Company website presentation (b) January 2014

Company OverviewJanuary 2014

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, 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 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

ANTERO: A “PURE PLAY” ON THE MARCELLUS / UTICA● 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

Critical Mass In Two World Class Shale Plays

● 182% Appalachian production CAGR since 2010● 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

Market Leading Growth

● 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

Industry Leading Capital Efficiency and Recycle Ratio

● 1.3 Bcf/d of processing capacity and 1.5 Bcf/d of gas takeaway by year-end 2014

● Liquids expected to grow from 8% of third quarter 2013 production due to focus on liquids-rich development

Significant Emphasis on Takeaway and

Liquids Processing

● ~$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/MMBtuand $96.54/Bbl

Liquidity and Hedge Position Support High

Growth Story

● 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

Outstanding Management Team

21. Three year average through 2012; pro forma for Arkoma and Piceance divestitures.2. See page 21 for the derivation of 9/30/2013 liquidity.

UPPER DEVONIAN SHALE

Net Proved Reserves(1) 44 BcfeNet 3P Reserves (1) 3.8 TcfePre-Tax 3P PV-10(1) $220 MM% Liquids – Net 3P 6%3Q 2013 Net Production 3 MMcfe/dUndrilled 3P Locations 915

C

PREMIER UNCONVENTIONAL RESOURCE PLATFORM

1. 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.

2. Represents the average net daily production for the period July 1, 2013 through September 30, 2013. 3. 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.4. RigData as of 1/22/2014.

TOTAL – 6/30/13 RESERVES(1)

Assumes Ethane RejectionNet Proved Reserves(1) 6.3 TcfeNet 3P Reserves(1) 27.7 TcfePre-Tax 3P PV-10(1) $19,100 MM

Net 3P Liquids 667 MMBbls% Liquids – Net 3P 14%3Q 2013 Net Production(2) 566 MMcfe/d- 3Q 2013 Net Liquids(2) 7,900 Bbl/dNet Acres(3) 450,000Undrilled 3P Locations 4,576

MARCELLUS SHALE

Net Proved Reserves(1) 6.0 TcfeNet 3P Reserves (1) 18.7 TcfePre-Tax 3P PV-10(1) $13,656 MM% Liquids – Net 3P 15%3Q 2013 Net Production 519 MMcfe/dUndrilled 3P Locations 2,941

• 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

A

UTICA SHALE – LIQUIDS RICH

Net Proved Reserves(1) 279 BcfeNet 3P Reserves (1) 5.3 TcfePre-Tax 3P PV-10(1) $5,223 MM % Liquids – Net 3P 19%3Q 2013 Net Production 44 MMcfe/dUndrilled 3P Locations 720

B

3

AC

B Appalachia Rig Count vs. Peers(4)

“Pure-Play” Appalachian-Focused Shale Company

UTICA SHALE – DRY GAS

Net Acres(3) 116,000Net Resource 5.0 TcfeUndrilled Locations 950

D

D

15 9 9 74

5

05

10152025

Antero EQT RRC COG CNXR

igs

Marcellus Shale Utica Shale

20

458

522

44

0

100

200

300

400

500

600

700

2010 2011 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013

Marcellus Utica

30

124

239

383

566

678

(4)

4

458

522

678

44

0

100

200

300

400

500

600

700

2006 2007 2008 2009 2010 2011 2012 1Q2013

2Q2013

3Q2013

4Q2013

Woodford Piceance Marcellus Utica

631

87 105 133

244

334383

566

(4)

AVERAGE NET DAILY PRODUCTION (MMcfe/d) APPALACHIAN PRODUCTION (MMcfe/d)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2006 2007 2008 2009 2010 2011 2012 6/30/2013

Woodford Piceance Marcellus Utica(3)

87 235680 1,141

3,231

5,017 4,929

6,282

NET PROVED SEC RESERVES (Bcfe)(2)

197

0

25

50

75

100

125

150

175

200

2006 2007 2008 2009 2010 2011 2012 2013E 2014E

Woodford Piceance Marcellus Utica

8596

126

18

66

91

119

157

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 press release on January 27, 2014; midpoint of 675-680 MMcfe/d range.

FinancialCrisis

STRONG TRACK RECORD OF GROWTH

OPERATED GROSS WELLS SPUD

Sold Woodford and Piceance

$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

`

505

777673

986

93%

58%

38% 29%0

200

400

600

800

1000

0%

20%

40%

60%

80%

100%

Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Gro

ss L

ocat

ions

RO

R

Locations ROR

MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW RISK, HIGH-RETURN GROWTH PROFILE

Large Inventory of Low Breakeven Projects(2)

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 1/27/2014.

3 Yr Strip - $4.37/MMBtu(3)

505Locations

1,450Locations208

Locations

986Locations

$ / M

MB

tu N

YMEX

(Gas

)

335Locations

5

MARCELLUS WELL ECONOMICS(1) UTICA WELL ECONOMICS(1)

208198

137177220%

194%

114%

40% 0

50

100

150

200

250

0%

50%

100%

150%

200%

250%

Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Gro

ss L

ocat

ions

RO

R

Locations ROR

1,000

66% of Marcellus locations are processable (1100-plus Btu) 75% of Utica locations are processable (1100-plus Btu)

0.0x

2.0x

4.0x

6.0x

8.0x6.1x

3.5x 3.1x 2.7x

$0.00

$1.00

$2.00

$3.00

$4.00

$1.03 $1.14 $1.41 $1.57 $1.71

LOW DEVELOPMENT COST DRIVES BEST-IN-CLASS RECYCLE RATIOS

6

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 All-in Development Costs ($/Mcfe) through 2012

Antero Appalachia-Focused Peers

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.

Antero Appalachia-Focused Peers

3-Year Average Growth – Adjusted Recycle Ratio through 2012

$/Mcfe

INTEGRATED MIDSTREAM INFRASTRUCTURE

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 producersAntero has sold ~76% of its year-to-date production

through August 2013 at TCO index at NYMEX less $0.07/MMbtu

71. 80,000 MMBtu/d and 70,000 MMbtu/d also utilize firm transportation in 2014 and 2015, respectively.2. Basis data from Wells Fargo daily indications and various private quotes.

“Infrastructure-Ready” for Rapid, Large Scale Marcellus And Utica Development Programs

0

200

400

600

800

1,000

1,200

1,400

(MM

cf/d

)

Sherwood I Sherwood II Sherwood III Sherwood IV Sherwood V

Cadiz I Seneca I Seneca II Seneca III

Total Capacity 1,300

MarcellusUtica

Sherwood I

Sherwood II

Sherwood IIICadiz I

Seneca I

Seneca II

Seneca III

TCOBasis to NYMEXCurrent 2015-$0.18 -$0.47

Dom SouthBasis to NYMEXCurrent 2015-$0.92 -$1.02

LeidyBasis to NYMEXCurrent 2015-$1.18 -$1.62

Antero Transport and Processing 2014 2015Firm Transport (FT) (MMBtu/d) 1,227,000 1,227,000Firm Sales (MMBtu/d)(1) 330,000 320,000

Firm Processing Capacity (Mcf/d) 1,300,000 1,300,000Ethane FT (Bbl/d) 20,000 20,000

Growing Processing Capacity

2014 2015 2016 2017 2018 2019

-$1.80-$1.60-$1.40-$1.20-$1.00-$0.80-$0.60-$0.40-$0.20$0.00

Appalachian Basis to NYMEX(2)

TETCO M2

Leidy

TCODom South

YTD % of Production Sold

TCO 76%Dom South 18%

NYMEX 5%

CGTLABasis to NYMEXCurrent 2015-$0.06 -$0.10

ChicagoBasis to NYMEXCurrent 2015+$0.26 -$0.09

Sherwood V

Sherwood IV

0200,000400,000600,000800,000

1,000,0001,200,0001,400,000

Antero CHK EQT TLM STO SWN RRC CNX WPX RDS COG APC NFG

Mcf

/d

(2)

LONG HAUL PIPELINE AND TRANSPORTATION NETWORK

8

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

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.

Source: Tudor Pickering & Holt research report dated 9/3/2013.

(1)

TCOBasis to NYMEXCurrent 2015-$0.18 -$0.47

Dom SouthBasis to NYMEXCurrent 2015-$0.92 -$1.02

LeidyBasis to NYMEXCurrent 2015-$1.18 -$1.62

CGTLABasis to NYMEXCurrent 2015-$0.06 -$0.10

ChicagoBasis to NYMEXCurrent 2015+$0.26 -$0.09

Appalachian Firm Transportation Capacity by Operator

628 550 633 750 650 288

$5.29 $5.37 $5.14$4.42

$4.65 $4.51

$4.20 $4.14 $4.09 $4.11 $4.16 $4.22

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

0

200

400

600

800

2014 2015 2016 2017 2018 2019

BBtu/d

14%

21%

19%

44%

2%

NYMEX

CGTLA

Dom South

TCOChicago

SIGNIFICANT LONG-TERM COMMODITY HEDGE POSITION

9

% HEDGE VOLUMES BY INDEX – 9/30/2013

Hedged NYMEX-Equivalent Price(1)Hedged Volume NYMEX Strip (1/2/2014)

NATURAL GAS HEDGES – CURRENT

1. 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.

ASSET OVERVIEW

10

PREMIER POSITION IN THE CORE OF THE MARCELLUS AND UTICA LIQUIDS-RICH FAIRWAYS

Source: Company presentations and press releases.

Utica Shale Core Area

Marcellus Shale

Southwestern & Northeastern

Core Areas

Upper Devonian Shale Resource

Overlies Marcellus Acreage

11

ANTERO LIQUIDS-RICH UTICA SHALE

105,000 Net Acres17 Horizontals Completed5 Rigs Currently Running

ANTERO MARCELLUS SHALE SW PA

25,000 Net Acres2 Horizontals Completed

Strong Results

ANTERO MARCELLUS SHALE NW WV

320,000 Net Acres(Primarily Liquids-Rich Fairway)

215 Horizontals Completed15 Rigs Currently Running

Utica ShaleLiquids-Rich

Fairway

Utica Shale Dry Gas

Resource Underlies Marcellus Acreage

Marcellus Shale Liquids-Rich

Fairway

WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECTAntero 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

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

12

Highly-Rich Gas96,000 Net Acres

777 Gross Locations

Rich Gas82,000 Net Acres

673 Gross Locations

Dry Gas104,000 Net Acres

986 Gross Locations

Highly-Rich/Condensate54,000 Net Acres

505 Gross Locations

MOORE UNIT30-Day Rate

1H: 9.9 MMcfe/d 2H: 10.0 MMcfe/d

(17% liquids)

MHR WEESE UNIT30-Day Rate

4-well average9.3 MMcfe/d (31% liquids)

CHK HADLEY UNIT24-Hour IP

9.1 MMcfe/d(32% liquids)

EQT PENN 15 UNIT30-Day Rate

5-well average9.3 MMcfe/d (29% liquids)

CONSTABLE UNIT30-Day Rate

1H: 15.2 MMcfe/d (30% liquids)

142 Horizontals Completed30-Day Rate

10.3 Bcf average EUR8.1 MMcf/d

6,915’ average lateral length

PRUNTY UNIT30-Day Rate

1H: 11.0 MMcfe/d(29% liquids)

HINTERER UNIT30-Day Rate

1H: 12.9 MMcfe/d (20% liquids)

RUTH UNIT30-Day Rate

1H: 19.3 MMcfe/d (14% liquids)

SherwoodProcessing

Plant

EQT30-Day Rate

12 Recent Wells9.2 MMcfe/d (20% Liquids)

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.

BLANCHE UNIT30-Day Rate

2H: 10.0 MMcfe/d(29% liquids)

DOTSON UNIT30-Day Rate

1H: 12.4 MMcfe/d2H: 11.8 MMcfe/d

(27% liquids)

MARCELLUS – SIMPLE STRUCTURE

13

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

Average Marcellus Lateral Lengths

7,000

4,800 4,500 4,100

0

2,000

4,000

6,000

8,000

Antero EQT RRC COG

Feet

Source: Company presentations.

Wolf SummitArches ForkBig Moses

MarcellusOnondaga

BensonRhinestreet

Profile along regional seismic line (time)W E

Regional Seismic Line

No Data

Tully

100’ Contours Top Marcellus

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

0 1 2 3 4 5 6 7 8 9 10

Cum

ulat

ive

Bcf

MM

cf/d

Production Year

Type Curve (7,000' Lateral) Actual Production (Normalized to 7,000' Lateral) Type Curve Cumulative Production (7,000' Lateral)

0

5

10

15

20

25

30

35

MM

cf/d

1st Production from All Wells 2009 - 2013

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

ANTERO’S MARCELLUS SHALE TYPE CURVE SUPPORT

1. All 217 Antero Marcellus wells normalized to time zero, production for each well normalized to 7,000’ lateral length.

Marcellus Type Curve Support(1)

14

24-Hour Peak Rate

30-Day Avg. Rate

90-Day Avg. Rate

180-Day Avg. Rate

One-Year Avg. Rate

Two-Year Avg. Rate

Three-YearAvg. Rate

Wellhead (MMcf/d) 14.1 8.0 6.3 5.4 4.2 3.0 2.3# of wells 217 209 180 158 109 56 18

EURs Increase With Lateral Length Well Cost / 1,000’ Decreases with Lateral Length Wellhead 24-hour Peak Rates (IPs) - 217 Wells

Average IP – 14.1 MMcf/d

$0.6

$0.8

$1.0

$1.2

$1.4

$1.6

$1.8

2,000 4,000 6,000 8,000 10,000

$MM

/ 1,

000'

Lateral length, ft

0

4

8

12

16

20

2,000 4,000 6,000 8,000 10,000

EUR

, BC

F

Lateral Length, ft

MARCELLUS SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION

15

DRY GAS LOCATIONS RICH GAS LOCATIONS

HIGHLY RICH GAS

LOCATIONS

Assumptions 6/30/2013 Strip Pricing & SEC Reserves

NYMEX($/MMBtu)

WTI($/Bbl)

NGL(2)

($/Bbl)

2013 $3.64 $95 $46.10

2014 $3.91 $90 $44.89

2015 $4.14 $86 $43.86

2016 $4.28 $83 $43.34

2017+ $4.46 $81 $43.34

Marcellus Well Economics and Locations(1)

ClassificationHighly-Rich/Condensate

Highly-Rich Gas Rich Gas Dry Gas

BTU Range 1275-1350 1200-1275 1100-1200 <1100Modeled BTU 1313 1250 1150 1050EUR (Bcfe): 14.3 12.8 11.5 10.5EUR (MMBoe): 2.4 2.1 1.9 1.8% Liquids: 34% 24% 11% 0%Lateral Length (ft): 7,000 7,000 7,000 7,000Stage Length (ft): 350 350 350 350Well Cost ($MM): $7.6 $7.6 $7.6 $7.6Bcf/1,000’: 1.5 1.5 1.5 1.5Bcfe/1,000’: 2.0 1.8 1.6 1.5

Pre-Tax NPV10 ($MM): $17.0 $12.0 $7.1 $5.3Pre-Tax ROR: 93% 60% 38% 29%Net F&D ($/Mcfe): $0.62 $0.69 $0.77 $0.85Payout (Years): 1.2 1.6 2.4 3.0

Gross 3P Locations: 505 777 673 9861. 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.

505

777673

986

93%

60%

38%29%

0

200

400

600

800

1000

0%

20%

40%

60%

80%

100%

Highly-Rich Gas/Condensate

Highly-Rich Gas Rich Gas Dry GasR

OR

Locations ROR

1,000

Gro

ss L

ocat

ions

1,000

10,000

0 30 60 90 120 150 180

Gas

Pro

duct

ion

(Mcf

/d)

Days From Peak GasUnconstrained SSL Average 1.5 Bcf/1,000' Type Curve

Enhancing Recoveries Since June 2013 Antero has

implemented shorter stage lengths (SSL) in the Marcellus Shale– 29 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 30-day 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

16

ENHANCING MARCELLUS RECOVERIES – SHORTER STAGE LENGTHS (“SSL”)

1.5 Bcf/1,000' Type Curve

Normalized production increase for 22 SSL wells over 1.5 Bcf/1,000' Type Curve

SSL vs Non-SSL Wellhead Average Rate Comparison (MMcf/d)

30-day Rate

60-day Rate

90-day Rate

120-day Rate

SSL Well Count 22 19 19 10

SSL Average Rate – MMcf/d(1) 10.0 8.6 8.1 7.91.5 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

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.

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

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 processing plant came online in

November 2013; production constrained until completion of initial compressor stations

− First 120 MMcf/d compressor station went into service in late January with an additional 120 MMcf/d expected by late 1Q 2014

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

EXCITING CORE UTICA SHALE POSITION DELIVERS CONDENSATE AND NGLS

17

Utica Shale Industry Activity and 30-Day Rates(1)

SenecaProcessing

Plant

CadizProcessing

Plant

CHESAPEAKE24-Hour IPBuell #8H

9.5 MMcf/d + 1,425 Bbl/d liquids

GULFPORT24-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

REXX24-Hour IP

Guernsey 1H, 2H,Noble 1H

Average 7.9 MMcf/d + 1,192 Bbl/d NGL

+ 502 Bbl/d Oil

MILEY UNIT30-Day Rate

2 wells average3.0 MMcf/d + 187 Bbl/d NGL

+ 559 Bbl/d Oil

NORMAN UNIT 1H30-Day Rate 13.6 MMcf/d

+ 461 Bbl/d NGL + 2 Bbl/d Oil

YONTZ UNIT 1H30-Day Rate 14.6 MMcf/d

+ 392 Bbl/d NGL + 1 Bbl/d Oil

RUBEL UNIT30-Day Rate

3 wells average13.5 MMcf/d + 583 Bbl/d NGL

+ 45 Bbl/d Oil

GULFPORT24-Hour IP

McCort1-28H, 2-28H, Stutzman 1-14H

Average 13.1 MMcf/d + 922 Bbl/d NGL

+ 21 Bbl/d Oil

GULFPORT24-Hour IP

Wagner 1-28H, Shugert 1-1H, 1-12H

Average 21.0 MMcf/d + 2,270 Bbl/d NGL

+ 292 Bbl/d Oil

Utica Core AreaWAYNE UNIT

30-Day Rate3 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

GARY UNIT 1H30-Day Rate23.1 MMcf/d

+ 1,023 Bbl/d NGL + 65 Bbl/d Oil

Highly-Rich/Cond35,000 Net Acres

208 Locations

Highly-Rich Gas19,000 Net Acres

198 Locations

Rich Gas25,000 Net Acres

137 Locations

Dry Gas26,000 Net Acres

177 Locations

MILLIGAN UNIT24-Hour IP

3 wells average11.3 MMcf/d + 1,971 Bbl/d NGL

+ 1,586 Bbl/d Oil

COAL UNIT 1H24-Hour IP

11.8 MMcf/d + 2,063 Bbl/d NGL + 1,850 Bbl/d Oil

0.0

10.0

20.0

30.0

40.0

50.0

60.0

MM

cfe/

d

Source: Antero, press releases and company presentations.

ANTERO HAS MOST OF THE TOP UTICA 24-HOUR IPS

Antero has 11 of the top 12 Utica 24-hour peak rates (IPs) announced to date

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 24-

hour peak rate in the core area

– Excellent reservoir pressure with gradients in the 0.7 psi/ft range

Liquids content ranges from 40%-70% (assumes ethane recovery) in the liquids-rich window

Antero recently announced 30-day 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

18

UTICA 24-HOUR IPsCore

12 to 53MMcfe/d IPs

Tier 16 to 12

MMcfe/d IPs

Antero Utica Wells 3rd Party Core Utica Wells 3rd Party Non-Core Utica Wells

UTICA SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION

19

DRY GAS LOCATIONS RICH GAS LOCATIONS

HIGHLY RICH GAS

LOCATIONS

Assumptions 6/30/2013 Strip Pricing & SEC Reserves

Utica Well Economics and Locations(1)

ClassificationHighly-Rich/Condensate

Highly-Rich Gas Rich Gas Dry Gas

BTU Range 1250-1300 1200-1250 1100-1200 <1100Modeled BTU 1275 1225 1175 1050EUR (Bcfe): 13.7 19.9 18.0 15.3EUR (MMBoe): 2.3 3.3 3.0 2.5% Liquids 35% 26% 16% 0%Lateral Length (ft): 7,000 7,000 7,000 7,000Stage Length (ft): 250 250 250 250Well Cost ($MM): $11.3 $11.3 $11.3 $11.3Bcf/1,000’: 1.5 2.4 2.4 2.2Bcfe/1,000’: 2.0 2.8 2.6 2.2

Pre-Tax NPV10 ($MM): $20.8 $28.1 $19.9 $10.3Pre-Tax ROR: 220% 194% 114% 40%Net F&D ($/Mcfe): $1.02 $0.70 $0.78 $0.92Payout (Years): 0.7 0.7 1.0 2.3

Gross 3P Locations(3): 208 198 137 1771. 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.

NYMEX($/MMBtu)

WTI($/Bbl)

NGL(2)

($/Bbl)

2013 $3.64 $95 $50.24

2014 $3.91 $90 $48.78

2015 $4.14 $86 $47.43

2016 $4.28 $83 $46.72

2017+ $4.46 $81 $46.72

208198

137177220%

194%

114%

40%0

50

100

150

200

250

0%

50%

100%

150%

200%

250%

Highly-Rich Gas/Condensate

Highly-Rich Gas Rich Gas Dry Gas

Gro

ss L

ocat

ions

RO

RLocations ROR

SIGNIFICANT MIDSTREAM INFRASTRUCTURE POSITION

20

Ohio River WithdrawalJanuary 2014

completion date

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 positionQualifies for midstream MLP

UticaShale

MarcellusShale

Midstream Infrastructure(1)

Marcellus Shale

Utica Shale Total

YE 2013 Estimated Total Gathering / Compression Capex ($MM) $510 $220 $730Gathering Pipelines (Miles) 83 20 103Compressor Stations 4 0 4

YE 2013 Estimated Total WaterSystem Capex ($MM) $200 $50 $250Water Pipeline (Miles) 71 37 108Water Storage Facilities 17 2 19

YE 2013 Estimated Total Midstream($MM) $710 $270 $980

1. Represents inception to date actuals as of 9/30/2013 and remaining 2013 budget.

CAPITALIZATION

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.

PRO FORMA CAPITALIZATION

($ in millions) 9/30/2013(PF IPO)

9/30/2013 (1)(PF Bond Offering)

9/30/2013(3)

Cash $12 $77 $339

Senior Secured Revolving Credit Facility 1,513 – –9.375% Senior Notes Due 2017 525 525 –9.00% Senior Note 25 25 –7.25% Senior Notes Due 2019 400 400 2606.00% Senior Notes Due 2020 525 525 5255.375% Senior Notes Due 2021 – – 1,000Net Unamortized Premium 8 8 6Total Debt $2,996 $1,483 $1,791

Net Debt $2,984 $1,406 $1,452

Shareholders' Equity $1,875 $3,453 $3,427Net Book Capitalization $4,859 $4,859 $4,879

Net Market Capitalization(1) N/M $15,735 $15,781

Financial & Operating StatisticsLTM EBITDAX $521 $521 $521

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 2.8xLTM EBITDAX / Interest Expense 4.1x 4.7x 5.1xNet Debt / Net Book Capitalization 61.4% 28.9% 29.8%Net Debt / Net Market Capitalization N/M 8.9% 9.2%Net Debt / Proved Developed Reserves ($/Mcfe) $2.07 $0.97 $1.01Net Debt / Proved Reserves ($/Mcfe) $0.48 $0.22 $0.23

LiquidityCredit Facility Commitments(2) $1,750 $1,500 $1,500Less: Borrowings (1,513) – –Less: Letters of Credit (32) (32) (32)Plus: Cash 12 77 339

Liquidity (Credit Facility + Cash) $217 $1,545 $1,807

21

Keys to Execution

Pad Impact Mitigation 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 2015requirements)

Central Fresh Water System & Water Recycling

Numerous sources of water – building central water system to source water forcompletion

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 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

HEALTH, SAFETY, ENVIRONMENT & COMMUNITY

22

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

Antero named Business of the Year for 2013 in Harrison County, West Virginia “For outstanding corporate citizenship and community involvement”

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

ANTERO KEY ATTRIBUTES

23

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

24

APPENDIX

24

ANTERO FIRM TRANSPORTATION AND FIRM SALES

25

MMBtu/d

Columbia7/26/2009 – 9/30/2025

Firm Sales #110/1/2011– 10/31/2019

Firm Sales #2

10/1/2011 – 5/31/2017

Firm Sales #3

1/1/2013 – 5/31/2022

Momentum III9/1/2012 – 12/31/2021

EQT8/1/2012 – 8/31/2021

Chicago Direct4/1/2013 – 9/30/2021

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

1. 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. 2. Average of Antero’s first 16 core area wells, assuming ethane rejection.

ANTERO UTICA SHALE WELLS – 24 HOUR IPS

26

LateralWell Gas Eq. Rate Wellhead Gas Shrunk Gas NGL Condensate % Total Estimated LengthName County (MMcfe/d) (MMcf/d) (MMcf/d) (Bbl/d) (Bbl/d) Liquids BTU (Feet)

Yontz 1H Monroe 53.3 38.9 33.9 3,177 52 36% 1161 5,115Rubel 1H Monroe 47.5 31.1 25.9 3,391 214 46% 1231 6,554Gary 2H Monroe 43.5 28.9 24.2 3,053 162 44% 1224 8,882Rubel 3H * Monroe 42.6 28.4 23.7 3,003 142 44% 1220 6,424Milligan 2H Noble 40.2 17.2 13.5 2,361 2,087 66% 1276 5,989Rubel 2H Monroe 37.4 24.8 20.7 2,635 156 45% 1217 6,571Norman 1H Monroe 37.1 26.1 22.3 2,419 45 40% 1186 5,498Coal 3H Noble 35.3 15.1 11.8 2,063 1,850 67% 1278 7,768Wayne 3HA Noble 35.1 14.7 11.6 2,018 1,905 67% 1272 6,712Wayne 4H Noble 34.2 14.2 11.2 1,907 1,922 67% 1265 6,493Milligan 3H Noble 32.1 15.4 12.1 2,111 1,228 62% 1276 5,267Dollison 1H Noble 27.5 12.5 10.2 1,488 1,397 63% 1238 6,253Milligan 1H Noble 25.8 10.6 8.3 1,461 1,442 68% 1276 6,436Wayne 2H Noble 25.5 10.9 8.5 1,503 1,331 67% 1281 6,094Miley 2H Noble 22.4 8.6 6.7 1,172 1,450 70% 1278 6,153Miley 5HA Noble 20.2 7.7 6.0 1,090 1,285 70% 1291 6,296

35.0 19.1 15.7 2,178 1,042 58% 1248 6,40728.1 19.1 18.5 819 776 40% 1248 6,407

24‐hr Peak Rates ‐ Antero Core Area

Average ‐ Ethane Recovery(1)

Average ‐ Ethane Rejection(2)

1. Average of Antero’s first 11 core area wells, assuming ethane recovery.

ANTERO UTICA SHALE WELLS – 30-DAY RATES

27

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

LateralWell Gas Eq. Rate Wellhead Gas Shrunk Gas NGL Condensate % Total Estimated LengthName County (MMcfe/d) (MMcf/d) (MMcf/d) (Bbl/d) (Bbl/d) Liquids BTU (Feet)

Gary 2H Monroe 29.7 24.6 23.1 1,023 65 22% 1224 8,882Rubel 2H Monroe 19.2 15.9 15.0 625 64 22% 1217 6,571Rubel 3H Monroe 18.7 15.6 14.7 623 43 21% 1220 6,424Yontz 1H Monroe 17.0 15.2 14.6 392 1 14% 1161 5,115Norman 1H Monroe 16.4 14.3 13.6 461 2 17% 1186 5,498Rubel 1H Monroe 14.0 11.5 10.8 501 28 23% 1231 6,554Wayne 2H Noble 12.1 6.5 6.0 367 653 51% 1281 6,094Wayne 3HA Noble 11.0 6.1 5.6 354 540 49% 1272 6,712Wayne 4H Noble 9.2 5.2 4.7 284 452 48% 1265 6,493Miley 2H Noble 9.0 3.8 3.5 213 700 61% 1278 6,153Miley 5HA Noble 5.9 2.7 2.5 161 418 59% 1291 6,296

14.7 11.0 10.4 455 270 35% 1239 6,43617.9 11.0 9.2 1,189 270 53% 1239 6,436

30‐Day Rates ‐ Antero Core Area

Average ‐ Ethane RejectionAverage ‐ Ethane Recovery(1)

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

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.

ETHANE REJECTION(1) ETHANE RECOVERY(1)

28

Marcellus – 18.7 Tcfe

Utica – 5.3 Tcfe

Upper Devonian – 3.8 Tcfe

27.7Tcfe

Gas – 23.8 Tcf

Oil – 71 MMBbls

NGLs – 595 MMBbls

Marcellus – 21.8 Tcfe

Utica – 6.1 Tcfe

Upper Devonian – 4.2 Tcfe

32.1Tcfe

Gas – 22.2 Tcf

Oil – 71 MMBbls

NGLs – 1,580 MMBbls

14%Liquids

31%Liquids

Gas $4.39

Gas$4.12

Gas$4.07

Gas$4.00

Condensate$0.37

Condensate$0.70

NGLs (C3+)$1.04

NGLs(C3+)$2.39

NGLs(C3+)$3.23

$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 1300 BTU

$4.39$5.16

$6.84

$7.94

MARCELLUS SHALE RICH GAS –LIQUIDS AND PROCESSING 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.

Current – Ethane Rejection

(1073 BTU)8% shrink

(1103 BTU)12% shrink

(1110 BTU)14% shrink

$/Wellhead Mcf(1)

($/Mcf)

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

29

+$0.77Upgrade

+$2.45Upgrade

+$3.55Upgrade

Rich GasDry Gas

2013 YEAR-TO-DATE REALIZATIONS

Ethane (C2)

Propane (C3)

Iso Butane (C4)

Normal Butane

Natural Gasoline

Total $50.73 per Bbl48% of WTI(3)

9/30/2013 YTD NGL Y-GRADE (C3+) REALIZATIONS

9/30/2013 YTD NATURAL GAS REALIZATIONS

55%

1%

11%

16%

17%

$27.69

$5.72

$8.04

$8.69

$0.59

301. NYMEX differential represents contractual deduct to NYMEX-based sales.2. Includes firm sales.3. Based on monthly prices through 9/30/2013 WTI.

Antero Barrel

YTD % Sales

Average NYMEX Price

AverageDifferential(2)

AverageBTU Upgrade

Average YTD Realized Price

TCO 76% $3.68 $(0.07) $0.44 $4.05Dominion South 18% $3.68 $(0.39) $0.42 $3.71NYMEX(1) 5% $3.68 $(0.40) $0.41 $3.69TETCO 1% $3.68 $(0.34) $0.47 $3.80

Total 100% $3.68 $(0.15) $0.44 $3.97

ANTERO EBITDAX RECONCILIATION

31

EBITDAX Reconciliation($ in thousands) (9 Months Ended)Antero Resources LLC 9/30/12 9/30/2013

EBITDAX:Net income (loss) from continuing operations $140,431 $200,990Commodity 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 71,046 100,840Provision (benefit) for income taxes 108,525 120,695Depreciation, depletion, amortization and accretion 65,360 159,447Impairment of unproved properties 4,019 9,564Exploration expense 7,912 17,034Other 2,992 1,820EBITDAX from continuing operations $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 427,232Provision (benefit) for income taxes 4,085Depreciation, depletion, amortization and accretion 77,654Impairment of unproved properties 962Exploration expense 507EBITDAX from discontinued operations $125,353

EBITDAX $323,744 $434,191

CAUTIONARY NOTE

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates (collectively, “3P”). Antero has provided internally generated estimates for proved, probable and possible reserves in this presentation in accordance with SEC guidelines and definitions. 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.

Regarding Hydrocarbon Quantities

32