1. Company Overview
January 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 28 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
Market Leading Growth
● 182% Appalachian production CAGR since 2010
● 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
Liquidity and Hedge
Position Support High
Growth Story
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.
● 1.3 Bcf/d of processing capacity by year-end 2014 and 1.5 Bcf/d of gas
takeaway by 2015
● Liquids expected to grow from 8% of third quarter 2013 production
due to focus on liquids-rich development
● ~$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
● 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 – 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%
566 MMcfe/d
7,900 Bbl/d
450,000
4,576
“Pure-Play” Appalachian-Focused Shale Company
Reserves(1)
Net Proved
Net 3P Reserves (1)
Pre-Tax 3P PV-10(1)
6.0 Tcfe
18.7 Tcfe
$13,656 MM
% Liquids – Net 3P
3Q 2013 Net Production
Undrilled 3P Locations
6.3 Tcfe
27.7 Tcfe
$19,100 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
15%
519 MMcfe/d
2,941
B UTICA SHALE – LIQUIDS RICH
B
D
C
279 Bcfe
5.3 Tcfe
$5,223 MM
19%
44 MMcfe/d
720
100% operated
•
Stable acreage base
− Marcellus Shale: 49% HBP, with additional 30%
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
− 20 rigs currently operating
UPPER DEVONIAN SHALE
Net Proved Reserves(1)
Net 3P Reserves (1)
Pre-Tax 3P PV-10(1)
% Liquids – Net 3P
3Q 2013 Net Production
Undrilled 3P Locations
44 Bcfe
3.8 Tcfe
$220 MM
6%
3 MMcfe/d
915
D UTICA SHALE – DRY GAS
Net Acres(3)
Net Resource
Undrilled Locations
Appalachia Rig Count vs. Peers(4)
Rigs
C
Net Proved
Net 3P Reserves (1)
Pre-Tax 3P PV-10(1)
% Liquids – Net 3P
3Q 2013 Net Production
Undrilled 3P Locations
A
Reserves(1)
•
116,000
5.0 Tcfe
950
25
20
15
10
5
0
20
5
9
15
Antero
EQT
9
RRC
Marcellus Shale
1.
2.
3.
4.
7
COG
4
CNX
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.
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.
RigData as of 12/27/2013.
3

5. STRONG TRACK RECORD OF GROWTH
AVERAGE NET DAILY PRODUCTION (MMcfe/d)
Woodford
Piceance
700
Marcellus
APPALACHIAN PRODUCTION (MMcfe/d)
Utica
Marcellus
675
Sold Woodford
and Piceance
600
500
458
400
334
300
100
6
0
87
31
2006
500
2008
2009
2010
2011
2012
1Q
2013
2Q
2013
3Q
2013
4Q (4)
2013
NET PROVED SEC RESERVES (Bcfe)(2)
Woodford
Piceance
Marcellus(3)
30
2010
2011
5,017 4,929
Piceance
680
87
100
2007
2008
Marcellus
126
85
96
(4)
Utica
197
119
91
Financial
Crisis
66
18
25
2009
4Q 2013
50
1,141
235
2006
3Q 2013
157
75
2,000
2Q 2013
175
150
3,231
3,000
1Q 2013
200
125
4,000
2012
Woodford
6,000
0
124
Utica
6,282
5,000
0
522
OPERATED GROSS WELLS SPUD
7,000
1,000
239
200
100
2007
383
300
522
566
44
458
400
133
105
675
600
383
244
200
566
44
Utica
700
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. Per Company guidance released on November 6, 2013.
4

6. MULTI-YEAR DRILLING INVENTORY SUPPORTS
LOW RISK, HIGH-RETURN GROWTH PROFILE
93%
600
505
58%
40%
400
38%
20%
0%
800
673
Highly-Rich
Gas/
Condensate
Highly-Rich
Gas
29%
Rich Gas
Locations
Dry Gas
200
250%
200%
ROR
ROR
60%
777
1000
1,000
Gross Locations
986
100%
80%
UTICA WELL ECONOMICS(1)
208
220%
150%
250
198
177
100%
0%
ROR
 66% of Marcellus locations are processable (1100-plus Btu)
150
100
114%
50%
0
200
137
194%
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)
$ / MMBtu NYMEX (Gas)
Large Inventory of Low Breakeven Projects(2)
$6.75
$7.00
$6.00
$5.00
3 Yr Strip -
335
$3.00
$1.00
$0.00
208
505
1,450
$0.00
$0.00
Locations
Locations
Locations Locations
$0.00
$3.65
Locations
$4.00
$2.00
$5.05
986
$4.15/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 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 NYMEX STRIP as of 1/2/2014.
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 August 2013 at TCO index at NYMEX less
$0.07/MMbtu
Antero Transport and Processing
Leidy
Basis to NYMEX
Current 2015
-$1.18 -$1.62
Dom South
Basis to NYMEX
Current 2015
-$0.92 -$1.02
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)
1,300,000
20,000
Chicago
Basis to NYMEX
Current 2015
+$0.26 -$0.09
2015
1,300,000
20,000
TCO
Basis to NYMEX
Current 2015
-$0.18 -$0.47
Growing Processing Capacity
Total Capacity
1,300
1,400
CGTLA
Basis to NYMEX
Current 2015
-$0.06 -$0.10
1,200
Seneca III
(MMcf/d)
1,000
Sherwood V
Seneca II
800
Seneca I
Sherwood IV
600
400
Cadiz I
Sherwood III
Appalachian Basis to NYMEX(2)
YTD % of
Production Sold
Sherwood II
200
2014
TCO
0
76%
Dom South
Sherwood I
TCO
18%
Dom South
TETCO M2
NYMEX
Marcellus
1.
2.
Sherwood I
Sherwood II
Sherwood III
Sherwood IV
Utica
Cadiz I
Seneca I
Seneca II
Seneca III
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.
5%
Leidy
2015
2016
2017
2018
2019
$0.00
-$0.20
-$0.40
-$0.60
-$0.80
-$1.00
-$1.20
-$1.40
-$1.60
-$1.80
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
-$1.18 -$1.62
Chicago
Basis to NYMEX
Current 2015
+$0.26 -$0.09
Dom South
Basis to NYMEX
Current 2015
-$0.92 -$1.02
(1)
TCO
Basis to NYMEX
Current 2015
-$0.18 -$0.47
CGTLA
Basis to NYMEX
Current 2015
-$0.06 -$0.10
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. Firm transport as of year-end 2014. See Page 25 for timing of firm transportation graph.
2. Antero firm transportation as of 1/2/2014; excludes 250 MMcf/d of firm sales.
8

10. SIGNIFICANT LONG-TERM
COMMODITY HEDGE POSITION
NATURAL GAS HEDGES – CURRENT
BBtu/d
Hedged NYMEX-Equivalent Price(1)
Hedged Volume
800
$5.29
$5.37
$5.14
600
400
$4.65
$4.42
$4.20
$4.14
$7.00
$4.51
$4.16
$4.22
628
550
633
750
650
288
2014
1.
$5.00
$3.00
$2.00
200
0
$6.00
$4.00
$4.11
$4.09
NYMEX Strip (1/2/2014)
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 2013 and 2014, WTI hedges comprise ~1% of overall hedge book.
 ~$960 million mark-to-market unrealized gain as of January 2, 2014.
 1.3 Tcfe hedged from January 1, 2014 through year-end 2019.
% HEDGE VOLUMES BY INDEX – 9/30/2013
2%
Chicago
TCO
14%
NYMEX
21%
44%
Dom South
19%
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
105,000 Net Acres
12 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
320,000 Net Acres
(Primarily Liquids-Rich Fairway)
215 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
 345,000 net acres in
Southwestern Core
– 49% HBP with additional
30% not expiring for 5+ years
 217 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
4-well average
9.3 MMcfe/d
30-day rate
(31% liquids)
BLANCHE UNIT
2H: 10.0 MMcfe/d
30-day rate
(29% liquids)
DOTSON UNIT
1H: 12.4 MMcfe/d
2H: 11.8 MMcfe/d
30-day rates
(27% liquids)
EQT
12 Recent Wells
9.2 MMcfe/d
30-day rate
(20% Liquids)
CHK HADLEY UNIT
9.1 MMcfe/d IP
(32% liquids)
MOORE UNIT
1H: 9.9 MMcfe/d
2H: 10.0 MMcfe/d
30-day rates
(17% liquids)
Sherwood
Processing
Plant
EQT PENN 15 UNIT
5-well average
9.3 MMcfe/d
30-day rate
(29% liquids)
142 Horizontals Completed
10.3 Bcfe average EUR
8.1 MMcfe/d average 30-day rate
6,915’ average lateral length
 2,941 future drilling locations
(66% are processable)
 Operating 15 drilling rigs
including 4 shallow rigs
 18.7 Tcfe of net 3P (15%
liquids), includes 6.0 Tcfe of
proved reserves
CONSTABLE UNIT
1H: 15.2 MMcfe/d
30-day rate
(30% liquids)
PRUNTY UNIT
1H: 11.0 MMcfe/d
30-day rate
(29% liquids)
Highly-Rich/Condensate
54,000 Net Acres
505 Gross Locations
Highly-Rich Gas
96,000 Net Acres
777 Gross Locations
HINTERER UNIT
1H: 12.9 MMcfe/d
30-day rate
(20% liquids)
Rich Gas
82,000 Net Acres
673 Gross Locations
RUTH UNIT
1H: 19.3 MMcfe/d
30-day rate
(14% liquids)
Dry Gas
104,000 Net Acres
986 Gross Locations
12
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.

14. MARCELLUS – SIMPLE STRUCTURE
 Several regional anticlines in core area
− Predictable “layer cake” geology
− No faults at Marcellus level
• Over 1.5 million feet (285 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 four years of production data, from 217 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 wellhead peak rate (IP) of 14.1 MMcf/d; 14.9 MMcfe/d processed assuming ethane rejection
 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
10.0
Type Curve Cumulative Production (7,000' Lateral)
30-Day
Avg. Rate
90-Day
Avg. Rate
180-Day
Avg. Rate
One-Year
Avg. Rate
Two-Year
Avg. Rate
Three-Year
Avg. Rate
14.1
217
8.0
209
6.3
180
5.4
158
4.2
109
3.0
56
2.3
18
Wellhead (MMcf/d)
# of wells
8.0
14.0
12.0
10.0
8.0
6.0
6.0
4.0
4.0
2.0
Cumulative Bcf
12.0
Actual Production (Normalized to 7,000' Lateral)
24-Hour
Peak Rate
14.0
MMcf/d
(1)
Type Curve (7,000' Lateral)
2.0
0.0
0.0
0
1
2
3
4
5
6
7
8
9
10
Production Year
EURs Increase With Lateral Length
Well Cost / 1,000’ Decreases with Lateral Length
Wellhead 24-hour Peak Rates (IPs) - 217 Wells
$1.6
30
$1.4
25
12
8
MMcf/d
35
$MM / 1,000'
$1.8
16
EUR, BCF
20
$1.2
$1.0
4
$0.6
2,000
20
15
10
$0.8
0
2,000
Average IP – 14.1 MMcf/d
5
4,000
6,000
8,000
Lateral Length, ft
10,000
4,000
1. All 217 Antero Marcellus wells normalized to time zero, production for each well normalized to 7,000’ lateral length.
6,000
8,000
Lateral length, ft
10,000
0
1st Production from All Wells 2009 - 2013
14

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 First 15 Unconstrained SSL Wells – 24-hour Peak Rate
28.4
30.0
31% Increase in IPs for SSL
22.9 22.2
MMcf/d
25.0
Average Antero SSL 24-hour Peak Rate: 18.1 MMcf/d
19.5 19.5 19.1 17.9 17.4 17.2 16.9 16.3 16.0 15.6
20.0
13.4
15.0
Average Antero 24-hour Peak Rate: 13.8 MMcf/d(1)
10.0
9.1
5.0
0.0
Normalized production increase for 20 SSL wells over 1.5 Bcf/1,000' Type Curve
Gas Production (Mcf/d)
 Since June 2013 Antero has
implemented shorter stage lengths
(SSL) in the Marcellus Shale
– 24 SSL wells completed
– 150’ to 250’ vs. 350’ stages
previously
 The 24-hour peak rate for Antero’s
first 15 unconstrained SSL wells has
averaged 18.1 MMcf/d or 31% higher
than the average Antero non-SSL IP
of 13.8 MMcf/d
– Other Marcellus Southwestern
Core operators (EQT and Range)
have announced 20% to 30%
improvement in IPs and EURs
 Estimated 20% increase in well costs
for SSL
Antero SSL Wells
10,000
1.5 Bcf/1,000' Type Curve
1,000
0
1. Excludes 15 SSL wells.
30
60
90
120
Days From Peak Gas
Unconstrained SSL Average
150
1.5 Bcf/1,000' Type Curve
180
16

18. EXCITING CORE UTICA SHALE POSITION DELIVERS
CONDENSATE AND NGLS
 100% operated
 ~105,000 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
 12 horizontal wells completed - all 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
− Production constrained until completion of
initial compressor stations with first
compression expected in 4Q 2013
 720 future drilling locations
– Approximately 36% of EUR is liquids
assuming ethane recovery
 Operating 5 rigs including 1 shallow rig
 5.3 Tcfe of net 3P (19% liquids), includes
279 Bcfe of proved reserves
Utica Shale Industry Activity and 24-Hour Peak Rates(1)
CHESAPEAKE
8 Wells
Average 8.3 MMcfe/d
(1,391 Boe/d)
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
CHESAPEAKE
Buell #8H
9.5 MMcf/d
+ 1,425 Bbl/d liquids
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
Seneca
Processing
Plant
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
10.4 MMcf/d + 1,809 Bbl/d NGL
+ 1,719 Bbl/d Oil
RUBEL UNIT
3 wells average
23.4 MMcf/d + 1,488 Bbl/d NGL
+ 171 Bbl/d Oil
MILEY UNIT
2 wells average
6.3 MMcf/d + 1,131 Bbl/d NGL
+ 1,368 Bbl/d Oil
NORMAN UNIT 1H
22.3 MMcf/d
+ 2,419 Bbl/d NGL
+ 45 Bbl/d Oil
Highly-Rich/Cond
34,000 Net Acres
208 Locations
DOLLISON UNIT 1H
Currently Completing
YONTZ UNIT 1H
33.9 MMcf/d
+ 3,177 Bbl/d NGL
+ 52 Bbl/d Oil
Highly-Rich Gas
19,000 Net Acres
198 Locations
Rich Gas
25,000 Net Acres
137 Locations
GARY UNIT 1H
24.2 MMcf/d
+ 3,053 Bbl/d NGL
+ 162 Bbl/d Oil
Dry Gas
26,000 Net Acres
177 Locations
Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are owned. Note: Peak rates assume ethane recovery.
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 8 of the top 9 Utica
24-hour peak rates (IPs)
announced to date
 Liquids content ranges from
40%-70% (assumes ethane
recovery) in the liquids-rich
window
 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
Core
2,000 to 9,000
10,000
Boe/d IPs
9,000
8,000
7,000
6,000
Boe/d
 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
UTICA IPs
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 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
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
$15,781
$521
$521
$521
Net Market
Capitalization(1)
Financial & Operating Statistics
LTM EBITDAX
Proved Reserves (Bcfe) (6/30/2013)
6,282
6,282
6,282
Proved Developed Reserves (Bcfe) (6/30/2013)
1,445
1,445
1,445
Credit Statistics
Net Debt / LTM EBITDAX
5.7x
2.7x
2.8x
LTM EBITDAX / Interest Expense
4.1x
4.7x
5.1x
Net Debt / Net Book Capitalization
61.4%
28.9%
29.8%
N/M
8.9%
9.2%
Net Debt / Proved Developed Reserves ($/Mcfe)
$2.07
$0.97
$1.01
Net Debt / Proved Reserves ($/Mcfe)
$0.48
$0.22
$0.23
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 $54.69 as of 12/5/2013. 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
 Antero named Business of
 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 running on natural gas and the
majority of its rigs should run on natural gas by year-end 2013
Natural Gas
Vehicles (NGV)
the Year for 2013 in Harrison
County, West Virginia “For
outstanding corporate
citizenship and community
involvement”
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
 87 of Antero’s 233 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
450,000 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
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. UTICA SHALE WELLS – ANTERO INITIAL RESULTS
24‐hr Peak Rate
Oil Eq. Rate Wellhead Gas Shrunk Gas
(MMcf/d)
(MMcf/d)
(Boe/d)(1)
8,879
38.9
33.9
7,917
31.1
25.9
7,246
28.9
24.2
BTU
1161
1231
1224
44%
1220
6,424
156
45
1,905
1,922
1,331
1,450
1,285
653
45%
40%
67%
67%
67%
70%
70%
79%
1217
1186
1272
1265
1281
1278
1291
1316
6,571
5,498
6,712
6,493
6,094
6,153
6,296
7,159
776
776
56%
40%
1245
1245
6,496
6,496
Well
Name
Yontz 1H
Rubel 1H
Gary 2H
County
Monroe
Monroe
Monroe
Rubel 3H
Monroe
7,097
28.4
23.7
3,003
142
Rubel 2H
Norman 1H
Wayne 3HA
Wayne 4H
Wayne 2H
Miley 2H
Miley 5HA
Sanford
Monroe
Monroe
Noble
Noble
Noble
Noble
Noble
Noble
6,241
6,181
5,852
5,698
4,257
3,740
3,369
1,148
24.8
26.1
14.7
14.2
10.9
8.6
7.7
1.8
20.7
22.3
11.6
11.2
8.5
6.7
6.0
1.4
2,635
2,419
2,018
1,907
1,503
1,172
1,090
256
5,635
4,677
19.7
19.7
16.3
18.5
2,135
819
Average ‐ Ethane Recovery
Average ‐ Ethane Rejection(2)
1.
2.
NGL
(Bbl/d)
3,177
3,391
3,053
Lateral
Length
(Feet)
5,115
6,554
8,882
Condensate % Total
(Bbl/d)
Liquids
52
36%
214
46%
162
44%
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 12 wells, assuming ethane rejection.
26

28. 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.
27

29. 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.
28

30. 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)
29

31. 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
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