Company OverviewOctober 2013

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. – 20 Bcf/d projected by 2020(1)

● Antero has 28 Tcfe of 3P reserves in Marcellus and Utica Shales● 640 MMcfe/d of current net production including 11,500 Bbl/d of liquids− Additional 160 MMcfe/d of constrained/shut-in net production

Critical Mass In Two World Class Shale Plays

● 220% Appalachian production CAGR since 2010● Most active driller in Marcellus Shale – 15 rigs running● Drilled 7 of the top 8 initial producers in the Utica Shale – 4 rigs running

Market Leading Growth

● Low development cost leader: $1.03/Mcfe(2)

● Industry leading growth-adjusted recycle ratio: 6.1x(2)

● Top quartile return on productive capital: 27% for 2013E

Industry Leading Capital Efficiency and Recycle Ratio

● 1 Bcf/d of processing capacity by 2014, 1.3 Bcf/d of firm transport by 2015 and 20,000 Bbl/d of ethane takeaway by 2014

● Liquids expected to grow from 12% of production volume today due to focus on liquids-rich development

Significant Emphasis on Takeaway and

Liquids Processing

● ~$2.3 billion pro forma liquidity with current $1.75 billion bank commitment● 1.1 Tcfe hedged through 2019 at an average $5.02 / MMBtu NYMEX● Midstream MLP potential adds a low cost equity financing vehicle

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 450 horizontal shale

wells in the Barnett, Woodford, Marcellus and Utica Shales● Management incentivized by increasing equity ownership with stock

price appreciation; no equity dilution

Outstanding Management Team

21. Tudor Pickering Holt research report dated 9/3/2013.2. Three year average through 2012; pro forma for Arkoma and Piceance divestitures.

15 106 5

4

0

5

10

15

20

Antero EQT COG RRCR

igs

Marcellus Shale Utica Shale

19

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%Current Net Production 4 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. For discussion of PV-10, please read the final prospectus.

2. Represents the average net daily production for the period from September 1, 2013 through September 25, 2013. Current constrained/shut-in net production of 160 MMcfe/d.3. All net acres allocated to the Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as they are stacked pay formations attributable to the same leases.4. RigData, other industry sources as of 9/20/2013.

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 MMNet 3P Liquids 667 MMBbls% Liquids – Net 3P 14%Current Net Production(2) 640 MMcfe/d2Q 2013 Net Production 458 MMcfe/dNet Acreage(3) 431,000Undrilled 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%Current Net Production 551 MMcfe/dUndrilled 3P Locations 2,941

• 100% operated

• Stable acreage base− Marcellus Shale: 50% HBP, with additional 28%

not expiring for 5+ years− Utica Shale: 20% HBP, with additional 79% not

expiring for 5+ years

• Portfolio flexibility across dry gas to liquids-rich and condensate windows

• Significant investment in midstream infrastructure and secured takeaway capacity

• Financial flexibility to pursue planned 2013 and 2014 development drilling activities

• Full scale development underway− 19 rigs currently operating

A

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%Current Net Production 85 MMcfe/dUndrilled 3P Locations 720

B

3

AC

B Appalachia Rig Count vs. Peers(4)

“Pure-Play” Appalachian-Focused Shale Company

UTICA SHALE – DRY GASD

D

4

458

555

85

0

100

200

300

400

500

600

700

2006 2007 2008 2009 2010 2011 2012 1Q2013

2Q2013

Current

Woodford Piceance Marcellus Utica

631

87 105 133

244334

383

640

AVERAGE NET DAILY PRODUCTION (MMcfe/d)

458

555

85

0

100

200

300

400

500

600

700

2010 2011 2012 1Q 2013 2Q 2013 Current

Marcellus Utica

30124

239

383

640

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

161

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.

EconomicCrisis

STRONG TRACK RECORD OF GROWTH

OPERATED GROSS WELLS SPUD

Sold Woodford and Piceance

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

$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

`

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 STRIP as of 9/25/2013.

3 Yr Strip - $3.82/MMBtu(3)

505Locations

1,450Locations

208Locations

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 see much less basis widening and volatility than Pennsylvania producersAntero has sold ~81% of its year-to-date production at

TCO at NYMEX less $0.01/MMbtu

71. 80,000 MMBtu/d and 70,000 MMbtu/d are related to 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

300

600

900

1200

(MM

cf/d

)

Sherwood I Sherwood IISherwood III Sherwood IVCadiz I Seneca ISeneca II Seneca III

Total Capacity 1,050

MarcellusUtica

Sherwood I

Sherwood II

Sherwood III

Sherwood IV

Cadiz I

Seneca I

Seneca II

Seneca III

TCOBasis to NYMEXCurrent 2015-$0.06 -$0.31

Dom SouthBasis to NYMEXCurrent 2015-$0.17 -$0.42

LeidyBasis to NYMEXCurrent 2015-$1.05 -$1.06

Antero Transport and Processing 2013 2014 2015Firm Transport (FT) (MMBtu/d) 542,000 882,000 1,152,000Firm Sales (MMBtu/d)(1) 143,000 230,000 220,000

Firm Processing Capacity (Mcf/d) 800,000 1,050,000 1,050,000Ethane FT (Bbl/d) 0 20,000 20,000

Growing Processing Capacity

2013 2014 2015 2016 2017 2018 2019

-$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 81%Dom South 14%

NYMEX 5%

CGTLABasis to NYMEXCurrent 2015-$0.04 -$0.06

ChicagoBasis to NYMEXCurrent 2015+$0.09 -$0.10

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

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)

Appalachian Firm Transportation Capacity by Operator

Note: Antero firm transportation and firm sales positions listed by pipeline in colored-coded boxes. 1. See Page 23 for timing of firm transportation.2. Antero firm transportation as of 9/25/2013; excludes 150 MMcf/d of firm sales.

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

(1)

TCOBasis to NYMEXCurrent 2015-$0.06 -$0.31

Dom SouthBasis to NYMEXCurrent 2015-$0.17 -$0.42

LeidyBasis to NYMEXCurrent 2015-$1.05 -$1.06

CGTLABasis to NYMEXCurrent 2015-$0.04 -$0.06

ChicagoBasis to NYMEXCurrent 2015+$0.09 -$0.10

$1,750$2,347($960)

($32) $11

$1,578

$0

$500

$1,000

$1,500

$2,000

$2,500

Credit Facility6/30/2013

Bank Debt6/30/2013

L/Cs Outstanding6/30/2013

Cash6/30/2013

IPO Proceeds Pro FormaLiquidity

6/30/2013

$MM

SIGNIFICANT LIQUIDITY AND LONG-TERM COMMODITY HEDGE POSITION

9

NATURAL GAS HEDGES

470 478 480 583 720 530 88

$5.25 $5.60 $5.40 $5.13$4.40 $4.73 $4.75

$3.63 $3.91 $4.10

$4.20 $4.33 $4.43 $4.61

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

0

200

400

600

800

2013 2014 2015 2016 2017 2018 2019

BBtu/d Hedged NYMEX-Equivalent Price(1)Hedged Volume NYMEX Strip (9/10/2013)

Pro forma liquidity of $2.3 Bn

1. Current borrowing base of $2.0 billion. 2. Assumes $1,658 million IPO less $80 million fees and expenses; includes exercise of the shoe.

LIQUIDITY POSITION

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.

Current $771 million mark-to-market unrealized gain

(1) (2)

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

102,000 Net Acres11 Horizontals Completed4 Rigs Currently Running

ANTERO MARCELLUS SHALE SW PA

25,000 Net Acres2 Horizontals Completed

Strong Results

ANTERO MARCELLUS SHALE NW WV

304,000 Net Acres(Primarily Liquids-Rich Fairway)

197 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 329,000 net acres in

Southwestern Core– 50% HBP with additional

28% not expiring for 5+ years 199 horizontal wells completed

– 197 online– Laterals average 7,000’– 100% drilling success rate

2,941 future drilling locations (66% are processable)

Operating 15 drilling rigs including 4 shallow rigs

18.7 Tcfe of net 3P (15% liquids), includes 6.0 Tcfe of proved reserves

12

Antero Net ProductionPeriod (MMcfe/d) (Bbl/d)1H 2013 420 3,129 August 2013 549 6,528

Current 555 7,400Constrained/shut-in 130 3,300

Highly-Rich Gas91,000 Net Acres

777 Gross Locations

Rich Gas79,000 Net Acres

673 Gross Locations

Dry Gas106,000 Net Acres

986 Gross Locations

Highly-Rich/Condensate53,000 Net Acres

505 Gross Locations

BLANCHE UNIT2H: 18.1MMcfe/d IP

(52% liquids)

DOTSON UNIT1H: 22.7 MMcfe/d IP 2H: 27.3 MMcfe/d IP

(50% liquids)

MOORE UNIT1H: 13.0 MMcfe/d 2H: 13.0 MMcfe/d

30-day rates(41% liquids)

MHR WEESE UNIT4-well average9.3 MMcfe/d 30-day rate

(54% liquids)

CHK HADLEY UNIT11.3 MMcfe/d IP

(58% liquids)

EQT PENN 15 UNIT5-well average9.3 MMcfe/d 30-day rate

(51% liquids)

CONSTABLE UNIT1H: 19.3 MMcfe/d

30-day rate(51% liquids)

141 Horizontals Completed10.1 Bcfe average EUR

8.3 MMcfe/d average 30-day rate6,917’ average lateral length

PRUNTY UNIT1H: 15.2 MMcfe/d

30-day rate(50% liquids)

LITTLE TOM UNIT

1H: 16.0 MMcfe/d 30-day rate

(41% liquids)

CLETA UNIT1H: 15.9 MMcfe/d 2H: 17.0 MMcfe/d

30-day rates(38% liquids)

SherwoodProcessing

Plant

EQT12 Recent Wells11.6 MMcfe/d 30-day rate 44% Liquids

Source: Company presentations and press releases. Note: Rates assume ethane recovery. Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.

MARCELLUS – SIMPLE STRUCTURE

13

Several regional anticlines in core area− Predictable “layer cake” geology− No faults at Marcellus level

• Over 1.3 million feet (250 miles) drilled horizontally without crossing a fault

− 3-D seismic not required to guide horizontal wells

Regional East-West seismic line shows gentle structure at Marcellus level

Allegheny Front and complex structure located many miles east of core area

Favorable geology allows for longer laterals

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. Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.

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

5

10

15

20

25

30

35

MM

cf/d

1st Production from All Wells 2009 - 2013

0.02.04.06.08.010.012.014.016.0

0.02.04.06.08.0

10.012.014.016.0

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)

Antero has almost four years of production, and almost 200 operated horizontal wells, to support its 1.5 Bcf / 1,000’ of lateral type curve– DeGolyer & MacNaughton (D&M), Antero’s third-party reserve auditor, fully supports this type curve

Average 24-hour peak rate (IP) of 14.0 MMcf/d Lack of faulting and contiguous acreage position allows for drilling of long laterals− Drives down costs per 1,000’ of lateral resulting in best-in-class development costs

ANTERO’S MARCELLUS SHALE TYPE CURVE SUPPORT

1. All 199 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) 14.0 7.8 6.2 5.4 4.1 3.0 2.3# of wells 199 191 175 142 98 52 16

EURs Increase With Lateral Length Well Cost / 1,000’ Decreases with Lateral Length

$0.6

$1.0

$1.4

$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

Wellhead 24-hour Peak Rates (IPs) - 199 Wells

Average IP - 14 MMcf/d

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

28.4

22.9 22.2 19.5 19.5 19.1 17.9 17.4 17.2 16.9 16.3 16.0 15.6

9.1

0.0

5.0

10.0

15.0

20.0

25.0

30.0

MM

cf/d

1,000

10,000

0 30 60 90 120

Gas

Pro

duct

ion

(Mcf

/d)

Days From Peak Gas

Unconstrained 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– 17 SSL wells completed– 150’ to 250’ vs. 350’ stages

previously The 24-hour peak rate for Antero’s

first 14 unconstrained SSL wells has averaged 18.4 MMcf/d or 31% higher than the overall average Marcellus IP of 14.0 MMcf/d– Other Marcellus Southwestern

Core operators (EQT and Range) have announced 20% to 30% improvement in IPs and EURs

Early production ≈ 30% higher than 1.5 Bcf/1,000’ of lateral type curve(1)

(1st 60 days aggregated for nine unconstrained SSL wells)

Estimated 20% increase in well costs for SSL

Antero SSL Wells

16

Normalized 30-day production increase for SSL over 1.5 Bcf/1,000' Type Curve: 29%(1)

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

1. Based on nine relatively unconstrained wells.

1.5 Bcf/1,000' Type Curve

Average Antero 24-hour Peak Rate: 14.0 MMcf/d

Antero’s First 14 Unconstrained SSL Wells – 24-hour Peak Rate

Normalized production for 9 relatively unconstrained

SSL wells

Average Antero SSL 24-hour Peak Rate: 18.4 MMcf/d

Antero’s Mid-Year 2013 3P Reserves Do Not Assume SSL Completions

31% Increase in IPs for SSL

Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are owned.1. In some cases, Antero has converted rich gas rates where BTU has been disclosed to NGLs, assuming ethane recovery. Where BTU has not been disclosed, Antero has estimated BTU and gas composition.

100% operated

~102,000 net acres in the core rich gas / condensate window– 20% HBP with additional 79% not expiring

for 5+ years– 73%+ of acreage has rich gas processing

potential

11 horizontal wells completed - all online

− 100% drilling success rate

720 future drilling locations– Approximately 36% of EUR is liquids

assuming ethane recovery

Operating 4 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

Antero Net ProductionPeriod (MMcfe/d) (Bbl/d)1H 2013 1 102 August 2013 45 2,102

Current 85 4,100 Constrained/shut-in 25 1,600

Utica Shale Industry Activity and 24-Hour Peak Rates(1)

SenecaProcessing

Plant

CadizProcessing

Plant

CHESAPEAKE8 Wells

Average 8.3 MMcfe/d (1,391 Boe/d)

CHESAPEAKEBuell #8H

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

Boy Scout 1-33H, Ryser 1-25H, Groh 1-12H

Average 5.3 MMcf/d + 675 Bbl/d NGL + 1,411 Bbl/d Oil

REXXGuernsey 1H, 2H,

Noble 1HAverage 7.9 MMcf/d + 1,192 Bbl/d NGL

+ 502 Bbl/d Oil

MILEY UNIT2 wells average

7.3 MMcf/d + 1,114 Bbl/d NGL + 1,300 Bbl/d Oil

NORMAN UNIT 1H 22.4 MMcf/d

+ 2,323 Bbl/d NGL + 45 Bbl/d Oil

YONTZ UNIT 1H 33.5 MMcf/d

+ 3,464 Bbl/d NGL + 52 Bbl/d Oil

RUBEL UNIT3 wells average

25.3 MMcf/d + 3,170 Bbl/d NGL + 196 Bbl/d Oil

CNX/HESSNoble 1A, 16A

Average 7.9 MMcf/d + 1,184 Bbl/d NGL

+ 389 Bbl/d Oil

GULFPORTMcCort1-28H, 2-28H,

Stutzman 1-14HAverage 13.1 MMcf/d

+ 922 Bbl/d NGL + 21 Bbl/d Oil

GULFPORTWagner 1-28H,

Shugert 1-1H, 1-12HAverage 21.0 MMcf/d

+ 2,270 Bbl/d NGL + 292 Bbl/d Oil

Utica Core Area

WAYNE UNIT 3 wells average

10.5 MMcf/d + 1,757 Bbl/d NGL + 1,719 Bbl/d Oil

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Source: Antero, press releases and company presentations.

ANTERO HAS MOST OF THE TOP UTICA IPS

Antero has 7 of the top 8 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– 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

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

18

Boe

/d

UTICA IPsCore

2,000 to 9,000 Boe/d IPs

Tier 11,000 to 2,000

Boe/d IPs

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

Antero’s acreage position is “blocked-up” compared to other operators in the Utica core

EUR regimes are well-supported by Antero and third-party results

Production constrained until completion of Seneca processing plant and first compression expected in 4Q 2013

Utica Production Ramp

19

Highly-Rich Gas18,000 Net Acres

198 Locations

Rich Gas23,000 Net Acres

137 Locations

Dry Gas27,000 Net Acres

177 Locations

Highly-Rich/Cond34,000 Net Acres

208 Locations

UTICA WELL RESULTS SUPPORT EUR REGIMES

-

20

40

60

80

100

120

140

MM

cfe/

d

Estimated Gross (MMcfe/d) Estimated Net (MMcfe/d)

Note: Antero acreage position reflects townships in which greater than 3,000 net acres are owned.

UTICA SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION

20

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

21

Ohio River WithdrawalDecember 2013 completion date

Antero estimated YE 2013 total capital investment in midstream ≈ $930 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 / well

− One of the benefits of a consolidated acreage position

Qualifies for midstream MLP

UticaShale

MarcellusShale

Midstream Infrastructure(1)

Marcellus Shale

Utica Shale Total

YE 2013 Estimated Total Gathering / Compression Capex ($MM) $460 $220 $680Gathering Pipelines (Miles) 83 20 103Compressor Stations 4 0 4

YE 2013 Estimated Total WaterSystem Capex ($MM) $200 $50 $250Water Pipeline (Miles) 89 39 128Water Storage Facilities 40 22 62

YE 2013 Estimated Total Midstream($MM) $660 $270 $930

1. Represents inception to date actuals as of 6/30/2013 and remaining 2013 budget.

CAPITALIZATION

1. Reflects 262.0 million shares outstanding priced at $52.01 per share as of 10/10/2013; includes the exercise of the shoe.2. Lender commitments under facility are $1.75 billion which can be expanded to the full $2.0 billion borrowing base upon bank approval.3. As of September 27, 2013, pro forma for the offering our liquidity would have been $1.8 billion.

SOURCES & USES

PRO FORMA CAPITALIZATIONSignificant Liquidity to Fund Drilling Program

Sources ($ in millions)

Primary IPO Proceeds $1,658

Total Sources $1,658

Uses

Debt Paydown $960

Cash 618

Fees & Expenses 80

Total Uses $1,658

($ in millions) 6/30/2013 6/30/2013 (Pro Forma)Cash $11 $629

Credit Facility 960 –Unsecured Debt 25 25Senior Unsecured Notes 1,458 1,458Total Debt $2,443 $1,483

Net Debt $2,432 $854

Shareholders' Equity $1,757 $3,335Total Book Capitalization $4,200 $4,818Total Market Capitalization(1) NM $15,112

Financial & Operating StatisticsLTM EBITDAX $457 $457LTM Interest Expense $112 $93Proved Reserves (Bcfe) (6/30/2013) 6,282 6,282 Proved Developed Reserves (Bcfe) (6/30/2013) 1,445 1,445

Credit Statistics

Net Debt / LTM EBITDAX 5.3x 1.9xLTM EBITDAX/Interest Expense 4.1x 4.9x

Net Debt / Net Book Capitalization 58.1% 20.4%Net Debt / Net Market Capitalization NM 5.9%Net Debt / Proved Developed Reserves ($/Mcfe) $1.68 $0.59Net Debt / Proved Reserves ($/Mcfe) $0.39 $0.14

LiquidityCredit Facility Commitments(2) $1,750 $1,750 Less: Borrowings (960) –Less: Letters of Credit (32) (32)Plus: Cash 11 629

Liquidity (Credit Facility + Cash)(3) $769 $2,347

22

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 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

Four of Antero’s contracted drilling rigs are running on natural gas and the majority of its rigs should run on natural gas by year-end 2013

Natural Gas Vehicles (NGV)

Antero supported the first natural gas fueling station in West Virginia which recently opened

Antero has a dozen NGV trucks and plans to continue to convert its truck fleet to NGV

Safety & Environmental

Five company safety representatives and 40 safety consultants cover all material field operations 24/7 including drilling, completion, construction and pipelining

10-person company environmental staff plus outside consultants monitor all operations and perform baseline water well testing

Local Presence Land office in Ellenboro, WV Recently moved into new 50,000 square foot district office in Bridgeport, WV 80 of Antero’s 215 employees are located in West Virginia and Ohio

LEED Gold Headquarters Building

Antero’s new corporate headquarters in Denver has been LEED Gold Certified Completion expected by spring of 2014

HEALTH, SAFETY, ENVIRONMENT & COMMUNITY

23

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

WHY INVEST IN ANTERO?

24

Over 400,000 Net Acres in the Core Marcellus and Utica Shales

“Triple Digit” Historical Production and Reserve Growth

Low Cost Leader / High Return Projects

Significant Takeaway and Processing Capacity Already in Place

Clean Balance Sheet Supports High Growth Story

“Forward Thinking” Management Team with a History of Success

25

APPENDIX

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)

26

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

27

+$0.77Upgrade

+$2.45Upgrade

+$3.55Upgrade

Rich GasDry Gas

2013 REALIZATIONS

Ethane (C2)

Propane (C3)

Iso Butane (C4)

Normal Butane

Natural Gasoline

Total $49.75 per BBl52% of WTI(2)

6/30/2013 YTD NGL Y-GRADE (C3+) REALIZATIONS

NATURAL GAS REALIZATIONS

60%

1%

10%

14%

14%

$23.52

$5.97

$7.10

$12.58

$0.59

281. NYMEX differential represents contractual deduct to NYMEX-based sales.2. Based on monthly prices through 6/30/13 WTI.

Antero Barrel

`August 2013 YTD

% Sales Index Price2013 YTD

DifferentialWet Gas BTUEnhancement

2013 YTD Realized Price

TCO 81% $3.73 $(0.01) $0.38 $4.09Dominion South 14% $3.60 $(0.06) $0.42 $3.96NYMEX(1) 5% $3.82 $(0.43) $0.34 $3.72

Total 100% $3.72 $(0.04) $0.38 $4.05

ANTERO FIRM TRANSPORTATION AND FIRM SALES

29

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

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

ANTERO EBITDAX RECONCILIATION

30

EBITDAX Reconciliation($ in thousands) LTM EndedAntero Resources LLC 6/30/13

EBITDAX:Net income (loss) from continuing operations $54,154Commodity derivative fair value (gains) losses (91,874)Net cash receipts on settled commodity derivatives instruments 144,052(Gain) loss on sale of assets 115Interest expense and other 112,313Provision (benefit) for income taxes (9,415)Depreciation, depletion, amortization and accretion 157,134Impairment of unproved properties 16,848Exploration expense 21,581Other 3,272EBITDAX from continuing operations $408,180

EBITDAX:Net income (loss) from discontinued operations ($105,671)Commodity derivative fair value (gains) losses 18,880Net cash receipts on settled commodity derivatives instruments 26,292(Gain) loss on sale of assets 368,713Provision (benefit) for income taxes (285,280)Depreciation, depletion, amortization and accretion 25,758Impairment of unproved properties (31)Exploration expense 252EBITDAX from discontinued operations $48,913

EBITDAX $457,093

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

31