Company Overview January 2015 FORWARD-LOOKING STATEMENTS This - - PowerPoint PPT Presentation

Company Overview January 2015

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 under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for

the year ended December 31, 2013 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 our Annual Report on Form 10-K for the year ended December 31, 2013 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

2

CHANGES SINCE DECEMBER 2014 PRESENTATION

Updated single well economic returns for Marcellus and Utica at 12/31/2014 strip prices Slides 17, 26, 29, 44, 45 Realized natural gas and equivalent pricing for 4Q 2014, including hedges Updated natural gas and liquids hedge portfolio with mark-to-market value as of 1/13/2015

Slide 13 Slides 24, 25, 28 Slide 12

New drilling performance metric slides for Marcellus and Utica development programs New slide highlighting low breakeven price of Antero’s shale plays compared to other U.S. shale plays

Slide 16

Updated land position as of 12/31/2014 and Marcellus rig count position as of 1/9/2015

Slide 5

Updated “Road Map” for natural gas realizations based

• n 1/13/2015 strip prices

Slide 14

3

Most Active Operator in Appalachia Most Active Land Organization in Appalachia Largest Firm Transport and Processing Portfolio in Appalachia Largest Gas Hedge Position in U.S. E&P + Strong Financial Liquidity Highest Growth Large Cap E&P Largest Liquids-Rich Core Position in Appalachia Highest Realizations and Margins Among Large Cap Appalachian Peers

Growth Land Liquidity Midstream Drilling

LEADING UNCONVENTIONAL BUSINESS MODEL

MLP (NYSE: AM) Highlights Substantial Value in Midstream Business

Realizations Takeaway Liquids-Rich

1 2 3 4 5 6 7 8

Premier Appalachian E&P Company Run by Co-Founders

Downstream LNG and NGL Sales Production and Cash Flow Growth 4 Antero has 170,000 net acres in WV and PA prospective for Utica dry gas – adjacent to current industry activity with highly encouraging initial results

CATALYSTS

45-50% production growth targeted for both 2015 and 2016 with 88% hedged at $4.42/MMBtu and 43% hedged at $4.47/MMBtu, respectively Large, low cost core Marcellus and Utica natural gas drilling inventory with associated liquids generates attractive returns supported by long- term natural gas hedges, takeaway portfolio and downstream LNG and NGL sales agreements Pursuing additional value enhancing long-term LNG and NGL sales agreements, supported by firm takeaway Antero owns 70% of Antero Midstream Partners and thereby participates directly in its growth and value creation Midstream MLP Growth Sustainability of Antero’s Integrated Business Model Potential Water System Monetization 1 2 3 4 5 6 Contingent on receiving private letter ruling from the IRS, AM holds an

• ption to acquire Antero’s fresh water system at fair market value

Utica Dry Gas Activity

DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA

• 1. All net acres allocated to the WV/PA Utica Shale Dry Gas 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 leasehold.

• 2. Locations as of 9/30/2014 adjusted for additional 245 locations acquired through 12/31/2014.
• 3. Antero and industry rig locations and rig count as of 1/9/2015 per RigData.

5

COMBINED TOTAL – 6/30/14 RESERVES Assumes Ethane Rejection

Net Proved Reserves 9.1 Tcfe Net 3P Reserves 37.5 Tcfe Pre-Tax 3P PV-10 $25.9 Bn Net 3P Reserves & Resource 47.0 Tcfe Net 3P Liquids 966 MMBbls % Liquids – Net 3P 15% 3Q 2014 Net Production 1,080 MMcfe/d

• 3Q 2014 Net Liquids

25,000 Bbl/d Net Acres(1) 542,000 Undrilled 3P Locations(2) 5,359 UTICA SHALE CORE Net Proved Reserves 537 Bcfe Net 3P Reserves 6.4 Tcfe Pre-Tax 3P PV-10 $6.5 Bn Net Acres 148,000 Undrilled 3P Locations(2) 1,112 MARCELLUS SHALE CORE Net Proved Reserves 8.5 Tcfe Net 3P Reserves 26.4 Tcfe Pre-Tax 3P PV-10 $19.4 Bn Net Acres 394,000 Undrilled 3P Locations 3,131 UPPER DEVONIAN SHALE Net Proved Reserves 40 Bcfe Net 3P Reserves 4.6 Tcfe Pre-Tax 3P PV-10 NM Undrilled 3P Locations 1,116 WV/PA UTICA SHALE DRY GAS Net Resource 9.5 Tcf Net Acres 170,000 Undrilled Locations 1,390

5 10 15 20 25 Rig Count Operators SW Marcellus + Utica Rigs(3)

47.5% 29.9% 27.7% 26.8% 25.0% 23.6% 21.3% 19.7% 17.9% 16.4% 9.7% 6.6% 5.3% 3.8% 2.8% 2.3% 0.1% (2.8%)

• 10%

0% 10% 20% 30% 40% 50%

6

Appalachian Peers

Source: Represents median of Wall Street research estimates for 2015E production growth vs. 2014 estimated production.

• 1. Includes all North American E&P companies with a market capitalization greater than $9.0 billion.
• 2. Based on midpoint of publicly announced 2015 production growth target range of 45% - 50%.

 Antero’s 45%-50% production growth target for 2015 leads the U.S. large cap E&P industry(1)

(2)

GROWTH – HIGHEST GROWTH LARGE CAP E&P

• 1. 2012, 2013 and 6/30/2014 proved reserves assuming ethane rejection.
• 2. Based on 45-50% production growth targets for 2015 and 2016.
• 3. Per current First Call median estimate from Bloomberg.

600 1,200 1,800 2,400

2010 2011 2012 2013 2014 2015E 2016E

Marcellus Utica Guidance

30 124 239 522

(2)

1,500 2,200

(2)

1,007 2,000 4,000 6,000 8,000 10,000 2010 2011 2012 2013 6/30/2014

Marcellus Utica

677 2,844 4,283 7,632

(1) (1) (1)

9,107

7

AVERAGE NET DAILY PRODUCTION (MMcfe/d) NET PROVED SEC RESERVES (Bcfe)

25 50 75 100 125 150 175 200 225

2010 2011 2012 2013 2014E

Marcellus Utica

29 36 86 162 215

GROWTH – STRONG TRACK RECORD

OPERATED GROSS WELLS SPUD EBITDAX ($MM)

$0 $200 $400 $600 $800 $1,000 $1,200 $1,400

2010 2011 2012 2013 2014E

$28 $160 $285 $649 $1,147

(4)

45-50% Annual Growth Target 92% Growth

 Assembled a 542,000 net acre position in the core of the Marcellus and Utica shale plays over the past 6 years

December 2008 Net Acreage 118,000 Net Production (MMcfe/d) NM 3P Reserves (Bcfe) NM 3P PV-10 ($MM) NM Rigs Running NM

Dec 2008 Dec 2011 Dec 2014

December 2011(1) Net Acreage 214,000 Net Production (MMcfe/d) 167 3P Reserves (Bcfe) 18,400 3P PV-10 ($MM) $9,000 Rigs Running 5 December 2014(1) Net Acreage 542,000 Net Production (MMcfe/d) 1,265 6/30/14 3P Reserves (Bcfe) 37,500 6/30/14 3P PV-10 ($MM) $25,900 Rigs Running 21

• 1. Reserves and PV-10 data for December 2014 reflect data as of 6/30/2014. Net daily production for December 2011 and December 2014 is for fourth quarter respectively.

LAND – MOST ACTIVE LAND ORGANIZATION IN APPALACHIA

8

118,000 118,000 118,000 162,000 189,000 213,000 285,000 371,000 420,000 450,000 486,000 542,000 100,000 200,000 300,000 400,000 500,000 600,000 12/2008 12/2009 6/2010 12/2010 6/2011 12/2011 6/2012 12/2012 6/2013 12/2013 6/2014 12/2014

Antero Net Acreage

Utica Marcellus

9

LIQUIDS-RICH – LARGEST CORE POSITION

Source: Core outlines and peer net acreage positions based on peer presentations, news releases and 10-K/10-Qs.

 Antero has the largest liquids-rich core position in Appalachia ≈371,000 net acres (> 1100 Btu)

MIDSTREAM – MLP (NYSE: AM) HIGHLIGHTS SUBSTANTIAL VALUE IN MIDSTREAM BUSINESS

• 1. AR enterprise value excludes AM minority interest and cash. Values as of 1/13/2015.
• 2. Based on First Call 9/30/2015 NTM EBITDA forecast of $142 million for Water Business included in preliminary AM S-1 and applying AR enterprise value to EBITDAX multiple derived from First Call AR

9/30/2015 NTM EBITDAX estimates.

• 3. Represents difference between AR enterprise value and Antero Midstream net market value and Water System enterprise value.
• 4. Based on 262.0 million AR shares outstanding.

10

Antero Resources Corporation (NYSE: AR) $12.8 Billion Enterprise Value(1) Ba3/BB Corporate Rating Antero Midstream Partners LP (NYSE: AM) $3.3 Billion Valuation(1) 70% Limited Partner Interest E&P Assets Gathering Assets

Corporate Structure Overview(1) Market Valuation of AR Ownership in AM:

• AR ownership: 69.7% LP Interest = 105.9 million units

AM Price per Unit AM Units Owned by AR (MM) AR Value in AM LP Units ($MMs) Value Per AR Share(4) $22 106 $2,332 $9 $23 106 $2,445 $9 $24 106 $2,544 $10 $25 106 $2,647 $10 $26 106 $2,753 $11 $27 106 $2,858 $11 $28 106 $2,964 $12 Fresh Water Distribution System Compression Assets = $2.3 Billion Market Valuation(1) $9.0 Billion Implied Valuation(3) $1.5 Billion Derived Valuation(2)

TAKEAWAY – LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA

Odebrecht / Braskem 30 MBbl/d Commitment Ascent Cracker (Pending Final Investment Decision)

Antero Long Term Firm Processing & Takeaway Position (2018) – Accessing Favorable Markets

Mariner East II 62 MBbl/d Commitment(2) Marcus Hook Export Shell 25 MBbl/d Commitment Beaver County Cracker (Pending Final Investment Decision) Sabine Pass (Trains 1-4) 50 MMcf/d per Train

• 1. February 2015 and full year 2016 futures basis, respectively, provided by Wells Fargo dated 1/13/2015. Favorable gas markets shaded in green.
• 2. As an anchor shipper on Mariner East II, Antero has the right to expand its NGL commitment with notice to operator.

Chicago(1) +$0.19 / $(0.09) CGTLA(1) $(0.08) / $(0.10) Dom South(1) $(1.37) / $(1.32) TCO(1) $(0.20) / $(0.42)

11 4 Bcf/d Firm Gas Takeaway By 2018

Cove Point

1,316 943 780 1,073 818 100

$4.42 $4.47 $4.34 $4.50 $4.41 $4.24 $2.95 $3.33 $3.60 $3.73 $3.83 $3.94

$0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 200 400 600 800 1,000 1,200 1,400 2015 2016 2017 2018 2019 2020 BBtu/d

$/MMBtu

12

Average Index Hedge Price(1) Hedged Volume Current NYMEX Strip(2)

COMMODITY HEDGE POSITION

• 1. Reflects weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio. Antero has hedged 3,000 Bbl/d of oil and 23,000 Bbl/d of propane for 2015.
• 2. As of 1/13/2015.
• 3. Percentage of net gas equivalent production target hedged for respective years.

 ~$2.0 billion mark-to-market unrealized gain based on 1/13/2015 prices  1.8 Tcfe hedged from January 1, 2015 through year-end 2020 and 273 Bcf of TCO basis hedges from 2015 to 2017 $760 MM $539 MM $229 MM $302 MM $174 MM $11MM

Mark-to-Market Value(2)

LIQUIDITY – LARGEST GAS HEDGE POSITION IN U.S. E&P + STRONG FINANCIAL LIQUIDITY

$3,000 $2,012 ($1,505) ($332) $6 $843 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000

Credit Facility 9/30/2014 Bank Debt 9/30/2014 L/Cs Outstanding 9/30/2014 Cash 9/30/2014 AM IPO Proceeds to AR Pro Forma Liquidity 9/30/2014

AR LIQUIDITY POSITION ($MM) AM LIQUIDITY POSITION ($MM)

$1,000 $1,250 $0 $0 $0 $250 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000

Credit Facility 9/30/2014 Bank Debt 9/30/2014 L/Cs Outstanding 9/30/2014 Cash 9/30/2014 AM IPO Proceeds to AM Pro Forma Liquidity 9/30/2014

≈ 88% of 2015E Target Production(3)  Over $3 billion of combined AR and AM financial liquidity as of 9/30/2014, pro forma for AM IPO closed on 11/10/2014 ≈ 43% of 2016E Target Production(3)

1. Includes firm sales. 2. Price realization includes $0.05 of midstream revenues in 3Q, 2014. 3. Includes natural gas hedges. 4. Source: Public data from 3Q 2014 10-Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp. and Range Resources. 5. Includes realized hedge gains and losses. Operating costs include lease operating expenses, production taxes, gathering, processing and firm transport costs and general and administrative costs. 4-year proved reserve average all-in F&D from 2010-2013. Calculation = (Development costs + exploration costs + leasehold costs) / Total reserves added (2013 ending reserves – 2010 beginning reserves + 4-year reserve sales – 4-year reserve purchases + 4-year accumulated production). AR price realization includes $0.04 of midstream revenues.

$4.16 $3.97 $0.58 $0.95 $0.74 $0.77 $0.81

$0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 Antero Peer 1 Peer 2 Peer 3 Peer 4 $/Mcfe

LOE Production Taxes GPT G&A EBITDAX 4-year Avg. All-in F&D ($/Mcfe)

$4.96 $3.25 $4.48 $2.93 $2.40 $2.64 $2.11 $2.09

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REALIZATIONS – HIGHEST REALIZATIONS & MARGINS AMONG LARGE-CAP APPALACHIAN PEERS

3Q & 4Q 2014 Natural Gas Realizations ($/Mcf) 3Q 2014 Natural Gas Realizations(3) 3Q 2014 Price Realization & EBITDAX Margin vs F&D(2)(4)

$4.31 $4.12 $3.66 $3.62 $3.60 $2.98 $2.87 $2.75 $0.00 $2.00 $4.00 $6.00 AR EQT GPOR RRC CNX RICE ECR COG $/Mcf

3Q 2014 NYMEX = $4.06/Mcf

AR Peer 1 Peer 2 Peer 3 Peer 4

Average NYMEX Price ($/Mcf) Average Differential(1) ($/Mcf) Average BTU Upgrade ($/Mcf) Discount to NYMEX ($/Mcf) Gas Hedge Effect ($/Mcf) Average Realized Gas Price ($/Mcf) Average Realized Gas Premium/ Discount ($/Mcf) Liquids Upgrade ($/Mcfe) Realized Equivalent Price ($/Mcfe) Equivalent Premium ($/Mcfe) 3Q 2014 $4.06 $(0.84) $0.41 $(0.43) $0.68 $4.31 $0.25 $0.60 $4.91 $0.85 4Q 2014 $4.00 $(0.71) $0.37 $(0.34) $0.73 $4.39 $0.39 $0.29 $4.68 $0.68

DOM S 22% DOM S 8% TETCO M2 8% TETCO M2 10% TCO 19% TCO 15% NYMEX 7% NYMEX 11% Gulf Coast 24% Gulf Coast 38% Chicago 20% Chicago 18% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

2015 Basis(1) 2016 Basis(1) 2015 Hedges 2016 Hedges

($/Mcf) 2015E 2016E NYMEX Strip Price(1) $2.95 $3.33 Basis Differential to NYMEX(1) $(0.47) $(0.38) BTU Upgrade(5) $0.25 $0.30 Estimated Realized Hedge Gains (6) $1.39 $0.67 Realized Gas Price with Hedges $4.12 $3.92 Premium to NYMEX +$1.17 +$0.59 Liquids Impact(7) +$0.29 +$0.33 Premium to NYMEX w/ Liquids +$1.46 +$0.92 Realized Gas-Equivalent Price $4.41 $4.25

• 4. Represents 60,000 MMBtu/d of TCO index hedges and 205,000 MMBtu/d of TCO basis

hedges that are matched with NYMEX hedges for presentation purposes.

• 5. Assumes ethane rejection resulting in 1100 BTU residue sales gas.
• 6. Includes hedge gains associated with oil and propane hedges.
• 7. Represents equivalent price upgrade associated with NGL (C3+) and oil production.

REALIZATIONS – REALIZED PRICE “ROAD MAP”

• 1. Based on 1/13/2015 strip pricing.
• 2. Differential represents contractual deduct to NYMEX-based firm sales contract.
• 3. Represents 120,000 MMBtu/d of TCO index hedges and 390,000 MMBtu/d of TCO basis hedges that are

matched with NYMEX hedges for presentation purposes. Marketed % of Target Residue Gas Production +$0.05/MMBtu $(0.25)/MMBtu(2) $(1.33)/MMBtu $(0.28)/MMBtu $(0.09)/MMBtu $(0.25)/MMBtu(2) $(1.32)/MMBtu $(0.42)/MMBtu $(0.10)/MMBtu $(0.09)/MMBtu 40,000 MMBtu/d @ $4.00/MMBtu 230,000 MMBtu/d @ $5.60/MMBtu 510,000 MMBtu/d @ $3.87/MMBtu(3) 170,000 MMBtu/d @ $4.09/MMBtu 272,500 MMBtu/d @ $5.35/MMBtu 265,000 MMBtu/d @ $3.89/MMBtu(4)

$1.39/Mcfe in estimated hedge gains(1) 70% exposure to favorable price indices $0.67/Mcfe in estimated hedge gains(1) 82% exposure to favorable price indices

 Antero is forecasting realized gas prices including hedges at a premium to NYMEX strip prices for 2015 and 2016, assuming current strip prices and basis, existing firm transportation and hedges, and targeted 2015 and 2016 production figures

$(1.28)/MMBtu $(1.21)/MMBtu

• Wtd. Avg.

Basis $(0.47) 1,160,000 MMBtu/d @ $4.34/MMBtu

• Wtd. Avg.

Basis $(0.38) 942,500 MMBtu/d @ $4.47/MMBtu

2015E 2016E

14

380,000 MMBtu/d @ $3.88/MMBtu 235,000 MMBtu/d @ $4.00/MMBtu

SECTOR POSITIONING

15

$39 $42 $44 $51 $53 $54 $60 $64 $65 $68 $69 $72 $83 $86 $0 $20 $40 $60 $80 $100 WTI Price ($/Bbl) Antero 2015 Drilling $1.94 $2.20 $2.20 $2.37 $2.96 $3.13 $3.31 $3.48 $3.50 $3.63 $3.77 $3.85 $3.88 $3.98 $4.33 $4.38 $5.56 $5.62 $5.69 $5.71 $5.74 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 NYMEX Price ($/MMBtu) Antero 2015 Drilling

PREMIER POSITION IN LOW-COST RICH GAS PLAYS

North American Gas Resource Play Breakeven Natural Gas Price(3)

16

North American Breakeven Oil Prices ($/Bbl)(1)

2015 NYMEX Strip: $3.01/MMBtu(2) 2015 WTI Strip: $56.26/Bbl(2)

 Over 70% of Antero’s 4,243 Marcellus and Utica undeveloped 3P locations are rich gas locations which have the lowest breakeven prices for both oil and natural gas

• 1. Source: Credit Suisse report dated December 2014 – Break-even WTI oil price to generate 15% after-tax rate of return. Assumes NYMEX gas price of $3.66/MMBtu for 2015-2019; $4.23/MMBtu thereafter.
• 2. 2015 one year WTI crude oil strip price as of 12/31/14; NYMEX one year natural gas strip price as of 12/31/14.
• 3. Source: Credit Suisse report dated December 2014 – Break-even NYMEX gas price to generate 15% after-tax rate of return. Assumes WTI oil price of $64.74/Bbl for 2015-2019; $70.50/Bbl thereafter.

Antero Projects

0% 10% 20% 30% 40%

248 143 87 265 369 10% 31% 46% 33% 30% 100 200 300 400 0% 25% 50% 75%

Condensate Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR Locations ROR

MARCELLUS SSL WELL ECONOMICS(1)

727 896 633 875 42% 28% 12% 11% 200 400 600 800 1,000 0% 25% 50% 75% 100%

Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total 3PLlocations ROR Locations ROR

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

Large 3P Drilling Inventory of High Return Projects(3)

• 1. Pre-tax well economics based on 12/31/2014 natural gas and WTI strip pricing for 2015-2020, flat thereafter, NGLs at 55% of oil price and applicable firm transportation costs; 8,000’ lateral.
• 2. Adjusted for additional 245 gross locations acquired as of 12/31/2014.
• 3. Source: Credit Suisse report dated December 2014 – After-tax internal rate of return based on 12/31/2014 strip pricing.

26% 26% 31% 15%

Internal Rate of Return (%)

20%

17

UTICA WELL ECONOMICS(1)(2)

 72% of Marcellus locations are processable (1100-plus Btu)  67% of Utica locations are processable (1100-plus Btu) 3,000 Antero Liquids-Rich Locations

16%

2015 Drilling Plan

Antero Projects  Antero is well positioned in the core of the highest return shale projects in the U.S. in the current commodity price environment

LNG Exports 48% Mexico/Canada Exports 18% Power Generation 17% Transportation 1% Industrial 16%

20 Bcf/d OF INCREMENTAL GAS DEMAND BY 2020

 Significant demand growth expected for U.S. natural gas  More than 65% of the 20 Bcf/d in incremental gas demand forecast by 2020 is expected to be generated from exports:

− LNG: 9.5 Bcf/d (~48%) − Mexico/Canada: 3.5 Bcf/d (~18%)

 Of the 9.5 Bcf/d of expected incremental demand from LNG export projects, 5.8 Bcf/d (or 61%) of the projects have secured the necessary DOE and FERC permits

18

Incremental Demand Growth Through 2020 by Category Projected Incremental Natural Gas Demand Through 2020

Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014.

Sherwood 7

2 5 9 13 17 20 4 8 12 16 20 2015 2016 2017 2018 2019 2020 Mexico/Canada Exports Power Generation Transportation Petrochem LNG Exports 9.5 Bcf/d of the 20 Bcf/d of incremental demand is expected to come from LNG exports (Bcf/d) LNG Exports Power Gen Petrochem

LNG EXPORTS BY PROJECT – EXPECTED START UP

 Assuming 9.5 Bcf/d of LNG exports by 2020, the U.S. would be the world’s 3rd largest LNG exporter (behind Qatar and Australia)

− 7.7 Bcf/d (81%) of the 9.5 Bcf/d of expected LNG exports have secured US DOE non-FTA (free trade agreement) permit approval − 6.7 Bcf/d (four projects, 70%) have been awarded FERC construction permits (see next page for more detail)

 The first LNG export project, Sabine Pass LNG Train 1 is expected to commence operations in early 2016

− Antero has committed to 200 MMcf/d on Sabine Pass Trains 1-4

 The second LNG export project, Cove Point LNG, is expected to commence operations in 2017

− Antero has committed to 330 MMcf/d on Cove Point 1-2

19

LNG Exports by Project Through 2020

LNG Exports by Project

(in Bcf/d)

2015 2016 2017 2018 2019 2020 Sabine Pass 1

• 0.6
• Sabine Pass 2
• 0.6
• Sabine Pass 3
• 0.6
• Sabine Pass 4
• 0.6
• Sabine Pass 5
• 0.6
• Cove Point 1
• 0.4
• Cove Point 2
• 0.4
• Cameron 1
• 0.6
• Cameron 2
• 0.6
• Cameron 3
• 0.6
• Freeport 1
• 0.5
• Freeport 2
• 0.5
• Freeport 3
• 0.5
• Freeport 4
• 0.4

Corpus Christi 1

• 0.6
• Corpus Christi 2
• 0.6

Lake Charles 1

• 0.6

LNG Incremental Exports

• 1.2

1.6 2.2 2.9 1.7

Antero Supply Agreements for Portion of Capacity

Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014. Data updated for recent announcements subsequent to Simmons report.

MARCELLUS/UTICA DRIVING GAS SUPPLY GROWTH

 Of the 23 Bcf/d of expected incremental gas supply from 2009 to 2015, ~18 Bcf/d, or 78%, is expected to be generated from Marcellus and Utica production  Marcellus and Utica gross gas production in 2015 is expected to grow 3.6 Bcf/d, which represents the total expected growth in overall supply from all areas for 2015(1)

20

Gas Supply Growth by Area: 2009 – 2015E Lower 48 Gas Supply by Area

Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014; EIA.

• 1. Other contributing areas to growth include the Permian (+0.5 Bcf/d), Eagle Ford (+0.6 Bcf/d), Williston (+0.3 Bcf/d) and DJ (+0.2 Bcf/d), offset by declines in the Barnett (-0.3 Bcf/d)

and Haynesville (-0.6 Bcf/d).

Sherwood 7

Marcellus & Utica 78% Eagle Ford 22% (MMcf/d) 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 Nov-12 Nov-13 Nov-14 Marcellus production has driven U.S. gas supply growth

ASSET OVERVIEW

21

WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT

100% operated Operating 13 drilling rigs including 5 intermediate rigs 394,000 net acres in Southwestern Core (73% includes processable rich gas assuming an 1100 Btu cutoff) – 50% HBP with additional 27% not expiring for 5+ years 362 horizontal wells completed and online – Laterals average 7,400’ – 100% drilling success rate 5 plants in-service at Sherwood Processing Complex capable of processing 1 Bcf/d of rich gas − Over 800 MMcf/d being processed currently Net production of 937 MMcfe/d in 3Q 2014, including 17,300 Bbl/d

• f liquids

3,131 future drilling locations in the Marcellus (2,256 or 72% are processable rich gas) 26.4 Tcfe of net 3P (18% liquids), includes 8.5 Tcfe of proved reserves (assuming ethane rejection)

Highly-Rich Gas 128,000 Net Acres 896 Gross Locations Rich Gas 92,000 Net Acres 633 Gross Locations Dry Gas 105,000 Net Acres 875 Gross Locations Highly-Rich/Condensate 69,000 Net Acres 727 Gross Locations HEFLIN UNIT 30-Day Rate 2H: 21.4 MMcfe/d (21% liquids) CONSTABLE UNIT 30-Day Rate 1H: 14.3 MMcfe/d (26% liquids) 142 Horizontals Completed 30-Day Rate 8.1 MMcf/d 6,915’ average lateral length

Sherwood Processing Complex

Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held. Note: Rates in ethane rejection. NERO UNIT 30-Day Rate 1H: 18.2 MMcfe/d (27% liquids) BEE LEWIS PAD 30-Day Rate 4-well combined 30-Day Rate of 67 MMcfe/d (26% liquids) RJ SMITH PAD 30-Day Rate 4-well combined 30-Day Rate of 56 MMcfe/d (21% liquids)

22

MHR COLLINS UNIT 30-Day Rate 4-well average 9.3 MMcfe/d (26% liquids) HENDERSHOT UNIT 30-Day Rate 1H: 16.3 MMcfe/d 2H: 18.1 MMcfe/d (29% liquids) HORNET UNIT 30-Day Rate 1H: 21.5 MMcfe/d 2H: 17.2 MMcfe/d (26% liquids) CARR UNIT 30-Day Rate 2H: 20.6 MMcfe/d (20% liquids) WAGNER PAD 30-Day Rate 4-well combined 30-Day Rate of 59 MMcfe/d (14% liquids)

$0.0 $0.5 $1.0 $1.5 $2.0 $2.5 $3.0 2,000 4,000 6,000 8,000 10,000 $MM / 1,000' Lateral length, ft

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

Non-SSL Type Curve (1.5 Bcf/1,000') Non-SSL Actual Production Non-SSL Type Curve Cumulative Production SSL Type Curve (1.7 Bcf/1,000') SSL Actual Production SSL Type Curve Cumulative Production

 Antero has over five years of production history to support its Non-SSL type curve  Antero has one and a half years of production history to support its SSL type curve: 1.7 Bcf/1,000’ with only 10% to 15% higher well costs vs. Non-SSL  Lack of faulting and contiguous acreage position allows for drilling of long laterals; ~7,400’ average since inception and ~8,000’ in 2014 − Drives down cost per 1,000’ of lateral resulting in best in class development costs

ANTERO’S MARCELLUS SHALE TYPE CURVE

• 1. 198 Antero Marcellus Non-SSL wells normalized to time zero, production for each well normalized to 8,000’ lateral length.
• 2. 164 Antero Marcellus SSL wells normalized to time zero, production for each well normalized to 8,000’ lateral length.

Marcellus Type Curves – Normalized to 8,000’ Lateral

(1)

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

(2)

Actual Rates 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

Four-Year

• Avg. Rate

Wellhead Gas (MMcf/d) 15.3 9.2 7.1 5.8 4.3 3.2 2.6 1.8 # of Antero Wells 362 343 322 291 227 124 63 24

23

5 10 15 20 25

2,000 4,000 6,000 8,000 10,000 EUR, BCF Lateral Length, ft

 Antero’s Marcellus 30-day rates have increased by 64% over the past two years as the Company increased per well lateral lengths by 20% and shortened stage lengths by 43%

INCREASING RECOVERIES AND LOW VARIANCE IN MARCELLUS

• 1. Processed rates converting C3+ NGLs and condensate at 6:1. Ethane rejected and sold in gas stream.

30-Day Rates – 343 Marcellus Wells(1)

24

SSL Reserves per 1,000’ of Lateral – 164 Marcellus SSL Wells

5 10 15 20 25

MMcfe/d

2014 – 13.1 MMcfe/d 2013 – 9.4 MMcfe/d 2009–2012 – 8.0 MMcfe/d  The Marcellus is a reliable, low risk play as demonstrated by the relatively tight distribution of EURs per 1,000’ and the P10/P90 ratio of 1.5x for 164 SSL wells 5 10 15 20 25 30 35 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2 2.1 2.2 2.3 2.4 2.5 2.6 2.7 > 2.7 Well Count Bcfe/1,000‘ of Lateral 2.0 P10/P90 = 1.5x

1.5 1.6 1.5 1.6 2.0 $0.97 $0.89 $0.98 $1.13 $0.89

$0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 0.00 0.50 1.00 1.50 2.00 2.50 2010 2011 2012 2013 2014

Development Cost ($/Mcfe) EUR/1,000' Lateral

EUR vs. Development Cost

EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe)

25

MARCELLUS WELL PERFORMANCE IMPROVEMENTS

 Increasing recoveries and efficiencies, through longer laterals, shorter stage lengths and faster drilling  SSL completions drove a 21% decline in estimated development costs in 2014 while lower service costs are expected to drive further development cost reductions in 2015

37 36 34 32 29

10 20 30 40 50 2010 2011 2012 2013 2014

Spud-to-Spud Days

Average Spud-to-Spud Days

411 420 361 283 200 14 16 21 27 40

50 100 150 200 250 300 350 400 450 10 20 30 40 50 2010 2011 2012 2013 2014

Average Stage Length (Feet) Average Frac Stages per Well

Increasing Frac Stages per Well

Average Stage Length Average Frac Stages/Well

5,732 6,717 7,345 7,308 8,052 19 38 59 103 136

20 40 60 80 100 120 140 160 2,000 4,000 6,000 8,000 10,000 2010 2011 2012 2013 2014

Wells on First Sales

Lateral Length (1,000 Feet)

Lateral Length Improvements

Lateral Length Wells on First Sales

(2)

• 1. Average vertical length of ~7,300’ drilled for 362 Marcellus wells.
• 2. Based on preliminary reserve and cost estimates for 136 Marcellus wells completed in 2014 subject to completion of year-end reserves and financial audit.

(1)

0% 20% 40% 60% 80% 100% $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 Pre-Tax ROR (%) Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

MARCELLUS ROR% AND GAS PRICE SENSITIVITY

26

• 1. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 8,000’ lateral.

 Large portfolio of Highly-Rich Gas/Condensate to Dry Gas locations  Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime  Assumes 12/31/2014 WTI strip pricing for 2015-2020, flat thereafter; NGL price 55% of WTI

NYMEX Flat Price Sensitivity(1)

ROR% at Flat 2015-2020 Strip Price Highly-Rich Gas/Condensate: 44% Highly-Rich Gas: 30% Rich Gas: 12% Dry Gas: 11% 727 Locations 896 Locations 633 Locations 875 Locations

Antero Rigs Employed 2015 Drilling Plan

Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held. Note: Third party peak rates assume ethane recovery; Antero 30-day rates in ethane rejection.

• 1. For non-Antero wells, 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.

• 2. 30-day rate reflects restricted choke regime.

 100% operated  Operating 8 rigs including 3 intermediate rigs  148,000 net acres in the core rich gas/ condensate window (72% includes processable rich gas assuming an 1100 Btu cutoff) – 20% HBP with additional 79% not expiring for 5+ years  52 operated horizontal wells completed and

• nline in Antero core areas

− 100% drilling success rate 3 plants at Seneca Processing Complex capable

• f processing 600 MMcf/d of rich gas

− Over 500 MMcf/d being processed currently, including third party production  Net production of 143 MMcfe/d in 3Q 2014 including 7,700 Bbl/d of liquids − Seneca 3 processing plant online in July 2014 − Fourth third party compressor station in- service December 2014 with a capacity of 120 MMcf/d  1,112 future gross drilling locations (743 or 67% are processable gas)  6.4 Tcfe of net 3P (13% liquids), includes 537 Bcfe of proved reserves (assuming ethane rejection)

LEADING UTICA SHALE CORE POSITION DELIVERS CONDENSATE AND NGLS

27

Utica Shale Industry Activity(1)

Cadiz Processing Plant NORMAN UNIT 30-Day Rate 2 wells average 20.3 MMcfe/d (17% liquids) RUBEL UNIT 30-Day Rate 3 wells average 21.1 MMcfe/d (24% liquids) 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 GARY UNIT 30-Day Rate 3 wells average 29.8 MMcfe/d (22% liquids) Highly-Rich/Cond 26,000 Net Acres 143 Gross Locations Highly-Rich Gas 15,000 Net Acres 87 Gross Locations Rich Gas 33,000 Net Acres 265 Gross Locations Dry Gas 42,000 Net Acres 369 Gross Locations NEUHART UNIT 3H 30-Day Rate 18.7 MMcfe/d (58% liquids) Condensate 32,000 Net Acres 248 Gross Locations DOLLISON UNIT 1H 30-Day Rate 23.3 MMcfe/d (44% liquids) MYRON UNIT 1H 30-Day Rate 30.4 MMcfe/d (49% liquids) Seneca Processing Complex LAW UNIT 30-Day Rate 2 wells average 18.4 MMcfe/d (50% liquids) SCHAFER UNIT 30-Day Rate(2) 2 wells average 16.2 MMcfe/d (49% liquids) URBAN PAD 30-Day Rate 4-well combined 30-Day Rate of 74 MMcfe/d (16% liquids)

1.4 1.6 $1.64 $1.24 $0.00 $0.30 $0.60 $0.90 $1.20 $1.50 $1.80 0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60 2013 2014

Development Cost ($/Mcfe) EUR/1,000' Lateral

EUR vs. Development Cost

EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe)

28

UTICA WELL PERFORMANCE IMPROVEMENTS

32 29 26 27 28 29 30 31 32 33 2013 2014

Spud-to-Spud Days

Average Spud-to-Spud Days

289 183 26 47

• 50

100 150 200 250 300 350 10 20 30 40 50 60 2013 2014

Average Stage Spacing (FT) Average Frac Stages per Well

Increasing Frac Stages per Well

Average Stage Length Average Frac Stages/Well

 Increasing recoveries and efficiencies, through longer laterals, shorter stage lengths and faster drilling  Lower service costs are expected to drive development cost reductions in 2015

6,431 8,021 11 41

5 10 15 20 25 30 35 40 45 2,000 4,000 6,000 8,000 10,000 2013 2014

Wells on First Sales Lateral Length (Feet)

Lateral Length Improvements

Lateral Length Wells on First Sales

• 1. Average vertical length of ~7,800’ drilled for 53 Utica wells.
• 2. Based on preliminary reserve and cost estimates for 41 Utica wells completed in 2014 subject to completion of year-end reserves and financial audit.

(1) (2)

0% 20% 40% 60% 80% 100% 120% 140% 160% 180% 200% $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 Pre-Tax ROR (%)

Condensate Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

UTICA ROR% AND GAS PRICE SENSITIVITY

29

NYMEX Flat Price Sensitivity(1)

87 Locations ROR% at Flat 2015-2020 Strip Price

Condensate: 13% Highly-Rich Gas/Condensate: 41% Highly-Rich Gas: 63% Rich Gas: 47% Dry Gas: 44%

 Large portfolio of Condensate to Dry Gas locations  Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime  Assumes 12/31/2014 WTI strip pricing for 2015-2020, flat thereafter; NGL price 55% of WTI

• 1. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 8,000’ lateral.

265 Locations 143 Locations 369 Locations 248 Locations

2015 Drilling Plan

LARGE UTICA SHALE DRY GAS POSITION

30

 Antero has 212,000 net acres of exposure to Utica dry gas play − 42,000 net acres in Ohio with net 3P reserves of 1.9 Tcf as of 6/30/2014 − 170,000 net acres in West Virginia and Pennsylvania with net resource of 9.5 Tcf as of 6/30/2014 (not included in 37.5 Tcfe

• f net 3P reserves)

− 1,390 locations underlying current Marcellus Shale leasehold in West Virginia and Pennsylvania as of 9/30/2014  Other operators have reported strong Utica Shale dry gas results including the following wells:

Chesapeake Hubbard BRK #3H 3,550’ Lateral IP 11.1 MMcf/d Hess Porterfield 1H-17 5,000’ Lateral IP 17.2 MMcf/d Gulfport Irons #1-4H 5,714’ Lateral IP 30.3 MMcf/d Eclipse Tippens #6H 5,858’ Lateral IP 23.2 MMcf/d Magnum Hunter Stalder #3UH 5,050’ Lateral IP 32.5 MMcf/d Antero Planned Utica Well 2015

Well Operator IP (MMcf/d) Lateral Length (Ft) Claysville SC #1 Range 59.0 5,420 Stewart Winland 1300U Magnum Hunter 46.5 5,289 Bigfoot 9H Rice Energy 41.7 6,957 Stalder #3UH Magnum Hunter 32.5 5,050 Irons #1-4H Gulfport 30.3 5,714 Pribble 6HU Stone Energy 30.0 3,605 Simms U-5H Gastar 29.4 4,447 Conner 6H Chevron 25.0 6,451 Tippens #6H Eclipse 23.2 5,858 Porterfield 1H-17 Hess 17.2 5,000 Hubbard BRK #3H Chesapeake 11.1 3,550

• 1. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA.

Magnum Hunter Stewart Winland 1300U 5,289’ Lateral IP 46.5 MMcf/d Range Claysville SC #1 5,420’ Lateral IP 59.0 MMcf/d Chevron Conner 6H 6,451’ Lateral IP 25.0 MMcf/d Gastar Simms U-5H 4,447’ Lateral IP 29.4 MMcf/d

Utica Shale Dry Gas Acreage in OH/WV/PA(1)

Rice Bigfoot 9H 6,957’ Lateral IP 41.7 MMcf/d

Utica Shale Dry Gas WV/PA Net Resource 9.5 Tcf 1,390 Gross Locations 170,000 Net Acres Utica Shale Dry Gas Ohio 3P Reserves 1.9 Tcf 369 Gross Locations 42,000 Net Acres Utica Shale Dry Gas Total OH/WV/PA Net Resource 11.4 Tcf 1,759 Gross Locations 212,000 Net Acres

Stone Energy Pribble 6HU 3,605’ Lateral IP 30.0 MMcf/d Chesapeake Utica Well Drilling Rice Blue Thunder 10H, 12H ≈9,000’ Lateral

FRESH WATER DISTRIBUTION SYSTEMS

31

Marcellus Fresh Water Distribution System

• Provides fresh water to support Marcellus well completions
• Year-round water supply sources: Ohio River and local rivers
• Significant growth projected over the next twelve months as summarized

below:

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

• 1. Represents inception to date actuals as of 6/30/2014 and 2014 guidance.
• 2. Estimated fee of $3.50 per barrel at an average of 200,000 Bbls of water per well.

Utica Fresh Water Distribution System

• Provides fresh water to support Utica well completions
• Year-round water supply sources: local reservoirs and rivers
• Significant growth projected over the next twelve months as summarized

below:

Marcellus Water System YE 2014 Buried Water Pipeline (Miles) 107 Fresh Water Storage Impoundments 26 Water Fees per Well ($)(2) $600K - $800K Utica Water System YE 2014 Buried Water Pipeline (Miles) 48 Fresh Water Storage Impoundments 8 Water Fees per Well ($)(2) $600K - $800K

OHIO

Projected Midstream Infrastructure(1) Marcellus Shale Utica Shale Total YE 2014E Cumulative Fresh Water System Capex ($MM) $300 $100 $400 Water Pipelines (Miles) 107 48 155 Water Storage Facilities 26 8 34

• 500,000

1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000 4,500,000

FIRM TRANSPORTATION AND FIRM SALES PORTFOLIO

32

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 – 12/31/2023 EQT 8/1/2012 – 6/30/2025 REX/MGT/ANR 7/1/2014 – 12/31/2034 Tennessee 11/1/2015– 9/30/2030

Mid-Atlantic/NYMEX Gulf Coast Appalachia or Gulf Coast Appalachia Appalachia

ANR 3/1/2015– 2/28/2045

Midwest

Local Distribution 11/1/2015 – 9/30/2037

Gulf Coast

$0.14 $0.17 $0.23 $0.33 $0.11 $0.11 $0.12 $0.13 $0.00 $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 $0.70

2013A 2014E 2015E 2016E

($/MMBtu)

• Wtd. Avg. FT Demand ($/MMBtu)
• Wtd. Avg. FT Commodity/Fuel ($/MMBtu)

All-in Firm Transportation Costs(1)

FIRM TRANSPORTATION REDUCES APPALACHIAN BASIS EXPOSURE

Appalachia 49% Gulf Coast 51%

2013 Firm Transportation(1)(2) 2013 Firm Transportation – 647 MMcf/d Average All-in FT Cost $0.25/MMBtu 2016 Firm Transportation – 3.1 Bcf/d Average All-in FT Cost $0.46/MMBtu

+ $0.18/MMBtu  Antero’s firm transportation (FT) portfolio increases visibility on production growth and increases exposure to Gulf Coast and Midwest pricing, with little incremental cost per Mcf  Reduces weighted average basis by $0.22 per MMBtu compared to 2014 basis (3) – while significantly reducing Appalachian basis exposure

Utilized portion included in cash production expense (fixed cost)

• 1. Assumes full utilization of firm transportation capacity; page 14 assumes Antero targeted production figures.
• 2. Represents accessible firm transportation and sales agreements.
• 3. Based on current strip pricing as at 1/13/2015.

Included in cash production expense (variable cost)

$0.25 $0.28 $0.35 $0.46 2016 Basis(3) TCO – $(0.42)/MMBtu DOM S – $(1.32)/MMBtu 2016 Basis(3) Chicago – $(0.09)/MMBtu 2016 Basis(3) CGTLA – $(0.10)/MMBtu

33

Appalachia 35% Midwest 20% Gulf Coast 45%

500 1,000 1,500 2,000 2,500 3,000 3,500 Firm Transportation / Firm Sales (BBtu/d) Marketable FT (BBtu/d) (3) Risked Gross Gas Production Target (Bbtu/d)

ANTERO FIRM TRANSPORTATION APPROPRIATELY DESIGNED TO ACCOMMODATE GROWTH

34

• 1. Based on production of 1,265 MMcfe/d for 4Q 2014 and 45-50% production growth targets for 2015 and 2016.
• 2. Assumes 1100 BTU residue sales gas.
• 3. Represents excess firm transportation that is deemed marketable to 3rd parties based on a positive differential between the receipt and delivery points of the FT capacity, less variable transport cost.

% FT Utilization (including marketable FT): (BBtu/d)

4Q 2014 2015 2016 Net Production Target (MMcfe/d) (1) 1,265 1,500 2,200 Net Gas Production Target (MMcf/d) 1,082 1,225 1,775 Net Revenue Interest Gross-up 81% 80% 80% Gross Gas Production Target (MMcf/d) 1,336 1,525 2,223 BTU Upgrade (2) x1.100 x1.100 x1.100 Gross Gas Production Target (BBtu/d) 1,469 1,678 2,446 Firm Transportation / Firm Sales (BBtu/d) 1,775 2,225 3,150 Estimated % Utilization of FT/FS 83% 75% 78% Marketable Firm Transport (BBtu/d) (3) 225 325 325 Estimated % Utilization of FT/FS (Including Marketable FT) 95% 88% 87% Cost of Unutilized / Unmarketable FT ($MM) $1.8 $10.8 $21.1 $ / Mcfe of Net Production Target $0.02 $0.02 $0.03

% FT Utilization (including marketable FT): % FT Utilization (including marketable FT):

• Antero’s firm transport (FT) is

well utilized during the forecast period (75% - 83%) − Excess FT for acquisitions and well productivity improvements

• A portion of the excess FT is

highly marketable, further increasing utilization to the 87% - 95% range

• Cost of remaining unutilized

FT is immaterial ($0.02 - $0.03/Mcfe assuming net production target)

• Expect to fully utilize FT

portfolio by 2018

95% 88% 87%

Keys to Execution

Local Presence

• Antero has more than 4,000 employees and contract personnel working full-time

for Antero in West Virginia. 79% of these personnel are West Virginia residents.

• Land office in Ellenboro, WV
• District office in Bridgeport, WV
• 199 (45%) of Antero’s 446 employees are located in West Virginia and Ohio

Safety & Environmental

• Five company safety representatives and 56 safety consultants cover all

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

• 41 person environmental staff plus outside consultants monitor all operations

and perform baseline water well testing Central Fresh Water System & Water Recycling

• Numerous sources of water – built central water system to source fresh water

for completions

• Antero recycled over 80% of its flowback and produced water through the first 9

months of 2014 – no discharge to water treatment plants in West Virginia Natural Gas Vehicles (NGV)

• Antero supported the first natural gas fueling station in West Virginia
• Antero has 30 NGV trucks and plans to continue to convert its truck fleet to NGV

Pad Impact Mitigation

• Closed loop mud system – no mud pits
• Protective liners or mats on all well pads in addition to berms

Natural Gas Powered Drilling Rigs & Frac Equipment

• 11 of Antero’s contracted drilling rigs are currently running on natural gas
• First natural gas powered clean fleet frac crew began operations this summer

Green Completion Units

• All Antero well completions use green completion units for completion flowback,

essentially eliminating methane emissions (full compliance with EPA 2015 requirements) LEED Gold Headquarters Building

• Recently moved into new corporate headquarters in Denver, Colorado that has

been LEED Gold Certified

HEALTH, SAFETY, ENVIRONMENT & COMMUNITY

Antero Core Values: Protect Our People, Communities And The Environment

Strong West Virginia Presence

• 79% of all 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

35

CLEAN FLEET & CNG TECHNOLOGY LEADER

• Antero has contracted for two clean completion

fleets to enhance the economics of its completion

• perations and reduce the environmental impact
• Replaces diesel engines (for pressure pumping)

with electric motors powered by natural gas-fired electric generators

• A clean fleet allows Antero to fuel part of its

completion operations from field gas instead of more expensive diesel fuel. Benefits of using a clean fleet include: − Reduce fuel costs by up to 80% representing cost savings of up to $40,000/day − Reduces NOx and CO emissions by 99% − Eliminates 25 diesel trucks from the roads for an average well completion − Reduces silica dust to levels 90% below OSHA permissible exposure limits resulting in a safer and cleaner work environment − Significantly reduces noise pollution from a well site − Is the most environmentally responsible completion solution in the oil and gas industry

• Additionally, Antero utilizes compressed natural

gas (CNG) to fuel its truck fleet in Appalachia − Antero supported the first natural gas fueling station in West Virginia − Antero has 30 NGV trucks and plans to continue to convert its truck fleet to NGV

36

37

Antero Midstream (NYSE: AM) Asset Overview

• 1. Represents inception to date actuals as of 6/30/2014 and 2H 2014 and next twelve months (NTM) guidance.
• 2. Includes $14.7 million of maintenance capex.

38

• Gathering and compression assets in core of rapidly

growing Marcellus and Utica Shale plays – Acreage dedication of ~411,000 net leasehold acres for gathering and compression services – 100% fixed fee long term contracts

Utica Shale Marcellus Shale

Projected Midstream Infrastructure(1)

Marcellus Shale Utica Shale Total YE 2014E Cumulative Gathering/ Compression Capex ($MM) $850 $350 $1,200 Gathering Pipelines (Miles) 180 85 265 Compression Capacity (MMcf/d) 370

• 370

Condensate Gathering Pipelines (Miles)

• 20

20 NTM (9/30/2015) Gathering/ Compression Capex ($MM)(2) $473 $129 $602 Gathering Pipelines (Miles) 219 108 327 Compression Capacity (MMcf/d) 835

• 835

Condensate Gathering Pipelines (Miles)

• 27

27

Midstream Assets

SUBSTANTIAL INVESTMENT IN MIDSTREAM MLP (NYSE: AM)

ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS

39

• Provides Marcellus gathering and compression

services − Liquids-rich gas is delivered to MWE’s Sherwood Complex for processing

• Significant growth projected over the next twelve

months as set out below:

• Antero sold the Harrison County portion of its gathering

system to a 3rd party midstream company in 2012, which is now recognized as the 3rd Party Gathering and Compression Dedication area

• Development upside as AR continues to drill, step-out

and add acreage

Marcellus Gathering & Compression

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

YE 2014 9/30/2015 Gathering Pipelines (Miles) 180 219 Compression Capacity (MMcf/d) 370 835

WV/PA Utica Dry Gas Gathering & Compression

• Further development upside in 167,000 net acres of

Utica deep rights beneath the Marcellus Shale − Will require a separate dry gas gathering system

40

• Provides Utica natural gas and condensate gathering

services − Liquids-rich gas delivered into MWE’s Seneca Complex for processing − Condensate delivered to centralized stabilization and truck loading facilities

• Significant growth projected over the next twelve

months as set out below:

• Development upside as AR continues to drill, step-out

and add acreage

Utica Gathering

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

ANTERO MIDSTREAM ASSETS – RICH & DRY GAS UTICA

YE 2014 9/30/2015 Gathering Pipelines (Miles) 85 108 Condensate Pipelines (Miles) 20 27

Utica Compression

• Opportunity to build up to ten new compressor stations

that are planned to support AR development over the next several years − Compressor stations are not included in AM NTM forecast

41

APPENDIX

41

PRO FORMA CAPITALIZATION

($ in millions) 9/30/2014 Pro Forma $1.15 Bn AM IPO(4) 9/30/2014 Cash $6 $256 Senior Secured Revolving Credit Facility 1,505 662 6.00% Senior Notes Due 2020 525 525 5.375% Senior Notes Due 2021 1,000 1,000 5.125% Senior Notes Due 2022 1,100 1,100 Net Unamortized Premium 8 8 Total Debt $4,138 $3,295 Net Debt $4,132 $3,039 Minority Interest

• $326

Shareholders' Equity $3,751 $4,372 Net Book Capitalization $7,883 $7,737 Enterprise Value(1) $13,631 $12,788 Financial & Operating Statistics LTM EBITDAX $1,047 $1,047 LQA EBITDAX $1,109 $1,109 LTM Interest Expense(2) $155 $138 Proved Reserves (Bcfe) (6/30/2014) 9,107 9,107 Proved Developed Reserves (Bcfe) (6/30/2014) 2,772 2,772 Credit Statistics Net Debt / LTM EBITDAX 3.9x 2.9x Net Debt / LQA EBITDAX 3.7x 2.7x LTM EBITDAX / Interest Expense 6.8x 7.6x Net Debt / Net Book Capitalization 52.4% 39.3% Net Debt / Proved Developed Reserves ($/Mcfe) $1.49 $1.10 Net Debt / Proved Reserves ($/Mcfe) $0.45 $0.33 Liquidity Credit Facility Commitments(3)(4) $3,000 $4,000 Less: Borrowings (1,505) (662) Less: Letters of Credit (332) (332) Plus: Cash 6 256 Liquidity (Undrawn Credit Facility + Cash) $1,169 $3,262

• 1. Equity valuation based on 262.0 million shares outstanding and a share price of $36.28 as of 1/13/2015. AR enterprise value excludes AM minority interest and cash.
• 2. LTM interest expense adjusted for $1,578 million net proceeds from IPO priced on 10/14/2013 and $1,000 million 5.375% Senior Notes priced on 10/24/2013 net of fees; assumes $525 million 9.375%

Senior Notes, $25 million 9.00% Senior Notes, $140 million 7.25% Senior Notes repaid at 10/31/2013 with residual cash used to repay bank debt. Adjusted for $600 million 5.125% Senior Notes priced

• n 4/23/2014 net of fees; $260 million of 7.25% Senior Notes and $315 million of bank debt repaid. Adjusted for $500 million 5.125% Senior Notes add-on priced on 9/4/2014 at 100.5 net of fees; $496

million of bank debt repaid.

• 3. AR lender commitments under the facility increased to $3.0 billion from $2.5 billion on 10/16/2014; commitments can be expanded to the full $4.0 billion borrowing base upon bank approval. AM credit

facility of $1 billion as of 11/4/2014.

• 4. Pro forma for $1,150 million IPO of 70% post-offering owned Antero Midstream; $843 million of debt repaid, $250 million of cash left at AM and $57 million of transaction expenses. AM $1 billion credit

facility currently undrawn.

42

LOWEST FINDING & DEVELOPMENT COST AMONG U.S. PRODUCERS

43

3-Year All-In F&D Cost – Excluding Revisions ($/Mcfe) through 2013

Source: Credit Suisse research dated 4/28/2014.

 Antero ranks as the most efficient finder and developer of reserves, on a per Mcfe basis, based on a 2011-2013 average all-in F&D cost analysis prepared by Credit Suisse

$10.24 $7.14 $6.68 $5.74 $4.66 $4.66 $4.54 $4.23 $4.01 $3.70 $3.63 $3.28 $3.12 $3.07 $3.05 $3.05 $2.91 $2.91 $2.88 $2.87 $2.78 $2.66 $2.57 $2.40 $2.06 $1.94 $1.74 $1.60 $1.53 $1.26 $1.04 $0.84 $0.79 $0.58 $0 $2 $4 $6 $8 $10 $12 MHR APC GPOR MUR APA MRO WLL FANG KOG CRK EXXI EOX PVA CXO DVN KWK FST DNR NBL EOG CRZO PXD BCEI SD CHK ROSE SFY ATHL EPE REXX SWN PDCE RRC AR

MARCELLUS SINGLE WELL ECONOMICS – IN ETHANE REJECTION

44

DRY GAS LOCATIONS RICH GAS LOCATIONS HIGHLY RICH GAS LOCATIONS

Assumptions

 Natural Gas – 12/31/2014 strip  Oil – 12/31/2014 strip  NGLs – 55% of Oil Price

NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL(2) ($/Bbl) 2015 $3.08 $57 $31 2016 $3.48 $63 $35 2017 $3.77 $67 $37 2018 $3.95 $69 $38 2019+ $4.08 $71 $39

Marcellus SSL Well Economics and Total Gross Locations(1)

Classification Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Modeled BTU 1313 1250 1150 1050 EUR (Bcfe): 17.7 16.2 14.7 13.6 EUR (MMBoe): 2.9 2.7 2.4 2.3 % Liquids: 31% 22% 10% 0% Lateral Length (ft): 8,000 8,000 8,000 8,000 Stage Length (ft): 225 225 225 225 Well Cost ($MM): $10.6 $10.6 $10.6 $10.6 Bcfe/1,000’: 2.2 2.0 1.8 1.7 Pre-Tax NPV10 ($MM): $11.9 $7.4 $0.6 $0.4 Pre-Tax ROR: 42% 28% 12% 11% Net F&D ($/Mcfe): $0.70 $0.77 $0.85 $0.92 Payout (Years): 2.1 3.0 6.6 6.7 Gross 3P Locations(3): 727 896 633 875

• 1. Well economics are based on 12/31/2014 strip differential pricing and related transportation costs. Includes gathering, compression and processing fees.
• 2. Pricing for a 1225 BTU y-grade ethane rejection barrel.
• 3. Undeveloped well locations as of 9/30/2014.

727 896 633 875 42% 28% 12% 11% 200 400 600 800 1,000 0% 15% 30% 45% 60%

Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR Locations ROR

2015 Drilling Plan

248 143 87 265 369 10% 31% 46% 33% 30% 100 200 300 400 0% 15% 30% 45% 60%

Condensate Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR Locations ROR

UTICA SINGLE WELL ECONOMICS – IN ETHANE REJECTION

45

DRY GAS LOCATIONS RICH GAS LOCATIONS HIGHLY RICH GAS LOCATIONS

Utica Well Economics and Gross Locations(1)

Classification Condensate Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Modeled BTU 1275 1235 1215 1175 1050 EUR (Bcfe): 8.3 15.0 22.4 21.2 19.0 EUR (MMBoe): 1.4 2.5 3.7 3.5 3.2 % Liquids 35% 26% 21% 14% 0% Lateral Length (ft): 8,000 8,000 8,000 8,000 8,000 Stage Length (ft): 240 240 240 240 240 Well Cost ($MM): $12.1 $12.1 $12.1 $12.1 $12.1 Bcfe/1,000’: 1.0 1.9 2.8 2.7 2.4 Pre-Tax NPV10 ($MM): $0.0 $7.6 $13.0 $9.1 $8.0 Pre-Tax ROR: 10% 31% 46% 33% 30% Net F&D ($/Mcfe): $1.79 $0.99 $0.67 $0.71 $0.79 Payout (Years): 5.5 1.5 1.1 1.5 2.6 Gross 3P Locations(3): 248 143 87 265 369

• 1. Well economics are based on 12/31/2014 strip differential pricing and related transportation costs. Includes gathering, compression and processing fees.
• 2. Pricing for a 1225 BTU y-grade ethane rejection barrel.
• 3. Undeveloped well locations as of 9/30/2014, adjusted for subsequent 245 gross locations acquired as of 12/31/2014. 3P locations representative of BTU regime; EUR and economics within regime

will vary based on BTU content.

2015 Drilling Plan

Assumptions

 Natural Gas – 12/31/2014 strip  Oil – 12/31/2014 strip  NGLs – 55% of Oil Price

NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL(2) ($/Bbl) 2015 $3.08 $57 $31 2016 $3.48 $63 $35 2017 $3.77 $67 $37 2018 $3.95 $69 $38 2019+ $4.08 $71 $39

3-Year Average Growth – Adjusted Recycle Ratio through 2013 0.0x 2.0x 4.0x 6.0x 4.8x 3.3x 3.5x 2.4x $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $1.15 $1.18 $1.21 $1.60

Other Peers

LOW DEVELOPMENT COST DRIVES BEST IN CLASS RECYCLE RATIOS

46

Source: Proved developed F&D industry data based on company presentations, 10-Ks and press releases. 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 data pro forma for Arkoma and Piceance divestitures in 2012.

3-Year Proved Development Costs ($/Mcfe) through 2013

Antero Appalachia-Focused Peers

Source: Wall Street research. Defined as 2011-2013 average (Cash Operating Netback / PD F&D costs) x (1 + 2013-2015 consensus production CAGR). Antero’s production CAGR based on guidance

• targets. 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 Includes all drilling

and completion costs but excludes land and acquisition costs for all companies.

• 1. Antero data pro forma for Arkoma and Piceance divestitures in 2012.

Antero Appalachia-Focused Peers $/Mcfe Other Peers

CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY

 30 year proved reserve life based on 1H 2014 production annualized  Reserve base provides significant exposure to liquids-rich projects – 3P reserves of over 2.3 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 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)

47

Marcellus – 26.4 Tcfe Utica – 6.4 Tcfe Upper Devonian – 4.6 Tcfe

37.5 Tcfe

Gas – 31.7 Tcf Oil – 86 MMBbls NGLs – 880 MMBbls Marcellus – 31.3 Tcfe Utica – 7.3 Tcfe Upper Devonian – 5.1 Tcfe

43.7 Tcfe

Gas – 29.3 Tcf Oil – 86 MMBbls NGLs – 2,305 MMBbls

15% Liquids 33% Liquids

Moody's S&P

POSITIVE RATINGS MOMENTUM

Moody’s / S&P Historical Corporate Credit Ratings

“We could raise the ratings due to our assessment of an improvement in the company's financial profile. An improvement in the financial profile would include maintaining FFO to debt of greater than 45% and narrowing the amount that the company outspends its cash flows by.”

• S&P Credit Research, September 2014

“An upgrade could be considered if debt / average daily production is sustained below $20,000 per boe and debt / proved-developed reserves is sustained below $8.00 per boe. An upgrade would also be contingent on Antero maintaining unleveraged cash margins greater than $25.00 per boe and retained cash flow to debt over 40%.”

• Moody’s Credit Research, September 2014

Credit Rating (Moody’s / S&P) Ba3 / BB- B1 / B+ B2 / B B3 / B- 9/1/2010 2/24/2011 10/21/2013 9/4/2014 5/31/13 Ba2 / BB Ba1 / BB+ Caa1 / CCC+

(1)

___________________________ 1. Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC.

Baa3 / BBB-

Moody’s Upgrade Criteria S&P Upgrade Criteria

48

9/30/2014

($ in millions)

As At Interest Current Maturity Maturity 09/30/14 Rate Yield (2) (Years) (Date) Senior Secured Revolving Credit Facility $662 2.440% (3) 2.440% (3) 4.6 May-19 6.0% Senior Notes due 2020 525 6.000% 6.204% 6.2 Dec-20 5.375% Senior Notes due 2021 1,000 5.375% 6.102% 7.1 Nov-21 5.125% Senior Notes due 2022 1,100 5.125% 6.201% 8.2 Dec-22 Total Long-Term Debt $3,287 Weighted Average: 4.800% 5.414% 6.8 Jul-21

PRO FORMA OFFERING – BALANCE SHEET POSITIONED FOR LONG-TERM GROWTH

PRO FORMA DEBT MATURI TY PROFI LE (1) PRO FORMA WEI GHTED AVERAGE I NTEREST RATE AND MATURI TY(1)

49

• 1. As of 9/30/2014 per 10-Q; pro forma for $1,150 million AM IPO priced on 11/4/2014; net proceeds of $843 million used to repay the credit facility.
• 2. Current yields of senior notes tranches represent the current yield-to-worst per Bloomberg.
• 3. Represents weighted average interest rate under the revolving credit facility as of 9/30/2014.

Senior Secured Revolving Credit Facility Senior Notes  The recent bond offerings, at progressively lower coupons, have allowed Antero to reduce its cost of debt to approximately 5.0% and enhance liquidity while extending the pro forma average debt maturity to July 2021  Current cost of debt 4.8%, average debt maturity 6.8 years $662 $525 $1,000 $1,100 $0 $200 $400 $600 $800 $1,000 $1,200 2014 2015 2016 2017 2018 2019 2020 2021 2022 ($ in Millions)

Needed to make up for base declines in conventional and GOM production

? ? ?

3,000 Antero Drilling Locations Permian Niobrara Granite Wash Barnett Haynesville

U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE(1)

50

 Low cost, liquids-rich Utica and Marcellus Shales will remain attractive in most commodity price environments Utica Shale SW (Rich) Marcellus Shale

• 1. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI

NE (Dry) Marcellus Shale Eagle Ford Shale

MARCELLUS & UTICA – ADVANTAGED ECONOMICS

LNG EXPORTS BY PROJECT – CURRENT STATUS

51

LNG Exports by Project – Current Status

Sherwood 7

Dates of Key Milestones Send Out Non- DOE Non-FTA FERC FTA Permit Underlying Permit Construction Capacity Gas Demand Project Awarded Approval (Bcf/d) (Bcf/d) Contracts Offtakers Sabine Pass 1-4 05/20/11 04/16/12 2.20 2.42 Fully Subscribed BG, GasNatural Fenosa, Kogas, GAIL Cove Point 09/11/13 09/29/14 0.77 0.85 Fully Subscribed Sumitomo, GAIL, Tokyo Gas Cameron 02/11/14 06/19/14 1.70 1.87 Fully Subscribed Sempra, Misui, Mitsubishi, GDF Suez Freeport 05/17/13 07/30/14 1.40 1.54 Fully Subscribed Osaka Gas, Chubu Electric, BP, Toshiba, SK E&S Lake Charles 08/07/13 Expected 2015 2.00 2.20 Fully Subscribed BG Subtotal 8.07 8.88 Freeport Phase II 11/15/13 Pending 0.40 0.44 Not Subscribed N/A Total 8.47 9.32

Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014. Data updated for recent announcements subsequent to Simmons report.

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, 2014 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates as of June 30, 2014 assume 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, 2014. 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.  “Condensate” refers to gas having a heat content between 1250 BTU and 1300 BTU in the Utica Shale.  “Highly-Rich Gas/Condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1225 BTU and 1250 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 1225 BTU in the Utica Shale.  “Rich Gas” refers to gas having a heat content of between 1100 BTU and 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

52