cost.

34. UTICA ROR% AND GAS PRICE SENSITIVITY
• 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 11/28/2014 WTI strip pricing for 2014-2019, flat thereafter; NGL price of 55% of WTI
200.0%
150.0%
100.0%
50.0%
0.0%
254 Locations
$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00
Condensate Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas Antero Rigs Employed
33
NYMEX Price Sensitivity(1)
87 Locations
ROR% at 5-Year Strip
Condensate: 14%
Highly-Rich Gas/Condensate: 57%
Highly-Rich Gas: 76%
Rich Gas: 50%
Dry Gas: 45%
1. Assumes 11/28/2014 strip pricing, market differentials and relevant transportation cost.
265 Locations
143 Locations
248 Locations
2H 2014 / 2015
Drilling Plan

35. LARGE UTICA SHALE DRY GAS POSITION
34
 Antero has ≈200,000 net acres of exposure to Utica dry gas
play
− 32,000 net acres in Ohio with net 3P reserves of 1.9 Tcf as of
6/30/2014
− 167,000 net acres in West Virginia and Pennsylvania with net
resource of 9.5 Tcf as of 6/30/2014 (not included in 37.5 Tcfe
of net 3P reserves)
− 1,390 locations underlying current Marcellus Shale leasehold
in West Virginia and Pennsylvania as of 9/30/2014
 Expect to drill and complete a Utica Shale dry gas well in West
Virginia in 2015
 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
Utica Shale Dry Gas Acreage in OH/WV/PA(1)
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
IP
(MMcf/d)
Lateral
Length (Ft)
Well Operator 2015
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 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
Utica Well
Flow Testing
Chevron
Conner 6H
6,451’ Lateral
IP 25.0 MMcf/d
Gastar
Simms U-5H
4,447’ Lateral
IP 29.4 MMcf/d
Rice
Bigfoot 9H
6,957’ Lateral
IP 41.7 MMcf/d
Utica Shale Dry Gas
WV/PA
Net Resource
9.5 Tcf
1,390 Gross Locations
167,000 Net Acres
Utica Shale Dry Gas
Ohio
3P Reserves
1.9 Tcf
226 Gross Locations
32,000 Net Acres
Utica Shale Dry Gas
Total OH/WV/PA
Net Resource
11.4 Tcf
1,616 Gross Locations
≈200,000 Net Acres
Stone Energy
Pribble 6HU
3,605’ Lateral
IP ≈30 MMcf/d
Chesapeake
Utica Well
Drilling
Rice
Blue Thunder
10H, 12H
≈9,000’ Lateral

36. MARCELLUS & UTICA – ADVANTAGED ECONOMICS
3,000 Antero
Drilling Locations
Needed to make up
for base declines in
conventional and
GOM production
Permian
NE (Dry)
Marcellus
Shale
? ? ?
Niobrara
Granite Wash
Barnett
Haynesville
U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE(1)
35
 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
Eagle Ford
Shale

37. 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 June 30, 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 June 30, 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.
36
Regarding Hydrocarbon Quantities