Credit Suisse 20 th Annual Energy Summit February 25, 2015

Transcription

1 Credit Suisse 20 th Annual Energy Summit February 25, 2015

2 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 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, forwardlooking statements contained in this presentation specifically include estimates of the Company s reserves, expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced 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 or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. 1

3 OUTSTANDING RESERVE GROWTH 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 NET PROVED RESERVES (Bcfe) (1) Marcellus Utica 12,683 7,632 4,283 2, P RESERVE GROWTH (1) 2014 RESERVE ADDITIONS 3P reserves increased 16% to 40.7 Tcfe with a PV-10 of $22.8 billion All-in finding and development cost of $0.61/Mcfe for 2014 (includes land) Bottoms-up development cost of $0.98/Mcfe for 2014 Top-down proved developed F&D of $1.15/Mcfe for 2014 (excludes land) Only 66% of 3P Marcellus locations booked as SSL (1.7 Bcf/1,000 type curve) at 12/31/2014 No Utica Shale WV/PA dry gas reserves booked estimated net resource of 11.1 Tcf 3P RESERVES BY VOLUME 2014 (1) (Tcfe) Marcellus Utica Upper Devonian Key Drivers 93,000 net acres added in 2014 SSL results Utica results Proved Probable Possible 6.3 Tcfe Possible 21.8 Tcfe Probable 40.7 Tcfe 3P 12.7 Tcfe Proved , 2013 and 2014 reserves assuming ethane rejection SEC prices were $4.07/MMBtu for natural gas and $81.48/Bbl for oil on a weighted average Appalachian index basis. 2

4 2015 CAPITAL BUDGET On January 20 th, Antero announced its 2015 capital budget of $1.8 billion, a 41% decrease from the final 2014 capital budget of $3.05 billion $3.05 Billion $200 By Segment $450 Land 41% $1.8 Billion New 2015 $50 By Segment $150 Land $2,400 D&C 177 Completions $1,600 D&C 130 Completions Drilling & Completion Water Infrastructure Land By Area Drilling & Completion Water Infrastructure Land By Area 29% Utica 71% Marcellus 41% Utica 59% Marcellus Marcellus Utica Marcellus Utica 3

5 COMPLETION DEFERRALS OPERATIONAL FLEXIBILITY Plan to defer 50 Marcellus well completions into 2016 to achieve higher gas price realizations Regional gathering pipeline expected in-service late 2015 will connect incremental Marcellus production to CGTLA (Gulf Coast) and TCO pricing Results in estimated pre-tax IRR of 57% vs. 39% from 2015 TETCO pricing in first year, excluding sunk drilling costs Potential to accelerate if TETCO prices improve Completion Deferral Impact on 2016 Production Completion Deferral Impact on Realized Gas Price $4.00 $3.50 +$1.39/MMBtu Pickup in Price = 18% BTAX IRR Increase Gross Wellhead Production (MMcf/d) Production From 50 Deferred Completions Jan-16 Mar-16 May-16 Gas Price $/MMBtu $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 BTAX IRR: 39% TETCO Cal 2015: $1.88/MMBtu BTAX IRR: 57% CGTLA Cal 2016: $3.27/MMBtu $ TETCO CGTLA 4

6 ANTERO RESOURCES 2015 GUIDANCE Key Operating & Financial Assumptions Key Variable 2015 Guidance Net Daily Production (MMcfe/d) 1,400 Net Residue Natural Gas Production (MMcf/d) 1,175 Net Liquids Production (Bbl/d) 33,000 Net Oil Production (Bbl/d) 4,000 Natural Gas Realized Price Differential to NYMEX Henry Hub Before Hedging ($/Mcf) $(0.20) - $(0.30) Oil Realized Price Differential to NYMEX WTI Before Hedging ($/Bbl) $(12.00) - $(14.00) NGL Realized Price (% of WTI) 48% - 52% Cash Production Expense ($/Mcfe) (2) $ $1.60 Marketing Expense, Net of Marketing Revenue ($/Mcfe) $ $0.30 G&A Expense ($/Mcfe) $ $0.27 Net Income Attributable to Non-Controlling Interest ($MM) $23 - $27 Operated Wells Completed 130 Average Operated Drilling Rigs 14 Capital Expenditures ($MM) Drilling & Completion $1,600 Water Infrastructure $50 Land $150 Total Capital Expenditures ($MM) $1, Financial assumptions per Company press release dated 1/20/ Includes lease operating expenses, gathering, compression and transportation expenses and production taxes. Excludes net marketing expense. 5

7 LEADING UNCONVENTIONAL BUSINESS MODEL Highest Growth Large Cap E&P Most Active Land Organization in Appalachia 2 3 Most Active Operator in Appalachia 1 Drilling Growth Land 4 Liquids-Rich Largest Liquids-Rich Core Position in Appalachia Highest Realizations and Margins Among Large Cap Appalachian Peers 8 Realizations 7 Premier Appalachian E&P Company Run by Co-Founders Liquidity 6 Takeaway 5 Midstream MLP (NYSE: AM) Highlights Substantial Value in Midstream Business Largest Gas Hedge Position in U.S. E&P + Strong Financial Liquidity Largest Firm Transport and Processing Portfolio in Appalachia 6

8 DRILLING MOST ACTIVE OPERATOR IN APPALACHIA COMBINED TOTAL 12/31/14 RESERVES Assumes Ethane Rejection Net Proved Reserves 12.7 Tcfe Net 3P Reserves 40.7 Tcfe Pre-Tax 3P PV-10 $22.8 Bn Net 3P Reserves & Resource 51.8 Tcfe Net 3P Liquids 1,026 MMBbls % Liquids Net 3P 15% 4Q 2014E Net Production 1,265 MMcfe/d - 4Q 2014E Net Liquids 30,400 Bbl/d Net Acres (1) 543,000 Undrilled 3P Locations 5,331 Rig Count SW Marcellus & Utica (2) UTICA SHALE CORE Operators Net Proved Reserves Net 3P Reserves 758 Bcfe 7.6 Tcfe MARCELLUS SHALE CORE Pre-Tax 3P PV-10 $6.1 Bn Net Acres 148,000 Undrilled 3P Locations 1,024 Net Proved Reserves Net 3P Reserves Pre-Tax 3P PV Tcfe 28.4 Tcfe $16.8 Bn Net Acres 395,000 Undrilled 3P Locations 3,191 UPPER DEVONIAN SHALE WV/PA UTICA SHALE DRY GAS Net Resource 11.1 Tcf Net Acres 170,000 Undrilled Locations 1,616 Net Proved Reserves 8 Bcfe Net 3P Reserves 4.6 Tcfe Pre-Tax 3P PV-10 NM Undrilled 3P Locations 1,116 Note: 2014 SEC prices were $4.07/MMBtu for natural gas and $81.48/Bbl for oil on a weighted average Appalachian index basis. 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. Antero and industry rig locations and rig count as of 2/20/2015 per RigData. 7

9 GROWTH STRONG TRACK RECORD NET PROVED SEC RESERVES (Bcfe) 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 Marcellus Utica 12,683 7,632 4,283 2, (1) (1) (1) OPERATED GROSS WELLS COMPLETED Marcellus Utica Deferred Completions E AVERAGE NET DAILY PRODUCTION (MMcfe/d) 1,800 1, EBITDAX ($MM) $1,400 $1,200 $1,000 $800 $600 $400 $200 $0 124 Marcellus Utica Guidance ,007 1, E $28 $160 $285 92% Growth $649 40% Growth Guidance $1, E (2) , 2013 and 2014 proved reserves assuming ethane rejection. 2. Per current First Call median estimate from Bloomberg. 8

10 LAND MOST ACTIVE LAND ORGANIZATION IN APPALACHIA Assembled a 543,000 net acre position in the core of the Marcellus and Utica shale plays over the past 6 years Dec 2008 Dec 2011 Dec 2014 December 2008 Net Acreage 118,000 Net Production (MMcfe/d) NM 3P Reserves (Bcfe) NM 3P PV-10 ($MM) NM Rigs Running NM December 2011 (1) Net Acreage 213,000 Net Production (MMcfe/d) 167 3P Reserves (Bcfe) 18,400 3P PV-10 ($MM) $9,000 Rigs Running 5 December 2014 (1) Net Acreage 543,000 Net Production (MMcfe/d) 1,265 3P Reserves (Bcfe) 40,700 3P PV-10 ($MM) $22,800 Rigs Running , , , , , , , , , ,000 Antero Net Acreage 285, , , , , , , , / /2009 6/ /2010 6/ /2011 6/ /2012 6/ /2013 6/ /2014 Utica Marcellus 1. Net daily production for December 2011 and December 2014 is for the fourth quarter, respectively. 9

11 LIQUIDS-RICH LARGEST CORE POSITION Antero has the largest liquids-rich core position in Appalachia 371,000 net acres (> 1100 Btu) Source: Core outlines and peer net acreage positions based on peer presentations, news releases and 10-K/10-Qs. 10

12 MIDSTREAM MLP (NYSE: AM) HIGHLIGHTS SUBSTANTIAL VALUE IN MIDSTREAM BUSINESS Corporate Structure Overview (1) Antero Resources Corporation (NYSE: AR) $13.8 Billion Enterprise Value (1) Ba3/BB Corporate Rating 70% Limited Partner Interest = $2.7 Billion Market Valuation (1) $1.5 Billion Derived Valuation (2) $9.6 Billion Implied Valuation (3) Antero Midstream Partners LP (NYSE: AM) $3.8 Billion Valuation (1) Fresh Water Distribution System E&P Assets Gathering Assets Compression Assets MLP Benefits: - Highlights value of Antero Midstream - Funding vehicle to expand midstream business - Liquid asset for Antero Resources Market Valuation of AR Ownership in AM: AR ownership: 69.7% LP Interest = million units AM Price per Unit AM Units Owned by AR (MM) AR Value in AM LP Units ($MMs) Value Per AR Share (4) $ $2,445 $9 $ $2,544 $10 $ $2,647 $10 $ $2,753 $11 $ $2,858 $11 $ $2,964 $12 1. AR enterprise value excludes AM minority interest and cash. Market values as of 2/20/ 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 million AR shares outstanding and million AM shares outstanding. 11

13 TAKEAWAY LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA Antero Long Term Firm Processing & Takeaway Position (2018) Accessing Favorable Markets 4.1 Bcf/d Firm Gas Takeaway By 2018 Chicago (1) +$0.38 / $(0.06) Dom South (1) $(0.73) / $(1.15) Mariner East II 62 MBbl/d Commitment (2) Marcus Hook Export Sabine Pass (Trains 1-4) 50 MMcf/d per Train TCO (1) $(0.10) / $(0.36) Odebrecht / Braskem 30 MBbl/d Commitment Ascent Cracker (Pending Final Investment Decision) Cove Point Shell 25 MBbl/d Commitment Beaver County Cracker (Pending Final Investment Decision) CGTLA (1) $(0.06) / $(0.09) 1. March 2015 and full year 2016 futures basis, respectively, provided by Wells Fargo dated 2/20/2015. 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. 12

14 LIQUIDITY LARGEST GAS HEDGE POSITION IN U.S. E&P + STRONG FINANCIAL LIQUIDITY ~$1.6 billion mark-to-market unrealized gain based on 12/31/2014 prices 1.8 Tcfe hedged from January 1, 2015 through year-end 2020 and 262 Bcf of TCO basis hedges from 2015 to 2017 COMMODITY HEDGE POSITION BBtu/d 1,400 1,200 1, $4.42 $4.47 $4.34 $4.50 $4.41 $4.41 $3.09 Hedged Volume Average Index Hedge Price (1) Current NYMEX Strip (2) $3.48 Mark-to-Market Value (2) $3.77 $3.95 $4.08 $4.21 $689 MM $464 MM $176 MM $214 MM $98 MM $3 MM 1, , % of 2015 Guidance Hedged $/MMBtu $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 Over $4 billion of combined AR and AM financial liquidity as of 9/30/2014, pro forma for AM IPO closed on 11/10/2014 and lender commitment increase on 2/17/2015 AR LIQUIDITY POSITION ($MM) $4,000 $3,500 $3,000 $2,500 $2,000 $1,500 $1,000 $500 $0 $4,000 Credit Facility 9/30/2014 ($1,505) Bank Debt 9/30/2014 ($332) $6 $843 L/Cs Outstanding 9/30/2014 Cash 9/30/2014 AM IPO Proceeds to AR $3,012 Pro Forma Liquidity 9/30/2014 AM LIQUIDITY POSITION ($MM) $3,000 $2,500 $2,000 $1,500 $1,000 $500 $0 $1,000 Credit Facility 9/30/2014 $0 $0 $0 Bank Debt 9/30/2014 L/Cs Outstanding 9/30/2014 Cash 9/30/2014 $250 AM IPO Proceeds to AM $1,250 Pro Forma Liquidity 9/30/ 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 As of 12/31/

15 REALIZATIONS HIGHEST REALIZATIONS & MARGINS AMONG LARGE-CAP APPALACHIAN PEERS 3Q & 4Q 2014 Natural Gas Realizations ($/Mcf) Average NYMEX Price ($/Mcf) Average Differential (1) ($/Mcf) Average BTU Upgrade ($/Mcf) Discount to NYMEX ($/Mcf) Gas Hedge Effect ($/Mcf) Average Realized Gas Price ($/Mcf) Average Realized Gas Premium to Liquids NYMEX Upgrade ($/Mcf) ($/Mcfe) Realized Equivalent Price ($/Mcfe) Gas Equivalent Premium to NYMEX ($/Mcfe) 4Q 2014 $4.00 $(0.71) $0.37 $(0.34) $0.73 $4.39 $0.39 $0.29 $4.68 $0.68 3Q 2014 $4.06 $(0.84) $0.41 $(0.43) $0.68 $4.31 $0.25 $0.60 $4.91 $0.85 Peer Group 3Q 2014 Natural Gas Realizations (3) 3Q 2014 Price Realization & EBITDAX Margin vs F&D (2)(4) $6.00 $6.00 $/Mcf $4.00 $2.00 $4.31 $4.12 3Q 2014 NYMEX = $4.06/Mcf $3.66 $3.62 $3.60 $2.98 $2.87 $2.75 $/Mcfe $5.00 $4.00 $3.00 $2.00 $1.00 $4.96 $2.93 $0.58 $4.48 $2.40 $0.95 $4.16 $3.97 $3.25 $2.64 $2.11 $2.09 $0.74 $0.77 $0.81 $0.00 AR EQT GPOR RRC CNX RICE ECR COG $0.00 Antero AR Peer 11 Peer 2 Peer 3 Peer 4 1. Includes firm sales. LOE Production Taxes GPT G&A EBITDAX 4-year Avg. All-in F&D ($/Mcfe) 2. Price realization includes $0.05 of midstream revenues in 3Q, Includes natural gas hedges. 4. Source: Public data from 3Q Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp. and Range Resources 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 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.

16 REALIZATIONS REALIZED PRICE ROAD MAP Antero s exposure to favorable gas price indices like Chicago, Gulf Coast, NYMEX and TCO is expected to increase to 94% by % exposure to favorable price indices 85% exposure to favorable price indices 94% exposure to favorable price indices Marketed % of Target Residue Gas Production 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Basis (1) 2015E Hedges Basis (1) 2016E Hedges Basis (1) 2017E Wtd. Avg. Basis ($0.46) +$0.05/MMBtu $(0.10)/MMBtu $(0.25)/MMBtu (2) $(0.24)/MMBtu $(1.35)/MMBtu $(1.28)/MMBtu Chicago 21% Gulf Coast 18% NYMEX 8% TCO 24% TETCO M2-7% DOM S 22% ($/Mcf) 2015E NYMEX Strip Price (1) $3.09 Basis Differential to NYMEX (1) $(0.46) BTU Upgrade (6) $0.26 Estimated Realized Hedge Gains $1.35 Realized Gas Price with Hedges $4.24 Premium to NYMEX +$1.15 Liquids Impact +$0.39 Premium to NYMEX w/ Liquids +$1.54 Realized Gas-Equivalent Price $4.63 1,160,000 $4.34/MMBtu 40,000 $4.00/MMBtu 380,000 $3.88/MMBtu 510,000 $3.87/MMBtu (3) 230,000 $5.60/MMBtu Wtd. Avg. Basis $(0.32) $(0.07)/MMBtu $(0.09)/MMBtu $(0.25)/MMBtu (2) $(0.41)/MMBtu $(1.26)/MMBtu $(1.11)/MMBtu Chicago 20% Gulf Coast 38% NYMEX 11% TCO 16% 942,500 $4.47/MMBtu 170,000 $4.09/MMBtu 170,000 $3.35/MMBtu Wtd. Avg. Basis $(0.18) $(0.20)/MMBtu $(0.07)/MMBtu 330,000 MMBtu/d $3.82/MMBtu (4) (2) Chicago 19% Gulf Coast 56% NYMEX 10% TETCO M2-6% 272,500 MMBtu/d $(0.50)/MMBtu TCO - 9% DOM S - $5.35/MMBtu $(0.83)/MMBtu DOM S - 6% 2017 Hedges 780,000 $4.34/MMBtu 182,500 $4.38/MMBtu 107,500 $3.88/MMBtu (5) 1. Based on 12/31/14 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. 4. Represents 60,000 MMBtu/d of TCO index hedges and 270,000 MMBtu/d of TCO basis hedges that are matched with NYMEX hedges for presentation purposes. 5. Represents 107,500 MMBtu/d of TCO basis hedges matched with NYMEX hedges. 6. Assumes ethane rejection resulting in 1100 BTU residue sales gas. 70,000 $4.57/MMBtu 420,000 $4.27/MMBtu 15

17 ASSET OVERVIEW 16

18 PREMIER POSITION IN LOW-COST RICH GAS PLAYS WTI Price ($/Bbl) $100 $80 $60 $40 Over 3,000 of Antero s Marcellus and Utica undeveloped 3P locations are rich gas locations which have the lowest breakeven prices for both oil and natural gas compared to other U.S. shale plays North American Breakeven Oil Prices ($/Bbl) (1) $ WTI Strip: $56.26/Bbl (2) Antero 2015 Drilling Plan $42 $44 $51 $53 $54 Assumes $3.66/MMBtu NYMEX Gas (1) $60 $64 $65 $68 $69 Antero Projects $72 $83 $86 $20 $0 NYMEX Price ($/MMBtu) North American Gas Resource Play Breakeven Natural Gas Price (3) $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $ NYMEX Strip: $3.01/MMBtu (2) Antero 2015 Drilling Plan $1.94 $2.20 $2.20 $2.37 $2.96 $3.13 $3.31 $3.48 Assumes $65/Bbl WTI Oil (3) $3.50 $3.63 $3.77 $3.85 $3.88 $3.98 $4.33 $4.38 $5.56 $5.62 $5.69 $5.71 $ 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 ; $4.23/MMBtu thereafter one year WTI crude oil strip price as of 12/31/14; NYMEX one year natural gas strip price as of 12/31/ 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 ; $70.50/Bbl thereafter; NGLs at 35% WTI vs. 48%-52% for Antero per guidance. 17

19 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 Projected Incremental Natural Gas Demand Through 2020 (Bcf/d) 9.5 Bcf/d of the 20 Bcf/d of 20 incremental demand is expected to come from LNG exports LNG Petrochem Incremental Demand Growth Through 2020 by Category Transportation 1% Industrial 16% Power Generation 17% LNG Exports 48% Sherwood Power Gen Exports Mexico/Canada Exports Power Generation Transportation Petrochem LNG Exports Mexico/Canada Exports 18% Source: Simmons & Company International, 2015 US Natural Gas Outlook and Updated Long Term Demand Forecast, September

20 MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW RISK, HIGH RETURN GROWTH PROFILE Antero is well positioned in the core of the highest return shale projects in the U.S. in the current commodity price environment MARCELLUS SSL WELL ECONOMICS (1) ROR 60% 45% 30% 15% 0% 42% 664 Highly-Rich Gas/ Condensate 1,010 28% Highly-Rich Gas Locations % 11% Rich Gas ROR Dry Gas 1, % of Marcellus locations are processable (1100-plus Btu) Large 3P Drilling Inventory of High Return Projects (2) 3,037 Antero Liquids-Rich Locations 0 Total 3P Locations ROR 2015 Drilling Plan UTICA WELL ECONOMICS (1) 60% 40% 20% 0% % Condensate 31% 139 Highly-Rich Gas/ Condensate 46% 94 Highly-Rich Gas Locations % 30% Rich Gas ROR Dry Gas 72% of Utica locations are processable (1100-plus Btu) Total 3P Locations Internal Rate of Return (%) 40% 30% 20% 10% 0% 31% 26% 26% 20% 16% 15% Antero Projects 1. Pre-tax well economics based on 12/31/2014 natural gas and WTI strip pricing for , flat thereafter, NGLs at 55% of oil price and applicable firm transportation costs; 8,000 lateral. 2. Source: Credit Suisse report dated December 2014 After-tax internal rate of return based on 12/31/2014 strip pricing. 19

21 WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT 100% operated Operating 7 drilling rigs including 3 intermediate rigs 395,000 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, % 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 of liquids 3,191 future drilling locations in the Marcellus (2,302 or 72% are processable rich gas) 28.4 Tcfe of net 3P (17% liquids), includes 11.9 Tcfe of proved reserves (assuming ethane rejection) 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) Highly-Rich/Condensate 69,000 Net Acres 664 Gross Locations CONSTABLE UNIT 30-Day Rate 1H: 14.3 MMcfe/d (25% liquids) Highly-Rich Gas 130,000 Net Acres 1,010 Gross Locations BEE LEWIS PAD 30-Day Rate 4-well combined 30-Day Rate of 67 MMcfe/d (26% liquids) NERO UNIT 30-Day Rate 1H: 18.2 MMcfe/d (27% liquids) Rich Gas 91,000 Net Acres 628 Gross Locations RJ SMITH PAD 30-Day Rate 4-well combined 30-Day Rate of 56 MMcfe/d (21% liquids) HEFLIN UNIT 30-Day Rate 2H: 21.4 MMcfe/d (20% liquids) Sherwood Processing Complex CARR UNIT 30-Day Rate 2H: 20.6 MMcfe/d (20% liquids) Dry Gas 105,000 Net Acres 889 Gross Locations 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. 142 Horizontals Completed 30-Day Rate 8.1 MMcf/d 6,915 average lateral length WAGNER PAD 30-Day Rate 4-well combined 30-Day Rate of 59 MMcfe/d (14% liquids) 20

22 PROLIFIC PREDICTABLE RESULTS ACROSS ENTIRE MARCELLUS POSITION Antero s Marcellus well performance has continued to improve over time with a tight statistical range of results across its entire Marcellus acreage position >1275 BTU 2.2 Bcfe/1,000 Lateral 7 SSL Wells Marcellus PDP Locations (As of 12/31/14) (1) BTU 2.0 Bcfe/1,000 Lateral 72 SSL Wells BTU 1.8 Bcfe/1,000 Lateral 85 SSL Wells 1. Source: IHS; 3 rd party producing wells include Consol, EQT, Exxon/XTO, Noble, AEP, PDC, Magnum Hunter, Statoil, Chesapeake / SWN. 21

23 INCREASING RECOVERIES AND LOW VARIANCE IN MARCELLUS Antero s Marcellus average 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% Antero 30-Day Rates 343 Marcellus Wells (1) MMcfe/d MMcfe/d MMcfe/d MMcfe/d 5 0 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 only 1.5x for 164 SSL wells Antero SSL Reserves per 1,000 of Lateral 164 Marcellus SSL Wells 35 P10: 2.35 Bcfe/1, P90: 1.56 Bcfe/1, P10/P90: 1.5x 20 P90 P > 2.7 Well Count 1. Processed rates converting C3+ NGLs and condensate at 6:1. Ethane rejected and sold in gas stream. Bcfe/1,000 of Lateral 22

24 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 Spud-to-Spud Days Lateral Length (1,000 Feet) Lateral Length Improvements 10, ,052 8, ,000 6,717 7,345 7, ,000 5, , , E Increasing Drilling Efficiency 15,355 13,181 14,067 14,658 14, Avg Spud-to-Spud Days reflects Antero guidance per 1/20/2015 press release. (1) Average Lateral Length (Feet) Wells on First Sales 20,000 16,000 12,000 8,000 4,000 - Total Measured Depth (Feet) Wells on First Sales Total Measured Depth (Feet) Average Stage Length (Feet) EUR/1,000' Lateral Increasing Frac Stages per Well E Average Stage Length (Feet) $ $ $ (1) Average Frac Stages per Well EUR vs. Development Cost per Unit $ $ $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe) 23 Average Frac Stages per Well Development Cost ($/Mcfe)

25 LEADING UTICA SHALE CORE POSITION DELIVERS CONDENSATE AND NGLS 100% operated Operating 7 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 online in Antero core areas 100% drilling success rate 3 plants at Seneca Processing Complex capable of 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 Fourth third party compressor station in-service December 2014 with a capacity of 120 MMcf/d 1,024 future gross drilling locations (735 or 72% are processable gas) 7.6 Tcfe of net 3P (15% liquids), includes 758 Bcfe of proved reserves (assuming ethane rejection) Utica Shale Industry Activity (1) MYRON UNIT 1H 30-Day Rate 26.8 MMcfe/d (52% liquids) NEUHART UNIT 3H 30-Day Rate 16.2 MMcfe/d (57% liquids) LAW UNIT 30-Day Rate 2 wells average 16.1 MMcfe/d (50% liquids) SCHAFER UNIT 30-Day Rate (2) 2 wells average 14.2 MMcfe/d (49% liquids) Seneca Processing Complex DOLLISON UNIT 1H 30-Day Rate 19.8 MMcfe/d (40% liquids) GARY UNIT 30-Day Rate 3 wells average 24.2 MMcfe/d (21% liquids) Utica Core Area NORMAN UNIT 30-Day Rate 2 wells average 16.8 MMcfe/d (15% liquids) Cadiz Processing Plant URBAN PAD 30-Day Rate 4-well combined 30-Day Rate of 75.1 MMcfe/d (15% liquids) RUBEL UNIT 30-Day Rate 3 wells average 17.2 MMcfe/d (20% liquids) Condensate 32,000 Net Acres 248 Gross Locations Highly-Rich/Cond 26,000 Net Acres 139 Gross Locations Highly-Rich Gas 15,000 Net Acres 94 Gross Locations Rich Gas 33,000 Net Acres 254 Gross Locations Dry Gas 42,000 Net Acres 289 Gross Locations 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 day rate reflects restricted choke regime. 24

26 UTICA WELL PERFORMANCE IMPROVEMENTS Increasing recoveries and efficiencies through longer laterals, shorter stage lengths and faster drilling Lower service costs are expected to drive development cost per unit reductions in 2015 Lateral Length Improvements (1) Increasing Frac Stages per Well (1) Lateral Length (Feet) 10,000 8,000 6,000 4,000 2, ,700 8,021 6, E Wells on First Sales Average Stage Length (Feet) E Average Frac Stages per Well Average Lateral Length Wells on First Sales Average Stage Length (Feet) Average Frac Stages per Well Spud-to-Spud Days Increasing Drilling Efficiency 16,321 18,000 14,643 15,000 12,000 9, ,000 3, Spud-to-Spud Days Total Measured Depth (Feet) Total Measured Depth (Feet) EUR/1,000' Lateral EUR vs. Development Cost per Unit $1.64 $ $1.80 $1.50 $1.20 $0.90 $0.60 $0.30 $0.00 EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe) 25 Development Cost ($/Mcfe) reflects Antero guidance per 1/20/2015 press release.

27 LARGE UTICA SHALE DRY GAS POSITION Antero has 212,000 net acres of exposure to Utica dry gas play 42,000 net acres in Ohio with net 3P reserves of 2.4 Tcf as of 12/31/ ,000 net acres in West Virginia and Pennsylvania with net resource of 11.1 Tcf as of 12/31/2014 (not included in 40.7 Tcfe of net 3P reserves) 1,616 locations underlying current Marcellus Shale leasehold in West Virginia and Pennsylvania as of 12/31/2014 Other operators have reported strong Utica Shale dry gas results including the following wells: Well Operator IP (MMcf/d) Claysville SC #1 Range ,420 Stewart Winland 1300U Magnum Hunter ,289 Bigfoot 9H Rice Energy ,957 Stalder #3UH Magnum Hunter ,050 Irons #1-4H Gulfport ,714 Pribble 6HU Stone Energy ,605 Simms U-5H Gastar ,447 Conner 6H Chevron ,451 Tippens #6H Eclipse ,858 Porterfield 1H-17 Hess ,000 Hubbard BRK #3H Chesapeake ,550 Lateral Length (Ft) Utica Shale Dry Gas Acreage in OH/WV/PA (1) Rice Blue Thunder 10H, 12H 9,000 Lateral Gulfport Irons #1-4H 5,714 Lateral IP 30.3 MMcf/d Gastar Simms U-5H 4,447 Lateral IP 29.4 MMcf/d Stone Energy Pribble 6HU 3,605 Lateral IP 30.0 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 Utica Shale Dry Gas Ohio 3P Reserves 2.4 Tcf 289 Gross Locations 42,000 Net Acres Rice Bigfoot 9H 6,957 Lateral IP 41.7 MMcf/d Magnum Hunter Stewart Winland 1300U 5,289 Lateral IP 46.5 MMcf/d Hess Porterfield 1H-17 5,000 Lateral IP 17.2 MMcf/d Utica Shale Dry Gas Total OH/WV/PA Net Resource 13.5 Tcf 1,905 Gross Locations 212,000 Net Acres Chesapeake Hubbard BRK #3H 3,550 Lateral IP 11.1 MMcf/d Chevron Conner 6H 6,451 Lateral IP 25.0 MMcf/d Antero Planned Utica Well Range Claysville SC #1 5,420 Lateral IP 59.0 MMcf/d Chesapeake Utica Well Drilling Utica Shale Dry Gas WV/PA Net Resource 11.1 Tcf 1,616 Gross Locations 170,000 Net Acres 1. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA. 26

28 FRESH WATER DISTRIBUTION SYSTEMS Projected Midstream Infrastructure (1) Marcellus Shale Utica Shale Total YE 2015E Cumulative Fresh Water System Capex ($MM) $338 $112 $450 Water Pipelines (Miles) Water Storage Facilities Marcellus Fresh Water Distribution System Provides fresh water to support Marcellus well completions Year-round water supply sources: Ohio River and local rivers Significant growth projected over the next twelve months as summarized below: Marcellus Water System YE 2015 Water Pipeline (Miles) 49 Fresh Water Storage Impoundments 2 Water Fees per Well ($) (2) $600K - $800K OHIO Utica Fresh Water Distribution System Provides fresh water to support Utica well completions Year-round water supply sources: local reservoirs and rivers Significant growth projected over the next twelve months as summarized below: Utica Water System YE 2015 Water Pipeline (Miles) 29 Fresh Water Storage Impoundments 6 Water Fees per Well ($) (2) $600K - $800K 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, 2014 guidance and 2015 guidance. 2. Estimated fee of $3.50 per barrel at an average of 200,000 Bbls of water per well. 27

29 CATALYSTS Sustainability of Antero s Integrated Business Model Production and Cash Flow Growth Downstream LNG and NGL Sales Midstream MLP Growth Large, low cost core Marcellus and Utica natural gas drilling inventory with associated liquids generates attractive returns supported by longterm natural gas hedges, takeaway portfolio and downstream LNG and NGL sales agreements 40% production growth targeted for 2015 with 94% hedged at $4.42/MMBtu; capital budget flexibility to commodity price changes 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 5 Potential Water System Monetization Contingent on receiving private letter ruling from the IRS, AM holds an option to acquire Antero s fresh water system at fair market value 6 Utica Dry Gas Activity 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 28

30 Antero Midstream (NYSE: AM) Asset Overview 29

31 SUBSTANTIAL INVESTMENT IN MIDSTREAM MLP (NYSE: AM) Midstream Assets Gathering and compression assets in core of rapidly growing Marcellus and Utica Shale plays Acreage dedication of ~412,000 net leasehold acres for gathering and compression services 100% fixed fee long term contracts Utica Shale Projected Midstream Infrastructure (1) Marcellus Shale Utica Shale Total YE 2014E Cumulative Gathering/ Compression Capex ($MM) $850 $350 $1,200 Gathering Pipelines (Miles) Compression Capacity (MMcf/d) Condensate Gathering Pipelines (Miles) Gathering/Compression Capex Budget ($MM) (2) $256 $182 $438 Gathering Pipelines (Miles) Compression Capacity (MMcf/d) Condensate Gathering Pipelines (Miles) Marcellus Shale 1. Represents inception to date actuals as of 6/30/2014, 2014 guidance and 2015 guidance. 2. Includes $12.5 million of maintenance capex at 2015 midpoint guidance. 30

32 HIGH GROWTH THROUGHPUT Low Pressure Gathering (MMcf/d) Compression (MMcf/d) 1,000 Utica Marcellus Marcellus Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q'14 NTM 9/30/15 0 2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM 9/30/15 High Pressure Gathering (MMcf/d) Antero Midstream Partners EBITDA ($MM) (1) Utica Marcellus Midstream EBITDA does not include EBITDA contribution from fresh water distribution 773 2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM 9/30/ $1.4 $5.0 $6.8 $8.4 EBITDA $11.4 $18.8 $ Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM 9/30/15 $ E 31

33 FULL MIDSTREAM VALUE CHAIN POTENTIAL Fresh Water Distribution (1) Well Pad Condensate Gathering (Miles) YE 2014 YE 2015 Utica Low Pressure Gathering (Miles) YE 2014 YE 2015 Stabilization Compression End Users (Miles) YE 2014 YE 2015 Marcellus Utica Total Marcellus Utica (MMcf/d) YE 2014 YE 2015 Marcellus Total Utica Terminals and Storage Total Fractionation Gas Processing End Users NGL Product Pipelines (Ethane, Propane, Butane, etc.) Y-Grade Pipeline End Users AM has option to participate in processing, fractionation, terminaling and storage projects offered to AR Long-Haul Interstate Pipeline AM Owned Assets Inter Connect AM Option Assets (De-ethanization) Unnamed Regional Pipeline Regional Gas Pipelines Miles Capacity In-Service Bcf/d 4Q Currently owned by AR; AM holds option to purchase 100% of assets at fair market value, subject to receiving a private letter ruling from the IRS. 32

34 SIGNIFICANT FINANCIAL FLEXIBILITY Sources & Uses (11/10/2014) Sources ($ in millions) Primary IPO Proceeds $1,150 Total Sources $1,150 Uses Proceeds to AR $843 Proceeds retained by AM 250 AM Liquidity ($ in millions) At IPO (1) Revolver Capacity $1,000 Less: Borrowings - Plus: Cash 250 Liquidity $1,250 Fees & Expenses 57 Total Uses $1,150 Financial Flexibility AM Peer Leverage Comparison (2) Unfunded $1 billion revolver in place at time of IPO to fund future growth capital (5x Debt/EBITDA Cap) No leverage and $230 million of cash at 12/31/2014 provides significant financial flexibility Sponsor (NYSE: AR) has Ba3/BB corporate ratings Debt / LTM EBITDA 6.0x 4.0x 2.0x 0.0x 4.0x 4.1x 3.1x 3.1x 3.3x 3.3x 2.2x 2.4x 1.5x 1.1x 1.3x 0.0x 0.0x 0.1x 1. IPO completed on 11/10/ Peers include ACMP, EQM, MPLX, MWE, OILT, PSXP, QEPM, RRMS, SXL, TEP, TLLP, VLP and WES. 33

35 ANTERO MIDSTREAM 2015 GUIDANCE Key Operating & Financial Assumptions Key Variable 2015 Guidance Adjusted EBITDA ($MM) $150 - $160 Distributable Cash Flow ($MM) $135 - $145 Year-over-Year Distribution Growth 28% - 30% Low Pressure Pipelines Added (Miles) 44 High Pressure Pipelines Added (Miles) 20 Compression Capacity Added (MMcf/d) 545 Capital Expenditures ($MM) Low Pressure Gathering $165 - $170 High Pressure Gathering $85 - $90 Compression $160 - $165 Condensate Gathering $5 - $10 Maintenance Capital $10 - $15 Total Capital Expenditures ($MM) $425 - $ Financial assumptions per Partnership press release dated 1/20/

36 ANTERO MIDSTREAM MLP INVESTMENT HIGHLIGHTS Premier E&P Sponsorship Top Tier MLP Organic Growth Financial Flexibility & Strong Capital Structure Pure Play Marcellus/Utica Midstream MLP Full Midstream Value Chain Potential Best in Class Distribution Growth Expected 35

37 APPENDIX 36

38 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, % Senior Notes Due % Senior Notes Due ,000 1, % Senior Notes Due ,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) $14,669 $13,826 Financial & Operating Statistics LTM EBITDAX $1,047 $1,047 LQA EBITDAX $1,109 $1,109 LTM Interest Expense (2) $155 $138 Proved Reserves (Bcfe) (12/31/2014) 12,683 12,683 Proved Developed Reserves (Bcfe) (12/31/2014) 3,803 3,803 Credit Statistics Net Debt / LTM EBITDAX 3.9x 2.9x Net Debt / LQA EBITDAX 3.7x 2.7x LTM EBITDAX / Interest Expense 6.8x 7.6x Net Debt / Net Book Capitalization 52.4% 39.3% Net Debt / Proved Developed Reserves ($/Mcfe) $1.09 $0.80 Net Debt / Proved Reserves ($/Mcfe) $0.33 $0.24 Liquidity Credit Facility Commitments (3)(4) $3,000 $5,000 Less: Borrowings (1,505) (662) Less: Letters of Credit (332) (332) Plus: Cash Liquidity (Undrawn Credit Facility + Cash) $1,169 $4, Equity valuation based on million shares outstanding and a share price of $40.24 as of 2/20/2015. 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 on 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 net of fees; $496 million of bank debt repaid. 3. AR lender commitments under the facility increased to $4.0 billion from $3.0 billion on 2/17/2015. AM credit facility of $1 billion as of 11/4/ 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. 37

39 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 Keys to Execution Local Presence Safety & Environmental Central Fresh Water System & Water Recycling Natural Gas Vehicles (NGV) Antero has more than 3,500 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 213 (47%) of Antero s 455 employees are located in West Virginia and Ohio Five company safety representatives and 57 safety consultants cover all material field operations 24/7 including drilling, completion, construction and pipelining 37 person environmental staff plus outside consultants monitor all operations and perform baseline water well testing Numerous sources of water built central water system to source fresh water for completions Antero recycled over 74% of its flowback and produced water through 2014 no discharge to water treatment plants in West Virginia 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 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 Pad Impact Mitigation Natural Gas Powered Drilling Rigs & Frac Equipment Green Completion Units LEED Gold Headquarters Building Closed loop mud system no mud pits Protective liners or mats on all well pads in addition to berms 9 of Antero s contracted drilling rigs are currently running on natural gas First natural gas powered clean fleet frac crew began operations summer 2014 All Antero well completions use green completion units for completion flowback, essentially eliminating methane emissions (full compliance with EPA 2015 requirements) Recently moved into new corporate headquarters in Denver, Colorado that has been LEED Gold Certified 38

40 CLEAN FLEET & CNG TECHNOLOGY LEADER Antero has contracted for two clean completion fleets to enhance the economics of its completion operations 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 39

41 LOWEST FINDING & DEVELOPMENT COST AMONG U.S. PRODUCERS Antero ranks as the most efficient finder and developer of reserves, on a per Mcfe basis, based on a average all-in F&D cost analysis prepared by Credit Suisse 3-Year All-In F&D Cost Excluding Revisions ($/Mcfe) through 2013 AR RRC PDCE SWN REXX EPE ATHL SFY ROSE CHK SD BCEI PXD CRZO EOG NBL DNR FST KWK DVN CXO PVA EOX EXXI CRK KOG FANG WLL MRO APA MUR GPOR APC MHR $0.58 $0.79 $0.84 $1.04 $1.26 $1.53 $1.60 $1.74 $1.94 $2.06 $2.40 $2.57 $2.66 $2.78 $2.87 $2.88 $2.91 $2.91 $3.05 $3.05 $3.07 $3.12 $3.28 $3.63 $3.70 $4.01 $4.23 $4.54 $4.66 $4.66 $5.74 $6.68 $7.14 $0 $2 $4 $6 $8 $10 $12 $10.24 Source: Credit Suisse research dated 4/28/

42 LOW DEVELOPMENT COST DRIVES BEST IN CLASS RECYCLE RATIOS 3-Year Proved Development Costs ($/Mcfe) through 2013 $/Mcfe $6.00 $5.00 $4.00 $3.00 Antero Appalachia-Focused Peers Other Peers $2.00 $1.00 $0.00 $1.15 $1.18 $1.21 $1.60 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 Year Average Growth Adjusted Recycle Ratio through x 4.8x Antero Appalachia-Focused Peers Other Peers 4.0x 2.0x 3.5x 3.3x 2.4x 0.0x Source: Wall Street research. Defined as average (Cash Operating Netback / PD F&D costs) x ( 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

43 MARCELLUS ROR% AND GAS PRICE SENSITIVITY 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 , flat thereafter; NGL price 55% of WTI NYMEX Flat Price Sensitivity (1) 100% ROR% at Flat Strip Price 80% 2015 Drilling Plan Highly-Rich Gas/Condensate: 44% Highly-Rich Gas: 30% Rich Gas: 12% Dry Gas: 11% 664 Locations 1,010 Locations Pre-Tax ROR (%) 60% 40% 628 Locations 889 Locations 20% 0% $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas Antero Rigs Employed 1. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 8,000 lateral. 42

44 UTICA ROR% AND GAS PRICE SENSITIVITY 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 , flat thereafter; NGL price 55% of WTI NYMEX Flat Price Sensitivity (1) 200% 180% 160% ROR% at Flat Strip Price Condensate: 13% Highly-Rich Gas/Condensate: 41% Highly-Rich Gas: 63% 94 Locations 289 Locations 140% Rich Gas: 47% 254 Locations Pre-Tax ROR (%) 120% 100% 80% 2015 Drilling Plan Dry Gas: 44% 139 Locations 60% 40% 20% 248 Locations 0% $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 Condensate Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas 1. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 8,000 lateral. 43

45 CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY 35 year proved reserve life based on 2014 production annualized Reserve base provides significant exposure to liquids-rich projects 3P reserves of over 2.5 BBbl of NGLs and condensate in ethane recovery mode; 32% liquids ETHANE REJECTION (1) ETHANE RECOVERY (1) Marcellus 28.4 Tcfe Utica 7.6 Tcfe Upper Devonian 4.6 Tcfe 40.7 Tcfe Marcellus 33.7 Tcfe Utica 8.6 Tcfe Upper Devonian 5.1 Tcfe 47.4 Tcfe Gas 34.5 Tcf Oil 102 MMBbls NGLs 924 MMBbls 15% Liquids Gas 32.0 Tcf Oil 102 MMBbls NGLs 2,459 MMBbls 32% 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. 44

46 FIRM TRANSPORTATION AND FIRM SALES PORTFOLIO Columbia Tennessee Momentum III EQT REX/MGT/ANR 7/26/2009 9/30/ /1/2015 9/30/2030 9/1/ /31/2023 8/1/2012 6/30/2025 7/1/ /31/2034 ANR 3/1/2015 2/28/2045 Local Distribution 11/1/2015 9/30/2037 Firm Sales #1 10/1/ /31/2019 Firm Sales #2 10/1/2011 5/31/2017 Firm Sales #3 1/1/2013 5/31/2022 Antero Transportation Portfolio MMBtu/d 4,500,000 4,000,000 3,500,000 3,000,000 2,500,000 2,000,000 1,500,000 Mid-Atlantic/NYMEX Gulf Coast Midwest Appalachia Appalachia 1,000, ,000 - Gulf Coast Appalachia or Gulf Coast Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 May-18 Jul-18 Sep-18 Nov-18 Jan-19 Mar-19 May-19 Jul-19 Sep-19 Nov-19 Jan-20 Mar-20 May-20 Jul-20 Sep-20 Nov-20 45

47 FIRM TRANSPORTATION REDUCES APPALACHIAN BASIS EXPOSURE 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 $0.28 per MMBtu compared to 2014 basis (3) while significantly reducing Appalachian basis exposure ($/MMBtu) $0.70 $0.60 $0.50 $0.40 $0.30 $0.20 $0.10 $0.00 $0.25 $0.11 $0.11 $0.14 $0.17 $0.12 $0.23 $0.13 $ A 2014E 2015E 2016E Wtd. Avg. FT Demand ($/MMBtu) All-in Firm Transportation Costs (1) $ $0.18/MMBtu $0.35 $0.46 Wtd. Avg. FT Commodity/Fuel ($/MMBtu) Included in cash production expense (variable cost) Utilized portion included in cash production expense (fixed cost) 2013 Firm Transportation 647 MMcf/d Average All-in FT Cost $0.25/MMBtu 2013 Firm Transportation (1)(2) 2016 Basis (3) Chicago $(0.08)/MMBtu 2016 Firm Transportation 3.1 Bcf/d Average All-in FT Cost $0.46/MMBtu 2016 Basis (3) TCO $(0.41)/MMBtu DOM S $(1.11)/MMBtu Gulf Coast 51% Appalachia 49% Midwest 20% Gulf Coast 45% Appalachia 35% 1. Assumes full utilization of firm transportation capacity; page 15 assumes Antero targeted production figures. 2. Represents accessible firm transportation and sales agreements. 3. Based on current strip pricing as at 12/31/ Basis (3) CGTLA $(0.09)/MMBtu 46