Company Overview October 2013

1. Company Overview
October 2013

2. FORWARD-LOOKING STATEMENTS
This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities,
events or developments that Antero Resources Corporation and its subsidiaries (collectively, the “Company” or “Antero”) expects, believes or
anticipates 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, forwardlooking statements contained in this presentation specifically include estimates of the Company’s reserves, expectations of plans, strategies,
objectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program, production, hedging
activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made
by the Company 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 Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking
statements. These include the factors discussed or referenced in the Company’s Registration Statement on Form S-1 (File No. 333 – 189284)
(the “Registration Statement”) with the U.S. Securities and Exchange Commission (the “SEC”) and in the Company’s subsequent filings with the
SEC.
The Company cautions 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 exploration for and development, production, gathering and sale of natural gas
and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and
services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil
reserves and 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 “Risk Factors” in the Registration Statement and in the Company’s subsequent filings with the SEC.
Any forward-looking statement speaks only as of the date on which such statement is made and the Company 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: A “PURE PLAY” ON THE MARCELLUS / UTICA
Critical Mass In Two
World Class Shale Plays
● Marcellus is the largest gas field in the U.S. – 20 Bcf/d projected by 2020(1)
● Antero has 28 Tcfe of 3P reserves in Marcellus and Utica Shales
● 640 MMcfe/d of current net production including 11,500 Bbl/d of liquids
− Additional 160 MMcfe/d of constrained/shut-in net production
Market Leading Growth
● 220% Appalachian production CAGR since 2010
● Most active driller in Marcellus Shale – 15 rigs running
● Drilled 7 of the top 8 initial producers in the Utica Shale – 4 rigs running
Industry Leading Capital
Efficiency and Recycle Ratio
Significant Emphasis on
Takeaway and
Liquids Processing
Liquidity and Hedge
Position Support High
Growth Story
Outstanding
Management Team
1. Tudor Pickering Holt research report dated 9/3/2013.
2. Three year average through 2012; pro forma for Arkoma and Piceance divestitures.
● Low development cost leader: $1.03/Mcfe(2)
● Industry leading growth-adjusted recycle ratio: 6.1x(2)
● Top quartile return on productive capital: 27% for 2013E
● 1 Bcf/d of processing capacity by 2014, 1.3 Bcf/d of firm transport by
2015 and 20,000 Bbl/d of ethane takeaway by 2014
● Liquids expected to grow from 12% of production volume today due to
focus on liquids-rich development
● ~$2.3 billion pro forma liquidity with current $1.75 billion bank commitment
● 1.1 Tcfe hedged through 2019 at an average $5.02 / MMBtu NYMEX
● Midstream MLP potential adds a low cost equity financing vehicle
● Over 30 years as a team (over 20 years in unconventional)
● “Shale Pioneers” – early mover and driller of over 450 horizontal shale
wells in the Barnett, Woodford, Marcellus and Utica Shales
● Management incentivized by increasing equity ownership with stock
price appreciation; no equity dilution
2

4. PREMIER UNCONVENTIONAL RESOURCE PLATFORM
TOTAL – 6/30/13 RESERVES(1)
Assumes Ethane Rejection
Net Proved Reserves(1)
Net 3P Reserves(1)
Pre-Tax 3P PV-10(1)
667 MMBbls
14%
640 MMcfe/d
458 MMcfe/d
431,000
4,576
Net Proved Reserves(1)
Net 3P Reserves (1)
Pre-Tax 3P PV-10(1)
6.0 Tcfe
18.7 Tcfe
$13,656 MM
% Liquids – Net 3P
Current Net Production
Undrilled 3P Locations
6.3 Tcfe
27.7 Tcfe
$19,100 MM
Net 3P Liquids
% Liquids – Net 3P
Current Net Production(2)
2Q 2013 Net Production
Net Acreage(3)
Undrilled 3P Locations
“Pure-Play” Appalachian-Focused Shale Company
A MARCELLUS SHALE
15%
551 MMcfe/d
2,941
B UTICA SHALE – LIQUIDS RICH
Net Proved Reserves(1)
Net 3P Reserves (1)
Pre-Tax 3P PV-10(1)
279 Bcfe
5.3 Tcfe
$5,223 MM
% Liquids – Net 3P
Current Net Production
Undrilled 3P Locations
19%
85 MMcfe/d
720
•
100% operated
•
Stable acreage base
− Marcellus Shale: 50% HBP, with additional 28%
not expiring for 5+ years
− Utica Shale: 20% HBP, with additional 79% not
expiring for 5+ years
•
Portfolio flexibility across dry gas to liquids-rich and
condensate windows
•
Significant investment in midstream infrastructure and
secured takeaway capacity
•
Financial flexibility to pursue planned 2013 and 2014
development drilling activities
•
Full scale development underway
− 19 rigs currently operating
A
C
B
UPPER DEVONIAN SHALE
Net Proved Reserves(1)
Net 3P Reserves (1)
Pre-Tax 3P PV-10(1)
% Liquids – Net 3P
Current Net Production
Undrilled 3P Locations
D
D
UTICA SHALE – DRY GAS
44 Bcfe
3.8 Tcfe
$220 MM
6%
4 MMcfe/d
915
Appalachia Rig Count vs. Peers(4)
20
15
Rigs
C
10
19
4
15
10
6
5
2.
3.
4.
COG
RRC
0
Antero
EQT
Marcellus Shale
1.
5
Utica Shale
Proved, probable, and possible reserves as of June 30, 2013, assuming ethane rejection using SEC methodology and strip pricing. Evaluations prepared by our internal reserve engineers and audited by DeGolyer & MacNaughton (D&M).
Pre-Tax 3P PV-10 is a non-GAAP financial measure. For discussion of PV-10, please read the final prospectus.
Represents the average net daily production for the period from September 1, 2013 through September 25, 2013. Current constrained/shut-in net production of 160 MMcfe/d.
All net acres allocated to the Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as they are stacked pay formations attributable to the same leases.
RigData, other industry sources as of 9/20/2013.
3

5. STRONG TRACK RECORD OF GROWTH
AVERAGE NET DAILY PRODUCTION (MMcfe/d)
Woodford
Piceance
Marcellus
Utica
Marcellus
500
383
700
640
85
Sold Woodford
and Piceance
400
600
85
458
100
31
87
105
555
133
2006
2007
100
2008
2009
2010
2011
2012
NET PROVED SEC RESERVES (Bcfe)
Woodford
Piceance
1Q
2013
2Q Current
2013
(2)
Marcellus(3)
30
2010
2011
Woodford
6,282
5,017 4,929
5,000
0
Piceance
680
87
100
2007
2008
Marcellus
126
85
96
Utica
197
119
91
Economic
Crisis
66
18
25
2009
Current
50
1,141
235
2006
2Q 2013
161
75
2,000
1Q 2013
175
150
3,231
3,000
2012
200
125
4,000
555
124
Utica
6,000
0
239
OPERATED GROSS WELLS SPUD
7,000
1,000
300
200
6
0
383
400
244
200
458
500
334
300
Utica
640
700
600
APPALACHIAN PRODUCTION (MMcfe/d)
2010
2011
2012
6/30/2013
0
2006
2007
2008
2009
2010
2011
2012
2013E
2014E
1. CAGR = Compound Annual Growth Rate.
2. Proved reserves for 2006, 2007, and 2008 represent previously effective SEC methodology. 2009, 2010, 2011, 2012 and mid-year 2013 proved reserves based on current SEC reserve methodology and SEC pricing and are audited by
independent third-party engineers; excludes Arkoma Basin reserves which were sold on June 20, 2012 and Piceance Basin reserves which were sold on December 21, 2012.
3. Includes 44 Bcfe of Upper Devonian Shale proved reserves.
4

6. MULTI-YEAR DRILLING INVENTORY SUPPORTS
LOW RISK, HIGH-RETURN GROWTH PROFILE
986
600
505
40%
400
58%
38%
20%
0%
800
673
Highly-Rich
Gas/
Condensate
Highly-Rich
Gas
Rich Gas
Locations
200
29%
Dry Gas
250%
200%
ROR
ROR
60%
777
93%
1000
1,000
Gross Locations
100%
80%
UTICA WELL ECONOMICS(1)
208
220%
150%
250
198
177
194%
100%
200
137
150
100
114%
50%
0
0%
ROR
 66% of Marcellus locations are processable (1100-plus Btu)
50
40%
Highly-Rich
Gas/
Condensate
Highly-Rich
Gas
Rich Gas
Locations
Gross Locations
MARCELLUS WELL ECONOMICS(1)
0
Dry Gas
ROR
 75% of Utica locations are processable (1100-plus Btu)
Large Inventory of Low Breakeven Projects(2)
$6.75
$ / MMBtu NYMEX (Gas)
$7.00
$6.00
$5.00
Locations
$3.26
$4.00 3 Yr Strip - $3.82/MMBtu(3)
$3.00
1,450
$2.00
$1.00
$0.00
$5.05
986
208
Locations
505
Locations Locations
$0.00
$0.00
$0.00
$0.29
335 $2.47 $2.50
$2.94
$3.27 $3.34
$3.65
$3.66
$3.70 $3.75
$3.81
$4.13
$5.37
$5.49
$4.25
$3.02
Locations
$1.35
$0.62
`
1. Well economics based on 6/30/2013 3P reserves.
2. Source: Credit Suisse report dated 06/18/2013 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI.
3. 3-year STRIP as of 9/25/2013.
5

7. LOW DEVELOPMENT COST DRIVES
BEST-IN-CLASS RECYCLE RATIOS
3-Year All-in Development Costs ($/Mcfe) through 2012
$/Mcfe
$4.00
Antero
$3.00
$2.00
$1.00
$1.03
$1.14
Appalachia-Focused Peers
$1.41
$1.71
$1.57
$0.00
Source: Proved developed F&D research prepared by JP Morgan Research report dated 07/22/2013. Defined as total drilling and completion capital expenditures for the period divided by PDP and PDNP volumes added after adding back
production for the period. Includes all drilling and completion costs but excludes land and acquisition costs for all companies.
1. Antero internal estimate using JP Morgan development cost methodology; excludes Arkoma and Piceance operations.
2. Antero estimate based on public information; includes Arkoma and Piceance operations.
3-Year Average Growth – Adjusted Recycle Ratio through 2012
8.0x
6.0x
4.0x
6.1x
Antero
3.5x
Appalachia-Focused Peers
3.1x
2.7x
2.0x
0.0x
Source: Wall Street research. Defined as 2010-2012 average (Cash Operating Netback / PD F&D costs) x (1 + 2012-2014 production CAGR). PD F&D Costs defined as total drilling and completion capital expenditures for the
period divided by PDP and PDNP volumes added after adding back production for the period per JP Morgan analysis. Includes all drilling and completion costs but excludes land and acquisition costs for all companies.
1. Antero data pro forma for Woodford and Piceance divestitures; Antero production growth based on first half of 2013 only.
6

8. INTEGRATED MIDSTREAM INFRASTRUCTURE
“Infrastructure-Ready” for Rapid, Large Scale Marcellus And Utica Development Programs
Infrastructure and commitments in place to handle
strong natural gas, NGL and oil production growth
– Portfolio of firm transportation and sales and
West Virginia location minimizes basis risk
Producers located at the southern end of the Marcellus
see much less basis widening and volatility than
Pennsylvania producers
Antero has sold ~81% of its year-to-date production at
TCO at NYMEX less $0.01/MMbtu
Antero Transport and Processing
Leidy
Basis to NYMEX
Current 2015
-$1.05 -$1.06
Dom South
Basis to NYMEX
Current 2015
-$0.17 -$0.42
2013
2014
2015
Firm Transport (FT) (MMBtu/d)
Firm Sales (MMBtu/d)(1)
542,000
143,000
882,000
230,000
1,152,000
220,000
Firm Processing Capacity (Mcf/d)
Ethane FT (Bbl/d)
800,000
0
1,050,000
20,000
Chicago
Basis to NYMEX
Current 2015
+$0.09 -$0.10
1,050,000
20,000
Growing Processing Capacity
1200
Seneca III
TCO
Basis to NYMEX
Current 2015
-$0.06 -$0.31
Total Capacity
1,050
900
CGTLA
Basis to NYMEX
Current 2015
-$0.04 -$0.06
(MMcf/d)
Seneca II
Seneca I
Sherwood IV
600
Cadiz I
Sherwood III
300
YTD % of
Production Sold
Sherwood II
0
Appalachian Basis to NYMEX(2)
2013
TCO
81%
TCO
Dom South
Sherwood I
14%
Dom South
TETCO M2
Marcellus
Utica
1.
2.
Sherwood I
Sherwood III
Cadiz I
Seneca II
Sherwood II
Sherwood IV
Seneca I
Seneca III
80,000 MMBtu/d and 70,000 MMbtu/d are related to firm transportation in 2014 and 2015, respectively.
Basis data from Wells Fargo daily indications and various private quotes.
NYMEX
5%
2014
2015
2016
2017
2018
2019
$0.00
-$0.20
-$0.40
-$0.60
-$0.80
Leidy
-$1.00
-$1.20
7

9. LONG HAUL PIPELINE AND TRANSPORTATION NETWORK
 Antero has the most firm transportation capacity of any Appalachian operator and is well-positioned in the southern portion of the
Marcellus and Utica Shale from a gas takeaway perspective
Leidy
Basis to NYMEX
Current 2015
-$1.05 -$1.06
Chicago
Basis to NYMEX
Current 2015
+$0.09 -$0.10
Dom South
Basis to NYMEX
Current 2015
-$0.17 -$0.42
(1)
TCO
Basis to NYMEX
Current 2015
-$0.06 -$0.31
CGTLA
Basis to NYMEX
Current 2015
-$0.04 -$0.06
Mcf/d
Appalachian Firm Transportation Capacity by Operator
1,400,000
1,200,000
1,000,000
800,000
600,000
400,000
200,000
0
(2)
Antero CHK EQT TLM STO SWN RRC CNX WPX RDS COG APC NFG
Source: Tudor Pickering & Holt research report dated 9/3/2013.
Note: Antero firm transportation and firm sales positions listed by pipeline in colored-coded boxes.
1. See Page 23 for timing of firm transportation.
2. Antero firm transportation as of 9/25/2013; excludes 150 MMcf/d of firm sales.
8

10. SIGNIFICANT LIQUIDITY AND LONG-TERM
COMMODITY HEDGE POSITION
 Pro forma liquidity of $2.3 Bn
LIQUIDITY POSITION
$MM
$2,500
$2,000
$1,578
$1,500
($960)
$1,000
($32)
L/Cs Outstanding
6/30/2013
$2,347
$11
Cash
6/30/2013
$1,750
$500
$0
1.
2.
Credit Facility(1)
6/30/2013
Bank Debt
6/30/2013
(2)
IPO Proceeds
Current borrowing base of $2.0 billion.
Assumes $1,658 million IPO less $80 million fees and expenses; includes exercise of the shoe.
Pro Forma
Liquidity
6/30/2013
 Current $771 million mark-to-market unrealized gain
NATURAL GAS HEDGES
BBtu/d
Hedged Volume
800
$5.25
600
$3.63
$5.60
$3.91
Hedged NYMEX-Equivalent Price(1)
NYMEX Strip (9/10/2013)
$7.00
$5.40
$5.13
$4.10
$4.20
400
$4.40
$4.33
$4.73
$4.43
$4.75
$4.61
$4.00
$3.00
$1.00
470
478
480
583
720
530
88
2013
1.
$5.00
$2.00
200
0
$6.00
2014
2015
2016
2017
2018
2019
$0.00
In order to compare hedges across basins and commodities, hedged basin prices are converted by Antero to NYMEX-equivalent prices using current basis differentials in the over-the-counter futures market and 6:1 gas to oil ratio.
Antero has hedged ~3,000 Bbl/d for 2013 and 2014, WTI hedges comprise ~1% of overall hedge book.
9

11. ASSET OVERVIEW
10

12. PREMIER POSITION IN THE CORE OF THE MARCELLUS
AND UTICA LIQUIDS-RICH FAIRWAYS
ANTERO LIQUIDS-RICH UTICA SHALE
Utica Shale
Liquids-Rich
Fairway
102,000 Net Acres
11 Horizontals Completed
4 Rigs Currently Running
Utica Shale
Core Area
Marcellus
Shale
Southwestern
& Northeastern
Core Areas
Marcellus Shale
Liquids-Rich
Fairway
ANTERO MARCELLUS SHALE SW PA
25,000 Net Acres
2 Horizontals Completed
Strong Results
ANTERO MARCELLUS SHALE NW WV
304,000 Net Acres
(Primarily Liquids-Rich Fairway)
197 Horizontals Completed
15 Rigs Currently Running
Utica Shale
Dry Gas
Resource
Underlies
Marcellus
Acreage
Upper Devonian
Shale Resource
Overlies
Marcellus
Acreage
11
Source: Company presentations and press releases.

13. WORLD CLASS MARCELLUS SHALE
DEVELOPMENT PROJECT
Antero Has Delineated And De-Risked Its Large Scale Acreage Position
 100% operated
 329,000 net acres in
Southwestern Core
– 50% HBP with additional
28% not expiring for 5+ years
 199 horizontal wells completed
– 197 online
– Laterals average 7,000’
– 100% drilling success rate
 2,941 future drilling locations
(66% are processable)
 Operating 15 drilling rigs
including 4 shallow rigs
MHR WEESE UNIT
4-well average
9.3 MMcfe/d
30-day rate
(54% liquids)
BLANCHE UNIT
2H: 18.1MMcfe/d IP
(52% liquids)
DOTSON UNIT
1H: 22.7 MMcfe/d IP
2H: 27.3 MMcfe/d IP
(50% liquids)
EQT
12 Recent Wells
11.6 MMcfe/d
30-day rate
44% Liquids
CHK HADLEY UNIT
11.3 MMcfe/d IP
(58% liquids)
MOORE UNIT
1H: 13.0 MMcfe/d
2H: 13.0 MMcfe/d
30-day rates
(41% liquids)
Sherwood
Processing
Plant
EQT PENN 15 UNIT
5-well average
9.3 MMcfe/d
30-day rate
(51% liquids)
141 Horizontals Completed
10.1 Bcfe average EUR
8.3 MMcfe/d average 30-day rate
6,917’ average lateral length
 18.7 Tcfe of net 3P (15%
liquids), includes 6.0 Tcfe of
proved reserves
Antero Net Production
Period
(MMcfe/d)
1H 2013
420
August 2013
549
Current
Constrained/shut-in
555
130
(Bbl/d)
3,129
6,528
CONSTABLE UNIT
1H: 19.3 MMcfe/d
30-day rate
(51% liquids)
PRUNTY UNIT
1H: 15.2 MMcfe/d
30-day rate
(50% liquids)
7,400
3,300
Highly-Rich/Condensate
53,000 Net Acres
505 Gross Locations
Highly-Rich Gas
91,000 Net Acres
777 Gross Locations
LITTLE
TOM UNIT
1H: 16.0 MMcfe/d
30-day rate
(41% liquids)
Rich Gas
79,000 Net Acres
673 Gross Locations
CLETA UNIT
1H: 15.9 MMcfe/d
2H: 17.0 MMcfe/d
30-day rates
(38% liquids)
Dry Gas
106,000 Net Acres
986 Gross Locations
Source: Company presentations and press releases. Note: Rates assume ethane recovery. Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
12

14. MARCELLUS – SIMPLE STRUCTURE
 Several regional anticlines in core area
− Predictable “layer cake” geology
− No faults at Marcellus level
• Over 1.3 million feet (250 miles)
drilled horizontally without
crossing a fault
− 3-D seismic not required to guide
horizontal wells
 Regional East-West seismic line shows
gentle structure at Marcellus level
 Allegheny Front and complex structure
located many miles east of core area
 Favorable geology allows for longer
laterals
Regional Seismic Line
Average Marcellus Lateral Lengths
8,000
7,000
Feet
6,000
4,800
4,500
4,100
4,000
100’ Contours Top Marcellus
W
Profile along regional seismic line
(time)
No Data
2,000
0
Antero
EQT
RRC
COG
Big Moses
Arches Fork
Source: Company presentations. Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
Wolf Summit
E
Benson
Rhinestreet
Tully
Marcellus
Onondaga
13

15. ANTERO’S MARCELLUS SHALE TYPE CURVE SUPPORT
 Antero has almost four years of production, and almost 200 operated horizontal wells, to support its 1.5 Bcf / 1,000’ of lateral type curve
– DeGolyer & MacNaughton (D&M), Antero’s third-party reserve auditor, fully supports this type curve
 Average 24-hour peak rate (IP) of 14.0 MMcf/d
 Lack of faulting and contiguous acreage position allows for drilling of long laterals
− Drives down costs per 1,000’ of lateral resulting in best-in-class development costs
(1)
MMcf/d
Type Curve (7,000' Lateral)
16.0
14.0
12.0
10.0
8.0
6.0
4.0
2.0
0.0
Actual Production (Normalized to 7,000' Lateral)
Type Curve Cumulative Production (7,000' Lateral)
24-Hour
Peak Rate
30-Day
Avg. Rate
90-Day
Avg. Rate
180-Day
Avg. Rate
One-Year
Avg. Rate
Two-Year
Avg. Rate
14.0
199
7.8
191
6.2
175
5.4
142
4.1
98
3.0
52
2.3
16
Wellhead (MMcf/d)
# of wells
0
1
2
3
EURs Increase With Lateral Length
4
5
Production Year
6
7
Well Cost / 1,000’ Decreases with Lateral Length
8
30
Average IP - 14 MMcf/d
25
$1.4
MMcf/d
$MM / 1,000'
EUR, BCF
8
10
35
16
12
9
Wellhead 24-hour Peak Rates (IPs) - 199 Wells
$1.8
20
$1.0
20
15
10
4
0
2,000
16.0
14.0
12.0
10.0
8.0
6.0
4.0
2.0
0.0
Three-Year
Avg. Rate
Cumulative Bcf
Marcellus Type Curve Support
5
4,000
6,000
8,000
Lateral Length, ft
10,000
$0.6
2,000
0
4,000
6,000
8,000
Lateral length, ft
10,000
1st Production from All Wells 2009 - 2013
14
1. All 199 Antero Marcellus wells normalized to time zero, production for each well normalized to 7,000’ lateral length.

16. MARCELLUS SINGLE WELL ECONOMICS
– ASSUMES ETHANE REJECTION
Marcellus Well Economics and Locations(1)
 6/30/2013 Strip Pricing & SEC Reserves
986
100%
NGL(2)
WTI
($/Bbl)
($/Bbl)
80%
93%
2013
$3.64
$95
$46.10
60%
$3.91
$90
$44.89
2015
$4.14
$86
$43.86
2016
$4.28
$83
$43.34
20%
2017+
$4.46
$81
$43.34
1,000
1000
505
2014
0%
ROR
NYMEX
($/MMBtu)
777
800
673
600
60%
40%
400
38%
29%
200
Gross Locations
Assumptions
0
Highly-Rich Gas/
Condensate
Highly-Rich Gas
Classification
Highly-Rich/
Condensate
Highly-Rich
Gas
Rich Gas
Dry Gas
BTU Range
Modeled BTU
1275-1350
1313
1200-1275
1250
1100-1200
1150
<1100
1050
14.3
2.4
34%
7,000
350
$7.6
1.5
2.0
12.8
2.1
24%
7,000
350
$7.6
1.5
1.8
EUR (Bcfe):
EUR (MMBoe):
% Liquids:
Lateral Length (ft):
Stage Length (ft):
Well Cost ($MM):
Bcf/1,000’:
Bcfe/1,000’:
Pre-Tax NPV10DRY GAS LOCATIONS
($MM):
Pre-Tax ROR:
Net F&D ($/Mcfe):
Payout (Years):
Gross 3P Locations:
Locations
RICH GAS LOCATIONS
$17.0
Rich Gas
Dry Gas
ROR
11.5
1.9
11%
7,000
350
$7.6
1.5
1.6
HIGHLY
RICH GAS
$7.1
LOCATIONS
10.5
1.8
0%
7,000
350
$7.6
1.5
1.5
93%
$0.62
1.2
$12.0
60%
$0.69
1.6
38%
$0.77
2.4
$5.3
29%
$0.85
3.0
505
777
673
986
1. Well economics are based on 6/30/13 3P reserves. Includes gathering, compression and processing fees.
2. Pricing for a 1225 BTU y-grade barrel.
15

17. ENHANCING MARCELLUS RECOVERIES
– SHORTER STAGE LENGTHS (“SSL”)
Enhancing Recoveries
Antero’s Mid-Year 2013 3P Reserves Do
Not Assume SSL Completions
1. Based on nine relatively unconstrained wells.
Antero’s First 14 Unconstrained SSL Wells – 24-hour Peak Rate
30.0
MMcf/d
31% Increase in IPs for SSL
28.4
22.9 22.2
25.0
20.0
Average Antero SSL 24-hour Peak Rate: 18.4 MMcf/d
19.5 19.5 19.1
17.9 17.4 17.2 16.9 16.3 16.0 15.6
15.0
10.0
Average Antero 24-hour Peak Rate: 14.0 MMcf/d
9.1
5.0
0.0
Normalized 30-day production increase for SSL over 1.5 Bcf/1,000' Type Curve: 29%(1)
Gas Production (Mcf/d)
 Since June 2013 Antero has
implemented shorter stage lengths
(SSL) in the Marcellus Shale
– 17 SSL wells completed
– 150’ to 250’ vs. 350’ stages
previously
 The 24-hour peak rate for Antero’s
first 14 unconstrained SSL wells has
averaged 18.4 MMcf/d or 31% higher
than the overall average Marcellus IP
of 14.0 MMcf/d
– Other Marcellus Southwestern
Core operators (EQT and Range)
have announced 20% to 30%
improvement in IPs and EURs
 Early production ≈ 30% higher than
1.5 Bcf/1,000’ of lateral type curve(1)
(1st 60 days aggregated for nine
unconstrained SSL wells)
 Estimated 20% increase in well costs
for SSL
Antero SSL Wells
Normalized production for 9
relatively unconstrained
SSL wells
10,000
1.5 Bcf/1,000' Type Curve
1,000
0
30
60
Days From Peak Gas
Unconstrained SSL Average
90
1.5 Bcf/1,000' Type Curve
120
16

18. EXCITING CORE UTICA SHALE POSITION DELIVERS
CONDENSATE AND NGLS
Utica Shale Industry Activity and 24-Hour Peak Rates(1)
 100% operated
 ~102,000 net acres in the core rich gas /
condensate window
– 20% HBP with additional 79% not expiring
for 5+ years
– 73%+ of acreage has rich gas processing
potential
 11 horizontal wells completed - all online
− 100% drilling success rate
 720 future drilling locations
– Approximately 36% of EUR is liquids
assuming ethane recovery
 5.3 Tcfe of net 3P (19% liquids), includes
279 Bcfe of proved reserves
Antero Net Production
(MMcfe/d)
1
45
Current
Constrained/shut-in
85
25
GULFPORT
Boy Scout 1-33H,
Ryser 1-25H,
Groh 1-12H
Average 5.3 MMcf/d
+ 675 Bbl/d NGL
+ 1,411 Bbl/d Oil
REXX
Guernsey 1H, 2H,
Noble 1H
Average 7.9 MMcf/d
+ 1,192 Bbl/d NGL
+ 502 Bbl/d Oil
 Operating 4 rigs including 1 shallow rig
Period
1H 2013
August 2013
CHESAPEAKE
8 Wells
Average 8.3 MMcfe/d
(1,391 Boe/d)
CHESAPEAKE
Buell #8H
9.5 MMcf/d
+ 1,425 Bbl/d liquids
Seneca
Processing
Plant
Cadiz
Processing
Plant
GULFPORT
Wagner 1-28H,
Shugert 1-1H, 1-12H
Average 21.0 MMcf/d
+ 2,270 Bbl/d NGL
+ 292 Bbl/d Oil
GULFPORT
McCort1-28H, 2-28H,
Stutzman 1-14H
Average 13.1 MMcf/d
+ 922 Bbl/d NGL
+ 21 Bbl/d Oil
CNX/HESS
Noble 1A, 16A
Average 7.9 MMcf/d
+ 1,184 Bbl/d NGL
+ 389 Bbl/d Oil
Utica
Core
Area
WAYNE UNIT
3 wells average
10.5 MMcf/d + 1,757 Bbl/d NGL
+ 1,719 Bbl/d Oil
(Bbl/d)
102
2,102
4,100
1,600
MILEY UNIT
2 wells average
7.3 MMcf/d + 1,114 Bbl/d NGL
+ 1,300 Bbl/d Oil
RUBEL UNIT
3 wells average
25.3 MMcf/d + 3,170 Bbl/d NGL
+ 196 Bbl/d Oil
NORMAN UNIT 1H
22.4 MMcf/d
+ 2,323 Bbl/d NGL
+ 45 Bbl/d Oil
YONTZ UNIT 1H
33.5 MMcf/d
+ 3,464 Bbl/d NGL
+ 52 Bbl/d Oil
Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are owned.
1. In some cases, 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.
17

19. ANTERO HAS MOST OF THE TOP UTICA IPS
 Antero has 7 of the top 8 Utica
24-hour peak rates (IPs)
announced to date
Core
UTICA IPs
10,000
 Completed wells represent
some of the best 24-hour peak
rates of any shale play in North
America
– 3,000 to 9,000 Boe/d per well
in the core area
– Excellent reservoir pressure
with gradients in the 0.7 psi/ft
range
 Core located in Noble, Monroe,
Guernsey, Belmont and
Harrison Counties, Ohio
− Actual core is a subset of
these counties and ties to
Antero’s geologic model
Boe/d IPs
9,000
8,000
7,000
6,000
Boe/d
 Liquids content ranges from
40%-70% (assumes ethane
recovery) in the liquids-rich
window
2,000 to 9,000
5,000
Tier 1
4,000
1,000 to 2,000
Boe/d IPs
3,000
2,000
1,000
0
Antero Utica Wells
Source: Antero, press releases and company presentations.
3rd Party Core Utica Wells
3rd Party Non-Core Utica Wells
18

20. UTICA WELL RESULTS SUPPORT EUR REGIMES
 Antero’s acreage position is “blocked-up” compared
to other operators in the Utica core
 EUR regimes are well-supported by Antero and
third-party results
 Production constrained until completion of Seneca
processing plant and first compression expected in
4Q 2013
Utica Production Ramp
140
120
MMcfe/d
100
80
60
40
20
-
Estimated Gross (MMcfe/d)
Estimated Net (MMcfe/d)
Highly-Rich/Cond
34,000 Net Acres
208 Locations
Note: Antero acreage position reflects townships in which greater than 3,000 net acres are owned.
Highly-Rich Gas
18,000 Net Acres
198 Locations
Rich Gas
23,000 Net Acres
137 Locations
Dry Gas
27,000 Net Acres
177 Locations
19

21. UTICA SINGLE WELL ECONOMICS
– ASSUMES ETHANE REJECTION
Utica Well Economics and Locations(1)
 6/30/2013 Strip Pricing & SEC Reserves
250%
WTI
($/Bbl)
NGL(2)
($/Bbl)
200%
2013
$3.64
$95
$50.24
2014
$3.91
$90
$48.78
2015
$4.14
$86
$47.43
2016
$4.28
$83
$46.72
$4.46
$81
$46.72
0%
200
50%
2017+
198
150%
ROR
NYMEX
($/MMBtu)
250
208
220%
177
194%
150
114%
100%
137
100
50
40%
Highly-Rich Gas/
Condensate
Highly-Rich Gas
Locations
Rich Gas
Dry Gas
Gross Locations
Assumptions
0
ROR
Classification
Highly-Rich/
Condensate
Highly-Rich
Gas
Rich Gas
Dry Gas
BTU Range
Modeled BTU
1250-1300
1275
1200-1250
1225
1100-1200
1175
<1100
1050
13.7
2.3
35%
7,000
250
$11.3
1.5
2.0
19.9
3.3
26%
7,000
250
$11.3
2.4
2.8
18.0
3.0
16%
7,000
250
$11.3
2.4
2.6
15.3
2.5
0%
7,000
250
$11.3
2.2
2.2
$20.8
220%
$1.02
0.7
$28.1
194%
$0.70
0.7
114%
$0.78
1.0
$10.3
40%
$0.92
2.3
208
198
137
177
EUR (Bcfe):
EUR (MMBoe):
% Liquids
Lateral Length (ft):
Stage Length (ft):
Well Cost ($MM):
Bcf/1,000’:
Bcfe/1,000’:
Pre-Tax NPV10 ($MM):
DRY GAS LOCATIONS
Pre-Tax ROR:
Net F&D ($/Mcfe):
Payout (Years):
Gross 3P Locations(3):
RICH GAS LOCATIONS
1. Well economics are based on 6/30/13 3P reserves. Includes gathering, compression and processing fees.
2. Pricing for a 1225 BTU y-grade barrel.
3. Gross 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.
HIGHLY
RICH GAS
$19.9
LOCATIONS
20

22. SIGNIFICANT MIDSTREAM INFRASTRUCTURE POSITION
 Antero estimated YE 2013 total capital
investment in midstream ≈ $930 million
– Includes gathering lines, compressor
stations and water handling
infrastructure
Utica
Shale
 Proprietary water sourcing and distribution
system
− Improves operational efficiency and
reduces water truck traffic
− Cost savings of up to $600,000 / well
Marcellus
Shale
− One of the benefits of a consolidated
acreage position
 Qualifies for midstream MLP
Midstream Infrastructure(1)
Marcellus
Shale
Utica
Shale
Total
YE 2013 Estimated Total Gathering /
Compression Capex ($MM)
Gathering Pipelines (Miles)
Compressor Stations
$460
83
4
$220
20
0
$680
103
4
YE 2013 Estimated Total Water
System Capex ($MM)
Water Pipeline (Miles)
Water Storage Facilities
$200
89
40
$50
39
22
$250
128
62
YE 2013 Estimated Total Midstream
($MM)
$660
$270
Ohio River Withdrawal
December 2013
completion date
$930
1. Represents inception to date actuals as of 6/30/2013 and remaining 2013 budget.
21

23. PRO FORMA CAPITALIZATION
Significant Liquidity to Fund Drilling Program
CAPITALIZATION
SOURCES & USES
Sources
($ in millions)
Primary IPO Proceeds
$1,658
Total Sources
$1,658
6/30/2013
6/30/2013 (Pro Forma)
Cash
$11
$629
Credit Facility
960
–
25
25
($ in millions)
Unsecured Debt
Uses
Senior Unsecured Notes
Debt Paydown
Total Debt
$960
1,458
1,458
$2,443
$1,483
$3,335
Total Book Capitalization
$4,200
$4,818
NM
$15,112
$457
$457
$112
$93
6,282
6,282
Proved Developed Reserves (Bcfe) (6/30/2013)
1,445
1,445
Net Debt / LTM EBITDAX
5.3x
1.9x
LTM EBITDAX/Interest Expense
$1,658
$854
$1,757
Proved Reserves (Bcfe) (6/30/2013)
Total Uses
80
$2,432
Shareholders' Equity
LTM Interest Expense
Fees & Expenses
618
Net Debt
LTM EBITDAX
Cash
4.1x
4.9x
58.1%
20.4%
Total Market
Capitalization(1)
Financial & Operating Statistics
Credit Statistics
Net Debt / Net Book Capitalization
Net Debt / Net Market Capitalization
NM
5.9%
Net Debt / Proved Developed Reserves ($/Mcfe)
$1.68
$0.59
Net Debt / Proved Reserves ($/Mcfe)
$0.39
$0.14
$1,750
$1,750
Liquidity
Credit Facility Commitments(2)
Less: Borrowings
(960)
Liquidity (Credit Facility +
1. Reflects 262.0 million shares outstanding priced at $52.01 per share as of 10/10/2013; includes the exercise of the shoe.
2. Lender commitments under facility are $1.75 billion which can be expanded to the full $2.0 billion borrowing base upon bank approval.
3. As of September 27, 2013, pro forma for the offering our liquidity would have been $1.8 billion.
Cash)(3)
(32)
11
Plus: Cash
–
(32)
Less: Letters of Credit
629
$769
$2,347
22

24. HEALTH, SAFETY, ENVIRONMENT & COMMUNITY
Protection Of Our People And The Environment Is An Antero Core Value
Strong West Virginia Presence
 Over 75% of Antero Marcellus
employees and contract
workers are West Virginia
residents
Keys to Execution
the Year for 2013 in Harrison
County, West Virginia “For
outstanding corporate
citizenship and community
involvement”
 Closed loop mud system – no mud pits
 Protective liners or mats on all well pads in addition to berms
Green Completion Units
 All Antero well completions use green completion units for completion flowback,
essentially eliminating methane emissions (full compliance with EPA 2015
requirements)
Central Water System
& Water Recycling
 Numerous sources of water – building central water system to source water for
completion
 Antero recycles over 95% of its flowback water with the remainder injected into
disposal wells – no discharge to water treatment plants in West Virginia
Natural Gas Powered
Drilling Rigs
 Four of Antero’s contracted drilling rigs are running on natural gas and the
majority of its rigs should run on natural gas by year-end 2013
Natural Gas
Vehicles (NGV)
 Antero named Business of
Pad Impact Mitigation
 Antero supported the first natural gas fueling station in West Virginia which
recently opened
 Antero has a dozen NGV trucks and plans to continue to convert its truck fleet to
NGV
Safety & Environmental
 Five company safety representatives and 40 safety consultants cover all material
field operations 24/7 including drilling, completion, construction and pipelining
 10-person company environmental staff plus outside consultants monitor all
operations and perform baseline water well testing
Local Presence
 Land office in Ellenboro, WV
 Recently moved into new 50,000 square foot district office in Bridgeport, WV
 80 of Antero’s 215 employees are located in West Virginia and Ohio
LEED Gold Headquarters
Building
 Antero’s new corporate headquarters in Denver has been LEED Gold Certified
 Completion expected by spring of 2014
 Antero representatives
recently participated in a
ribbon cutting with the
Governor of West Virginia
for the grand opening of the
first natural gas fueling
station in the state; Antero
supported the station with
volume commitments for its
NGV truck fleet
23

25. WHY INVEST IN ANTERO?
Over 400,000 Net Acres in the
Core Marcellus and Utica Shales
“Triple Digit” Historical
Production and Reserve Growth
Low Cost Leader /
High Return Projects
Significant Takeaway and Processing
Capacity Already in Place
Clean Balance Sheet Supports
High Growth Story
“Forward Thinking” Management Team
with a History of Success
24

26. APPENDIX
25

27. CONSIDERABLE RESERVE BASE WITH
ETHANE OPTIONALITY
 26 year proved reserve life from current production annualized
 Reserve base provides significant exposure to liquids-rich projects
– 3P reserves of over 1.6 BBbl of NGLs and condensate in ethane recovery mode; 31% liquids
ETHANE REJECTION(1)
ETHANE RECOVERY(1)
Marcellus – 18.7 Tcfe
Marcellus – 21.8 Tcfe
Utica – 5.3 Tcfe
Utica – 6.1 Tcfe
Upper Devonian – 3.8 Tcfe
Upper Devonian – 4.2 Tcfe
27.7
Tcfe
32.1
Tcfe
Gas – 23.8 Tcf
Gas – 22.2 Tcf
Oil – 71 MMBbls
Oil – 71 MMBbls
NGLs – 595 MMBbls
NGLs – 1,580 MMBbls
14%
Liquids
31%
Liquids
1. Ethane rejection occurs when ethane is left in the wellhead gas stream as the gas is processed, rather than being separated out and sold as a liquid after fractionation. When ethane is left in the gas stream, the BTU content
of the residue gas at the outlet of the processing plant is higher. Producers will elect to “reject” ethane when the price received for the higher BTU residue gas is greater than the price received for the ethane being sold as a
liquid after fractionation. When ethane is recovered, the BTU content of the residue gas is lower, but a producer is then able to recover the value of the ethane sold as a separate NGL product.
26

28. MARCELLUS SHALE RICH GAS –
LIQUIDS AND PROCESSING UPGRADE
 Marcellus Shale rich gas and highly-rich gas acreage provides a significant advantage in well economics – assuming $4.25/MMBtu NYMEX,
$90.00/Bbl WTI and current spot NGL pricing correlation
 Upgrade analysis demonstrates that ethane recovery is not economic at current ethane price
$/Wellhead Mcf(1)
($/Mcf)
$9.00
+$2.45
$7.94
Upgrade
$8.00
$6.84
+$0.77
$7.00
NGLs
(C3+)
$3.23
Upgrade
NGLs
(C3+)
$2.39
$6.00
$5.00
+$3.55
Upgrade
$5.16
$4.39
NGLs (C3+)
$1.04
Gas
$4.39
Gas
$4.12
Condensate
$0.37
Condensate
$0.70
Gas
$4.07
$4.00
Gas
$4.00
$3.00
$2.00
$1.00
(1073 BTU)
(1103 BTU)
(1110 BTU)
8% shrink
12% shrink
14% shrink
$0.00
1050 BTU
Dry Gas
1150 BTU
1250 BTU
1300 BTU
Rich Gas
Current – Ethane Rejection
1. Assumes $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current NGL spot prices. 1.054 and 2.070 (ethane rejection) and 3.332 and 5.145 (ethane recovery) GPM s used, all processing costs, shrink and fuel included. No ethane takeaway
available until Enterprise ethane pipeline is online (expected 1Q 2014). Ethane recovery well economics include fixed fee cost tariff on ATEX ethane pipeline.
27

29. 2013 REALIZATIONS
NATURAL GAS REALIZATIONS
August 2013 YTD
% Sales
TCO
81%
Dominion South
14%
(1)
NYMEX
5%
Total
100%
`
Index Price
$3.73
$3.60
$3.82
$3.72
2013 YTD
Differential
$(0.01)
$(0.06)
$(0.43)
$(0.04)
Wet Gas BTU
Enhancement
$0.38
$0.42
$0.34
$0.38
2013 YTD
Realized Price
$4.09
$3.96
$3.72
$4.05
6/30/2013 YTD NGL Y-GRADE (C3+) REALIZATIONS
1%
$0.59
Ethane (C2)
14%
Propane (C3)
Iso Butane (C4)
$12.58
Normal Butane
14%
60%
10%
$23.52
Natural Gasoline
$7.10
$5.97
Antero Barrel
1. NYMEX differential represents contractual deduct to NYMEX-based sales.
2. Based on monthly prices through 6/30/13 WTI.
Total $49.75 per BBl
52% of WTI(2)
28

30. ANTERO FIRM TRANSPORTATION AND FIRM SALES
Columbia
Firm Sales #1
Firm Sales #2
Firm Sales #3
7/26/2009 – 9/30/2025
10/1/2011– 10/31/2019
10/1/2011 – 5/31/2017
1/1/2013 – 5/31/2022
Momentum III
EQT
Chicago Direct
9/1/2012 – 12/31/2021
8/1/2012 – 8/31/2021
4/1/2013 – 9/30/2021
MMBtu/d
1,400,000
1,200,000
1,000,000
800,000
600,000
400,000
200,000
-
29

31. ANTERO EBITDAX RECONCILIATION
EBITDAX Reconciliation
($ in thousands)
Antero Resources LLC
LTM Ended
6/30/13
EBITDAX:
Net income (loss) from continuing operations
$54,154
Commodity derivative fair value (gains) losses
(91,874)
Net cash receipts on settled commodity derivatives instruments
144,052
(Gain) loss on sale of assets
Interest expense and other
Provision (benefit) for income taxes
Depreciation, depletion, amortization and accretion
115
112,313
(9,415)
157,134
Impairment of unproved properties
16,848
Exploration expense
21,581
Other
EBITDAX from continuing operations
3,272
$408,180
EBITDAX:
Net income (loss) from discontinued operations
Commodity derivative fair value (gains) losses
Net cash receipts on settled commodity derivatives instruments
(Gain) loss on sale of assets
Provision (benefit) for income taxes
Depreciation, depletion, amortization and accretion
Impairment of unproved properties
Exploration expense
EBITDAX from discontinued operations
EBITDAX
($105,671)
18,880
26,292
368,713
(285,280)
25,758
(31)
252
$48,913
$457,093
30

32. CAUTIONARY NOTE
Regarding Hydrocarbon Quantities
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. The estimates of proved, probable and possible reserves as of June 30, 2013 included in this
presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates are as of June 30, 2013, assuming
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, 2013. 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.
 “Highly-rich/condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1250 BTU and 1300
BTU in the Utica Shale.
 “Highly-rich gas” refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and 1250 BTU in
the Utica Shale.
 “Rich gas” refers to gas having a heat content of between 1100 BTU to 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.
31