Company Overview February 2014 FORWARD-LOOKING STATEMENTS This - - PowerPoint PPT Presentation

Company Overview February 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,

• bjectives 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

• ther 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

• r 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 35 Tcfe of 3P reserves in Marcellus and Utica Shales
• 566 MMcfe/d of average net production in 3Q 2013 including 7,900 Bbl/d of

liquids; 675–680 MMcfe/d net production guidance for 4Q 2013

Critical Mass In Two World Class Shale Plays

• 159% Appalachian production CAGR since 2010 to YE 2013
• Most active driller in Appalachia – 20 rigs running
• Most active driller in Marcellus Shale – 15 rigs running
• 3rd most active driller in the Utica Shale – 5 rigs running

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

• 1.4 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/MMBtu

and $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 2

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

UPPER DEVONIAN SHALE Net Proved Reserves(1) 44 Bcfe Net 3P Reserves (1) 4.2 Tcfe Pre-Tax 3P PV-10(1) NM % Liquids – Net 3P 7% 3Q 2013 Net Production 3 MMcfe/d Undrilled 3P Locations 951

C

PREMIER UNCONVENTIONAL RESOURCE PLATFORM

1. Proved, probable, and possible reserves as of December 31, 2013, assuming ethane rejection using SEC methodology and SEC pricing. Evaluations prepared by our internal reserve engineers and audited by DeGolyer & MacNaughton (D&M). Pre-Tax 3P PV-10 is a non-GAAP financial measure. 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.

TOTAL – 12/31/13 RESERVES(1) Assumes Ethane Rejection

Net Proved Reserves(1) 7.6 Tcfe Net 3P Reserves(1) 35.0 Tcfe Pre-Tax 3P PV-10(1) $20,362 MM Net 3P Liquids 902 MMBbls % Liquids – Net 3P 15% 3Q 2013 Net Production(2) 566 MMcfe/d

• 3Q 2013 Net Liquids(2)

7,900 Bbl/d Net Acres(3) 454,000 Undrilled 3P Locations 4,778 MARCELLUS SHALE Net Proved Reserves(1) 7.2 Tcfe Net 3P Reserves (1) 25.0 Tcfe Pre-Tax 3P PV-10(1) $15,729 MM % Liquids – Net 3P 17% 3Q 2013 Net Production 519 MMcfe/d Undrilled 3P Locations 3,068

• 100% operated
• Stable acreage base

− Marcellus Shale: 51% HBP, with additional 21% 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 2014 and 2015

development drilling activities

• Full scale development underway

− 20 rigs currently operating

A

UTICA SHALE – LIQUIDS RICH Net Proved Reserves(1) 362 Bcfe Net 3P Reserves (1) 5.8 Tcfe Pre-Tax 3P PV-10(1) $4,666 MM % Liquids – Net 3P 15% 3Q 2013 Net Production 44 MMcfe/d Undrilled 3P Locations 759

B

3

A C B

Additional Hedge Value “Pure-Play” Appalachian-Focused Shale Company

UTICA SHALE – DRY GAS Net Acres(3) 126,000 Net Resource 5.0 Tcfe Undrilled Locations 950

D

D

• 1.3 Tcfe hedged from 1/1/2014 through 12/31/2019 at a

NYMEX-equivalent price of $4.97/MMBtu

• ~ $940 million mark-to-market value as of 1/31/2014 not

included in reserve PV-10

• ~ 50% hedged through NYMEX; 50% hedged through

regional hubs

200 400 600 800 1,000

2010 2011 2012 2013E 2014E

Marcellus Utica

30 124 239 522 950

(5) (4)

4

200 400 600 800 1,000

2006 2007 2008 2009 2010 2011 2012 2013E 2014E

Woodford Piceance Marcellus Utica

6 31 87 105 133 244 334 522

(5)

950

(4)

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

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000

2006 2007 2008 2009 2010 2011 2012 2013

Woodford Piceance Marcellus Utica

(3)

87 235 680 1,141 3,231 5,017 4,929 7,632

NET PROVED SEC RESERVES (Bcfe)(2)

193 25 50 75 100 125 150 175 200

2006 2007 2008 2009 2010 2011 2012 2013E 2014E

Woodford Piceance Marcellus Utica

85 96 126 18 66 91 119 157

(5) (4)

• 1. CAGR = Compound Annual Growth Rate.
• 2. Proved reserves for 2006, 2007, and 2008 represent previously effective SEC methodology. 2009, 2010, 2011, 2012 and 2013 proved reserves based on current SEC reserve methodology and SEC pricing and are audited by independent 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 dated January 27, 2014.
• 5. Per Company press release dated January 29, 2014; production mid-point of 925-975 MMcfe/d guidance.

Financial Crisis

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

` 637 834 707 890 130% 69% 33% 21% 200 400 600 800 1000 0% 50% 100% 150%

Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Gross Locations ROR 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 12/31/2013 3P reserves and strip pricing as of 12/31/2013.
• 2. Source: Credit Suisse report dated 06/18/2013 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI.
• 3. 3-year NYMEX STRIP as of 1/31/2014.

3 Yr Strip - $4.21/MMBtu(3)

637

Locations

1,541

Locations

205

Locations

890

Locations $ / MMBtu NYMEX (Gas)

343

Locations

5

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

205 161 182 211 145% 177% 99% 56% 50 100 150 200 250 0% 50% 100% 150% 200%

Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Gross Locations ROR Locations ROR

1,000  71% of Marcellus locations are processable (1100-plus Btu)  72% of Utica locations are processable (1100-plus Btu)

0.0x 2.0x 4.0x 6.0x 8.0x 6.1x 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 producers Antero has sold ~76% of its year-to-date production through September 2013 at TCO index at NYMEX less $0.07/MMbtu

7

1. 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 as of 1/31/2014.

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

200 400 600 800 1,000 1,200 1,400 1,600 (MMcf/d) Sherwood I Sherwood II Sherwood III Sherwood IV Sherwood V Seneca I Seneca II Seneca III Seneca IV

Total Capacity 1,550 Marcellus Utica

Sherwood I Sherwood II Sherwood III Seneca I Seneca II Seneca III

TCO Basis to NYMEX Current 2015

• $0.05
• $0.49

Dom South Basis to NYMEX Current 2015

• $0.60
• $1.13

Leidy Basis to NYMEX Current 2015

• $2.25
• $2.00

Antero Transport and Processing 2014 2015

Firm Transport (FT) (MMBtu/d) 1,227,000 1,227,000 Firm Sales (MMBtu/d)(1) 330,000 320,000 Firm Processing Capacity (Mcf/d) 1,400,000 1,550,000 Ethane FT (Bbl/d) 20,000 20,000

Growing Processing Capacity

2014 2015 2016 2017 2018 2019

• $2.20
• $1.80
• $1.40
• $1.00
• $0.60
• $0.20

Appalachian Basis to NYMEX(2)

TETCO M2 Leidy TCO Dom South

YTD % of Production Sold TCO 76% Dom South 18% NYMEX 5% CGTLA Basis to NYMEX Current 2015

• $0.02
• $0.09

Chicago Basis to NYMEX Current 2015 +$0.38

• $0.12

Sherwood V Sherwood IV Seneca IV

LONG HAUL PIPELINE AND TRANSPORTATION NETWORK

8

 Antero has a leading firm transportation capacity and is well-positioned in the southern portion of the Marcellus and Utica Shale from a gas takeaway perspective

Note: Antero firm transportation and firm sales positions listed by pipeline in colored-coded boxes.

• 1. Firm transport as of year-end 2014. See Page 25 for timing of firm transportation graph.
• 2. Antero firm transportation as of 1/31/2014; excludes 250 MMcf/d of firm sales.

(1) TCO Basis to NYMEX Current 2015

• $0.05
• $0.49

Dom South Basis to NYMEX Current 2015

• $0.60
• $1.13

Leidy Basis to NYMEX Current 2015

• $2.25
• $2.00

CGTLA Basis to NYMEX Current 2015

• $0.02
• $0.09

Chicago Basis to NYMEX Current 2015 +$0.38

• $0.12

628 550 633 750 650 288

$5.38 $5.51 $5.28 $4.43 $4.65 $4.51 $4.41 $4.14 $4.09 $4.12 $4.15 $4.24

$0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 200 400 600 800 2014 2015 2016 2017 2018 2019 BBtu/d 11% 19% 18% 49% 2% NYMEX CGTLA Dom South TCO Chicago

SIGNIFICANT LONG-TERM COMMODITY HEDGE POSITION

9

% HEDGE VOLUMES BY INDEX – 12/31/2013

Hedged NYMEX-Equivalent Price(1) Hedged Volume NYMEX Strip (1/31/2014)

NATURAL GAS HEDGES – 12/31/2013

• 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 2014, WTI hedges comprise ~1% of overall hedge book.

 ~$940 million mark-to-market unrealized gain as of January 31, 2014.  1.3 Tcfe hedged from January 1, 2014 through year-end 2019.

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

106,000 Net Acres 17 Horizontals Completed 5 Rigs Currently Running

ANTERO MARCELLUS SHALE SW PA

25,000 Net Acres 2 Horizontals Completed Strong Results

ANTERO MARCELLUS SHALE NW WV

323,000 Net Acres (Primarily Liquids-Rich Fairway) 221 Horizontals Completed 15 Rigs Currently Running Utica Shale Liquids-Rich Fairway Utica Shale Dry Gas Resource Underlies Marcellus Acreage Marcellus Shale Liquids-Rich Fairway

WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT

Antero Has Delineated And De-Risked Its Large Scale Acreage Position

 100% operated  348,000 net acres in Southwestern Core – 51% HBP with additional 21% not expiring for 5+ years  223 horizontal wells completed and online – Laterals average 7,000’ – 100% drilling success rate  Net production of 522 MMcfe/d in 3Q 2013, including 6,100 Bbl/d of liquids  3,068 future drilling locations (71% are processable)  Operating 15 drilling rigs including 4 shallow rigs  25.0 Tcfe of net 3P (17% liquids), includes 7.2 Tcfe of proved reserves

12

Highly-Rich Gas 100,000 Net Acres 834 Gross Locations Rich Gas 84,000 Net Acres 707 Gross Locations Dry Gas 104,000 Net Acres 890 Gross Locations Highly-Rich/Condensate 60,000 Net Acres 637 Gross Locations MOORE UNIT 30-Day Rate 1H: 9.9 MMcfe/d 2H: 10.0 MMcfe/d (17% liquids) MHR WEESE UNIT 30-Day Rate 4-well average 9.3 MMcfe/d (31% liquids) CHK HADLEY UNIT 24-Hour IP 9.1 MMcfe/d (32% liquids) EQT PENN 15 UNIT 30-Day Rate 5-well average 9.3 MMcfe/d (29% liquids) CONSTABLE UNIT 30-Day Rate 1H: 15.2 MMcfe/d (30% liquids) 142 Horizontals Completed 30-Day Rate 10.3 Bcf average EUR 8.1 MMcf/d 6,915’ average lateral length PRUNTY UNIT 30-Day Rate 1H: 11.0 MMcfe/d (29% liquids) HINTERER UNIT 30-Day Rate 1H: 12.9 MMcfe/d (20% liquids) RUTH UNIT 30-Day Rate 1H: 19.3 MMcfe/d (14% liquids)

Sherwood Processing Plant

EQT 30-Day Rate 12 Recent Wells 9.2 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 UNIT 30-Day Rate 2H: 10.0 MMcfe/d (29% liquids) DOTSON UNIT 30-Day Rate 1H: 12.4 MMcfe/d 2H: 11.8 MMcfe/d (27% liquids)

MARCELLUS – SIMPLE STRUCTURE

13

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

• Over 1.5 million feet (295 miles)

drilled horizontally without crossing a fault − 3-D seismic not required to guide horizontal wells  Regional East-West seismic line shows gentle structure at Marcellus level  Allegheny Front and complex structure located many miles east of core area  Favorable geology allows for longer laterals Average Marcellus Lateral Lengths

7,000 4,800 4,500 4,100 2,000 4,000 6,000 8,000 Antero EQT RRC COG Feet

Source: Company presentations.

Wolf Summit Arches Fork Big Moses

Marcellus Onondaga Benson Rhinestreet

Profile along regional seismic line (time)

W E

Regional Seismic Line

No Data

Tully 100’ Contours Top Marcellus

0.0 3.0 6.0 9.0 12.0 15.0 0.0 3.0 6.0 9.0 12.0 15.0 1 2 3 4 5 6 7 8 9 10 Cumulative Bcf MMcf/d Production Year

1.5 Bcf/1,000' Type Curve (7,000' Lateral) Actual Production (Normalized to 7,000' Lateral) Type Curve Cumulative Production (7,000' Lateral) 1.7 Bcf/1,000' SSL Type Curve SSL Actual Production (Normalized to 7,000' Lateral) $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 5 10 15 20 25 30 MMcfd 1st Production from All Wells 2009 - 2013

 Antero has over four years of production data, from 223 operated horizontal wells, to support its 1.5 Bcf/1,000’ of lateral type curve (non-SSL)  Due to recent success with shorter stage lengths (SSL), Antero’s type curve has been increased to 1.73 Bcf/1,000’ – 12% higher well costs  Lack of faulting and contiguous acreage position allows for drilling of long laterals − Drives down costs per 1,000’ of lateral resulting in best-in-class development costs

ANTERO’S MARCELLUS SHALE TYPE CURVE SUPPORT

• 1. 223 Antero Marcellus wells normalized to time zero, production for each well normalized to 7,000’ lateral length.
• 2. 32 Antero Marcellus SSL wells normalized to time zero, production for each well normalized to 7,000’ lateral length.

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-Year

• Avg. Rate

Wellhead (MMcf/d) 14.1 8.1 6.3 5.3 4.2 3.1 2.2 # of wells 223 217 221 179 127 63 25

EURs Increase With Lateral Length Well Cost / 1,000’ Decreases with Lateral Length Wellhead 24-hour Peak Rates (IPs) - 223 Wells

Average IP – 14.1 MMcf/d 4 8 12 16 20 2,000 4,000 6,000 8,000 10,000 EUR, BCF Lateral Length, ft

(2)

MARCELLUS SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION

15

DRY GAS LOCATIONS RICH GAS LOCATIONS HIGHLY RICH GAS LOCATIONS

Assumptions

 12/31/2013 Strip Pricing & SEC Reserves

NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL(2) ($/Bbl) 2014 $4.24 $95 $59 2015 $4.16 $88 $54 2016 $4.09 $83 $51 2017 $4.09 $80 $50 2018+ $4.14 $79 $50

Marcellus SSL Well Economics and Locations(1)

Classification Highly-Rich/ Condensate Highly-Rich Gas Rich Gas Dry Gas BTU Range 1275-1350 1200-1275 1100-1200 <1100 Modeled BTU 1313 1250 1150 1050 EUR (Bcfe): 16.5 14.9 13.3 12.1 EUR (MMBoe): 2.8 2.5 2.2 2.0 % Liquids: 34% 24% 12% 0% Lateral Length (ft): 7,000 7,000 7,000 7,000 Stage Length (ft): 225 225 225 225 Well Cost ($MM): $9.5 $9.5 $9.5 $9.5 Bcf/1,000’: 1.7 1.7 1.7 1.7 Bcfe/1,000’: 2.4 2.1 1.9 1.7 Pre-Tax NPV10 ($MM): $21.1 $14.1 $6.7 $3.7 Pre-Tax ROR: 130% 69% 33% 21% Net F&D ($/Mcfe): $0.68 $0.75 $0.84 $0.92 Payout (Years): 0.9 1.3 2.4 3.6 Gross 3P Locations: 637 834 707 890

• 1. Well economics are based on 12/31/2013 3P reserves. Includes gathering, compression and processing fees.
• 2. Pricing for a 1225 BTU y-grade rejection barrel.

637 834 707 890 130% 69% 33% 21% 200 400 600 800 1,000 0% 50% 100% 150%

Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Gross Locations ROR Locations ROR

1,000 10,000 30 60 90 120 150 180 Gas Production (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 – 32 SSL wells completed – 22 SSL wells have at least 30 days

• f 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

• perators 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 7.9 1.5 Bcf/1,000' Type Curve Average Rate – MMcf/d(1) 7.6 7.1 6.6 6.2 SSL % Rate Improvement 31% 21% 24% 27%

(1) Wellhead condensate production (where applicable) is converted on a 6:1 basis

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  106,000 net acres in the core rich gas / condensate window – 20% HBP with additional 79% not expiring for 5+ years – 72% of acreage has rich gas processing potential  17 Antero-operated horizontal wells completed with 16 currently online − 100% drilling success rate  Net production of 44 MMcfe/d in 3Q 2013 including 1,800 Bbl/d of liquids − First production in early August 2013 with access to Cadiz pipeline and processing − Seneca I processing plant came online in November 2013 and Seneca II came online in January 2014 − First 120 MMcf/d compressor station went into service in late January with an additional 120 MMcf/d expected by late 1Q 2014  759 future drilling locations – Approximately 36% of EUR is liquids assuming ethane recovery  Operating 5 rigs including 1 shallow rig  5.8 Tcfe of net 3P (15% liquids), includes 362 Bcfe of proved reserves

EXCITING CORE UTICA SHALE POSITION DELIVERS CONDENSATE AND NGLS

17

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

Seneca Processing Plant Cadiz Processing Plant CHESAPEAKE 24-Hour IP Buell #8H 9.5 MMcf/d + 1,425 Bbl/d liquids GULFPORT 24-Hour IP Boy Scout 1-33H, Ryser 1-25H, Groh 1-12H Average 5.3 MMcf/d + 675 Bbl/d NGL + 1,411 Bbl/d Oil REXX 24-Hour IP Guernsey 1H, 2H, Noble 1H Average 7.9 MMcf/d + 1,192 Bbl/d NGL + 502 Bbl/d Oil MILEY UNIT 30-Day Rate 2 wells average 3.0 MMcf/d + 187 Bbl/d NGL + 559 Bbl/d Oil NORMAN UNIT 1H 30-Day Rate 13.6 MMcf/d + 461 Bbl/d NGL + 2 Bbl/d Oil YONTZ UNIT 1H 30-Day Rate 14.6 MMcf/d + 392 Bbl/d NGL + 1 Bbl/d Oil RUBEL UNIT 30-Day Rate 3 wells average 13.5 MMcf/d + 583 Bbl/d NGL + 45 Bbl/d Oil GULFPORT 24-Hour IP McCort1-28H, 2-28H, Stutzman 1-14H Average 13.1 MMcf/d + 922 Bbl/d NGL + 21 Bbl/d Oil GULFPORT 24-Hour IP Wagner 1-28H, Shugert 1-1H, 1-12H Average 21.0 MMcf/d + 2,270 Bbl/d NGL + 292 Bbl/d Oil Utica Core Area WAYNE UNIT 30-Day Rate 3 wells average 5.4 MMcf/d + 335 Bbl/d NGL + 548 Bbl/d Oil DOLLISON UNIT 1H 24-Hour IP 10.2 MMcf/d + 1,488 Bbl/d NGL + 1,397 Bbl/d Oil GARY UNIT 1H 30-Day Rate 23.1 MMcf/d + 1,023 Bbl/d NGL + 65 Bbl/d Oil Highly-Rich/Cond 30,000 Net Acres 205 Locations Highly-Rich Gas 26,000 Net Acres 161 Locations Rich Gas 23,000 Net Acres 182 Locations Dry Gas 27,000 Net Acres 211 Locations MILLIGAN UNIT 24-Hour IP 3 wells average 11.3 MMcf/d + 1,971 Bbl/d NGL + 1,586 Bbl/d Oil COAL UNIT 1H 24-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 MMcfe/d

Source: Antero, press releases and company presentations. Note: Assumes ethane recovery.

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 IPs

Core

12 to 53

MMcfe/d IPs Tier 1

6 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

 12/31/2013 Strip Pricing & SEC Reserves

Utica Well Economics and Locations(1)

Classification Highly-Rich/ Condensate Highly-Rich Gas Rich Gas Dry Gas BTU Range 1250-1300 1200-1250 1100-1200 <1100 Modeled BTU 1275 1225 1175 1050 EUR (Bcfe): 11.3 20.5 18.8 16.6 EUR (MMBoe): 1.9 3.4 3.1 2.8 % Liquids 32% 23% 15% 0% Lateral Length (ft): 7,000 7,000 7,000 7,000 Stage Length (ft): 240 240 240 240 Well Cost ($MM): $11.0 $11.0 $11.0 $11.0 Bcf/1,000’: 1.2 2.4 2.4 2.4 Bcfe/1,000’: 1.6 2.9 2.7 2.4 Pre-Tax NPV10 ($MM): $16.1 $27.2 $18.7 $11.7 Pre-Tax ROR: 145% 177% 99% 56% Net F&D ($/Mcfe): $1.21 $0.66 $0.72 $0.82 Payout (Years): 0.5 0.5 0.8 1.3 Gross 3P Locations(3): 205 161 182 211

• 1. Well economics are based on 12/31/2013 3P reserves. Includes gathering, compression and processing fees.
• 2. Pricing for a 1225 BTU y-grade rejection barrel.
• 3. Gross 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.

NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL(2) ($/Bbl) 2014 $4.24 $95 $58 2015 $4.16 $88 $54 2016 $4.09 $83 $50 2017 $4.09 $80 $49 2018+ $4.14 $79 $49

205 161 182 211 145% 177% 99% 56% 50 100 150 200 250 0% 50% 100% 150% 200%

Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Gross Locations ROR Locations ROR

SIGNIFICANT MIDSTREAM INFRASTRUCTURE POSITION

20

Ohio River Withdrawal January 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 position Qualifies for midstream MLP Utica Shale Marcellus Shale

Midstream Infrastructure(1) Marcellus Shale Utica Shale Total YE 2013 Estimated Total Gathering / Compression Capex ($MM) $510 $220 $730 Gathering Pipelines (Miles) 83 20 103 Compressor Stations 4 4 YE 2013 Estimated Total Water System Capex ($MM) $200 $50 $250 Water Pipeline (Miles) 71 37 108 Water Storage Facilities 17 2 19 YE 2013 Estimated Total Midstream ($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 $58.74 as of 1/31/2014. Enterprise value includes net debt.
• 2. Lender commitments under the facility reduced to $1.5 billion from $1.75 billion on 10/21/2013; commitments can be expanded to the full $2.0 billion borrowing base upon bank approval.
• 3. $1,000 million 5.375% Senior Notes priced on 10/24/2013, $525 million 9.375% Senior Notes called, $25 million 9.00% Senior Note redeemed, 35% of $400 million 7.25% Senior Notes redeemed and transaction fees.

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 400 400 260 6.00% Senior Notes Due 2020 525 525 525 5.375% Senior Notes Due 2021 – – 1,000 Net Unamortized Premium 8 8 6 Total Debt $2,996 $1,483 $1,791 Net Debt $2,984 $1,406 $1,452 Shareholders' Equity $1,875 $3,453 $3,427 Net Book Capitalization $4,859 $4,859 $4,879 Net Market Capitalization(1) N/M $15,735 $16,842 Financial & Operating Statistics LTM EBITDAX $521 $521 $521 Proved Reserves (Bcfe) (12/31/2013) 7,632 7,632 7,632 Proved Developed Reserves (Bcfe) (12/31/2013) 2,023 2,023 2,023 Credit Statistics Net Debt / LTM EBITDAX 5.7x 2.7x 2.8x LTM EBITDAX / Interest Expense 4.1x 4.7x 5.1x Net Debt / Net Book Capitalization 61.4% 28.9% 29.8% Net Debt / Net Market Capitalization N/M 8.9% 8.6% Net Debt / Proved Developed Reserves ($/Mcfe) $1.48 $0.71 $0.72 Net Debt / Proved Reserves ($/Mcfe) $0.39 $0.19 $0.19 Liquidity Credit Facility Commitments(2) $1,750 $1,500 $1,500 Less: 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 2015 requirements) Central Fresh Water System & Water Recycling

• Numerous sources of water – building central water system to source water for

completion

• Antero recycles over 95% of its flowback water with the remainder injected into

disposal wells – no discharge to water treatment plants in West Virginia Natural Gas Powered Drilling Rigs

• Eight of Antero’s contracted drilling rigs are currently running on natural gas

Natural Gas Vehicles (NGV)

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

recently opened

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

NGV Safety & Environmental

• Five company safety representatives and 45 safety consultants cover all material

field operations 24/7 including drilling, completion, construction and pipelining

• 23-person company environmental staff plus outside consultants monitor all
• perations and perform baseline water well testing

Local Presence

• Land office in Ellenboro, WV
• Recently moved into new 50,000 square foot district office in Bridgeport, WV
• 101 of Antero’s 251 employees are located in West Virginia and Ohio

LEED Gold Headquarters Building

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

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

• utstanding 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

23 454,000 Net Acres in the Core Marcellus and Utica Shales “Triple Digit” Historical Production and Reserve Growth Low Cost Leader / High Return Projects Significant Takeaway and Processing Capacity Already in Place Clean Balance Sheet Supports High Growth Story “Forward Thinking” Management Team with a History of Success

24

APPENDIX

24

ANTERO FIRM TRANSPORTATION AND FIRM SALES

25

MMBtu/d

Columbia 7/26/2009 – 9/30/2025 Firm Sales #1 10/1/2011– 10/31/2019 Firm Sales # 2 10/1/2011 – 5/31/2017 Firm Sales # 3 1/1/2013 – 5/31/2022 Momentum III 9/1/2012 – 12/31/2021 EQT 8/1/2012 – 8/31/2021 Chicago Direct 4/1/2013 – 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

Lateral Well Gas Eq. Rate Wellhead Gas Shrunk Gas NGL Condensate % Total Estimated Length Name 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 5,115 Rubel 1H Monroe 47.5 31.1 25.9 3,391 214 46% 1231 6,554 Gary 2H Monroe 43.5 28.9 24.2 3,053 162 44% 1224 8,882 Rubel 3H * Monroe 42.6 28.4 23.7 3,003 142 44% 1220 6,424 Milligan 2H Noble 40.2 17.2 13.5 2,361 2,087 66% 1276 5,989 Rubel 2H Monroe 37.4 24.8 20.7 2,635 156 45% 1217 6,571 Norman 1H Monroe 37.1 26.1 22.3 2,419 45 40% 1186 5,498 Coal 3H Noble 35.3 15.1 11.8 2,063 1,850 67% 1278 7,768 Wayne 3HA Noble 35.1 14.7 11.6 2,018 1,905 67% 1272 6,712 Wayne 4H Noble 34.2 14.2 11.2 1,907 1,922 67% 1265 6,493 Milligan 3H Noble 32.1 15.4 12.1 2,111 1,228 62% 1276 5,267 Dollison 1H Noble 27.5 12.5 10.2 1,488 1,397 63% 1238 6,253 Milligan 1H Noble 25.8 10.6 8.3 1,461 1,442 68% 1276 6,436 Wayne 2H Noble 25.5 10.9 8.5 1,503 1,331 67% 1281 6,094 Miley 2H Noble 22.4 8.6 6.7 1,172 1,450 70% 1278 6,153 Miley 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 6,407 28.1 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

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

14.7 11.0 10.4 455 270 35% 1239 6,436 17.9 11.0 9.2 1,189 270 53% 1239 6,436

30‐Day Rates ‐ Antero Core Area

Average ‐ Ethane Rejection Average ‐ Ethane Recovery(1)

CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY

 25 year proved reserve life from current production annualized  Reserve base provides significant exposure to liquids-rich projects – 3P reserves of over 2.2 BBbl of NGLs and condensate in ethane recovery mode; 33% liquids

• 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
• f 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 – 25.0 Tcfe Utica – 5.8 Tcfe Upper Devonian – 4.2 Tcfe

35.0 Tcfe

Gas – 29.6 Tcf Oil – 91 MMBbls NGLs – 811 MMBbls Marcellus – 29.5 Tcfe Utica – 6.7 Tcfe Upper Devonian – 4.7 Tcfe

40.8 Tcfe

Gas – 27.4 Tcf Oil – 91 MMBbls NGLs – 2,151 MMBbls

15% Liquids 33% Liquids

Gas $4.15 Gas $3.90 Gas $3.86 Gas $3.80 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 1050 BTU $5.19 $6.95 $8.28 $4.15 1150 BTU 1250 BTU 1300 BTU

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

(1076 BTU)

8% shrink

(1109 BTU)

12% shrink

(1119 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

+$1.04

Upgrade

+$2.79

Upgrade

+$4.13

Upgrade

Rich Gas Dry Gas

NGLs (C3+) $1.30 NGLs (C3+) $2.93 NGLs (C3+) $3.92 Condensate $0.16 Condensate $0.56

2013 YEAR-TO-DATE REALIZATIONS

Ethane (C2) Propane (C3) Iso Butane (C4) Normal Butane Natural Gasoline

Total $50.73 per Bbl 48% of WTI(3)

9/ 30/ 2013 YTD NGL Y-GRADE (C3+ ) REALI ZATI ONS 9/ 30/ 2013 YTD NATURAL GAS REALI ZATI ONS

55% 1% 11% 16% 17% $27.69 $5.72 $8.04 $8.69 $0.59 30

• 1. 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 Average Differential(2) Average BTU Upgrade Average YTD Realized Price TCO 76% $3.68 $(0.07) $0.44 $4.05 Dominion South 18% $3.68 $(0.39) $0.42 $3.71 NYMEX(1) 5% $3.68 $(0.40) $0.41 $3.69 TETCO 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 $200,990 Commodity derivative fair value (gains) losses (52,210) (285,510) Net cash receipts on settled commodity derivatives instruments 141,506 109,311 (Gain) loss on sale of assets (291,190)

• Interest expense and other

71,046 100,840 Provision (benefit) for income taxes 108,525 120,695 Depreciation, depletion, amortization and accretion 65,360 159,447 Impairment of unproved properties 4,019 9,564 Exploration expense 7,912 17,034 Other 2,992 1,820 EBITDAX 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 427,232 Provision (benefit) for income taxes 4,085 Depreciation, depletion, amortization and accretion 77,654 Impairment of unproved properties 962 Exploration expense 507 EBITDAX 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