JP Morgan Global High Yield Conference February 24, 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, 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
CREATING ASSET COVERAGE Antero s proved developed PV-10 of $5.8 billion and proved PV-10 of $11.3 billion at year end 2014, in addition to $1.6 billion of hedge mark-to-market value and $2.6 billion of net MLP equity value (NYSE: AM), provide increasing asset coverage to AR s bondholders and lenders NET PROVED DEVELOPED RESERVES (Bcfe) 5,000 4,000 3,000 2,000 1,000 0 Marcellus Utica 3,803 2,023 933 421 110 2010 2011 2012 2013 2014 (1) (1) (1) NET PROVED DEVELOPED PV-10 ($MM) NET PROVED 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 2,844 677 2010 2011 2012 2013 2014 NET PROVED PV-10 ($MM) (1) (1) (1) $6,000 Marcellus Utica $5,829 $12,000 Marcellus Utica $11,320 $10,000 $4,000 $2,943 $8,000 $6,000 $5,997 $2,000 $0 1. Assumes ethane rejection. $1,004 $626 $172 2010 2011 2012 2013 2014 (1) (1) (1) $4,000 $2,000 $0 $2,264 $1,742 $363 2010 2011 2012 2013 2014 (1) (1) (1) 2
OUTSTANDING 3P RESERVE GROWTH (Tcfe) 45 40 35 30 25 20 15 10 5 0 3P RESERVE GROWTH (1) 35.0 4.2 4.2 5.8 25.0 40.7 4.6 7.6 28.4 2013 2014 Marcellus Utica Upper Devonian Key Drivers 93,000 net acres added in 2014 SSL results Utica results 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) 3P RESERVES BY GEOGRAPHY 2014 (1) Proved Probable Possible 6.3 Tcfe Possible 21.8 Tcfe Probable 12.7 Tcfe Proved Key Drivers SSL results Expanded proved footprint Marcellus Utica 19% Utica 7.6 Tcfe 33.1 Tcfe 81% Marcellus 40.7 Tcfe 3P 1. 2013 and 2014 reserves assuming ethane rejection. 40.7 Tcfe 3P 3
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 - 2014 $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 4
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 Potential to accelerate if TETCO prices improve Completion Deferral Impact on 2016 Production Completion Deferral Impact on Realized Gas Price Gross Wellhead Production (MMcf/d) 500 450 400 350 300 250 200 150 100 50 0 Production From 50 Deferred Completions Jan-16 Mar-16 May-16 Gas Price $/MMBtu $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 BTAX IRR: 39% TETCO Cal 2015: $1.88/MMBtu +$1.39/MMBtu Pickup in Price = 18% BTAX IRR Increase BTAX IRR: 57% CGTLA Cal 2016: $3.27/MMBtu $0.00 2015 2015 2016 2016 2017 TETCO CGTLA 5
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
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 16 14 12 10 8 6 4 2 0 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-10 11.9 Tcfe 28.4 Tcfe $16.8 Bn Net Acres 395,000 Undrilled 3P Locations 3,191 UPPER DEVONIAN SHALE WV/PA UTICA SHALE DRY GAS Net Resource 11.1 Tcf Net Acres 170,000 Undrilled Locations 1,616 Net Proved Reserves 8 Bcfe Net 3P Reserves 4.6 Tcfe Pre-Tax 3P PV-10 NM Undrilled 3P Locations 1,116 1. All net acres allocated to the WV/PA Utica Shale Dry Gas and Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as they are stacked pay formations attributable to the same leasehold. 2. Antero and industry rig locations and rig count as of 2/20/2015 per RigData. 7
GROWTH STRONG TRACK RECORD OPERATED GROSS WELLS COMPLETED AVERAGE NET DAILY PRODUCTION (MMcfe/d) 200 175 150 125 Marcellus Utica Deferred Completions 177 114 180 130 1,800 1,200 Marcellus Utica Guidance 1,007 1,400 100 75 50 25 0 60 38 19 2010 2011 2012 2013 2014 2015E 600 0 522 239 124 30 2010 2011 2012 2013 2014 2015E GROSS LATERAL FEET DRILLED EBITDAX ($MM) 92% Growth 40% Growth Guidance 1,600,000 1,400,000 1,200,000 1,000,000 800,000 600,000 400,000 200,000 0 1,426,309 1,107,000 823,419 440,515 255,257 108,915 2010 2011 2012 2013 2014 2015E $1,400 $1,200 $1,000 $800 $600 $400 $200 $0 $1,149 $649 $285 $160 $28 2010 2011 2012 2013 2014E (1) 1. Per current First Call median estimate from Bloomberg. 8
LAND MOST ACTIVE LAND ORGANIZATION IN APPALACHIA Assembled a 543,000 net acre position in the core of the Marcellus and Utica shale plays over the past 6 years Dec 2008 Dec 2011 Dec 2014 December 2008 Net Acreage 118,000 Net Production (MMcfe/d) NM 3P Reserves (Bcfe) NM 3P PV-10 ($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 21 600,000 500,000 400,000 300,000 200,000 100,000 118,000 118,000 118,000 162,000 Antero Net Acreage 285,000 213,000 189,000 371,000 420,000 450,000 486,000 543,000 0 12/2008 12/2009 6/2010 12/2010 6/2011 12/2011 6/2012 12/2012 6/2013 12/2013 6/2014 12/2014 Utica Marcellus 1. Net daily production for December 2011 and December 2014 is for the fourth quarter, respectively. 9
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
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) $3.8 Billion Valuation (1) Fresh Water Distribution System E&P Assets Gathering Assets Compression Assets Market Valuation of AR Ownership in AM: AR ownership: 69.7% LP Interest = 105.9 million units AM Price per Unit AM Units Owned by AR (MM) AR Value in AM LP Units ($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 1. AR enterprise value excludes AM minority interest and cash. Market values as of 2/20/2015. 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 and 151.9 million AM shares outstanding. 11
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
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 1,000 800 600 400 200 0 $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 1,316 943 780 1,073 818 40 2015 2016 2017 2018 2019 2020 94% 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 $1,250 Pro Forma Liquidity 9/30/2014 1. Reflects weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio. Antero has hedged 3,000 Bbl/d of oil and 23,000 Bbl/d of propane for 2015. 2. As of 12/31/2014. 13
REALIZATIONS HIGHEST REALIZATIONS & MARGINS AMONG LARGE-CAP APPALACHIAN PEERS 3Q & 4Q 2014 Natural Gas Realizations ($/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, 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. 14 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.
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 2017 71% 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% 2015 2015 2016 2016 2017 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 MMBtu/d @ $4.34/MMBtu 40,000 MMBtu/d @ $4.00/MMBtu 380,000 MMBtu/d @ $3.88/MMBtu 510,000 MMBtu/d @ $3.87/MMBtu (3) 230,000 MMBtu/d @ $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 MMBtu/d @ $4.47/MMBtu 170,000 MMBtu/d @ $4.09/MMBtu 170,000 MMBtu/d @ $3.35/MMBtu Wtd. Avg. Basis $(0.18) $(0.20)/MMBtu $(0.07)/MMBtu 330,000 MMBtu/d $(0.25)/MMBtu @ $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 - 9% @ $5.35/MMBtu $(0.83)/MMBtu DOM S - 6% 2017 Hedges 780,000 MMBtu/d @ $4.34/MMBtu 182,500 MMBtu/d @ $4.38/MMBtu 107,500 MMBtu/d @ $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 MMBtu/d @ $4.57/MMBtu 420,000 MMBtu/d @ $4.27/MMBtu 15
ASSET OVERVIEW 16
PREMIER POSITION IN LOW-COST RICH GAS PLAYS WTI Price ($/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) $39 2015 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 $0.00 2015 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 $5.74 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; NGLs at 35% WTI vs. 48%-52% for Antero per guidance. 17
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 628 889 12% 11% Rich Gas ROR Dry Gas 1,200 900 600 300 72% 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% 248 10% Condensate 31% 139 Highly-Rich Gas/ Condensate 46% 94 Highly-Rich Gas Locations 254 289 33% 30% Rich Gas ROR Dry Gas 72% of Utica locations are processable (1100-plus Btu) 300 200 100 0 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 2015-2020, 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. 18
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 7,400 100% 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 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) 19
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 6 SSL Wells Marcellus PDP Locations (As of 12/31/14) (1) 1200-1275 BTU 2.0 Bcfe/1,000 Lateral 60 SSL Wells 1100-1200 BTU 1.8 Bcfe/1,000 Lateral 70 SSL Wells 1. Source: IHS; 3 rd party producing wells include Consol, EQT, Exxon/XTO, Noble, AEP, PDC, Magnum Hunter, Statoil, Chesapeake / SWN. 20
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) 25 2014 13.1 MMcfe/d 20 2013 9.4 MMcfe/d MMcfe/d 15 10 2009 2012 8.0 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/1,000 30 P90: 1.56 Bcfe/1,000 25 P10/P90: 1.5x 20 P90 P10 15 10 5 0 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2.0 2 2.1 2.2 2.3 2.4 2.5 2.6 2.7 > 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 21
MARCELLUS WELL PERFORMANCE IMPROVEMENTS Increasing recoveries and efficiencies through longer laterals, shorter stage lengths and faster drilling SSL completions drove a 19% decline in estimated development cost per unit 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 10,000 8,052 8,400 8,000 7,345 7,308 6,717 136 6,000 5,732 103 4,000 80 59 2,000 38 0 19 2010 2011 2012 2013 2014 2015E Average Lateral Length (Feet) Increasing Drilling Efficiency 50 40 13,181 14,067 14,658 14,607 15,355 30 20 37 36 34 32 29 10 0 2010 2011 2012 2013 2014 Avg Spud-to-Spud Days 1. 2015 reflects Antero guidance per 1/20/2015 press release. (1) 160 140 120 100 80 60 40 20 0 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 450 400 350 300 250 200 150 100 50-2.00 1.80 1.60 1.40 1.20 1.00 0.80 0.60 0.40 0.20 0.00 411 420 14 Increasing Frac Stages per Well 16 361 21 283 27 40 45 200 185 2010 2011 2012 2013 2014 2015E Average Stage Length (Feet) $0.97 1.5 $0.89 1.6 $0.98 1.5 (1) Average Frac Stages per Well EUR vs. Development Cost Per Unit $1.14 1.6 $0.92 1.9 2010 2011 2012 2013 2014 50 45 40 35 30 25 20 15 10 5 - $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe) 22 Average Frac Stages per Well Development Cost ($/Mcfe)
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. 2. 30-day rate reflects restricted choke regime. 23
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 2,000 0 8,700 8,021 6,431 50 41 11 2013 2014 2015E 60 50 40 30 20 10 0 Wells on First Sales Average Stage Length (Feet) 350 300 250 200 150 100 50-289 47 50 183 175 26 2013 2014 2015E 60 50 40 30 20 10 - 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 40 30 20 10 0 Increasing Drilling Efficiency 16,321 18,000 14,643 15,000 12,000 9,000 32 29 6,000 3,000-2013 2014 Spud-to-Spud Days Total Measured Depth (Feet) Total Measured Depth (Feet) EUR/1,000' Lateral 1.60 1.40 1.20 1.00 0.80 0.60 0.40 0.20 0.00 EUR vs. Development Cost Per Unit $1.60 $1.31 1.4 1.5 2013 2014 $1.80 $1.50 $1.20 $0.90 $0.60 $0.30 $0.00 EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe) 24 Development Cost ($/Mcfe) 1. 2015 reflects Antero guidance per 1/20/2015 press release.
SUBSTANTIAL INVESTMENT IN MIDSTREAM MLP (NYSE: AM) Midstream Assets Gathering and compression assets in core of rapidly growing Marcellus and Utica Shale plays Acreage dedication of ~412,000 net leasehold acres for gathering and compression services 100% fixed fee long term contracts Utica Shale Projected Midstream Infrastructure (1) Marcellus Shale Utica Shale Total YE 2014E Cumulative Gathering/ Compression Capex ($MM) $850 $350 $1,200 Gathering Pipelines (Miles) 153 80 233 Compression Capacity (MMcf/d) 375-375 Condensate Gathering Pipelines (Miles) - 16 16 2015 Gathering/Compression Capex Budget ($MM) (2) $256 $182 $438 Gathering Pipelines (Miles) 46 18 64 Compression Capacity (MMcf/d) 425 120 545 Condensate Gathering Pipelines (Miles) - 4 4 Marcellus Shale 1. Represents inception to date actuals as of 6/30/2014, 2014 guidance and 2015 guidance. 2. Includes $12.5 million of maintenance capex at 2015 midpoint guidance. 25
SCALE VS. HIGH YIELD PEERS Enterprise Value ($ Billions) Proved Reserves (Bcfe) $25 $20 $15 $14 BBB/BB B Equity value Net debt 16,000 14,000 12,000 10,000 8,000 12,683 AR, CLR, CRK, PDCE, PQ, PVA, RRC, SM, XEC as of 12/31/2014; All others as of 12/31/2013 $10 6,000 $5 4,000 2,000 $0 CHK CLR CXO AR XEC RRC NFX DNR SM SD QEP PDCE PVA CRK BBG PQ 0 CHK AR RRC CLR QEP SM NFX XEC CXO DNR SD PDCE BBG PVA CRK PQ Daily Production (MMcfe/d) 4Q 2014 EBITDAX ($ Millions) 1,500 1,000 (1) 1,265 AR, CLR, CRK, PDCE, PQ, PVA, RRC, SM, XEC as of 4Q 2014; All others as of 3Q 2014 $1,200 $1,000 $800 CRK, XEC actual as of 4Q 2014; All others per Bloomberg consensus $600 500 $400 $320 $200 0 CHK RRC AR CLR SM XEC QEP NFX CXO SD DNR CRK PDCE PVA PQ BBG Source: Company filings, pro forma for announced acquisitions, divestitures and other capital markets transactions; FactSet as of 2/16/15. Note: AR is pro forma for $1.15bn AM IPO. Reserve figures as of 12/31/14 for Antero, CLR, CRK, PDCE, PQ, PVA, RRC, SM and XEC; Reserve figures as of 12/31/13, pro forma for announced acquisitions and divestitures, for all others; Production figures for 4Q 2014 for Antero, CLR, CRK, PDCE, PQ, PVA, RRC, SM and XEC; Production figures for 3Q 2014 for all others; last-quarter EBITDAX for CRK and XEC represents actuals as of 12/31/14; last-quarter EBITDAX for all others represents 4Q 2014 consensus estimates (per Bloomberg); balance sheet data as of most recent disclosure (12/31/14 figures for CRK and XEC). 1. CHK 3Q 2014 production: 4,354 MMcfe/d. $0 CHK CLR CXO SM QEP NFX XEC DNR AR RRC SD PVA CRK PDCE BBG PQ 26
BALANCE SHEET POSITIONED FOR LONG-TERM GROWTH The recent bond offerings, at progressively lower coupons, have allowed Antero to reduce its cost of debt to under 5.0% and enhance liquidity while extending the pro forma average debt maturity to July 2021 Current cost of debt 4.7%, average debt maturity 6.8 years PRO FORMA WEIGHTED AVERAGE INTEREST RATE AND MATURITY (1) ($ in millions) As Of 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% 5.330% 6.2 Dec-20 5.375% Senior Notes due 2021 1,000 5.375% 5.251% 7.1 Nov-21 5.125% Senior Notes due 2022 1,100 5.125% 5.354% 8.2 Dec-22 Total Long-Term Debt $3,287 Weighted Average: 4.800% 4.732% 6.8 Jul-21 PRO FORMA DEBT MATURITY PROFILE (1) $1,200 $1,000 Senior Secured Revolving Credit Facility Senior Notes $1,000 $1,100 ($ in Millions) $800 $600 $400 $662 $525 $200 $0 2014 2015 2016 2017 2018 2019 2020 2021 2022 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 $843 million used to repay the credit facility. 2. Current yields of senior notes tranches represent the current yield-to-worst per Bloomberg. 3. Represents weighted average interest rate under the revolving credit facility as of 9/30/2014. 27
ANTERO KEY ATTRIBUTES Critical Mass In Two World Class Shale Plays Market Leading Growth and Credit Quality Improvement Industry Leading Capital Efficiency and Recycle Ratio Leader in Northeast Takeaway and Liquids Processing Liquidity and Hedge Position Support High Growth Story Forward Thinking Management Team with a History of Success 28
APPENDIX 29
PRO FORMA CAPITALIZATION ($ 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) $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 6 256 Liquidity (Undrawn Credit Facility + Cash) $1,169 $4,262 1. Equity valuation based on 262.0 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 100.5 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 11/4/2014. 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 $1 billion credit facility currently undrawn. 30
OPERATING DATA VS. HIGH YIELD PEERS 4Q 14 Run-Rate R/P 4Q 14 Production Growth (YoY) 30 20 27.5 BBB/BB B 120% 100% 80% 60% 87% 10 40% 20% 0 AR PDCE RRC BBG CLR DNR PVA SD QEP CXO NFX CRK CHK XEC PQ SM 0% (20%) AR CLR XEC BBG SD RRC NFX SM CXO CHK PQ PDCE PVA DNR QEP CRK 2013 F&D Costs ($/Mcfe) (1) 2011-2013 Drill Bit Reserve Replacement Rate (2) $7 $6 $5 $4 $3 $2 $1 $0 $0.61 AR RRC PDCE BBG SM CLR PQ SD CHK XEC QEP CXO NFX DNR CRK PVA 2000% 1800% 1600% 1400% 1200% 1000% 800% 600% 400% 200% 0% 1,898% AR CLR PDCE RRC SM SD CXO DNR BBG PQ XEC QEP CHK NFX PVA CRK Source: Company filings, pro forma for announced acquisitions, divestitures and other capital markets transactions; FactSet as of 2/16/15. Note: Reserve figures as of 12/31/14 for Antero, CLR, CRK, PDCE, PQ, PVA, RRC, SM and XEC; Reserve figures as of 12/31/13, pro forma for announced acquisitions and divestitures, for all others; Production figures for 4Q 2014 for Antero, CLR, CRK, PDCE, PQ, PVA, RRC, SM and XEC; Production figures for 3Q 2014 for all others. 1. Includes land costs and excludes impact of acquisitions; 2014 F&D figure for Antero 2. Sourced from IHS Herold Global Upstream Performance Review. 31
CREDIT METRICS VS. HIGH YIELD PEERS Total Debt / 2014 Proved Reserves ($/Mcfe) Total Debt / LTM EBITDAX $2.00 $1.60 $1.20 $0.80 $0.40 $0.00 BBB/BB B $0.26 RRC AR PDCE XEC QEP SM CLR CHK NFX PQ CXO BBG DNR SD PVA CRK 4.5x 4.0x 3.5x 3.0x 2.5x 2.0x 1.5x 1.0x 0.5x 0.0x XEC SM QEP CXO NFX CLR RRC CHK PVA PDCE CRK DNR BBG PQ 2.9x AR SD Total Debt / 2014 PD Reserves ($/Mcfe) Net Debt / 4Q 14 Net Production (MMcfe/d) $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 RRC XEC $0.87 AR QEP CHK PDCE SM NFX PQ CXO CLR DNR SD CRK BBG PVA Source: Company filings, pro forma for announced acquisitions, divestitures and other capital markets transactions; FactSet as of 2/16/15. Note: AR is pro forma for $1.15bn AM IPO. Reserve figures as of 12/31/14 for Antero, CLR, CRK, PDCE, PQ, PVA, RRC, SM and XEC; Reserve figures as of 12/31/13, pro forma for announced acquisitions and divestitures, for all others; Production figures for 4Q 2014 for Antero, CLR, CRK, PDCE, PQ, PVA, RRC, SM and XEC; Production figures for 3Q 2014 for all others; LTM / last-quarter EBITDAX for CRK and XEC represents actuals as of 12/31/14; LTM EBITDAX for all others reflects 4Q 2014 consensus estimates (per Bloomberg) ; balance sheet data as of most recent disclosure (12/31/14 figures for CRK and XEC). $10,000 $8,000 $6,000 $4,000 $2,000 $0 2,402 XEC QEP RRC SM AR CHK PDCE NFX PQ CLR CXO BBG CRK DNR SD PVA 32
POSITIVE RATINGS MOMENTUM Moody s / S&P Historical Corporate Credit Ratings Moody s Upgrade Criteria 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 $25.00 per boe and retained cash flow to debt over 40%. - Moody s Credit Research, September 2014 S&P Upgrade Criteria We could raise the ratings due to our assessment of an improvement in the company's financial profile. An improvement in the financial profile would include maintaining FFO to debt of greater than 45% and narrowing the amount that the company outspends its cash flows by. - S&P Credit Research, September 2014 Credit Rating (Moody s / S&P) Baa3 / BBB- Ba1 / BB+ Ba2 / BB Ba3 / BB- B1 / B+ B2 / B B3 / B- Caa1 / CCC+ 9/1/2010 2/24/2011 5/31/13 10/21/2013 9/4/2014 12/31/2014 Moody's S&P (1) 1. Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC. 33
HIGH YIELD TRADING PERFORMANCE VS. PEERS Trading Performance Since February 2014 (YTW) AR 5.125% due 2022 RRC 5.000% due 2023 CXO 5.500% due 2023 DNR 4.625% due 2023 SM 5.000% due 2024 9% 8% 7% 6% 5% 4% 3% Feb-14 May-14 Aug-14 Nov-14 Feb-15 Current Trading Performance Amount Issue Current as of 02/17/15 Implied Current call Next call Next call Issuer Issue type Coupon ($mm) Issue Date Maturity Ratings Price YTW YTW date Tenor price date price Antero Resources Sr Nts 5.125% $1,100 Apr-14 Dec-22 B1 / BB 98.25 5.40% Dec-22 7.8 - Jun-17 103.844 Chesapeake Energy Sr Nts 4.875% 1,500 Apr-14 Apr-22 Ba1 / BB+ 99.75 4.92% Apr-22 7.2 - Apr-17 103.656 Range Resources Sr Sub Nts 5.000% 750 Mar-13 Mar-23 Ba2 / BB+ 101.00 4.81% Mar-21 6.1 - Mar-18 102.500 Concho Resources Sr Nts 5.500% 1,550 Aug-12 Apr-23 Ba3 / BB+ 102.69 4.95% Oct-20 5.6 - Oct-17 102.750 Denbury Resources Sr Sub Nts 4.625% 1,200 Jan-13 Jul-23 B1 / BB 89.75 6.21% Jul-23 8.4 - Jan-18 102.313 Cimarex Sr Nts 4.375% 750 May-14 Jun-24 Ba1 / BB+ 98.00 4.64% Jun-24 9.3 - - - QEP Resources Sr Nts 5.250% 650 Sep-12 May-23 Ba1 / BB+ 96.63 5.77% May-23 8.2 - Feb-23 100.000 SM Energy Sr Nts 5.000% 500 May-13 Jan-24 Ba2 / BB 95.00 5.72% Jan-24 8.9 - Jul-18 102.500 New field Exploration Sr Nts 5.625% 1,000 Jun-12 Jul-24 Ba1 / BBB- 102.75 5.25% Jul-24 9.4 - - - Sandridge Energy Sr Nts 7.500% 825 Aug-12 Feb-23 B2 / B- 71.75 13.36% Feb-23 8.0 - Aug-17 103.750 Petroleum Development Corporation Sr Nts 7.750% 500 Sep-12 Oct-22 B3 / B- 101.00 7.53% Oct-20 5.7 - Oct-17 103.875 Bill Barrett Corp Sr Nts 7.000% 400 Mar-12 Oct-22 B2 / B- 92.00 8.44% Oct-22 7.7 - Oct-17 103.500 Comstock Resources Sr Nts 9.500% 300 May-12 Jun-20 B3 / B- 64.50 20.85% Jun-20 5.3 - Jun-16 104.750 34
LOW DEVELOPMENT COST DRIVES BEST IN CLASS RECYCLE RATIOS 3-Year Proved Development Costs ($/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 2012. 3-Year Average Growth Adjusted Recycle Ratio through 2013 6.0x 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 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. 35
MARCELLUS & UTICA ADVANTAGED ECONOMICS Low cost, liquids-rich Utica and Marcellus Shales will remain attractive in most commodity price environments U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE (1) 3,000 Antero Drilling Locations Needed to make up for base declines in conventional and GOM production Utica Shale SW (Rich) Marcellus Shale Permian NE (Dry) Marcellus Shale??? Eagle Ford Shale Granite Wash Niobrara Barnett Haynesville 1. Source: Credit Suisse report dated January 2014 Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI 36
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 2015-2020, flat thereafter; NGL price 55% of WTI NYMEX Flat Price Sensitivity (1) 100% ROR% at Flat 2015-2020 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. 37
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 2015-2020, flat thereafter; NGL price 55% of WTI NYMEX Flat Price Sensitivity (1) 200% 180% 160% ROR% at Flat 2015-2020 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. 38
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 12/31/2014 170,000 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 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 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 2015 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. 39
FRESH WATER DISTRIBUTION SYSTEMS Projected Midstream Infrastructure (1) Marcellus Shale Utica Shale Total YE 2015E Cumulative Fresh Water System Capex ($MM) $338 $112 $450 Water Pipelines (Miles) 226 90 316 Water Storage Facilities 24 14 38 Marcellus Fresh Water Distribution System Provides fresh water to support Marcellus well completions Year-round water supply sources: Ohio River and local rivers Significant growth projected over the next twelve months as summarized below: Marcellus Water System YE 2015 Water Pipeline (Miles) 49 Fresh Water Storage Impoundments 2 Water Fees per Well ($) (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 and 2015 guidance. 2. Estimated fee of $3.50 per barrel at an average of 200,000 Bbls of water per well. 40
FIRM TRANSPORTATION AND FIRM SALES PORTFOLIO Columbia Tennessee Momentum III EQT REX/MGT/ANR 7/26/2009 9/30/2025 11/1/2015 9/30/2030 9/1/2012 12/31/2023 8/1/2012 6/30/2025 7/1/2014 12/31/2034 ANR 3/1/2015 2/28/2045 Local Distribution 11/1/2015 9/30/2037 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 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 1,000,000 500,000 - 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 41
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 $0.33 2013A 2014E 2015E 2016E Wtd. Avg. FT Demand ($/MMBtu) All-in Firm Transportation Costs (1) $0.28 + $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 12/31/2014. 2016 Basis (3) CGTLA $(0.09)/MMBtu 42