Company Overview September 2013

September 2013
Company Overview

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 LLC and its subsidiaries (collectively, the
“Company”) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,”
“expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify
forward-looking statements, which are generally not historical in nature. However, the absence of these words does not mean
that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements
contained in this presentation specifically include 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 filings with the SEC.
We caution 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 “Item 1A. Risk Factors” in
our Annual Report on Form 10-K for the year ended December 31, 2012.
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.
Forward-Looking Statements
1

Antero Resources Snapshot
• Private E&P company headquartered in Denver, Colorado – extensive shale experience
− Drilled and operated over 450 horizontal shale wells in Barnett, Woodford, Marcellus and Utica Shales
• Appalachian Shale-Focused – a “pure play” company with upstream and midstream assets
− Marcellus Shale: 328,000 net acres all located in the Southwestern Core area, 195 horizontal wells completed
− Utica Shale: 101,000 net acres all located in the Core of the play, 11 horizontal wells completed
− Upper Devonian Shale: 170,000 net acres (overlying Marcellus Shale), 2 horizontal wells completed
• High production growth – Appalachian production has increased 115% year-over-year to 458 MMcfe/d net for 2Q
2013, including 3,300 Bbl/d of liquids
− Estimated August 2013 net production averaged 590 MMcfe/d including 9,000 Bbl/d of liquids
− Current net production is 680 MMcfe/d including 13,500 Bbl/d of liquids, with an additional 115 MMcfe/d of net
production including 4,300 Bbl/d of liquids constrained/shut-in waiting on pipeline, compression or processing
• Large, low risk drilling inventory – Over 4,500 horizontal drilling locations will continue to feed high growth in
existing 6.3 Tcfe(1) proved reserve base as of June 30, 2013 (assuming ethane rejection)
• Low cost leader – $1.03/Mcfe 3-year pro forma development cost calculated using 2012 J.P. Morgan methodology(2)
− $0.90/Mcfe estimated net future development cost in 6/30/2013 3P reserve base (assuming ethane rejection)
• Rapidly growing liquids exposure – 12% by production volume today, forecast to grow to ~20% by 2014 assuming
ethane rejection (~40% liquids exposure if assume ethane recovery in 2014 and beyond)
• Large long-term hedge position – 1,024 Bcfe hedged at $5.11/MMBtu NYMEX-equivalent(3) through 2019
• Infrastructure emphasis – Gathering, compression and processing infrastructure either in place or committed and
underway – well positioned in southern portion of Marcellus and Utica Shale plays for access to gas takeaway
• Strong liquidity to fuel low cost growth – ~$1.0 billion(4) of undrawn borrowing base capacity as of June 30, 2013
2
___________________________
1. 6/30/2013 SEC reserves assuming ethane rejection using a price deck of $3.43/MMBtu for Appalachia. WTI SEC price averaged $91.65/Bbl. Reserves audited by independent third-party engineers DeGolyger & MacNaughton using
SEC reserve methodology and pricing.
2. Source: Proved developed F&D research report prepared by J.P. Morgan dated 7/22/2013. Includes total drilling and completion costs but excludes land and acquisition costs for all companies. 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. Calculated by Antero using J.P. Morgan methodology; Marcellus and Utica only.
3. 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.
4. Lender commitments under the facility are $1.75 billion which can be expanded to the full $2.0 billion borrowing base. Undrawn capacity as of 6/30/2013.

Appalachia
Total – SEC Reserves
___________________________
1. 6/30/2013 SEC reserves assuming ethane rejection and using a price deck of $3.43/MMBtu for Appalachia. WTI SEC price averaged $91.65/Bbl. Reserves prepared internally using SEC reserve methodology and pricing
and audited by independent third-party engineers DeGolyer & MacNaughton.
2. See note on page 38 for 3P definition.
3. Includes hedge PV-10 value of $944 million.
4. All net acres allocated to the Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as formations attributable to the same leases.
Marcellus Shale
Low Cost Liquids-Rich Reserve Base
SEC Proved Reserves(1) 5,959 Bcfe
Net 3P Gas Equivalent(1,2) 18,714 Bcfe
Net 3P Liquids(1,2) 465 MMBbls
% Liquids – Net 3P 15%
2Q 2013 Net Production 453 MMcfe/d
Net Acreage 328,000
Undrilled Locations 2,941
SEC Proved Reserves(1) 6.3 Tcfe
Net 3P Gas Equivalent(1,2) 27.7 Tcfe
Proved Developed PV-10(3) $3.0 Billion
Proved PV-10(3) $5.4 Billion
Net Acreage(4) 429,000
Utica Shale
SEC Proved Reserves(1) 279 Bcfe
Net Acreage 101,000
Undrilled Locations 720
Upper Devonian Shale
SEC Proved Reserves(1) 44 Bcfe
Net Acreage(4) 170,000
Undrilled Locations 915
3
● Antero increased Appalachian proved reserves by 44% at mid-year 2013, assuming ethane recovery, and 47%
assuming ethane rejection, from year-end 2012

Marcellus,
18.7 Tcfe
Utica, 5.3
Tcfe
Upper
Devonian,
3.8 Tcfe
• Antero’s liquids-rich position provides significant upside to improving NGL pricing
– 3P reserves of over 1.6 BBbls of NGLs and condensate assuming ethane recovery mode – 31% liquids
Significant Ethane Optionality
Ethane Rejection(1) Ethane Recovery(1)
Gas, 23.8
Tcf
Oil, 71
MMBbls NGLs, 595
MMBbls
Gas, 22.2
Tcf
Oil, 71
MMBbls
NGLs,
1,580
MMBbls
27.7 Tcfe 32.1 Tcfe
14% Liquids 31% Liquids
___________________________
1. Ethane rejection occurs when ethane is left in the wellhead gas stream when 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.
4
Marcellus,
21.8 Tcfe
Utica, 6.1
Tcfe
Upper
Devonian,
4.2 Tcfe

Strong Track Record of Growth
___________________________
1. Proved reserves for 2006, 2007 and 2008 represent previously effective SEC methodology. 2009, 2010, 2011, 2012 and 6/30/2013 proved reserves based on current SEC reserve methodology and
pricing and audited by independent third-party engineers. 2012 excludes Arkoma Basin reserves which were sold on June 29, 2012 and Piceance Basin reserves which were sold on December 21,
2012. Marcellus includes Upper Devonian Shale proved reserves.
2. CAGR = Compound Annual Growth Rate.
Average Net Daily Production
Net Proved SEC Reserves (1)
Appalachia Production
Operated Wells Spud
6 31
87 105
133
244
87 235
680
1,141
3,231
5,017
85
96
126
18
66
91Economic
Crisis
119
5
334
4,929
156
21
458
2Q 2013
6,282
30
124
239
458
1Q 2013
383
383

$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
Range
Cabot
EQT
SMEnergy
Noble
Cimarex
Southwestern
Pioneer
Concho
Devon
Chesapeake
EOG
Newfield
0%
20%
40%
60%
80%
100%
Industry Leading Finding Costs
Industry 3-Year All-in Finding Costs Through 2012(1)(2)
3‐Year Comp Median = $2.75/Mcfe(3)
• Based on the Howard Weil 2012 F&D Cost Study, Antero had the lowest three-year
average all-in finding cost through 2012 of $0.48/Mcfe
$/Mcfe
Antero
___________________________
1. Source: Howard Weil 2012 Finding & Development Cost Study.
2. Antero finding costs calculated over 3 years using 12/31/2012 SEC reserves, including Arkoma, Fayetteville and Piceance. Reserves were audited by DeGolyer & MacNaughton (Appalachia, Arkoma and
Fayetteville) and Ryder Scott (Piceance). Antero % Gas Reserves reflects MY 2013 proved reserves assuming ethane rejection.
3. Median calculated for comparable company set used in this graph; excludes Antero.
● Includes all drilling, land and acquisition expenditures
- Most direct Antero comparables
6
% Gas Proved
Reserves
$0.48
Marcellus Producers
$0.84 $1.02
$1.31

$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
Cabot
Range
Southwestern
EQT
Ultra
Chesapeake
Devon
Concho
Newfield
Pioneer
Cimarex
EOG
SMEnergy
Noble
0%
20%
40%
60%
80%
100%
$1.03 $1.14
$1.41 $1.57 $1.71
Most-direct Antero comparables___________________________
1. Source: Proved developed F&D research report prepared by J.P. Morgan Research dated 7/22/2013. Includes all total drilling and completion costs but excludes land and acquisition costs for all companies. Defined as
total drilling and completion capital expenditures for the period divided by PDP and PDNP volumes after adding back production for the period. Antero % Gas Reserves calculated from 6/30/2013 proved reserves.
2. Median calculated for comparable company set used in this graph; excludes Antero.
3. Calculated by Antero using J.P. Morgan methodology – pro forma for divestiture of Arkoma and Piceance properties.
4. Calculated by Antero using J.P. Morgan methodology.
Industry 3-Year Development Costs Through 2012(1)
AnteroPF(3)
$/Mcfe
● Per Mcfe development cost excluding land is a better measure of capital efficiency than finding costs
− Antero was the leader in 3-year development costs through 2012
Industry Leading Development Costs
7
Antero(4)
3‐Year Comp Median = $3.04(2)
% Gas Proved
Reserves
• Based on the J.P. Morgan proved developed F&D methodology, Antero ranks as the lowest
cost developer with a three-year average pro forma development cost of $1.03/Mcfe

● Antero expects to realize approximately $771 million(1) of hedge gains over the next seven years from its current
1,024 Bcfe hedge book which averages $5.11/MMBtu NYMEX-equivalent, assuming current strip prices
− Protects future cash flow thereby supporting drilling plans and production growth
Current Antero Hedge Position – July 1, 2013 through 2019(2)Current Antero Hedge Position – July 1, 2013 through 2019(2)
Natural Gas Swaps
Hedged Volume
(MMBtu/d)
NYMEX-Equivalent Price
($/MMBtu)(2)
2013 470,270 $5.25
2014 398,000 $5.93
2015 390,000 $5.69
2016 522,500 $5.23
2017 640,000 $4.41
2018 530,000 $4.73
2019 87,500 $4.75
___________________________
1. Undiscounted value based on STRIP natural gas prices as of August 30, 2013.
2. Virtually all hedges are fixed price swaps, hedged to the basin. Basin prices are converted by Antero to NYMEX-equivalent prices using current basis differentials in the over-the-counter futures market and a gas to oil
conversion ration of 6:1.
Strong Hedge Position
8
$91
$206 $217
$182
$24
$52
$-
$62
$(50)
$-
$50
$100
$150
$200
$250
2013 2014 2015 2016 2017 2018 2019
$MM Projected Annual Hedging Gains (1)(2)
Realized Gains Unrealized Gains
$154

Appalachian Basin – Overview
10
Antero Marcellus SW PA
25,000 Net Acres
2 horizontal wells completed
Antero Marcellus NW WV
303,000 Net Acres
15 rigs running
Southwestern and
Northeastern Core Areas
Marcellus Rich Gas Window
in Southwestern Core
Upper Devonian Shale Resource
Overlies Antero Marcellus Acreage
Antero Utica OH
101,000 Net Acres
4 rigs running
Utica Liquids
Rich Fairway
Source: Company presentations and press releases.
Utica Core Area

● 328,000 net acres of leasehold in Southwestern Core of the
Marcellus play
– 52% HBP with additional 26% not expiring for 5-plus years
– Over 80% of acreage has rich gas processing potential
● 100% operated by Antero
● 6.0 Tcfe of proved reserves; 18.7 Tcfe of 3P reserves
● 534 MMcfe/d net operated production estimated for August 2013
including 6,900 Bbl/d of liquids
– 585 MMcfe/d of estimated current net production including
8,500 Bbl/d of liquids (including Upper Devonian Shale)
● Operating 15 drilling rigs currently and two frac crews 24/7
● Antero has completed 195 consistently strong horizontal wells,
193 of which are online
– Demonstrated ability to drill wells with long laterals
7,000 ft + in less than 30 days
– 100% drilling success rate
Fully Integrated
● Sherwood I (running at full capacity) and Sherwood II
processing plants currently on line – 400 MMcf/d capacity fully
dedicated to Antero
– 200 MMcf/d Sherwood III processing plant expected to go
on line in 4Q 2013 with 200 MMcf/d Sherwood IV expected
in 2Q 2014
● 1,300,000 MMBtu/d of long-haul firm transportation or firm sales
secured – well positioned in southern portion of play
− 530,000 MMBtu/d of back-haul firm transportation to Gulf
Coast
● Committed to 20,000 Bbl/d ethane takeaway capacity on
Enterprise ATEX pipeline to Mont Belvieu expected to be in
service 1Q 2014
Antero Marcellus Shale
SummarySummary
11

Large Scale Position in Marcellus Core
● Antero has delineated and de-risked a large scale acreage position in the Southwestern Core of the Marcellus
Shale in northern West Virginia – currently building more infrastructure to process highly rich gas
Sherwood
Processing
Plant
Webley Fork 1H:
13.3 MMcfe/d 30-day rate
Little Tom 1H:
16.0 MMcfe/d 30-day rate
Valentine Unit
1H: 5,232 Boe/d IP
(50% Liquids)
2H: 3,726 Boe/d IP
(50% Liquids)
Moore Unit
1H: 21.5 MMcfe/d 30-day rate
2H: 20.5 MMcfe/d 30-day rate
Dry Gas
65,000 Net Acres
588 Gross Locations
Rich Gas
157,000 Net Acres
1,430 Gross Locations
Highly Rich Gas
106,000 Net Acres
923 Gross Locations
Dotson Unit
1H: 3,780 Boe/d IP
(50% Liquids)
2H:4,547 Boe/d IP
(50% Liquids)
Constable Unit
1H: 5,257 Boe/d IP
(51% Liquids)
Source: Company presentations and press releases. Note: All IPs are 24-hour peak rate; Boe/d IPs assume processing and full ethane recovery.
12
Cleta Unit
1H: 15.9 MMcfe/d
30-day rate
2H: 17.0 MMcfe/d
30-day rate
Triad Spencer Unit
4 wells averaged
1,550 Boe/d 30-day rate
(54% Liquids)
CHK Hadley Unit
1,884 Boe/d IP
(58% Liquids)
EQT PEN 15 Unit
5 wells averaged
1,553 Boe/d 30-day rate
(51% Liquids)
141 Horizontals Completed
10.1 Bcfe average EUR
8.3 MMcfe/d average 30-day rate
6,917’ avg lateral length
Prunty Unit
1H: 3,205 Boe/d IP
(50% Liquids)
Blanche Unit
2H:3,019 Boe/d IP
(52% Liquids)

0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
Dec-09
Feb-10
Apr-10
Jun-10
Aug-10
Oct-10
Dec-10
Feb-11
Apr-11
Jun-11
Aug-11
Oct-11
Dec-11
Feb-12
Apr-12
Jun-12
Aug-12
Oct-12
Dec-12
Feb-13
Apr-13
Jun-13
Aug-13
Mcf/d
Gross Mcfd NET MCFD
Strong Marcellus Production Growth
Antero Gross Operated Marcellus Production
13
Bobcat Lateral online
September 2010
Jarvisville Lateral online
June 2011
Tichenal Lateral online
September 2011
Shift to pad
development drilling
Tichenal Compressor
repairs Dec 2012
Infrastructure
Delays

14
● Antero has over 3-½ years of production history to support its 1.5 Bcf/1,000’ of lateral recovery assumption as
demonstrated by the graph and table below
− DeGolyer & MacNaughton (D&M), Antero’s third party reserve auditor, supports this type curve
● Antero’s average 24-hour peak rate is 13.9 MMcf/d in the Marcellus
24-hour
peak(3)
30-day
avg. rate
90-day
avg. rate
180-day
avg. rate
One-year
avg. rate
Two-year
avg. rate
Three-year
avg. rate
MMcf/d 13.9 7.9 6.2 5.3 4.0 2.9 2.3
# of wells 193 177 171 134 95 49 15
Antero Marcellus Type Curve Support
___________________________
Note: Type curve reflects pre-processed wellhead production.
1. Wells normalized to time-zero; production for each well normalized to 7,000’ lateral length.
2. Actual wellhead IPs, not normalized.
3. Excludes two wells that are shut-in and waiting on infrastructure.
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
11.0
12.0
13.0
14.0
15.0
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
11.0
12.0
13.0
14.0
15.0
0 1 2 3 4 5 6 7 8 9 10
CumulativeBcf
MMcf/d
Production Year
Area 1 Type Curve (7,000' Lateral)
Area 1 Actual Production (Normalized to 7,000' Lateral)
Area 1 Type Curve Cumulative Production (7,000' Lateral)
Antero Marcellus 1.5 Bcf/1,000’ Type Curve(1)Antero Marcellus 1.5 Bcf/1,000’ Type Curve(1) Antero Marcellus 24-hr Wellhead IPs(2)Antero Marcellus 24-hr Wellhead IPs(2)
0
5
10
15
20
25
30
35
MMcf/d
1st Production From All Wells 2009 - 2013
Average IP
13.9 MMcf/d

-
100
200
300
400
500
600
700
800
0%
50%
100%
150%
200%
250%
300%
950 1000 1050 1100 1150 1200 1250 1300 1350
ROR
DRY BTU
Marcellus Processing Economics
___________________________
1. Assumes 85% NRI and NGL price of 40% of WTI for 1200 BTU y-grade barrel. NGL WTI correlation changes to reflect y-grade barrel composition for different BTU regimes.
2. No ethane takeaway available until Enterprise ethane pipeline is online (expected 1Q 2014). Well economics include fixed fee cost tariff on ATEX ethane pipeline.
• Dramatic improvement in returns by processing higher BTU gas – Antero’s Marcellus rich gas leasehold spans the
1050 to 1350 BTU spectrum
• Antero has 2,353 gross processable horizontal locations (>1050 BTU)
Representative of single well
examples used for Marcellus
rich gas in Appendix
- Current
Antero rigs
15
No Processing
128% ROR
Dry Gas Locations Rich Gas Locations Highly Rich Gas Locations
57% ROR C2 Rejection
C2 Recovery
 Single well economics example(1)(2):
– 10.0 Bcf well
– $8.0 million well cost ($0.94/Mcf net F&D cost)
– Assumes $4.25/MMBtu NYMEX 3-year STRIP, $90.00/Bbl oil
and NGL pricing at 40% of WTI for 1200 BTU y-grade barrel
1250 BTU – NGL Margin
C2 Rejection: $2.12/Mcf
C2 Recovery: $2.17/Mcf
1150 BTU – NGL Margin
C2 Rejection: $0.73/Mcf
C2 Recovery: $0.76/Mcf

Gas
$4.38
Gas
$4.07
Gas
$4.04
Gas
$3.55
Gas
$3.36
Condensate $0.45
Condensate $0.45
NGLs (C3+)
$0.96
NGLs (C3+)
$2.26
NGLs (C2+)
$1.22
NGLs (C2+)
$2.62
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
$9.00
1050 BTU 1150 BTU 1250 BTU 1150 BTU 1250 BTU
Dry Gas Rich Gas Rich Gas
+$2.04
Upgrade
___________________________
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.
Marcellus Rich Gas – Liquids and Processing
Upgrade
Current – Ethane Rejection Projected – Ethane Recovery
(1085 BTU)
4% shrink
(1100 BTU)
6% shrink
(1006 BTU)
14% shrink
(1008 BTU)
17% shrink
$4.38
$5.03
$6.75
$4.77
$6.42
$/Wellhead Mcf(1)
• Marcellus rich gas and highly rich gas acreage provides a significant advantage in well economics – assuming
$4.25/MMBtu NYMEX, $90.00/Bbl WTI and current spot NGL pricing correlation
• Upgrade analysis demonstrates that ethane recovery is not economic at current ethane price
16
($/Mcf)
+$2.37
Upgrade
+$0.65
Upgrade
+$0.39
Upgrade

Fresh Water Management System
Water Management System MapSummary
17
December 2013
Expected Completion
Date
 158-mile Marcellus water sourcing and
distribution system to improve operational
efficiency and reduce water truck traffic
– $375 million total project costs
– $200 million in 2013E capital costs
– 150-miles of temporary and reusable pipeline,
40 centralized water storage facilities
equipped with transfer pumps and 4 pumping
stations optimize water delivery
 56-mile Utica water sourcing and distribution
system to improve operational efficiency and
reduce water truck traffic
– $150 million total project costs
– $50 million in 2013E capital costs
– 45-miles of temporary and reusable pipeline
and 22 centralized water storage facilities and
equipped with transfer pumps
 Reduces frac water costs from $6.00/Bbl to
$2.00/Bbl
– Cost savings of up to $600,000 per well
 Reliable year-round water supply
 Over 30% of wells drilled in 2013 and up to
90% of wells drilled in 2014 to utilize new water
infrastructure

CNX/Hess
Noble 16A
8.8 MMcf/d + 1,556 Bbl/d NGL +
768 Bbl/d oil
● Based on geologic analysis and announced drilling
results, the core area is in the southern portion of
the play
● Antero has 101,000 net acres of leasehold in Core
of the Utica play
– 20% HBP and remaining 77% not expiring for
5-plus years
– Over 90% of acreage has rich gas processing
potential
● 100% operated by Antero
● Operating four drilling rigs currently; fifth rig to be
added in 4Q 2013
● 279 Bcfe of proved reserves; 5.3 Tcfe of 3P
reserves
● 56 MMcfe/d net operated production estimated for
August 2013 including 2,100 Bbl/d of liquids
– 95 MMcfe/d of estimated current net
production including 5,000 Bbl/d of liquids
● 11 wells on line – 30 MMcfe/d of estimated
constrained production
● 100% drilling success rate
Fully Integrated
● 80 MMcf/d of priority processing capacity until 4Q
when Seneca I is expected on line
● 200 MMcf/d Seneca I cryogenic processing plant
on line in early 4Q 2013 and 200 MMcf/d Seneca
II expected on line late 4Q 2013
● Access to 20,000 Bbl/d of ethane takeaway
capacity on Enterprise ATEX pipeline to Mont
Belvieu expected to be in service 1Q 2014
Antero Utica Shale
SummarySummary
18
Gulfport Energy
Wagner #1-28H
17.1 MMcf/d + 1,881 Bbl/d NGL +
432 Bbl/d oil
Chesapeake
Bailey #3H
5.7 MMcf/d + 270 Bbl/d NGL +
205 Bbl/d oil
Chesapeake
Brown #10H
1,445 Boe/d
(Including 8.7 MMcf/d gas)
Chesapeake
Coniglio #6H
1,125 Boe/d with 290 Bbl/d Oil
Chesapeake
Mangun #8H
3.1 MMcf/d + 1,015 Bbl/d liquids
Chesapeake
Neider #3H
3.8 MMcf/d + 980 Bbl/d liquids
Chesapeake
Shaw #5H
1,435 Boe/d with
770 Bbl/d Oil + 180 Bbl/d NGL
Chesapeake
Burgett #8H
1,210 Boe/d with 70% Liquids
Chesapeake
Snoddy #6H
4.2 MMcf/d + 250 Bbl/d NGL + 320
Bbl/d oil
Chesapeake
Buell #8H
9.5 MMcf/d + 1,425 Bbl/d liquids
Gulfport Energy
Shugert #1-12H
26 MMcf/d + 2,907 Bbl/d NGL +
300 Bbl/d oil
Gulfport Energy
Shugert #1-1H
20 MMcf/d + 2,022 Bbl/d NGL +
144 Bbl/d oil
Gulfport Energy
BK Stephens #1-16H
1,224 Bbl/d oil
CNX/Hess
Noble 1A
7.0 MMcf/d + 812 Bbl/d NGL + 10
Bbl/d oil
Gulfport Energy
Boy Scout #1-33H
1,560 Bbl/d oil
Gulfport Energy
Ryser #1-25H
1,488 Bbl/d oil
Gulfport Energy
Groh #1-12H
1,186 Bbl/d oil
Enervest
Cairns #5H
2.2 MMcf/d + 1,316
Bbl/d liquids
Antero Miley Unit
2H and 5HA
Utica Shale Industry Activity(1)Utica Shale Industry Activity(1)
Hess/CNX
Athens A 1H-24
10.2 MMcf/d + 1,803 Bbl/d NGL +
1,056 Bbl/d oil
Utica
Core
Area
Gulfport Energy
Stutzman #1-14H
Peak rate 21 MMcf/d
___________________________
Source: Company presentations and press releases. Peak rates are 24-hour rates except where noted.
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.
Rexx
Guernsey 1H
534 Bbl/d oil
Rexx
Noble 1H
411 Bbl/d oil
Rexx
Guernsey 2H
560 Bbl/d oil
Antero Wayne Unit
2H, 3HA and 4H
Antero Rubel Unit
1H, 2H and 3H
Antero Norman Unit 1H
Antero Yontz Unit 1H
Gulfport Energy
McCort 1-28H
8.3 MMcf/d + 835 Bbl/d NGL + 21
Bbl/d oil
Gulfport Energy
McCort 2-28H
10 MMcf/d + 1009 Bbl/d NGL
Antero Sanford Unit
1H

0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
Antero Has Many of the Top Utica IPs
Announced
● Antero has achieved 7 of the
top 8, and 10 of the top 17,
announced Utica IPs to-date
● Some of the best 24-hour peak
rates of any shale play in North
America
– 3,000 to 8,900 Boe/d per
well in the core area
● Liquids content from 40% -
70% (assumes ethane
recovery)
● Utica Core defined as 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.
1. All rates converted to oil equivalent based on press release, assumed BTU and Antero processing model. Not normalized for lateral length.
2. Based on 6 and 4 hour tests, respectively.
3. Production data based on 7-day IPs.
19
Utica IPs (1)Summary
Core
2,000 to 8,900 Boe/d IPs
Antero Utica Wells 3rd Party Core Utica Wells 3rd Party Non-Core Utica Wells
Tier 1
1,000 to 2,000 Boe/d IPs
Boe/d
(2)(2) (3) (3)

Strong Utica Production Growth
Antero Gross Operated Utica Production
20
• Antero brought on 10 Utica wells in August after gaining access to third-party processing
0
2,000
4,000
6,000
8,000
10,000
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
8/1/2013 8/8/2013 8/15/2013 8/22/2013 8/29/2013 9/5/2013
Bo/d
Mcf/d
Gross Gas Net Gas Gross Oil Net Oil

Antero Marcellus PA
25,000 net acres
21
Integrated Marcellus and Utica Midstream
Infrastructure
Own and operate:
• 77 miles of gathering pipelines in the Marcellus Shale
• 1 mile of gathering pipelines in the Utica Shale
• Four compressor stations in the Marcellus Shale
• 2013 midstream capex of $500 million for gathering,
compression and water system
Third party access to:
• 94 miles of third party gathering in the Marcellus Shale
• Nine compressor stations in the Marcellus Shale and three
in the Utica
• Total compression capacity of 766 MMcf/d increasing to
2.3 Bcf/d by YE2014
• 1 Bcf/d of firm processing capacity (482 MMcf/d in service)
• 1.3 Bcf/d of long-haul firm transportation or firm sales
• 20,000 Bbl/d of committed ethane takeaway capacity
Fresh Water Pipeline:
• 158-mile proprietary water pipeline system in Marcellus
Shale and 56-mile system in the Utica Shale
• Total cost of $525 million, $250 million expected to be
spent in 2013
• Reduces well completion costs by up to $600,000 per well
Third Party
Plant Processing
Capacity (MMcf/d)
Contracted Firm
Processing Capacity
(MMcf/d)(1)
Anticipated Date
of Completion
Marcellus Shale
Sherwood I 200 200 In service
Sherwood II 200 200 In service
Sherwood III 200 150 Fourth Quarter 2013
Sherwood IV 200 200 Second Quarter 2014
Marcellus Shale Total 800 750
Third Party
Plant Processing
Capacity (MMcf/d)
Contracted Firm
Processing Capacity
(MMcf/d) (1)
Anticipated Date
of Completion
Utica Shale
Cadiz (2) 185 - In service
Seneca I (3) 200 200 Fourth Quarter 2013
Seneca II (3) 200 - Fourth Quarter 2013
Seneca III (4) 200 100 First Quarter 2014
Utica Shale Total 785 300
1. Contracted firm capacity at the Sherwood and Seneca facilities as of the start-up date of each identified unit.
2. Firm interim capacity of 80 MMcf/d at Cadiz will be fixed at 50 MMcf/d capacity upon start-up of the Seneca I processing complex and will terminate upon start-up of the Seneca II processing complex.
3. Antero has an option on Seneca I firm capacity that, if exercised by a certain date, would result in an additional 50 MMcf/d of temporary interim capacity at the Seneca II processing facility.
4. Remaining 100 MMcf/d of capacity at the Seneca III processing complex is available for commitment at our option.

$0.00 $0.00 $0.00
$0.29
$0.62
$1.35
$2.47 $2.50
$2.94 $3.02
$3.26 $3.27 $3.34
$3.65 $3.66 $3.70 $3.75 $3.81 $4.13 $4.25
$5.05
$5.37 $5.49
$6.75
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
Low Break Even Gas Price Portfolio
Gross Location and Returns Data(1)
Gross Horizontal Drilling Locations• 4,576 gross horizontal drilling locations
− Supports significant production growth potential
• Portfolio of rich gas locations provides significant flexibility
to achieve reserve and production growth with less
sensitivity to commodity price environment
• Over 80% of 4,576 identified horizontal drilling locations
target liquids-rich processable gas and many also have
condensate
___________________________
1. Source: Credit Suisse report dated 06/18/2013 – break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI.
1250 BTU 1050 BTU
22- Antero Projects
3 Yr Strip ~$4.25/MMBtu
923WellLocations
1,430WellLocations
208WellLocations
588WellLocations
512WellLocations
$/MMBtuNYMEX
Highly Rich Rich Dry Total
Marcellus 923 1,430 588 2,941
Utica 208 512 0 720
Upper Devonian 6 659 250 915
Total 1,137 2,601 838 4,576
Processable 1,137 2,601 3,738
% Processable 82%

Utica
21
Marcellus
135
2012 Capex Budget by Type 2012 Capex Budget by Project
Total: $1,690MM Total: $1,690MM
2013E Capex Budget by Type 2013E Capex Budget by Project
Total: $1,950MM Total: $1,950MM
2012 and 2013E Capital Budget
23
Land
41%
2012 Wells Spud by Project
Total: 119
2013E Wells Planned by Project
Total: 156
Piceance/Arkoma
33
Utica
3
Marcellus
83
Drilling
41%Midstream
8%
Piceance/Arkoma
6%
Utica
41%
Marcellus
53%
Utica
15%
Marcellus
85%
Land
13%
Midstream
26%
Drilling
62%

12 mos. 12 mos. 12 mos. 12 mos. LTM
$ millions 12/31/2009 12/31/2010 12/31/2011 12/31/2012 6/30/2013
Summary Operating Results
Production (Bcfe) (1) 38 49 89 122 138
Net Daily Production (MMcfe/d) (1) 105 133 244 334 378
EBITDAX (1) $201 $198 $341 $434 $457
Cash interest expense (1) $36 $56 $68 $90 $105
Proved reserves (Bcfe) (2) 1,141 3,231 5,017 4,929 6,282
Proved developed reserves (Bcfe) (2) 245 457 844 1,047 1,445
Pre-tax Proved PV 10 (2)(3) $625 $1,858 $4,103 $3,223 $5,412
Summary Capitalization
Cash and cash equivalents $11 $9 $3 $19 $11
Bank credit facility 142 100 365 217 960
2nd lien credit facility 375 0 0 0 0
Subordinated debt 0 25 25 25 25
Senior notes 0 528 927 1,227 1,458
Total debt $517 $653 $1,317 $1,469 $2,443
Members' equity 1,393 1,490 1,461 1,461 1,461
Non-controlling interest 30 0 0 0 0
Total book capitalization $1,940 $2,143 $2,778 $2,930 $3,904
Net debt $506 $644 $1,314 $1,450 $2,432
Credit Statistics
Net debt / net book capitalization 26.2% 30.2% 47.4% 49.8% 62.5%
Net debt / EBITDAX 2.5x 3.3x 3.9x 3.3x 5.3x
EBITDAX / interest expense 5.6x 3.5x 5.0x 4.8x 4.4x
Net debt / proved reserves ($/Mcfe) $0.44 $0.20 $0.26 $0.29 $0.39
Net debt / proved developed reserves ($/Mcfe) $2.07 $1.41 $1.56 $1.38 $1.68
Net debt / production ($/Mcfed) $4,860 $4,794 $5,381 $4,338 $6,433
Pre-tax Proved PV 10 / net debt 1.2x 2.9x 3.1x 2.2x 2.2x
Includes Discontinued Operations
Financial Summary
24
Current Financial Summary
___________________________
1. Production, EBITDAX and cash interest expense are non-GAAP as they include discontinued operations until transaction closing per 2009 - 2012 10-Ks and 6/30/2013 10-Q. Transactions include the Arkoma
Woodford and Fayetteville Shale asset sale for $445 million on June 29, 2012, and the Piceance Basin upstream and midstream asset sale for $325 million on December 21, 2012.
2. LTM proved developed and proved reserves as at 6/30/2013.
3. Pre-tax PV-10 value includes hedge value for each year; 2012 includes hedge value of $1.3 billion and 2Q 2013 hedge value is $0.9 billion.

Key Credit Strengths
World class asset
base with scale
 Liquids-rich Marcellus and Utica shale plays are two of the premier U.S. shale plays
 Antero has scale in both of these plays – 328,000 net acres in the Marcellus Shale
and 101,000 net acres in the Utica Shale
Large, low risk
drilling inventory
 $1.03/Mcfe 3-year development cost leader through 2012 per J.P. Morgan equity
research methodology
 $0.90/Mcfe average net development cost for 6/30/2013 3P reserves – assuming
ethane rejection
Low cost leader
 115% average Marcellus production growth from 2Q 2012 to 2Q 2013
 12% liquids by production volume today forecast to grow to ~20% by 2014 assuming
ethane rejection (~40% assuming ethane recovery)
Large long-term
hedge position
 1,024 Bcfe hedged at $5.11/MMBtu NYMEX-equivalent(1) through 2019
Rapid production
growth with liquids
exposure
 100% drilling success rate in the 208 horizontal wells in Marcellus, Utica and Upper
Devonian Shales to date
 Over 3,600 horizontal drilling locations in the Marcellus and Utica; an additional 900
horizontal drilling locations have been identified in the Upper Devonian
___________________________
1. Assumes 1000 Btu average heat content. Excluding Rockies hedges.
2. Lender commitments under the facility are $1.75 billion which can be expanded to the full $2.0 billion borrowing base. Undrawn borrowing base capacity as of 6/30/2013.
25
Strong liquidity
 ~$1.0 billion of undrawn borrowing base capacity as of June 30, 2013(2)

Firm Transportation/Sales Commitments –
Appalachia
27
Firm Sales #1
10/1/2011 – 10/31/2019
Firm Sales #2
10/1/2011 – 5/31/2017
EQT
8/1/2012 – 8/31/2021
Momentum III
9/1/2012 – 12/31/2021
Firm Sales #3
1/1/2013 – 5/31/2022
Columbia
7/26/2009 – 9/30/2025
Chicago Direct
4/1/2013 – 9/30/2021
MMBtu/d
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
Aug-13
Nov-13
Feb-14
May-14
Aug-14
Nov-14
Feb-15
May-15
Aug-15
Nov-15
Feb-16
May-16
Aug-16
Nov-16
Feb-17
May-17
Aug-17
Nov-17
Feb-18
May-18
Aug-18
Nov-18
Feb-19
May-19
Aug-19
Nov-19
Feb-20
May-20
Aug-20
Nov-20

$3.6
-$7.6
$4.7
$25.3
$33.6
$29.0$27.9$26.1
$12.3
$16.2$17.4
$27.8$29.2
$19.3
$25.2
$42.8
$80.0$82.5
$58.7
$49.4$48.1
$14.1
($1.50)
($1.00)
($0.50)
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
($20.0)
$0.0
$20.0
$40.0
$60.0
$80.0
$100.0
Q1
2008
Q2
2008
Q3
2008
Q4
2008
Q1
2009
Q2
2009
Q3
2009
Q4
2009
Q1
2010
Q2
2010
Q3
2010
Q4
2010
Q1
2011
Q2
2011
Q3
2011
Q4
2011
Q1
2012
Q2
2012
Q3
2012
Q4
2012
Q1
2013
Q2
2013
Quarterly Realized Gains/(Losses)
1Q '08 - 2Q '13
• Antero has realized over $665 million of gains on commodity hedges over the past
5-½ years
– Gains realized in 21 of last 22 quarters
Historical Antero Hedging Results
28
$MMs $/Mcfe

Utica Shale Wells – Antero Initial Results
● Antero has drilled and completed 11 Utica Shale wells in the Core of the play to-date
___________________________
1. 24-hour peak rates assume full ethane recovery however Antero is currently rejecting ethane due to current market prices.
2. Rubel 2H and 3H peak rates based on 6-hour and 4-hour flow tests, respectively.
3. Average of Antero’s first 11 wells, assuming ethane rejection.
29
Antero Utica Well Initial Production Data
Lateral
Well Oil Eq. Rate Wellhead Gas Condensate Shrunk Gas NGL % Total Length
Name County (Boe/d)(1)
(MMcf/d) (Bbl/d) (MMcf/d) (Bbl/d) Liquids BTU (Feet)
Yontz 1H Monroe 8,879 38.9 52 33.9 3,177 36% 1161 5,115
Rubel 1H Monroe 7,917 31.1 214 25.9 3,391 46% 1231 6,554
Rubel 2H(2)
Monroe 7,816 30.9 232 25.8 3,284 45% 1217 6,571
Rubel 3H(2)
Monroe 7,097 28.4 142 23.7 3,003 44% 1220 6,424
Norman 1H Monroe 6,181 26.1 45 22.3 2,419 40% 1186 5,498
Wayne 3HA Noble 5,852 14.7 1,905 11.6 2,018 67% 1272 6,712
Wayne 4H Noble 5,698 14.2 1,922 11.2 1,907 67% 1265 6,493
Wayne 2H Noble 4,257 10.9 1,331 8.5 1,503 67% 1281 6,094
Miley 2H Noble 3,740 8.6 1,450 6.7 1,172 70% 1278 6,153
Miley 5HA Noble 3,369 7.7 1,285 6.0 1,090 70% 1291 6,296
Sanford 1H Noble 1,148 1.8 653 1.4 256 79% 1316 7,159
5,632 19.4 839 16.1 2,111 57% 1247 6,279
4,682 19.4 839 18.2 805 42% 1247 6,279
Average ‐ Ethane Recovery
Average ‐ Ethane Rejection(3)
24‐hr Peak Rate

0%
20%
40%
60%
80%
100%
120%
140%
160%
180%
200%
$3.00 $4.00 $5.00 $6.00 $7.00
BTAXROR
NYMEX $/MMbtu
$8.0 MM / 9.0 Bcf $8.0 MM / 10.0 Bcf $8.0 MM / 11.0 Bcf
Lateral
Length
Well Cost
($MM) EUR (Bcf) Net F&D ($/Mcf)
7,000 $8.7 9.8 $1.03
___________________________
1. Fixed NYMEX gas prices with appropriate basis adjustment to the Marcellus area. 85% NRI assumed.
2. Defined as 10% before tax rate-of-return.
• Assumes 1050 BTU gas – no processing, dry gas
• Estimated 588 gross horizontal drilling locations in the dry gas category (950 to 1050 BTU)
Antero Average for First 195 Horizontal Wells
30
Marcellus Shale Well Economics
Horizontal Dry Gas
(1)(1) (1) (1) (1)
Well Cost
($MMs) EUR (Bcf) F&D ($/Mcf)
NYMEX
Breakeven(2)
$8.00 9.0 $1.05 $3.03
$8.00 10.0 $0.94 $2.78
$8.00 11.0 $0.86 $2.59
3 Yr Strip
$4.25/MMBtu
25-40% ROR
Long-term
$5.50/MMBtu
45-70% ROR
Natural
Gas,
100%

• Assumes 1150 BTU gas and includes processing margin at $90.00/Bbl oil and 36% WTI NGLs(1)
• Estimated 1,430 gross horizontal drilling locations in the 1050 to 1250 BTU category(2)
NGLs,
36%
Natural
Gas,
64%
769 MBbls NGLs
0%
20%
40%
60%
80%
100%
120%
140%
160%
180%
200%
$3.00 $4.00 $5.00 $6.00 $7.00
BTAXROR
NYMEX $/MMbtu
$8.0 MM / 9.0 Bcf $8.0 MM / 10.0 Bcf $8.0 MM / 11.0 Bcf $8.0 MM / 10.0 Bcf - Spot NGL Pricing 4/1/13
~57% ROR
Horizontal Rich Gas
___________________________
2. Economics will vary considerably depending on Btu and other factors.
3. Volumes assume ethane recovery. NGL and oil volumes based on 10 Bcf well.
5. Fixed NYMEX gas prices with appropriate basis adjustment to the Marcellus area. 85% NRI assumed. NGL price of 36% WTI assumed except for SPOT NGL pricing case which assumes C2 rejection.
31
(5) (5) (5) (5) (5)
3 Yr Strip
$4.25/MMBtu
45-70% ROR
Well Cost
NYMEX
Breakeven(4)
$8.00 9.0 $1.05 $1.26
$8.00 10.0 $0.94 $0.97
$8.00 11.0 $0.86 $0.73 Long-term
$5.50/MMBtu
65-105% ROR
Lateral
Length
Well Cost
($MM) EUR (Bcf) Net F&D ($/Mcf)
7,000 $8.7 9.8 $1.03
(3)

0%
50%
100%
150%
200%
250%
300%
$3.00 $4.00 $5.00 $6.00 $7.00
BTAXROR
NYMEX $/MMbtu
$8.0 MM / 9.0 Bcf $8.0 MM / 10.0 Bcf $8.0 MM / 11.0 Bcf $8.0 MM / 10.0 Bcf - Spot NGL Pricing 4/1/13
• Assumes 1250 BTU gas and includes processing margin at $90.00/Bbl oil and 44% WTI NGLs(1)
• Estimated 923 gross horizontal drilling locations in the 1250 to 1350 BTU category(2)
Horizontal Highly-Rich Gas
32
(5) (5) (5) (5) (5)
Well Cost
NYMEX
Breakeven(4)
$8.00 9.0 $1.05 $0
$8.00 10.0 $0.94 $0
$8.00 11.0 $0.86 $0
3 Yr Strip
$4.25/MMBtu
100-155% ROR
Long-term
$5.50/MMBtu
130-200% ROR
~128% ROR
% Oil,
2%
NGLs,
47%
Natural
Gas,
51%
(3)
Lateral
Length
Well Cost
($ MM) EUR (Bcf) Net F&D ($/Mcf)
7,000 $8.7 9.8 $1.03
___________________________
2. Economics will vary considerably depending on Btu and other factors.
3. Volumes assume ethane recovery. NGL and oil volumes based on 10 Bcf well.
5. Fixed NYMEX gas prices with appropriate basis adjustment to the Marcellus area. 85% NRI assumed. NGL price of 44% WTI assumed except for SPOT NGL pricing case which assumes C2 rejection.
1,194 MBbls NGLs; 24 MBbls/Oil

Marcellus Processing Barrels – 1150 BTU
NGL Barrel - VolumeNGL Barrel - Volume
Current NGL Value - $17.27/Bbl(1)Current NGL Value - $44.48/Bbl(1)
C2 Recovery
C2 Recovery
C2 Rejection
C2 Rejection
___________________________
1. Assumes $90.00/Bbl WTI pricing and current spot NGL prices.
33
Propane,
57%
Pentanes+,
16%
Normal
Butane,
13%
Iso Butane,
9% Ethane, 5%
Propane,
$18.64
Pentanes+,
$13.31
Normal
Butane,
$6.83
Iso Butane,
$5.44
Ethane,
$0.27
Ethane,
70%
Propane,
18%
Pentanes+,
5%
Normal
Butane, 4%
Iso Butane,
3%
Propane,
$6.06
Ethane,
$3.44
Pentanes+,
$4.04
Normal
Butane,
$2.06
Iso Butane,
$1.66

Marcellus Processing Barrels – 1250 BTU
NGL Barrel - VolumeNGL Barrel - Volume
Current NGL Value - $23.44/Bbl(1)Current NGL Value - $48.44/Bbl(1)
C2 Recovery
C2 Recovery
C2 Rejection
C2 Rejection
___________________________
1. Assumes $90.00/Bbl WTI pricing and current spot NGL prices.
34
Propane,
51%Pentanes+,
21%
Normal
Butane,
16%
Iso Butane,
8% Ethane, 3%
Pentanes+,
$18.26
Propane,
$16.80
Normal
Butane,
$8.20
Iso Butane,
$5.02
Ethane,
$0.16
Ethane,
58%
Propane,
23%
Pentanes+,
9%
Normal
Butane, 7%
Iso Butane,
4%
Propane,
$7.52
Pentanes+,
$7.55
Ethane,
$2.86
Normal
Butane,
$3.40
Iso Butane,
$2.11

Gas
$4.38
Gas
$4.07
Gas
$4.04
Gas
$3.55
Gas
$3.36
Condensate $0.45
Condensate $0.45
NGLs (C3+)
$1.11
NGLs (C3+)
$2.91
NGLs (C2+)
$1.68
NGLs (C2+)
$3.68
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
$9.00
$10.00
1050 BTU 1150 BTU 1250 BTU 1150 BTU 1250 BTU
Marcellus Rich Gas Provides Liquids and
Processing Upgrade
$4.38
$5.18
$7.40
$5.24
$7.49
• Marcellus rich gas and highly rich gas acreage provides a significant advantage in well economics – assuming
$4.25/MMBtu NYMEX, $90.00/Bbl WTI and 40% WTI NGL pricing
• Upgrade analysis demonstrates that ethane recovery is economic at higher ethane prices
35
Current – Ethane Rejection Projected – Ethane Recovery
$/Mcf on Wellhead Gas Volumes (1)
($/Mcf)
___________________________
1. Assumes $4.25/MMBtu NYMEX, $90.00/Bbl WTI and 40% WTI NGL pricing for 1200 BTU y-grade barrel for ethane recovery, C3+ spot prices for ethane rejection. 1.054 and 2.070 (ethane rejection)
and 3.332 and 5.145 (ethane recovery) GPMs 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.
+$0.80
Upgrade
+$3.02
Upgrade
+$0.86
Upgrade
+$3.11
Upgrade
(1085 BTU)
4% shrink
(1100 BTU)
6% shrink
(1006 BTU)
14% shrink
(1008 BTU)
17% shrink

Antero EBITDAX Reconciliation
EBITDAX
36
($ thousands) 6 Months Ended
Antero Resources LLC 6/30/2012 6/30/2013
EBITDAX:
Net income (loss) $254,318 $83,196
Unrealized loss (gain) on commodity derivative contracts (114,498) (61,265)
Interest expense and other 48,593 63,396
Provision (benefit) for income taxes 183,969 53,325
Depreciation, depletion, amortization and accretion 38,477 93,484
Impairment of unproved properties 1,581 6,359
Exploration expense 4,756 11,662
(Gain) Loss on sale of assets (291,305) --
Other 1,996 1,200
EBITDAX from Continuing Operations $127,887 $251,357
EBITDAX from Discontinued Operations 100,692 --
EBITDAX $228,579 $251,357

The U.S. Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved,
probable and possible reserve estimates (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 reserves included in this presentation have
been audited by Antero’s third-party engineers. Antero’s estimate of probable and possible reserves was prepared by Antero’s internal reserve
engineers, has not been reviewed by third-party engineers, and is provided in this presentation because management believes it is useful
information that is widely used by the investment community in the valuation, comparison and analysis of companies. Antero does not plan to
include probable and possible reserve estimates in its filings with the SEC.
We use certain other terms in this presentation relating to estimates of hydrocarbon volumes that the SEC’s guidelines prohibit us from
including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, possible or probable reserves
as defined by SEC regulations and accordingly are substantially less certain and no discount or other adjustment is included in the presentation
of such numbers. 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 our 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.
“Unrisked Resource” refers to Antero’s internal estimates of hydrocarbon quantities that Antero’s management believes may be potentially
discovered through exploratory drilling or recovered with additional drilling. Unrisked resource may not constitute 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. Actual
quantities that may be ultimately recovered from Antero’s interests will differ substantially. Factors affecting ultimate recovery include the
scope of our 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. Estimates of unrisked resource
may change significantly as development of Antero's resource plays provides additional data.
“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.
Cautionary Note Regarding Hydrocarbon
Quantities
37

Antero Resources
1625 17th Street
Denver CO 80202
www.anteroresources.com

Company Overview September 2013

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Company Overview September 2013