1. Company Overview
February 2014

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., 2nd largest in the world –
Industry production approximately 14 Bcf/d today
● Antero has 35 Tcfe of 3P reserves in Marcellus and Utica Shales
● 566 MMcfe/d of average net production in 3Q 2013 including 7,900 Bbl/d of
liquids; 675–680 MMcfe/d net production guidance for 4Q 2013
Market Leading Growth
● 159% Appalachian production CAGR since 2010 to YE 2013
● Most active driller in Appalachia – 20 rigs running
● Most active driller in Marcellus Shale – 15 rigs running
● 3rd most active driller in the Utica Shale – 5 rigs running
Industry Leading Capital
Efficiency and Recycle Ratio
● Low development cost leader: $1.03/Mcfe(1)
● Industry leading growth-adjusted recycle ratio: 6.1x(1)
● Top quartile return on productive capital: 27% for 2013E
Significant Emphasis on
Takeaway and
Liquids Processing
● 1.4 Bcf/d of processing capacity and 1.5 Bcf/d of gas takeaway by yearend 2014
● Liquids expected to grow from 8% of third quarter 2013 production
due to focus on liquids-rich development
Liquidity and Hedge
Position Support High
Growth Story
● ~$1.8 billion pro forma available liquidity with current $1.5 billion bank
commitment(2)
● 1.3 Tcfe hedged through 2019 at an average index price of $4.64/MMBtu
and $96.54/Bbl
Outstanding
Management Team
1. Three year average through 2012; pro forma for Arkoma and Piceance divestitures.
2. See page 21 for the derivation of 9/30/2013 liquidity.
● Over 30 years as a team (over 20 years in unconventional)
● “Shale Pioneers” – early mover and driller of over 500 horizontal shale
wells in the Barnett, Woodford, Marcellus and Utica Shales
2

4. PREMIER UNCONVENTIONAL RESOURCE PLATFORM
TOTAL – 12/31/13 RESERVES(1)
Assumes Ethane Rejection
Net Proved Reserves(1)
Net 3P Reserves(1)
Pre-Tax 3P PV-10(1)
902 MMBbls
15%
566 MMcfe/d
7,900 Bbl/d
454,000
4,778
“Pure-Play” Appalachian-Focused Shale Company
Reserves(1)
Net Proved
Net 3P Reserves (1)
Pre-Tax 3P PV-10(1)
7.2 Tcfe
25.0 Tcfe
$15,729 MM
% Liquids – Net 3P
3Q 2013 Net Production
Undrilled 3P Locations
7.6 Tcfe
35.0 Tcfe
$20,362 MM
Net 3P Liquids
% Liquids – Net 3P
3Q 2013 Net Production(2)
- 3Q 2013 Net Liquids(2)
Net Acres(3)
Undrilled 3P Locations
A MARCELLUS SHALE
17%
519 MMcfe/d
3,068
C
B
D
Reserves(1)
Net Proved
Net 3P Reserves (1)
Pre-Tax 3P PV-10(1)
C
2.
3.
•
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 2014 and 2015
development drilling activities
•
Full scale development underway
− 20 rigs currently operating
UPPER DEVONIAN SHALE
44 Bcfe
4.2 Tcfe
NM
7%
3 MMcfe/d
951
D UTICA SHALE – DRY GAS
1.
− Utica Shale: 20% HBP, with additional 79% not
expiring for 5+ years
15%
44 MMcfe/d
759
Net Acres(3)
Net Resource
Undrilled Locations
Stable acreage base
− Marcellus Shale: 51% HBP, with additional 21%
not expiring for 5+ years
362 Bcfe
5.8 Tcfe
$4,666 MM
Net Proved Reserves(1)
Net 3P Reserves (1)
Pre-Tax 3P PV-10(1)
% Liquids – Net 3P
3Q 2013 Net Production
Undrilled 3P Locations
100% operated
•
B UTICA SHALE – LIQUIDS RICH
% Liquids – Net 3P
3Q 2013 Net Production
Undrilled 3P Locations
A
•
126,000
5.0 Tcfe
950
Additional Hedge Value
•
1.3 Tcfe hedged from 1/1/2014 through 12/31/2019 at a
NYMEX-equivalent price of $4.97/MMBtu
•
~ $940 million mark-to-market value as of 1/31/2014 not
included in reserve PV-10
•
~ 50% hedged through NYMEX; 50% hedged through
regional hubs
Proved, probable, and possible reserves as of December 31, 2013, assuming ethane rejection using SEC methodology and SEC 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.
Represents the average net daily production for the period July 1, 2013 through September 30, 2013.
All net acres allocated to the Dry Gas Utica 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 leases.
3

5. STRONG TRACK RECORD OF GROWTH
AVERAGE NET DAILY PRODUCTION (MMcfe/d)
Woodford
Piceance
Marcellus
APPALACHIAN PRODUCTION (MMcfe/d)
Utica
800
Marcellus
950
1,000
600
522
400
950
800
Sold Woodford
and Piceance
600
522
400
334
244
200
0
6
2006
31
2007
105
87
2008
2009
2010
2011
2012
Piceance
Marcellus(3)
0
(5)
(4)
2013E 2014E
2010
2011
(4)
2012
(5)
2013E
2014E
OPERATED GROSS WELLS SPUD
Utica
Woodford
Piceance
Marcellus
Utica
193
200
7,632
8,000
7,000
175
157
150
6,000
100
4,000
3,231
680
87
2007
2008
2009
96
91
Financial
Crisis
66
50
1,141
18
25
235
2006
85
119
75
3,000
2,000
126
125
5,017 4,929
5,000
0
124
30
9,000
1,000
239
200
133
NET PROVED SEC RESERVES (Bcfe)(2)
Woodford
Utica
1,000
2010
2011
2012
2013
0
2006
2007
2008
2009
2010
2011
2012
(4)
2013E
(5)
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 2013 proved reserves based on current SEC reserve methodology and SEC pricing and are audited by independent thirdparty 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. Per Company press release dated January 27, 2014.
5. Per Company press release dated January 29, 2014; production mid-point of 925-975 MMcfe/d guidance.
4

6. MULTI-YEAR DRILLING INVENTORY SUPPORTS
LOW RISK, HIGH-RETURN GROWTH PROFILE
707
130%
800
400
69%
200
33%
Highly-Rich
Gas/
Condensate
1000
1,000
600
50%
0%
890
834
Highly-Rich
Gas
21%
Rich Gas
Locations
Dry Gas
200%
205
100%
161
0%
ROR
 71% of Marcellus locations are processable (1100-plus Btu)
200
145%
150
100
99%
50%
0
250
211
182
177%
150%
ROR
ROR
100%
637
Gross Locations
150%
UTICA WELL ECONOMICS(1)
50
56%
Highly-Rich
Gas/
Condensate
Highly-Rich
Gas
Rich Gas
Locations
Gross Locations
MARCELLUS SSL WELL ECONOMICS(1)
0
Dry Gas
ROR
 72% of Utica locations are processable (1100-plus Btu)
$ / MMBtu NYMEX (Gas)
Large Inventory of Low Breakeven Projects(2)
$6.75
$7.00
$6.00
$5.00
3 Yr Strip -
343
$3.00
$1.00
$0.00
205
637
1,541
$0.00
$0.00
Locations
Locations
Locations Locations
$0.00
$3.65
Locations
$4.00
$2.00
$5.05
890
$4.21/MMBtu(3)
$0.29
$2.47
$2.50
$2.94 $3.02
$3.26
$3.66 $3.70
$3.75 $3.81
$4.13
$5.37
$5.49
$4.25
$3.27 $3.34
$1.35
$0.62
`
1. Well economics based on 12/31/2013 3P reserves and strip pricing as of 12/31/2013.
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 NYMEX STRIP as of 1/31/2014.
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
have seen much less basis widening and volatility than
Pennsylvania producers
Antero has sold ~76% of its year-to-date production
through September 2013 at TCO index at NYMEX less
$0.07/MMbtu
Antero Transport and Processing
Leidy
Basis to NYMEX
Current 2015
-$2.25 -$2.00
Dom South
Basis to NYMEX
Current 2015
-$0.60 -$1.13
2014
Firm Transport (FT) (MMBtu/d)
Firm Sales (MMBtu/d)(1)
1,227,000
330,000
1,227,000
320,000
Firm Processing Capacity (Mcf/d)
Ethane FT (Bbl/d)
1,400,000
20,000
Chicago
Basis to NYMEX
Current 2015
+$0.38 -$0.12
2015
1,550,000
20,000
TCO
Basis to NYMEX
Current 2015
-$0.05 -$0.49
Growing Processing Capacity
Total Capacity
1,550
1,600
Seneca IV
1,400
CGTLA
Basis to NYMEX
Current 2015
-$0.02 -$0.09
1,200
Seneca III
(MMcf/d)
1,000
800
600
400
200
Seneca II
Seneca I
Sherwood V
Sherwood IV
Appalachian Basis to NYMEX(2)
YTD % of
Production Sold
Sherwood III
Sherwood II
2014
2015
2016
2017
2018
2019
-$0.20
TCO
18%
Dom South
-$0.60
TETCO M2
0
76%
Dom South
Sherwood I
TCO
-$1.00
NYMEX
Marcellus
Sherwood II
Sherwood III
Sherwood IV
Utica
1.
2.
Sherwood I
Seneca I
Seneca II
Seneca III
Seneca IV
Sherwood V
80,000 MMBtu/d and 70,000 MMbtu/d also utilize firm transportation in 2014 and 2015, respectively.
Basis data from Wells Fargo daily indications and various private quotes as of 1/31/2014.
-$1.40
5%
Leidy
-$1.80
-$2.20
7

9. LONG HAUL PIPELINE AND TRANSPORTATION NETWORK
 Antero has a leading firm transportation capacity 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
-$2.25 -$2.00
Chicago
Basis to NYMEX
Current 2015
+$0.38 -$0.12
Dom South
Basis to NYMEX
Current 2015
-$0.60 -$1.13
(1)
TCO
Basis to NYMEX
Current 2015
-$0.05 -$0.49
CGTLA
Basis to NYMEX
Current 2015
-$0.02 -$0.09
Note: Antero firm transportation and firm sales positions listed by pipeline in colored-coded boxes.
1. Firm transport as of year-end 2014. See Page 25 for timing of firm transportation graph.
2. Antero firm transportation as of 1/31/2014; excludes 250 MMcf/d of firm sales.
8

10. SIGNIFICANT LONG-TERM
COMMODITY HEDGE POSITION
NATURAL GAS HEDGES – 12/31/2013
BBtu/d
Hedged NYMEX-Equivalent Price(1)
Hedged Volume
800
$5.38
$5.51
$5.28
600
400
NYMEX Strip (1/31/2014)
$4.65
$4.43
$4.41
$4.14
$4.12
$4.09
$4.15
$4.51
$4.24
628
550
633
750
650
288
2014
1.
$6.00
$5.00
$4.00
$3.00
$2.00
200
0
$7.00
2015
2016
2017
2018
$1.00
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 2014, WTI hedges comprise ~1% of overall hedge book.
 ~$940 million mark-to-market unrealized gain as of January 31, 2014.
 1.3 Tcfe hedged from January 1, 2014 through year-end 2019.
% HEDGE VOLUMES BY INDEX – 12/31/2013
2%
Chicago
TCO
11%
NYMEX
19%
Dom South
49%
18%
CGTLA
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
106,000 Net Acres
17 Horizontals Completed
5 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
323,000 Net Acres
(Primarily Liquids-Rich Fairway)
221 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
 348,000 net acres in
Southwestern Core
– 51% HBP with additional
21% not expiring for 5+ years
 223 horizontal wells completed
and online
– Laterals average 7,000’
– 100% drilling success rate
 Net production of 522 MMcfe/d
in 3Q 2013, including 6,100
Bbl/d of liquids
MHR WEESE UNIT
30-Day Rate
4-well average
9.3 MMcfe/d
(31% liquids)
BLANCHE UNIT
30-Day Rate
2H: 10.0 MMcfe/d
(29% liquids)
DOTSON UNIT
30-Day Rate
1H: 12.4 MMcfe/d
2H: 11.8 MMcfe/d
(27% liquids)
EQT
30-Day Rate
12 Recent Wells
9.2 MMcfe/d
(20% Liquids)
CHK HADLEY UNIT
24-Hour IP
9.1 MMcfe/d
(32% liquids)
MOORE UNIT
30-Day Rate
1H: 9.9 MMcfe/d
2H: 10.0 MMcfe/d
(17% liquids)
Sherwood
Processing
Plant
EQT PENN 15 UNIT
30-Day Rate
5-well average
9.3 MMcfe/d
(29% liquids)
142 Horizontals Completed
30-Day Rate
10.3 Bcf average EUR
8.1 MMcf/d
6,915’ average lateral length
 3,068 future drilling locations
(71% are processable)
 Operating 15 drilling rigs
including 4 shallow rigs
 25.0 Tcfe of net 3P (17%
liquids), includes 7.2 Tcfe of
proved reserves
CONSTABLE UNIT
30-Day Rate
1H: 15.2 MMcfe/d
(30% liquids)
PRUNTY UNIT
30-Day Rate
1H: 11.0 MMcfe/d
(29% liquids)
Highly-Rich/Condensate
60,000 Net Acres
637 Gross Locations
Highly-Rich Gas
100,000 Net Acres
834 Gross Locations
HINTERER UNIT
30-Day Rate
1H: 12.9 MMcfe/d
(20% liquids)
Rich Gas
84,000 Net Acres
707 Gross Locations
RUTH UNIT
30-Day Rate
1H: 19.3 MMcfe/d
(14% liquids)
Dry Gas
104,000 Net Acres
890 Gross Locations
Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned. Note: Rates assume ethane rejection.
12

14. MARCELLUS – SIMPLE STRUCTURE
 Several regional anticlines in core area
− Predictable “layer cake” geology
− No faults at Marcellus level
• Over 1.5 million feet (295 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
Source: Company presentations.
EQT
RRC
COG
Big Moses
Arches Fork
Wolf Summit
E
Benson
Rhinestreet
Tully
Marcellus
Onondaga
13

15. ANTERO’S MARCELLUS SHALE TYPE CURVE SUPPORT
 Antero has over four years of production data, from 223 operated horizontal wells, to support its 1.5 Bcf/1,000’ of lateral type curve (non-SSL)
 Due to recent success with shorter stage lengths (SSL), Antero’s type curve has been increased to 1.73 Bcf/1,000’ – 12% higher well costs
 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
Marcellus Type Curve Support
12.0
24-Hour
Peak Rate
9.0
MMcf/d
Actual Production (Normalized to 7,000' Lateral) (1)
1.7 Bcf/1,000' SSL Type Curve
1.5 Bcf/1,000' Type Curve (7,000' Lateral)
Type Curve Cumulative Production (7,000' Lateral)
SSL Actual Production (Normalized to 7,000' Lateral) (2)
90-Day
Avg. Rate
180-Day
Avg. Rate
One-Year
Avg. Rate
Two-Year
Avg. Rate
8.1
217
6.3
221
5.3
179
4.2
127
3.1
63
12.0
Three-Year
Avg. Rate
14.1
223
Wellhead (MMcf/d)
# of wells
30-Day
Avg. Rate
15.0
2.2
25
9.0
6.0
6.0
3.0
3.0
0.0
0.0
0
1
2
3
EURs Increase With Lateral Length
4
5
Production Year
6
7
Well Cost / 1,000’ Decreases with Lateral Length
20
8
8
30
$1.6
25
$1.4
$1.2
$1.0
4
$0.8
0
2,000
$0.6
2,000
4,000
6,000
8,000
Lateral Length, ft
10,000
10
20
MMcfd
$MM / 1,000'
12
9
Wellhead 24-hour Peak Rates (IPs) - 223 Wells
$1.8
16
EUR, BCF
Cumulative Bcf
15.0
Average IP – 14.1 MMcf/d
15
10
5
4,000
6,000
8,000
Lateral length, ft
1. 223 Antero Marcellus wells normalized to time zero, production for each well normalized to 7,000’ lateral length.
2. 32 Antero Marcellus SSL wells normalized to time zero, production for each well normalized to 7,000’ lateral length.
10,000
0
1st Production from All Wells 2009 - 2013
14

16. MARCELLUS SINGLE WELL ECONOMICS
– ASSUMES ETHANE REJECTION
Marcellus SSL Well Economics and Locations(1)
 12/31/2013 Strip Pricing & SEC Reserves
WTI
($/Bbl)
2014
$4.24
$95
$59
2015
$4.16
$88
$54
2016
$4.09
$83
$51
2017
$4.09
$80
$50
2018+
$4.14
$79
150%
C3+ NGL(2)
($/Bbl)
637
$50
100%
1,000
890
834
800
707
130%
600
ROR
NYMEX
($/MMBtu)
50%
0%
400
69%
200
33%
Highly-Rich Gas/
Condensate
Highly-Rich Gas
Locations
21%
Rich Gas
Gross Locations
Assumptions
0
Dry Gas
ROR
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
16.5
2.8
34%
7,000
225
$9.5
1.7
2.4
14.9
2.5
24%
7,000
225
$9.5
1.7
2.1
EUR (Bcfe):
EUR (MMBoe):
% Liquids:
Lateral Length (ft):
Stage Length (ft):
Well Cost ($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:
RICH GAS LOCATIONS
$21.1
13.3
2.2
12%
7,000
225
$9.5
1.7
1.9
HIGHLY
RICH GAS
$6.7
LOCATIONS
12.1
2.0
0%
7,000
225
$9.5
1.7
1.7
130%
$0.68
0.9
$14.1
69%
$0.75
1.3
33%
$0.84
2.4
$3.7
21%
$0.92
3.6
637
834
707
890
1. Well economics are based on 12/31/2013 3P reserves. Includes gathering, compression and processing fees.
2. Pricing for a 1225 BTU y-grade rejection barrel.
15

17. ENHANCING MARCELLUS RECOVERIES
– SHORTER STAGE LENGTHS (“SSL”)
 Since June 2013 Antero has
implemented shorter stage lengths
(SSL) in the Marcellus Shale
– 32 SSL wells completed
– 22 SSL wells have at least 30 days
of production history
– 150’ to 225’ vs. 350’ stages
previously
 The 30-day rate for Antero’s first 22
unconstrained SSL wells has
averaged 10.0 MMcf/d or 31% higher
than the average Antero non-SSL 30day rate of 7.6 MMcf/d
– This rate improvement has been
maintained over longer production
periods with the 120-day SSL well
rate for 10 wells 27% higher than
for non-SSL wells
– Other Marcellus southwestern core
operators have announced 20% to
30% improvement in IPs and EURs
 Estimated 12% increase in well costs
for SSL as compared to non-SSL
wells
Antero SSL Wells
SSL vs Non-SSL Wellhead
Average Rate Comparison (MMcf/d)
60-day
90-day
120-day
30-day
Rate
Rate
Rate
Rate
SSL Well Count
22
19
19
10
SSL Average Rate – MMcf/d(1)
10.0
8.6
8.1
7.9
1.5 Bcf/1,000' Type Curve
Average Rate – MMcf/d(1)
7.6
7.1
6.6
6.2
SSL % Rate Improvement
31%
21%
24%
27%
(1) Wellhead condensate production (where applicable) is converted on a 6:1 basis
Normalized production increase for 22 SSL wells over 1.5 Bcf/1,000' Type Curve
Gas Production (Mcf/d)
Enhancing Recoveries
10,000
1.5 Bcf/1,000' Type Curve
1,000
0
30
60
90
120
Days From Peak Gas
Unconstrained SSL Average
150
180
1.5 Bcf/1,000' Type Curve
16

18. EXCITING CORE UTICA SHALE POSITION DELIVERS
CONDENSATE AND NGLS
 100% operated
Utica Shale Industry Activity and 30-Day Rates(1)
 106,000 net acres in the core rich gas /
condensate window
– 20% HBP with additional 79% not expiring
for 5+ years
– 72% of acreage has rich gas processing
potential
 17 Antero-operated horizontal wells completed
with 16 currently online
− 100% drilling success rate
 Net production of 44 MMcfe/d in 3Q 2013
including 1,800 Bbl/d of liquids
− First production in early August 2013 with
access to Cadiz pipeline and processing
− Seneca I processing plant came online in
November 2013 and Seneca II came online
in January 2014
− First 120 MMcf/d compressor station went
into service in late January with an
additional 120 MMcf/d expected by late 1Q
2014
 759 future drilling locations
– Approximately 36% of EUR is liquids
assuming ethane recovery
 Operating 5 rigs including 1 shallow rig
 5.8 Tcfe of net 3P (15% liquids), includes
362 Bcfe of proved reserves
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
GULFPORT
24-Hour IP
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
24-Hour IP
Guernsey 1H, 2H,
Noble 1H
Average 7.9 MMcf/d
+ 1,192 Bbl/d NGL
+ 502 Bbl/d Oil
CHESAPEAKE
24-Hour IP
Buell #8H
9.5 MMcf/d
+ 1,425 Bbl/d liquids
Cadiz
Processing
Plant
Seneca
Processing
Plant
RUBEL UNIT
30-Day Rate
3 wells average
13.5 MMcf/d + 583 Bbl/d NGL
+ 45 Bbl/d Oil
Utica
Core
Area
WAYNE UNIT
30-Day Rate
3 wells average
5.4 MMcf/d + 335 Bbl/d NGL
+ 548 Bbl/d Oil
DOLLISON UNIT 1H
24-Hour IP
10.2 MMcf/d + 1,488 Bbl/d NGL
+ 1,397 Bbl/d Oil
MILEY UNIT
30-Day Rate
2 wells average
3.0 MMcf/d + 187 Bbl/d NGL
+ 559 Bbl/d Oil
COAL UNIT 1H
24-Hour IP
11.8 MMcf/d
+ 2,063 Bbl/d NGL
+ 1,850 Bbl/d Oil
Highly-Rich/Cond
30,000 Net Acres
205 Locations
MILLIGAN UNIT
24-Hour IP
3 wells average
11.3 MMcf/d + 1,971 Bbl/d NGL
+ 1,586 Bbl/d Oil
Highly-Rich Gas
26,000 Net Acres
161 Locations
GULFPORT
24-Hour IP
McCort1-28H, 2-28H,
Stutzman 1-14H
Average 13.1 MMcf/d
+ 922 Bbl/d NGL
+ 21 Bbl/d Oil
Rich Gas
23,000 Net Acres
182 Locations
GARY UNIT 1H
30-Day Rate
23.1 MMcf/d
+ 1,023 Bbl/d NGL
+ 65 Bbl/d Oil
YONTZ UNIT 1H
30-Day Rate
14.6 MMcf/d
+ 392 Bbl/d NGL
+ 1 Bbl/d Oil
NORMAN UNIT 1H
30-Day Rate
13.6 MMcf/d
+ 461 Bbl/d NGL
+ 2 Bbl/d Oil
Dry Gas
27,000 Net Acres
211 Locations
Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are owned.
Note: Third party peak rates assume ethane recovery; Antero 24-hour peak rates assume ethane recovery; Antero 30-day rates assume ethane rejection.
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 24-HOUR IPS
UTICA 24-HOUR IPs
 Antero has 11 of the top 12
Utica 24-hour peak rates (IPs)
announced to date
Core
12 to 53
60.0
 Completed wells represent
some of the best 24-hour peak
rates of any shale play in North
America
– 20 to 53 MMcfe/d per well 24hour peak rate in the core
area
– Excellent reservoir pressure
with gradients in the 0.7 psi/ft
range
 Antero recently announced 30day rates on some of these
wells (see page 27)
 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
Source: Antero, press releases and company presentations.
Note: Assumes ethane recovery.
50.0
40.0
MMcfe/d
 Liquids content ranges from
40%-70% (assumes ethane
recovery) in the liquids-rich
window
MMcfe/d IPs
30.0
Tier 1
6 to 12
MMcfe/d IPs
20.0
10.0
0.0
Antero Utica Wells
3rd Party Core Utica Wells
3rd Party Non-Core Utica Wells
18

20. UTICA SINGLE WELL ECONOMICS
– ASSUMES ETHANE REJECTION
Utica Well Economics and Locations(1)
 12/31/2013 Strip Pricing & SEC Reserves
200%
NGL(2)
WTI
($/Bbl)
C3+
($/Bbl)
2014
$4.24
$95
$58
2015
$4.16
$88
$54
2016
$4.09
$83
$50
2017
$4.09
$80
$49
2018+
$4.14
$79
$49
100%
250
211
177%
150%
ROR
NYMEX
($/MMBtu)
161
205
200
182
145%
150
100
99%
50%
0%
56%
Highly-Rich Gas/
Condensate
Highly-Rich Gas
Locations
Rich Gas
Dry Gas
50
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
11.3
1.9
32%
7,000
240
$11.0
1.2
1.6
20.5
3.4
23%
7,000
240
$11.0
2.4
2.9
18.8
3.1
15%
7,000
240
$11.0
2.4
2.7
16.6
2.8
0%
7,000
240
$11.0
2.4
2.4
$16.1
145%
$1.21
0.5
$27.2
177%
$0.66
0.5
99%
$0.72
0.8
$11.7
56%
$0.82
1.3
205
161
182
211
EUR (Bcfe):
EUR (MMBoe):
% Liquids
Lateral Length (ft):
Stage Length (ft):
Well Cost ($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 12/31/2013 3P reserves. Includes gathering, compression and processing fees.
2. Pricing for a 1225 BTU y-grade rejection barrel.
3. Gross 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.
HIGHLY
RICH GAS
$18.7
LOCATIONS
19

21. SIGNIFICANT MIDSTREAM INFRASTRUCTURE POSITION
 Antero estimated YE 2013 total capital
investment in midstream ≈ $980 million
– Includes gathering lines, compressor
stations and water handling
infrastructure
 Proprietary water sourcing and distribution
system
− Improves operational efficiency and
reduces water truck traffic
− Cost savings of up to $600,000 $800,000 / well
− One of the benefits of a consolidated
acreage position
 Qualifies for midstream MLP
Midstream Infrastructure(1)
Marcellus
Shale
Utica
Shale
Total
YE 2013 Estimated Total Gathering /
Compression Capex ($MM)
Gathering Pipelines (Miles)
Compressor Stations
$510
83
4
$220
20
0
$200
71
17
$50
37
2
$710
$270
Ohio River Withdrawal
January 2014
completion date
$250
108
19
YE 2013 Estimated Total Midstream
($MM)
Marcellus
Shale
$730
103
4
YE 2013 Estimated Total Water
System Capex ($MM)
Water Pipeline (Miles)
Water Storage Facilities
Utica
Shale
$980
1. Represents inception to date actuals as of 9/30/2013 and remaining 2013 budget.
20

22. PRO FORMA CAPITALIZATION
CAPITALIZATION
Cash
Senior Secured Revolving Credit Facility
9.375% Senior Notes Due 2017
9.00% Senior Note
9/30/2013
(PF IPO)
9/30/2013 (1)
(PF Bond Offering)
9/30/2013(3)
$12
($ in millions)
$77
$339
1,513
–
–
525
525
–
25
25
–
7.25% Senior Notes Due 2019
400
400
260
6.00% Senior Notes Due 2020
525
525
525
–
–
1,000
5.375% Senior Notes Due 2021
Net Unamortized Premium
8
8
6
Total Debt
$2,996
$1,483
$1,791
Net Debt
$2,984
$1,406
$1,452
Shareholders' Equity
$1,875
$3,453
$3,427
Net Book Capitalization
$4,859
$4,859
$4,879
N/M
$15,735
$16,842
$521
$521
$521
Net Market
Capitalization(1)
Financial & Operating Statistics
LTM EBITDAX
Proved Reserves (Bcfe) (12/31/2013)
7,632
7,632
7,632
Proved Developed Reserves (Bcfe) (12/31/2013)
2,023
2,023
2,023
Credit Statistics
Net Debt / LTM EBITDAX
5.7x
2.7x
2.8x
LTM EBITDAX / Interest Expense
4.1x
4.7x
5.1x
Net Debt / Net Book Capitalization
61.4%
28.9%
29.8%
N/M
8.9%
8.6%
Net Debt / Proved Developed Reserves ($/Mcfe)
$1.48
$0.71
$0.72
Net Debt / Proved Reserves ($/Mcfe)
$0.39
$0.19
$0.19
Credit Facility Commitments(2)
$1,750
$1,500
$1,500
Less: Borrowings
(1,513)
–
–
(32)
(32)
(32)
Net Debt / Net Market Capitalization
Liquidity
Less: Letters of Credit
Plus: Cash
Liquidity (Credit Facility + Cash)
12
77
339
$217
$1,545
$1,807
1. Initial public offering priced on 10/10/2013; equity valuation based on 262.0 million shares outstanding and a share price of $58.74 as of 1/31/2014. Enterprise value includes net debt.
2. Lender commitments under the facility reduced to $1.5 billion from $1.75 billion on 10/21/2013; commitments can be expanded to the full $2.0 billion borrowing base upon bank approval.
3. $1,000 million 5.375% Senior Notes priced on 10/24/2013, $525 million 9.375% Senior Notes called, $25 million 9.00% Senior Note redeemed, 35% of $400 million 7.25% Senior Notes redeemed and transaction fees.
21

23. 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 Fresh 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
 Eight of Antero’s contracted drilling rigs are currently running on natural gas
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 45 safety consultants cover all material
field operations 24/7 including drilling, completion, construction and pipelining
 23-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
 101 of Antero’s 251 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
22

24. ANTERO KEY ATTRIBUTES
454,000 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
23

25. APPENDIX
24

26. 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
1,600,000
1,400,000
1,200,000
1,000,000
800,000
600,000
400,000
200,000
-
25

27. ANTERO UTICA SHALE WELLS – 24 HOUR IPS
Well
Name
Yontz 1H
Rubel 1H
Gary 2H
Rubel 3H *
Milligan 2H
Rubel 2H
Norman 1H
Coal 3H
Wayne 3HA
Wayne 4H
Milligan 3H
Dollison 1H
Milligan 1H
Wayne 2H
Miley 2H
Miley 5HA
County
Monroe
Monroe
Monroe
Monroe
Noble
Monroe
Monroe
Noble
Noble
Noble
Noble
Noble
Noble
Noble
Noble
Noble
Average ‐ Ethane Recovery(1)
Average ‐ Ethane Rejection(2)
1.
2.
Gas Eq. Rate
(MMcfe/d)
53.3
47.5
43.5
42.6
40.2
37.4
37.1
35.3
35.1
34.2
32.1
27.5
25.8
25.5
22.4
20.2
35.0
28.1
24‐hr Peak Rates ‐ Antero Core Area
Wellhead Gas Shrunk Gas
NGL
(MMcf/d)
(MMcf/d)
(Bbl/d)
38.9
33.9
3,177
31.1
25.9
3,391
28.9
24.2
3,053
28.4
23.7
3,003
17.2
13.5
2,361
24.8
20.7
2,635
26.1
22.3
2,419
15.1
11.8
2,063
14.7
11.6
2,018
14.2
11.2
1,907
15.4
12.1
2,111
12.5
10.2
1,488
10.6
8.3
1,461
10.9
8.5
1,503
8.6
6.7
1,172
7.7
6.0
1,090
19.1
19.1
15.7
18.5
2,178
819
Condensate
(Bbl/d)
52
214
162
142
2,087
156
45
1,850
1,905
1,922
1,228
1,397
1,442
1,331
1,450
1,285
1,042
776
Lateral
% Total Estimated Length
Liquids
BTU
(Feet)
36%
1161
5,115
46%
1231
6,554
44%
1224
8,882
44%
1220
6,424
66%
1276
5,989
45%
1217
6,571
40%
1186
5,498
67%
1278
7,768
67%
1272
6,712
67%
1265
6,493
62%
1276
5,267
63%
1238
6,253
68%
1276
6,436
67%
1281
6,094
70%
1278
6,153
70%
1291
6,296
58%
40%
1248
1248
24-hour peak rates assume full ethane recovery (assuming typical ethane plant product recoveries of 85% to 90%) however Antero is currently rejecting ethane due to current market prices.
Average of Antero’s first 16 core area wells, assuming ethane rejection.
6,407
6,407
26

28. ANTERO UTICA SHALE WELLS – 30-DAY RATES
 Antero’s wells have been producing against 1,100 psi line pressure due to lack of compression facilities
− First 120 MMcf/d compressor station started up in late January
Well
Name
Gary 2H
Rubel 2H
Rubel 3H
Yontz 1H
Norman 1H
Rubel 1H
Wayne 2H
Wayne 3HA
Wayne 4H
Miley 2H
Miley 5HA
County
Monroe
Monroe
Monroe
Monroe
Monroe
Monroe
Noble
Noble
Noble
Noble
Noble
Average ‐ Ethane Rejection
Average ‐ Ethane Recovery(1)
1.
30‐Day Rates ‐ Antero Core Area
Gas Eq. Rate Wellhead Gas Shrunk Gas
NGL
(MMcfe/d)
(MMcf/d)
(MMcf/d)
(Bbl/d)
29.7
24.6
23.1
1,023
19.2
15.9
15.0
625
18.7
15.6
14.7
623
17.0
15.2
14.6
392
16.4
14.3
13.6
461
14.0
11.5
10.8
501
12.1
6.5
6.0
367
11.0
6.1
5.6
354
9.2
5.2
4.7
284
9.0
3.8
3.5
213
5.9
2.7
2.5
161
14.7
17.9
Average of Antero’s first 11 core area wells, assuming ethane recovery.
11.0
11.0
10.4
9.2
455
1,189
Condensate % Total Estimated
(Bbl/d)
Liquids
BTU
65
22%
1224
64
22%
1217
43
21%
1220
1
14%
1161
2
17%
1186
28
23%
1231
653
51%
1281
540
49%
1272
452
48%
1265
700
61%
1278
418
59%
1291
270
270
35%
53%
1239
1239
Lateral
Length
(Feet)
8,882
6,571
6,424
5,115
5,498
6,554
6,094
6,712
6,493
6,153
6,296
6,436
6,436
27

29. CONSIDERABLE RESERVE BASE WITH
ETHANE OPTIONALITY
 25 year proved reserve life from current production annualized
 Reserve base provides significant exposure to liquids-rich projects
– 3P reserves of over 2.2 BBbl of NGLs and condensate in ethane recovery mode; 33% liquids
ETHANE REJECTION(1)
ETHANE RECOVERY(1)
Marcellus – 25.0 Tcfe
Marcellus – 29.5 Tcfe
Utica – 5.8 Tcfe
Utica – 6.7 Tcfe
Upper Devonian – 4.2 Tcfe
Upper Devonian – 4.7 Tcfe
35.0
Tcfe
40.8
Tcfe
Gas – 29.6 Tcf
Gas – 27.4 Tcf
Oil – 91 MMBbls
Oil – 91 MMBbls
NGLs – 811 MMBbls
NGLs – 2,151 MMBbls
15%
Liquids
33%
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.
28

30. 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)
+$4.13
Upgrade
+$2.79
$9.00
$8.28
Upgrade
$8.00
+$1.04
$7.00
$6.95
Upgrade
$6.00
NGLs (C3+)
$3.92
$5.19
$5.00
$4.15
NGLs (C3+)
$1.30
Gas
$4.15
NGLs (C3+)
$2.93
Gas
$3.90
$4.00
Condensate
$0.16
Condensate
$0.56
Gas
$3.86
Gas
$3.80
$3.00
$2.00
$1.00
(1076 BTU)
$0.00
1050 BTU
Dry Gas
1150 BTU
(1109 BTU)
(1119 BTU)
8% shrink
12% shrink
14% shrink
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.
29

31. 2013 YEAR-TO-DATE REALIZATIONS
9/30/2013 YTD NATURAL GAS REALIZATIONS
YTD
% Sales
76%
18%
5%
1%
100%
TCO
Dominion South
NYMEX(1)
TETCO
Total
Average
Average
NYMEX Price Differential(2)
$3.68
$(0.07)
$3.68
$(0.39)
$3.68
$(0.40)
$3.68
$(0.34)
$3.68
$(0.15)
Average
BTU Upgrade
$0.44
$0.42
$0.41
$0.47
$0.44
Average YTD
Realized Price
$4.05
$3.71
$3.69
$3.80
$3.97
9/30/2013 YTD NGL Y-GRADE (C3+) REALIZATIONS
1%
$0.59
Ethane (C2)
17%
Propane (C3)
$8.69
Iso Butane (C4)
16%
55%
$27.69
Normal Butane
Natural Gasoline
$8.04
11%
Antero Barrel
1. NYMEX differential represents contractual deduct to NYMEX-based sales.
2. Includes firm sales.
3. Based on monthly prices through 9/30/2013 WTI.
$5.72
Total $50.73 per Bbl
48% of WTI(3)
30

32. ANTERO EBITDAX RECONCILIATION
EBITDAX Reconciliation
(9 Months Ended)
($ in thousands)
Antero Resources LLC
9/30/12
9/30/2013
EBITDAX:
Net income (loss) from continuing operations
$140,431
$200,990
Commodity derivative fair value (gains) losses
(52,210)
(285,510)
Net cash receipts on settled commodity derivatives instruments
141,506
109,311
(Gain) loss on sale of assets
(291,190)
-
Interest expense and other
71,046
100,840
Provision (benefit) for income taxes
108,525
120,695
Depreciation, depletion, amortization and accretion
65,360
159,447
Impairment of unproved properties
4,019
9,564
Exploration expense
7,912
17,034
Other
EBITDAX from continuing operations
2,992
1,820
$198,391
$434,191
EBITDAX:
Net income (loss) from discontinued operations
($418,465)
Commodity derivative fair value (gains) losses
(46,358)
Net cash receipts on settled commodity derivatives instruments
79,736
(Gain) loss on sale of assets
427,232
Provision (benefit) for income taxes
4,085
Depreciation, depletion, amortization and accretion
77,654
Impairment of unproved properties
Exploration expense
962
507
EBITDAX from discontinued operations
$125,353
EBITDAX
$323,744
$434,191
31

33. 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.
32