Antero Resources (AR) 8-K Regulation FD Disclosure

Exhibit 99.1

Company Overview June 2015

Forward-Looking Statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Resources Corporation and its subsidiaries (collectively, the “Company” or “Antero”) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “estimate,” “project,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include estimates of the Company’s reserves, expectations of plans, strategies, 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, 2014 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, 2014 and in the Company’s subsequent filings with the SEC. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. 1 Antero Resources Corporation is denoted as “AR” and Antero Midstream Partners LP is denoted as “AM” in the presentation, which are their respective New York Stock Exchange ticker symbols.

2 changes since May 2015 presentation Updated AR slide showing 2015 production growth forecast vs. large capitalization E&P industry Slide 6 Updated AR consolidated enterprise value and AM equity value as of 5/29/2015 Slide 11 Updated catalysts slide highlighting receipt of private letter ruling (PLR) by AM for water business Slide 19 Updated SWE slides for new NGL price guidance for 2015 Slides 21, 29, 32, 50, 51 Updated AR NGL price guidance for 2015, including 1Q 2015 actuals Slide 46 Updated AR NGL price realizations and propane hedges as of 6/5/2015 Slide 18 New AR slide showing 3/31/2015 and LTM EBITDAX reconciliation Slide 57

Leadership in Appalachian basin 3 Top Producers in Appalachia (Net MMcfe/d) – 1Q 2015(1)(2) Top 12 U.S. Natural Gas Producers (Net MMcf/d) – 1Q 2015(1) Appalachian Producers by Proved Reserves (Bcfe) – YE 2014(1)(2) Appalachian Producers by Core Net Acres (000’s) – YE 2014(4)(5) Based on company filings and presentations. Appalachian only production and reserves where available. Excludes companies that do not break out Appalachian production including CHK, CVX, HES and XOM. Talisman acquisition by Repsol effective 5/8/2015; production data as of 4Q 2014. Based on Antero geologic interpretation supported by state well data, company presentations and public land data. Peer group includes AEP, CHK, CNX, COG, CVX, EQT, NBL, RICE, RRC, STO, SWN. Southwestern leasehold and reserves include the impact from STO and WPX property acquisitions closed in January 2015. Includes proved reserves categorized in “Northern Division” consisting of Utica Shale, Marcellus Shale and Powder River Basin. (5) (6) (3) 0 500 1,000 1,500 2,000 2,500 3,000 3,500 Appalachian Peers - 100 200 300 400 500 600 Core Net Acres - Dry Core Net Acres - Liquids Rich 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000

4 Most Active Operator in Appalachia Largest Firm Transport and Processing Portfolio in Appalachia Largest Gas Hedge Position in U.S. E&P + Strong Financial Liquidity Highest Growth Large Cap E&P Largest Core Liquids-Rich Position in Appalachia Highest Realizations and Margins Among Large Cap Appalachian Peers Growth Liquids-Rich Hedging & Liquidity Midstream Drilling Leading unconventional business model MLP (NYSE: AM) Highlights Substantial Value in Midstream Business Realizations Takeaway Well Economics 1 2 3 4 5 6 7 8 Premier Appalachian E&P Company Run by Co-Founders Low Break-Even Price Economics

Note: 2014 SEC prices were $4.07/MMBtu for natural gas and $81.48/Bbl for oil on a weighted average Appalachian index basis. 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. Antero and industry rig locations as of 3/27/2015, and average rig count for 1Q 2015, per RigData. Drilling – Most active operator in appalachia 5 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% 1Q 2015 Net Production 1,485 MMcfe/d - 1Q 2015 Net Liquids 40,000 Bbl/d Net Acres(1) 550,000 Undrilled 3P Locations 5,331 UTICA SHALE CORE Net Proved Reserves 758 Bcfe Net 3P Reserves 7.6 Tcfe Pre-Tax 3P PV-10 $6.1 Bn Net Acres 149,000 Undrilled 3P Locations 1,024 MARCELLUS SHALE CORE Net Proved Reserves 11.9 Tcfe Net 3P Reserves 28.4 Tcfe Pre-Tax 3P PV-10 $16.8 Bn Net Acres 401,000 Undrilled 3P Locations 3,191 UPPER DEVONIAN SHALE Net Proved Reserves 8 Bcfe Net 3P Reserves 4.6 Tcfe Pre-Tax 3P PV-10 NM Undrilled 3P Locations 1,116 WV/PA UTICA SHALE DRY GAS Net Resource 11.1 Tcf Net Acres 175,000 Undrilled Locations 1,616 0 2 4 6 8 10 12 14 16 18 Rig Count Operators 1Q 2015 Avg SW Marcellus & Utica (2)

6 Appalachian Peers Source: Represents median of Wall Street research estimates for 2015E production growth vs. 2014 actual production. Includes all North American E&P companies with a market capitalization greater than $9.0 billion. Based on publicly announced 2015 production growth target of 40%+. Antero’s 40%+ production growth target for 2015 leads the U.S. large cap E&P industry(1) Growth – Highest growth large cap E&P (2) 25.1% 24.3% 20.7% 20.0% 19.8% 14.1% 8.9% 8.5% 8.1% 2.5% 0.1% (0.6%) (1.1%) (3.2%) (8.1%) (13.5%) (14.3%) -25% -15% -5% 5% 15% 25% 35% 45% 40%+

Growth – Debt-adjusted per share Production 7 Based on the strength of its drilling program, and focus on the highly prolific Marcellus and Utica Shale core areas, Antero has delivered 51% compounded annual growth in net debt-adjusted production per share since its IPO in October 2013 Antero’s net debt-adjusted production per share growth rate is 12 percentage points higher than the next closest Appalachian peer NOTE: Production/Net Debt-Adjusted Share = total production divided by net debt-adjusted shares outstanding each period. Net debt-adjusted shares = net debt at end of each period/stock price average for each respective period, plus average common shares outstanding each respective period. Peers include CNX, COG, EQT, RRC, SWN. 51% CAGR Since IPO AR Annualized Production / Net Debt-Adjusted Share(1) Mcfe/Share Net Debt-Adjusted Production per Share Growth vs. Peers (2) (Since AR IPO) 0.25 0.50 0.75 1.00 1.25 1.50 4Q '13 1Q '14 2Q '14 3Q '14 4Q '14 1Q '15 51% 39% 33% 25% 10% (7%) -10.0% 0.0% 10.0% 20.0% 30.0% 40.0% 50.0% 60.0% AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

Assumes ethane rejection. Based on Company guidance. 8 AVERAGE NET DAILY PRODUCTION (MMcfe/d) 117% CAGR Growth – Strong track record OPERATED GROSS WELLS COMPLETED 40%+ Growth Guidance NET PROVED RESERVES (Bcfe) AVERAGE NET DAILY LIQUIDS PRODUCTION (Bbl/d) + (2) (2) 0 10,000 20,000 30,000 40,000 2010 2011 2012 2013 2014 2015E NGLs (C3+) Oil 5 246 6,436 23,051 37,000+ 61%+ Growth Guidance 0 600 1,200 1,800 2010 2011 2012 2013 2014 2015E Marcellus Utica Guidance 1,400 30 124 239 522 1,007 0 50 100 150 200 2010 2011 2012 2013 2014 2015E Marcellus Utica Deferred Completions 1 9 38 60 114 177 180 130 (2) 0 3,000 6,000 9,000 12,000 15,000 2010 2011 2012 2013 2014 Marcellus Utica 677 2,844 4,283 7,632 (1) (1) (1) 12,683

9 Liquids-rich – Largest core position Source: Core outlines and peer net acreage positions based on investor presentations, news releases and 10-K/10-Qs. Rig information per RigData as of 3/27/2015. Based on company filings and presentations. Peer group includes AEP, CHK, CNX, COG, CVX, EQT, NBL, RICE, RRC, STO, SWN. Antero has the largest core liquids-rich position in Appalachia with 375,000 net acres (> 1100 Btu) Represents over 21% of core liquids-rich acreage in Marcellus and Utica plays combined 2x its closest competitor Antero has over 3,000 undeveloped rich gas locations with an average lateral length of 6,800’ in its 3P reserves 0 100 200 300 400 (000s) Core Liquids - Rich Net Acres (1)

Well economics – low break-even price economics North American Gas Resource Play Breakeven Natural Gas Price(3) 10 North American Breakeven Oil Prices ($/Bbl)(1) 2015 NYMEX Strip: $3.01/MMBtu(2) 2015 WTI Strip: $56.26/Bbl(2) Marcellus and Utica undeveloped 3P rich-gas locations have the lowest breakeven prices for both oil and natural gas compared to other U.S. shale plays Marcellus – Super Rich Eagle Ford – Liquids Rich Utica – Wet Gas Marcellus – SW Liquids Rich Marcellus – NE Utica Dry Gas Barnett Shale - Core Fayetteville Shale Marcellus Shale - SW Pinedale Horn River Basin Eagle Ford Shale – Dry Gas Cotton Valley Horizontal Utica – Condensate Haynesville Shale – Core LA/TX Piceance Basin Valley Barnett Shale – Liquids Rich Haynesville / Bossier Shale – NE TX Granite Wash – Liquids Rich Horiz. Mississippian Horizontal - West Woodford Shale - Arkoma 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. 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. 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% of WTI vs. Antero guidance of 30%-35% of WTI for 2015-2016 and 50% of WTI for 2017 and thereafter, driven by completion of Mariner East II project expected by year-end 2016. Antero Projects Assumes $3.66/MMBtu NYMEX Gas(1) $39 $42 $44 $51 $53 $54 $60 $64 $65 $68 $69 $72 $83 $86 $0 $20 $40 $60 $80 $100 WTI Price ($/Bbl) Antero 2015 Drilling Plan $1.94 $2.20 $2.20 $2.37 $2.96 $3.13 $3.31 $3.48 $3.50 $3.63 $3.77 $3.85 $3.88 $3.98 $4.33 $4.38 $5.56 $5.62 $5.69 $5.71 $5.74 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 NYMEX Price ($/MMBtu) Antero 2015 Drilling Plan Assumes $65/Bbl WTI Oil (3)

Midstream – mlp (NYSE: AM) highlights substantial value in midstream business AR enterprise value excludes AM minority interest and cash. Market values as of 5/29/2015. Based on 276.8 million AR shares outstanding and 151.9 million AM units outstanding. 11 Antero Resources Corporation (NYSE: AR) $15.1 Billion Enterprise Value(1) Ba2/BB Corporate Rating Antero Midstream Partners LP (NYSE: AM) $4.3 Billion Valuation(1) 70% Limited Partner Interest E&P Assets Gathering Assets Corporate Structure Overview(1) Market Valuation of AR Ownership in AM: AR ownership: 70% LP Interest = 105.9 million units AM Price per Unit AM Units Owned by AR (MM) AR Value in AM LP Units ($MMs) Value Per AR Share(2) $27 106 $2,858 $10 $28 106 $2,964 $11 $29 106 $3,074 $11 $30 106 $3,176 $12 $31 106 $3,282 $12 $32 106 $3,388 $12 Water Business Compression Assets = $3.1 Billion Market Valuation(1) MLP Benefits: - Funding vehicle to expand midstream business - Highlights value of Antero Midstream - Liquid asset for Antero Resources

Takeaway – Largest Firm transportation and processing portfolio in appalachia Odebrecht / Braskem 30 MBbl/d Commitment Ascent Cracker (Pending Final Investment Decision) Antero Long Term Firm Processing & Takeaway Position (2018) – Accessing Favorable Markets Mariner East II 62 MBbl/d Commitment Marcus Hook Export Shell 25 MBbl/d Commitment Beaver County Cracker (Pending Final Investment Decision) Sabine Pass (Trains 1-4) 50 MMcf/d per Train May 2015 and full year 2016 futures basis, respectively, provided by Wells Fargo dated 3/31/2015. Favorable gas markets shaded in green. Chicago(1) $(0.04) / $(0.05) CGTLA(1) $(0.08) / $(0.09) Dom South(1) $(1.09) / $(1.06) TCO(1) $(0.16) / $(0.40) 12 4.1 Bcf/d Firm Gas Takeaway By 2018 Cove Point

Takeaway – NGL Marketing Geographically Diverse As an anchor shipper on Mariner East II, Antero has the right to expand its NGL commitment with notice to operator. 2015 NGL production assumes ethane rejection. 13 (2) Mariner East II 61,500 Bbl/d AR Commitment(1) 4Q 2016 In-Service MarkWest currently processes all of Antero’s rich gas and markets all NGLs 2015 NGL Marketing by Region (2) Export 15% Gulf Coast 13% Mid - Atlantic 6% Ontario 3% Northeast 43% Midwest 10% Edmonton 10%

14 hedging – Integral to business model 14 2Q 2015 – 4Q 2020 hedge gains based on current mark-to-market hedge gains. Based on NYMEX strip as of 3/31/2015. Hedging is a key component of Antero’s business model due to its large, repeatable drilling inventory Antero has realized $1.1 billion of gains on commodity hedges over the past 6 years Gains realized in 24 of last 25 quarters, or 96% of the quarters since 2009 Based on Antero’s hedge position and strip pricing as of 3/31/2015(2), a further $2.2 billion in hedge gains are projected to be realized through the end of 2020 Significant additional hedge capacity remains under the credit facility hedging covenant for 2016 – 2021 period Quarterly Realized Hedge Gains / (Losses)(1) Realized Hedge Gains Projected Hedge Gains(2) NYMEX Natural Gas Historical Spot Prices ($/Mcf) NYMEX Natural Gas Futures Prices (2) 2.4 Tcfe Hedged at average price of $4.20/Mcfe through 2020 $4.42 $4.14 $4.22 $4.40 $4.12 $3.85 Realized $1.1 Billion in Hedge Gains Over Past Six Years $2.2 Billion in Projected Hedge Gains Through 2020(1) Average Hedge Prices ($/Mcfe) $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $0 $50 $100 $150 $200 $250 $MM

15 Liquidity – strong financial liquidity and debt term structure 15 AR LIQUIDITY POSITION ($MM) AM LIQUIDITY POSITION ($MM) Over $3.9 billion of combined AR and AM financial liquidity as of 3/31/2015 No leverage covenant in AR bank facility, only interest coverage and working capital covenants Senior Secured Revolving Credit Facility Senior Notes DEBT MATURITY PROFILE Recent bond and equity offerings have allowed Antero to reduce its cost of debt to 4.8% and significantly enhance liquidity while extending the average debt maturity to October 2021 $1,000 $1,162 $0 $0 $162 $0 $250 $500 $750 $1,000 $1,250 $1,500 Credit Facility 3/31/2015 Bank Debt 3/31/2015 L/Cs Outstanding 3/31/2015 Cash 3/31/2015 Liquidity 3/31/2015 $4,000 $2,759 ($790) ($474) $23 $0 $1,000 $2,000 $3,000 $4,000 Credit Facility 3/31/2015 Bank Debt 3/31/2015 L/Cs Outstanding 3/31/2015 Cash 3/31/2015 Liquidity 3/31/2015 $525 $1,000 $1,100 $750 $0 $200 $400 $600 $800 $1,000 $1,200 2015 2016 2017 2018 2019 2020 2021 2022 2023 ($ in Millions) $790

Region 1Q 2015 % Sales Average NYMEX Price Average Differential(2) Average BTU Upgrade Hedge Effect Average 1Q 2015 Realized Gas Price(3) NYMEX Premium/ Discount TCO 42% $2.98 $(0.22) $0.29 $0.14 $3.19 $0.21 Dom South/TETCO 36% $2.98 $(1.06) $0.20 $0.73 $2.85 $(0.13) Gulf Coast(1) 12% $2.98 $0.06 $0.32 $0.69 $4.05 $1.07 Chicago/Michigan 10% $2.98 $0.37 $0.35 $0.00 $3.70 $0.72 Total Wtd. Avg. 100% $2.98 $(0.43) $0.26 $1.56 $4.37 $1.39 Gulf Coast differential includes contractual deduct to NYMEX-based sales. Includes firm sales. Includes natural gas hedges. Source: Public data from 1Q 2015 10-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 2011-2014. Calculation = (Development costs + exploration costs + leasehold costs) / Total reserves added (2014 ending reserves – 2011 beginning reserves + 4-year reserve sales – 4-year reserve purchases + 4-year accumulated production). AR price realization includes $0.05 of midstream revenues; EBITDAX excludes AR’s midstream EBITDA not attributable to AR’s ownership. 16 realizations – a leader in realizations & margins among large-cap appalachian peers 1Q 2015 Natural Gas Realizations(3)(4) 1Q 2015 Price Realization & EBITDAX Margin vs F&D(4)(5) Liquids Upgrade +0.10/Mcfe(3) 1Q 2015 NYMEX = $2.98/Mcf ($/Mcfe) Antero continues to be a leader in its peer group in price realizations and EBITDAX unit margins 1Q 2015 Natural Gas Realizations ($/Mcf) $2.77 $2.56 $2.10 $1.65 $1.58 $0.88 $0.58 $0.73 $0.72 $0.75 $3.95 $4.47 $3.54 $2.73 $3.56 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 EQT AR RRC COG CNX $/Mcfe Noncontrolling Interest of Midstream MLP EBITDA LOE Production Taxes GPT G&A EBITDAX 4-year Avg. All-in F&D $4.37 $4.10 $3.57 $3.54 $2.46 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 AR EQT CNX RRC COG $/Mcf

($/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 Represents 60,000 MMBtu/d of TCO index hedges and 290,000 MMBtu/d of TCO basis hedges that are matched with NYMEX hedges for presentation purposes. Represents 125,000 MMBtu/d of TCO basis hedges matched with NYMEX hedges. Assumes ethane rejection resulting in 1100 BTU residue sales gas. realizations – realized price “road map” Based on 12/31/2014 strip pricing. Differential represents contractual deduct to NYMEX-based firm sales contract. 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. 2015 Basis(1) 2016 Basis(1) 2017 Basis(1) 2015 Hedges 2016 Hedges 2017 Hedges Marketed % of Target Residue Gas Production +$0.05/MMBtu $(0.25)/MMBtu(2) $(1.28)/MMBtu $(0.24)/MMBtu $(0.07)/MMBtu $(0.25)/MMBtu(2) $(1.11)/MMBtu $(0.41)/MMBtu $(0.20)/MMBtu $(0.25)/MMBtu(2) $(0.83)/MMBtu $(0.50)/MMBtu $(0.09)/MMBtu $(0.07)/MMBtu 285,000 MMBtu/d @ $4.11/MMBtu 125,000 MMBtu/d @ $3.54/MMBtu (5) 40,000 MMBtu/d @ $4.00/MMBtu 230,000 MMBtu/d @ $5.60/MMBtu 510,000 MMBtu/d @ $3.87/MMBtu(3) 170,000 MMBtu/d @ $4.09/MMBtu 272,500 MMBtu/d @ $5.35/MMBtu 350,000 MMBtu/d @ $3.52/MMBtu(4) 85% exposure to favorable price indices 71% exposure to favorable price indices 94% exposure to favorable price indices Antero’s exposure to favorable gas price indices like Chicago, Gulf Coast, NYMEX and TCO is expected to increase to 94% by 2017 $(1.35)/MMBtu $(1.26)/MMBtu Wtd. Avg. Basis ($0.46) Wtd. Avg. Basis $(0.32) 1,160,000 MMBtu/d @ $4.34/MMBtu Wtd. Avg. Basis $(0.18) 1,252,500 MMBtu/d @ $4.15/MMBtu 420,000 MMBtu/d @ $4.27/MMBtu 2015E 2016E 2017E 17 380,000 MMBtu/d @ $3.88/MMBtu 460,000 MMBtu/d @ $3.65/MMBtu 70,000 MMBtu/d @ $4.57/MMBtu 900,000 MMBtu/d @ $4.22/MMBtu $(0.10)/MMBtu Note: Hedge volumes as of 3/31/2015. DOM S 22% DOM S - 9% DOM S - 6% TETCO M2 - 7 % TETCO M2 - 6 % TCO 24 % TCO 16 % TCO - 9 % NYMEX 8% NYMEX 11% NYMEX 10% Gulf Coast 18% Gulf Coast 38% Gulf Coast 56% Chicago 21% Chicago 20% Chicago 19% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

realizations – NGL Realizations and Propane Hedges 18 Based on 2015 NGL and WTI strip prices as of 6/5/2015, net of local transportation. In ethane rejection, a minimal amount of ethane is produced and sold as propane. 2015 NGL% of WTI of 33% represents midpoint of updated 2015 guidance. As of 6/5/2015. Mark-to-market value for 2015 reflects 9 months of hedges from April through December. Realized NGL Prices as % of WTI(1) 2015E NGL Price Road Map(1) (% of NGL Bbl) 57% Propane 11% Iso-Butane 15% Normal Butane 16% Natural Gasoline 1% Ethane 55% 54% 50% 33% ($/Bbl) 70% of 2015 NGL Guidance Hedged NGL Marketing Propane Hedges Mark-to-Market Value(4) (Bbl/d) ($/Gal) Realized NGL (C3+) price was 50% of WTI in 2014 and Antero is forecasting 30% to 35% of WTI for 2015 1Q 2015 NGL realizations were 50% of WTI Including propane hedges, 1Q 2015 realizations were 54% of WTI MarkWest is managing NGL volume growth in the northeast by moving 57% of the volumes out of the region, mostly by rail and ship Antero has hedged significant propane volumes in 2015 and 2016 By late 2016, Antero will market a significant portion of its NGL volumes out of Marcus Hook to export markets once Mariner East II is in service 61,500 Bbl/d firm commitment with expansion rights $24 MM $49 MM (3) (3) (2) (1) (1) 0.016146 BTU Strip as of % of Mont Belvieu Pricing ($/Gal) Factor 5/29/2015 2015E Jan. Sales Total Utica Marcellus Combined 2012 2013 2014 2015 YTD 2012 2013 2014 2015 YTD 15.17 $0.17 Ethane 1% 0.2821406 $0.08 6,853 0.7% 221 1.5% 1.1% 1.2% Propane 58.9% 58.9% 58.0% 58% $0.89 $1.00 $1.04 $0.28 $3.10 11.004 $3.10 $0.28 Propane 57% 0.2821406 $6.75 576,198 57.0% 18,587 46.2% 57.4% 55.1% Iso Butane 9.8% 9.8% 10.4% 11% $1.82 $1.43 $1.25 $0.45 98924 $4.60 10.11 $5.00 $0.45 Iso-Butane 11% 0.4547995 $2.06 109,268 10.8% 3,525 14.0% 9.0% 10.0% Normal Butane 15.3% 15.3% 15.6% 16% $1.61 $1.36 $1.19 $0.35 $3.44 9.71 $3.90 $0.35 Normal Butane 15% 0.3541719 $2.23 157,715 15.6% 5,088 13.0% 15.8% 15.2% Natural Gasoline 16% 16% 16% 16% $2.15 $2.13 $1.98 $1.07 9784.768 $9.29 8.7 $11.74 $1.07 Pentanes Plus 16% 1.0675078 $7.15 161,174 15.9% 5,199 25.3% 16.8% 18.5% Total 100% 100% 100% 100% 647% 592% 546% 216% 99% 18.27406 1,011,208 100.0% 8695.652 Adj. Factor: 0.0% % of Total Prod 20% 80% 0.352917 Historical NGL Realizations MB Realized NGL Price WTI Pricing 0.2 2012 $52.07 $42.03 54.25016 -4.0% 2013 $52.61 $45.40 53.71235 -2.1% 2014 $46.23 $46.80 51.98466 -11.1% Wtd. Avg. 2015 $18.27 $33.51 18.31739 -0.2% Mont Belvieu NGL Strip Net of Transportation % of C3+ Price Per ($/gal) ($/Bbl) Barrel Barrel Ethane (2) $0.28 $11.85 1% $0.08 Propane $0.28 $11.85 57% $6.75 Iso-Butane $0.45 $19.10 11% $2.06 Normal Butane $0.35 $14.88 15% $2.23 Natural Gasoline $1.07 $44.84 16% $7.15 Wtd. Average NGL Barrel: $18.27 2015 WTI Strip: $55.79 NGL Barrel as % of WTI: 33% % of WTI WTI 2012 55% 52.07 $94.10 2013 54% 52.61 $98.01 2014 50% 46.23 $93.03 2015E 50% 18.27406 $51.78 Realized NGL C3+ Price WTI 2012 AR NGL Pricing $52.07 $42.03 Mont Belvieu $54.25 2013 AR NGL Pricing $52.61 $45.40 50 Mont Belvieu $53.71 2014 AR NGL Pricing $46.23 $46.80 Mont Belvieu $51.98 50 2015E AR NGL Pricing $18.27 $33.51 Mont Belvieu $18.32 50 $0.61 $0.58 $0.43 $0.53 $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 $0.70 0 5,000 10,000 15,000 20,000 25,000 30,000 9 Mths 2015 2016 Hedged Volume Average Hedge Price Strip (6/5/2015) $52.07 $54.25 $52.61 $53.71 $46.23 $51.98 $18.27 $26.24 $94.10 $98.01 $93.03 $55.79 $0 $20 $40 $60 $80 $100 $120 AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu 2012 2013 2014 2015E Realized NGL C3+ Price WTI 0% 20% 40% 60% 80% 100% 2015E 55% 54% 50% 50% 0% 10% 20% 30% 40% 50% 60% 2012 2013 2014 2015E 16% 15% 11% 57% 1% 0% 20% 40% 60% 80% 100% 2015E Ethane Propane Iso-Butane Normal Butane Pentanes Plus $52.07 $52.61 $46.23 $18.27 $94.10 $98.01 $93.03 $51.78 $0 $20 $40 $60 $80 $100 $120 2012 2013 2014 2015 Realized NGL Price WTI

Downstream LNG and NGL Sales Production and Cash Flow Growth 19 Antero has 175,000 net acres in WV and PA prospective for Utica dry gas – adjacent to current industry activity with highly encouraging initial results catalysts 40%+ production growth targeted for 2015 with 94% hedged at $4.42/MMBtu; capital budget flexibility to commodity price changes Large, low cost core Marcellus and Utica natural gas drilling inventory with associated liquids generates attractive returns supported by long-term natural gas hedges, takeaway portfolio and downstream LNG and NGL sales agreements Pursuing additional value enhancing long-term LNG and NGL sales agreements, supported by firm takeaway Antero owns 70% of Antero Midstream Partners and thereby participates directly in its growth and value creation Midstream MLP Growth Sustainability of Antero’s Integrated Business Model Potential Water Business Monetization 1 2 3 4 5 6 AM received private letter ruling (PLR) and holds option to acquire AR’s water business at fair market value Utica Dry Gas Activity

Sector positioning 20

MARCELLUS WELL ECONOMICS(1) Marcellus Shale – SW Liquids-Rich Marcellus Shale – SW Dry Gas Utica Shale – Rich Gas Marcellus Shale – Super-Rich Utica Shale – Condensate Multi-Year Drilling Inventory Supports Low Risk, High Return Growth Profile Large 3P Drilling Inventory of High Return Projects(2) Pre-tax well economics based on a 9,000’ lateral, 12/31/2014 natural gas and WTI strip pricing for 2015-2024, flat thereafter, NGLs at 32.5% of WTI for 2015–2016 and 50% of WTI thereafter, and applicable firm transportation and operating costs. Well costs are current estimates and include $1.2 million of pad, road and location costs, as well as the cost of production facilities. Source: Credit Suisse report dated December 2014 – After-tax internal rate of return based on 12/31/2014 strip pricing. 26% 26% 31% 15% Internal Rate of Return (%) 20% 21 UTICA WELL ECONOMICS(1) 72% of Marcellus locations are processable (1100-plus Btu) 72% of Utica locations are processable (1100-plus Btu) 3,037 Antero Liquids-Rich Locations Utica Shale – Dry Gas 16% 2015 Drilling Plan Antero Projects Antero has over 3,000 undrilled liquids-rich Marcellus and Utica locations with an average lateral length of 6,800 feet 0% 10% 20% 30% 40% 248 139 94 254 289 13% 34% 45% 36% 39% 0 100 200 300 0% 20% 40% 60% Condensate Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR Locations ROR 664 1,010 628 889 37% 27% 14% 15% 0 300 600 900 1,200 0% 15% 30% 45% 60% Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR Locations ROR

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, 6.7 Bcf/d (or 70%) of the projects have secured the necessary DOE and FERC permits 22 Incremental Demand Growth Through 2020 by Category Projected Incremental Natural Gas Demand Through 2020 Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014. Sherwood 7 9.5 Bcf/d of the 20 Bcf/d of incremental demand is expected to come from LNG exports (Bcf/d) LNG Exports Power Gen Petrochem LNG Exports 48% Mexico/Canada Exports 18% Power Generation 17% Transportation 1% Industrial 16% 2 5 9 13 17 20 0 4 8 12 16 20 2015 2016 2017 2018 2019 2020 Mexico/Canada Exports Power Generation Transportation Petrochem LNG Exports

LNG Exports by Project – Expected Start UP Assuming 9.5 Bcf/d of LNG exports by 2020, the U.S. will be the world’s 3rd largest LNG exporter behind Qatar and Australia 7.7 Bcf/d (81%) of the 9.5 Bcf/d of expected LNG exports have secured US DOE non-FTA (Free Trade Agreement) permit approval 6.7 Bcf/d (four projects, 70%) have been awarded FERC construction permits The first LNG export project, Sabine Pass LNG Train 1, is expected to commence operations in early 2016 Antero has committed to 200 MMcf/d on Sabine Pass Trains 1-4 The second LNG export project, Cove Point LNG, is expected to commence operations in mid-2017 Antero has committed to 330 MMcf/d on Cove Point 1 & 2 23 LNG Exports by Project Through 2020 Antero Supply Agreements for Portion of Capacity Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014. Note: Data updated for recent announcements subsequent to Simmons report. Antero Supplied LNG Exports by Project (in Bcf/d) 2015 2016 2017 2018 2019 2020 Total Sabine Pass 1 - 0.6 - - - - Sabine Pass 2 - 0.6 - - - - Sabine Pass 3 - - 0.6 - - - Sabine Pass 4 - - 0.6 - - - Sabine Pass 5 - - - - 0.6 - 3.0 Cove Point 1 - - 0.4 - - - Cove Point 2 - - - 0.4 - - 0.8 Cameron 1 - - - 0.6 - - Cameron 2 - - - 0.6 - - Cameron 3 - - - - 0.6 - 1.8 Freeport 1 - - - 0.5 - - Freeport 2 - - - - 0.5 - Freeport 3 - - - - 0.5 - Freeport 4 - - - - - 0.4 2.1 Corpus Christi 1 - - - - 0.6 - Corpus Christi 2 - - - - - 0.6 1.2 Lake Charles 1 - - - - - 0.6 0.6 LNG Incremental Exports - 1.2 1.6 2.2 2.9 1.7 LNG Cumulative Exports - 1.2 2.8 5.0 7.9 9.5

Asset Overview 24

World Class Marcellus shale Development Project 100% operated Operating 7 drilling rigs including 2 intermediate rigs 401,000 net acres in Southwestern Core (74% includes processable rich gas assuming an 1100 Btu cutoff) 50% HBP with additional 29% not expiring for 5+ years 400 horizontal wells completed and online Laterals average 7,500’ 100% drilling success rate 5 plants in-service at Sherwood Processing Complex capable of processing in excess of 1 Bcf/d of rich gas Over 1 Bcf/d of Antero gas being processed currently Net production of 1,211 MMcfe/d in 1Q 2015, including 28,700 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) Highly-Rich Gas 133,000 Net Acres 1,010 Gross Locations Rich Gas 92,000 Net Acres 628 Gross Locations Dry Gas 104,000 Net Acres 889 Gross Locations Highly-Rich/Condensate 72,000 Net Acres 664 Gross Locations HEFLIN UNIT 30-Day Rate 2H: 21.4 MMcfe/d (20% liquids) CONSTABLE UNIT 30-Day Rate 1H: 14.3 MMcfe/d (25% liquids) 142 Horizontals Completed 30-Day Rate 8.1 MMcf/d 6,915’ average lateral length Sherwood Processing Complex Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held. Note: Rates in ethane rejection. NERO UNIT 30-Day Rate 1H: 18.2 MMcfe/d (27% liquids) BEE LEWIS PAD 30-Day Rate 4-well combined 30-Day Rate of 67 MMcfe/d (26% liquids) RJ SMITH PAD 30-Day Rate 4-well combined 30-Day Rate of 56 MMcfe/d (21% liquids) 25 HENDERSHOT UNIT 30-Day Rate 1H: 16.3 MMcfe/d 2H: 18.1 MMcfe/d (29% liquids) HORNET UNIT 30-Day Rate 1H: 21.5 MMcfe/d 2H: 17.2 MMcfe/d (26% liquids) CARR UNIT 30-Day Rate 2H: 20.6 MMcfe/d (20% liquids) WAGNER PAD 30-Day Rate 4-well combined 30-Day Rate of 59 MMcfe/d (14% liquids)

Antero’s Marcellus well performance has continued to improve over time with a tight statistical range of results across its entire acreage position Prolific Predictable Results across entire Marcellus Position 26 Marcellus PDP Locations (As of 12/31/14) (1) Source: IHS; 3rd party producing wells include Consol, EQT, Exxon/XTO, Noble, AEP, PDC, Magnum Hunter, Statoil, Chesapeake / SWN. >1275 BTU 2.2 Bcfe/1,000’ Lateral 7 SSL Wells 1200-1275 BTU 2.0 Bcfe/1,000’ Lateral 72 SSL Wells 1100-1200 BTU 1.8 Bcfe/1,000’ Lateral 85 SSL Wells Average Antero Marcellus Well 2014 Actual 2015 Budget 30-Day Rate (MMcfe/d): 13.1 16.1 Gross EUR (Bcfe): 15.3 19.2 Gross Well Cost ($MM): $11.8 $11.2 Lateral Length (Feet): 8,052 9,000 Net F&D ($/Mcfe): $0.89 $0.69 Btu: 1195 1250

Antero’s Marcellus average 30-day rates have increased by 63% over the past two years as the Company increased per well lateral lengths by 18% and shortened stage lengths by 48% Increasing recoveries and low variance in marcellus Processed rates converting C3+ NGLs and condensate at 6:1. Ethane rejected and sold in gas stream. Antero 30-Day Rates – 385 Marcellus Wells(1) 27 Antero SSL Reserves per 1,000’ of Lateral – 203 Marcellus SSL Wells 2014 and 2015 YTD – 13.1 MMcfe/d 2013 – 9.4 MMcfe/d 2009–2012 – 8.0 MMcfe/d The Marcellus is a reliable, low risk play as demonstrated by the tight distribution of EURs per 1,000’ and the P10/P90 ratio of only 1.6x for 203 SSL wells P10: 2.41 Bcfe/1,000’ P90: 1.51 Bcfe/1,000’ P10/P90: 1.6x P90 P10 0 5 10 15 20 25 30 35 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2.0 2.1 2.2 2.3 2.4 2.5 2.6 2.7 More Well Count Bcfe/1,000' of Lateral 0 5 10 15 20 25 MMcfe /d

28 Marcellus well performance improvements Increasing recoveries and efficiencies, through longer laterals, shorter stage lengths and faster drilling SSL completions drove a 21% decline in development costs in 2014 while lower service costs are expected to drive further development cost reductions in 2015 2015 reflects Antero guidance per 1/20/2015 press release. (1) 411 420 361 283 200 200 14 16 21 27 40 45 - 5 10 15 20 25 30 35 40 45 50 - 50 100 150 200 250 300 350 400 450 2010 2011 2012 2013 2014 2015E Average Frac Stages per Well Average Stage Length (Feet) Increasing Frac Stages per Well Average Stage Length (Feet) Average Frac Stages per Well (1) 1.5 1.6 1.5 1.6 2.0 $0.97 $0.89 $0.98 $1.13 $0.89 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 0.00 0.50 1.00 1.50 2.00 2.50 2010 2011 2012 2013 2014 Development Cost ($/Mcfe) EUR/1,000' Lateral ( Bcfe ) EUR vs. Development Cost per Unit EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe) 37 36 34 32 29 13,181 14,067 14,658 14,607 15,355 - 4,000 8,000 12,000 16,000 20,000 0 10 20 30 40 50 2010 2011 2012 2013 2014 Total Measured Depth (Feet) Spud - to - Spud Days Increasing Drilling Efficiency Avg Spud-to-Spud Days Total Measured Depth (Feet) 5,732 6,717 7,345 7,308 8,052 9,000 19 38 59 103 136 80 0 20 40 60 80 100 120 140 160 0 2,000 4,000 6,000 8,000 10,000 2010 2011 2012 2013 2014 2015E Wells on First Sales Lateral Length (Feet ) Increasing Lateral Lengths Average Lateral Length (Feet) Wells on First Sales

Marcellus ROR% and gas price sensitivity 29 Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 9,000’ lateral. Large portfolio of Highly-Rich Gas/Condensate to Dry Gas locations Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime Assumes 12/31/2014 WTI strip pricing for 2015-2024, flat thereafter; NGL price 32.5% of WTI for 2015-2016 and 50% of WTI thereafter following expected in-service date of Mariner East II in late 2016 NYMEX Flat Price Sensitivity(1) ROR% at Flat 2015-2024 Strip Price Highly-Rich Gas/Condensate: 44% Highly-Rich Gas: 32% Rich Gas: 16% Dry Gas: 16% 664 Locations 1,010 Locations 628 Locations 889 Locations Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Antero Rigs Employed 2015 Drilling Plan 0.0% 20.0% 40.0% 60.0% 80.0% 100.0% $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 Pre - Tax ROR (%) Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held. Antero 30-day rates in ethane rejection. 30-day rate reflects restricted choke regime. 100% operated Operating 4 drilling rigs 149,000 net acres in the core rich gas/ condensate window (72% includes processable rich gas assuming an 1100 Btu cutoff) 23% HBP with additional 75% not expiring for 5+ years 58 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 274 MMcfe/d in 1Q 2015 including 11,300 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) leading Utica shale core Position Delivers prolific liquids-rich wells 30 Cadiz Processing Plant NORMAN UNIT 30-Day Rate 2 wells average 16.8 MMcfe/d (15% liquids) RUBEL UNIT 30-Day Rate 3 wells average 17.2 MMcfe/d (20% liquids) Utica Core Area GARY UNIT 30-Day Rate 3 wells average 24.2 MMcfe/d (21% liquids) Highly-Rich/Cond 26,000 Net Acres 139 Gross Locations Highly-Rich Gas 16,000 Net Acres 94 Gross Locations Rich Gas 33,000 Net Acres 254 Gross Locations Dry Gas 42,000 Net Acres 289 Gross Locations NEUHART UNIT 3H 30-Day Rate 16.2 MMcfe/d (57% liquids) Condensate 32,000 Net Acres 248 Gross Locations DOLLISON UNIT 1H 30-Day Rate 19.8 MMcfe/d (40% liquids) MYRON UNIT 1H 30-Day Rate 26.8 MMcfe/d (52% liquids) Seneca Processing Complex LAW UNIT 30-Day Rate 2 wells average 16.1 MMcfe/d (50% liquids) SCHAFER UNIT 30-Day Rate(1) 2 wells average 14.2 MMcfe/d (49% liquids) URBAN PAD 30-Day Rate 4 wells average 18.8 MMcfe/d (15% liquids) GRAVES UNIT 500’ Density Pilot 30-Day Rate 4 wells average 15.5 MMcfe/d (24% liquids) FRANKLIN UNIT 30-Day Rate 3 wells average 17.6 MMcfe/d (16% liquids) FRAKES UNIT 30-Day Rate 2 wells average 18.6 MMcfe/d (42% liquids)

31 utica well performance improvements Increasing recoveries and efficiencies through longer laterals, shorter stage lengths and faster drilling Lower service costs and focus on liquids-rich locations expected to drive development cost reductions in 2015 2015 reflects Antero guidance per 1/20/2015 press release. 1.4 1.6 $1.64 $1.24 $0.00 $0.30 $0.60 $0.90 $1.20 $1.50 $1.80 0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60 2013 2014 Development Cost ($/Mcfe) EUR/1,000' Lateral ( Bcfe ) EUR vs. Development Cost per Unit EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe) 32 29 14,643 16,321 - 3,000 6,000 9,000 12,000 15,000 18,000 0 10 20 30 40 2013 2014 Total Measured Depth (Feet) Spud - to - Spud Days Increasing Drilling Efficiency Spud-to-Spud Days Total Measured Depth (Feet) 6,431 8,021 9,000 11 41 50 0 10 20 30 40 50 60 0 2,000 4,000 6,000 8,000 10,000 2013 2014 2015E Wells on First Sales Lateral Length (Feet) Increasing Lateral Lengths Average Lateral Length Wells on First Sales (1) 289 183 175 26 47 51 - 10 20 30 40 50 60 - 50 100 150 200 250 300 350 2013 2014 2015E Average Frac Stages per Well Average Stage Length (Feet) Increasing Frac Stages per Well Average Stage Length (Feet) Average Frac Stages per Well (1)

utica ROR% and gas price sensitivity 32 NYMEX Flat Price Sensitivity(1) 94 Locations ROR% at Flat 2015-2024 Strip Price Condensate: 14% Highly-Rich Gas/Condensate: 44% Highly-Rich Gas: 64% Rich Gas: 51% Dry Gas: 58% 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 2015-2024, flat thereafter; NGL price 32.5% of WTI for 2015-2016 and 50% of WTI thereafter following expected in-service date of Mariner East II in late 2016 Highly-Rich Gas Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 9,000’ lateral. Dry Gas Condensate 254 Locations 139 Locations 289 Locations 248 Locations 2015 Drilling Plan Highly-Rich Gas/Condensate Rich Gas Antero Rigs Employed 0.0% 20.0% 40.0% 60.0% 80.0% 100.0% 120.0% 140.0% 160.0% 180.0% $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 Pre - Tax ROR(%) Condensate Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

Large Utica shale dry gas position 33 Antero has 217,000 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 175,000 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: Chesapeake Hubbard BRK #3H 3,550’ Lateral IP 11.1 MMcf/d Hess Porterfield 1H-17 5,000’ Lateral IP 17.2 MMcf/d Gulfport Irons #1-4H 5,714’ Lateral IP 30.3 MMcf/d Eclipse Tippens #6H 5,858’ Lateral IP 23.2 MMcf/d Magnum Hunter Stalder #3UH 5,050’ Lateral IP 32.5 MMcf/d Antero Planned Utica Well Well Operator IP (MMcf/d) Lateral Length (Ft) Claysville SC #11H 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 Messenger 3H Southwestern 25.0 5,889 Tippens #6H Eclipse 23.2 5,858 Porterfield 1H-17 Hess 17.2 5,000 Hubbard BRK #3H Chesapeake 11.1 3,550 Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA. Magnum Hunter Stewart Winland 1300U 5,289’ Lateral IP 46.5 MMcf/d Range Claysville SC #11H 5,420’ Lateral IP 59.0 MMcf/d Chevron Conner 6H 6,451’ Lateral IP 25.0 MMcf/d Gastar Simms U-5H 4,447’ Lateral IP 29.4 MMcf/d Utica Shale Dry Gas Acreage in OH/WV/PA(1) Rice Bigfoot 9H 6,957’ Lateral IP 41.7 MMcf/d Utica Shale Dry Gas WV/PA Net Resource 11.1 Tcf 1,616 Gross Locations 175,000 Net Acres Utica Shale Dry Gas Ohio 3P Reserves 2.4 Tcf 289 Gross Locations 42,000 Net Acres Utica Shale Dry Gas Total OH/WV/PA Net Resource 13.5 Tcf 1,905 Gross Locations 217,000 Net Acres Stone Energy Pribble 6HU 3,605’ Lateral IP 30.0 MMcf/d Southwestern Messenger 3H 5,889’ Lateral IP 25.0 MMcf/d Rice Blue Thunder 10H, 12H 9,000’ Lateral

Antero water business 34 Marcellus Fresh Water System Provides fresh water to support Marcellus well completions Year-round water supply sources: Ohio River and local rivers Ozone Water treatment facility to be completed by 3Q 2015 Significant asset growth in 2015 as summarized below: Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned. Represents inception to date actuals as of 12/31/2014 and 2015 guidance. Estimated fee of $3.50 per barrel at an average of 240,000 Bbls of water per well. Utica Fresh Water System Provides fresh water to support Utica well completions Year-round water supply sources: local reservoirs and rivers Significant asset growth in 2015 as summarized below: Marcellus Water System YE 2014 YE 2015E Water Pipeline (Miles) 177 226 Fresh Water Storage Impoundments 22 24 Water Fees per Well ($)(2) $800K -$900K Utica Water System YE 2014 YE 2015E Water Pipeline (Miles) 61 90 Fresh Water Storage Impoundments 8 14 Water Fees per Well ($)(2) $800K -$900K OHIO Projected Water Infrastructure(1) Marcellus Shale Utica Shale Total YE 2015E Cumulative Water System Capex ($MM) $340 $113 $453 Water Pipelines (Miles) 226 90 316 Water Storage Facilities 24 14 38 Antero has built an integrated water business to serve its water needs including fresh water treating and delivery for completions as well as handling, recycling and disposal of produced water AM has the option to acquire AR’s water business at fair market value; private letter ruling (PLR) has been received by AM

Firm Transportation and Firm Sales Portfolio 35 MMBtu/d Columbia 7/26/2009 – 9/30/2025 Firm Sales #1 10/1/2011– 10/31/2019 Firm Sales #2 10/1/2011 – 5/31/2017 Firm Sales #3 1/1/2013 – 5/31/2022 Momentum III 9/1/2012 – 12/31/2023 EQT 8/1/2012 – 6/30/2025 REX/MGT/ANR 7/1/2014 – 12/31/2034 Tennessee 11/1/2015– 9/30/2030 Mid-Atlantic/NYMEX Gulf Coast (TCO) Appalachia or Gulf Coast Appalachia Appalachia ANR 3/1/2015– 2/28/2045 (REX/ANR/NGPL/MGT) Midwest Local Distribution 11/1/2015 – 9/30/2037 Gulf Coast Antero Transportation Portfolio 530 BBtu/d 790 BBtu/d 375 BBtu/d 250 BBtu/d 800 BBtu/d 600 BBtu/d 530 BBtu/d 40 BBtu/d (WGL) (ANR) (Tennessee) - 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000 4,500,000 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

Keys to Execution Local Presence 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 221 (48%) of Antero’s 465 employees are located in West Virginia and Ohio Safety & Environmental 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 Central Fresh Water System & Water Recycling 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 Natural Gas Vehicles (NGV) Antero supported the first natural gas fueling station in West Virginia Antero has 30 NGV trucks and plans to continue to convert its truck fleet to NGV Pad Impact Mitigation Closed loop mud system – no mud pits Protective liners or mats on all well pads in addition to berms Natural Gas Powered Drilling Rigs & Frac Equipment 7 of Antero’s contracted drilling rigs are currently running on natural gas First natural gas powered clean fleet frac crew began operations summer 2014 Green Completion Units All Antero well completions use green completion units for completion flowback, essentially eliminating methane emissions (full compliance with EPA 2015 requirements) LEED Gold Headquarters Building Corporate headquarters in Denver, Colorado LEED Gold Certified Health, Safety, Environment & Community Antero Core Values: Protect Our People, Communities And The Environment Strong West Virginia Presence 79% of all Antero Marcellus employees and contract workers are West Virginia residents Antero named Business of the Year for 2013 in Harrison County, West Virginia “For outstanding corporate citizenship and community involvement” Antero representatives recently participated in a ribbon cutting with the Governor of West Virginia for the grand opening of the first natural gas fueling station in the state; Antero supported the station with volume commitments for its NGV truck fleet 36

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 37

38 Antero Midstream (NYSE: AM) Asset Overview

Represents inception to date actuals as of 12/31/2014 and midpoint of 2015 guidance. Includes $12.5 million of maintenance capex at midpoint of 2015 guidance. 39 Gathering and compression assets in core of rapidly growing Marcellus and Utica Shale plays Acreage dedication of ~419,000 net leasehold acres for gathering and compression services 100% fixed fee long term contracts AR owns 70% of AM units (NYSE: AM) Utica Shale Marcellus Shale Projected Midstream Infrastructure(1) Marcellus Shale Utica Shale Total YE 2014 Cumulative Gathering/ Compression Capex ($MM) $836 $345 $1,181 Gathering Pipelines (Miles) 153 80 233 Compression Capacity (MMcf/d) 375 - 375 Condensate Gathering Pipelines (Miles) - 16 16 2015 Gathering/Compression Capex Budget ($MM)(2) $256 $182 $438 Gathering Pipelines (Miles) 46 18 64 Compression Capacity (MMcf/d) 425 120 545 Condensate Gathering Pipelines (Miles) - 4 4 Midstream Assets Antero midstream partners overview

Antero Midstream High growth Throughput Low Pressure Gathering (MMcf/d) Compression (MMcf/d) High Pressure Gathering (MMcf/d) Antero Midstream Partners EBITDA ($MM) 182% Y-O-Y Growth 894% Y-O-Y Growth 800% Y-O-Y Growth 326% Y-O-Y Growth 40 $1 $5 $7 $8 $11 $19 $28 $36 $0 $5 $10 $15 $20 $25 $30 $35 $40 2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 4Q '14 1Q '15 10 38 80 126 266 531 908 1,134 0 200 400 600 800 1,000 1,200 2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 4Q '14 1Q '15 Utica Marcellus 26 31 40 36 41 116 222 358 0 50 100 150 200 250 300 350 400 2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 4Q '14 1Q '15 Marcellus 108 216 281 331 386 531 738 935 0 200 400 600 800 1,000 2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 4Q '14 1Q '15 Utica Marcellus

significant Financial Flexibility 41 Undrawn $1 billion revolver in place to fund future growth capital (5x Debt/EBITDA Cap) $162 million of cash at 3/31/2015 Sponsor (NYSE: AR) has Ba2/BB corporate ratings AM Liquidity (3/31/2015) AM Peer Leverage Comparison(1) ($ in millions) Revolver Capacity $1,000 Less: Borrowings - Plus: Cash 162 Liquidity $1,162 As of 3/31/2015, pro forma for all 2Q 2015 transactions. Peers include EQM, MWE, PSXP, RRMS, SXL, TEP, TLLP, and WES. Financial Flexibility 0.0x 1.2x 3.7x 3.8x 4.0x 4.5x 4.6x 5.0x 5.6x 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x AM Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Total Debt / LTM EBITDA

42 APPENDIX 42

($ in millions) 3/31/2015 Cash $185 Senior Secured Revolving Credit Facility 790 6.00% Senior Notes Due 2020 525 5.375% Senior Notes Due 2021 1,000 5.125% Senior Notes Due 2022 1,100 5.625% Senior Notes Due 2023 750 Net Unamortized Premium 7 Total Debt $4,172 Net Debt $3,987 Financial & Operating Statistics LTM EBITDAX(1) $1,245 LQA EBITDAX(1) $1,418 LTM Interest Expense(2) $181 Proved Reserves (Bcfe) (12/31/2014) 12,683 Proved Developed Reserves (Bcfe) (12/31/2014) 3,803 Credit Statistics Net Debt / LTM EBITDAX 3.2x Net Debt / LQA EBITDAX 2.8x LTM EBITDAX / Interest Expense 6.9x Net Debt / Net Book Capitalization 42% Net Debt / Proved Developed Reserves ($/Mcfe) $1.05 Net Debt / Proved Reserves ($/Mcfe) $0.31 Liquidity Credit Facility Commitments(3) $5,000 Less: Borrowings (790) Less: Letters of Credit (474) Plus: Cash 185 Liquidity (Credit Facility + Cash) $3,921 Antero Capitalization – consolidated 1. LTM and 3/31/2015 EBITDAX reconciliation provided below; LQA EBITDAX equals 1st quarter 2015 EBITDAX multiplied by 4. 2. LTM interest expense adjusted for all capital market transactions since 1/1/2014. 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 3/31/2015. 43

2015 capital budget By Area 44 $3.5 Billion - 2014 By Segment ($MM) By Area $1.8 Billion – 2015 By Segment ($MM) Antero’s 2015 capital budget is $1.8 billion, a 49% decrease from 2014 capital expenditures of $3.5 billion 49% 177 Completions 130 Completions $2,477 $197 $841 Drilling & Completion Water Infrastructure Land 65% 35% Marcellus Utica $1,600 $50 $150 Drilling & Completion Water Infrastructure Land 59% 41% Marcellus Utica

45 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 Completion deferrals – optimizing pricing Production From 50 Deferred Completions +$1.39/MMBtu Pickup in Price = 18% BTAX IRR Increase BTAX IRR: 39% $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 2015 2015 2016 2016 2017 Gas Price $/ MMBtu Completion Deferral Impact on Realized Gas Price TETCO CGTLA TETCO Cal 2015: $1.88/MMBtu CGTLA Cal 2016: $3.27/ MMBtu BTAX IRR: 57% 0 50 100 150 200 250 300 350 400 450 500 Jan-16 Mar-16 May-16 Gross Wellhead Production ( MMcf /d) Completion Deferral Impact on 2016 Production

Antero resources – updated 2015 guidance 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) - $(14.00) NGL Realized Price (% of WTI)(1) 30% - 35% Cash Production Expense ($/Mcfe)(2) $1.50 - $1.60 Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.20 - $0.30 G&A Expense ($/Mcfe) $0.23 - $0.27 Net Income Attributable to Non-Controlling Interest ($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) $1,800 Updated NGL pricing guidance for 2015; 1Q 2015 NGL prices before hedges were 50% of WTI per press release dated 4/29/2015. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes. Excludes net marketing expense. Key Operating & Financial Assumptions 46

Antero midstream – 2015 guidance Key Variable 2015 Guidance Adjusted EBITDA ($MM) $150 - $160 Distributable Cash Flow ($MM) $135 - $145 Year-over-Year Distribution Growth(2) 28% - 30% Low Pressure Pipelines Added (Miles) 44 High Pressure Pipelines Added (Miles) 20 Compression Capacity Added (MMcf/d) 545 Capital Expenditures ($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 - $450 Financial assumptions per Partnership press release dated 1/20/2015. Reflects the expected distribution growth associated with the fourth quarter 2015 over the fourth quarter 2014. Key Operating & Financial Assumptions(1) 47

outstanding Reserve growth 2012, 2013 and 2014 reserves assuming ethane rejection. 2014 SEC prices were $4.07/MMBtu for natural gas and $81.48/Bbl for oil on a weighted average Appalachian index basis. 48 3P RESERVES BY VOLUME – 2014(1) 3P RESERVE GROWTH(1) NET PROVED RESERVES (Tcfe)(1) 2014 RESERVE ADDITIONS 35.0 40.7 93,000 net acres added in 2014 SSL results Utica results 3P reserves increased 16% to 40.7 Tcfe at 12/31/14 with a PV-10 of $22.8 billion Estimated 10% well cost reduction since YE 2014 results in $2.0 billion increase in 3P PV-10 All-in finding and development cost of $0.61/Mcfe for 2014 (includes land) “Bottoms-up” development cost of $0.98/Mcfe for 2014 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 12.7 Tcfe Proved 21.8 Tcfe Probable 6.3 Tcfe Possible Proved Probable Possible 40.7 Tcfe 3P 85% 2P Reserves 25.0 28.4 5.8 7.6 4.2 4.6 0 5 10 15 20 25 30 35 40 45 2013 2014 (Tcfe) Marcellus Utica Upper Devonian Key Drivers 4.2 0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 2010 2011 2012 2013 2014 Marcellus Utica 0.7 2.8 4.3 7.6 12.7 (Tcfe)

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 occurs when ethane is left in the wellhead gas stream as the gas is processed, rather than being separated out and sold as a liquid after fractionation. When ethane is left in the gas stream, the BTU content of the residue gas at the outlet of the processing plant is higher. Producers will elect to “reject” ethane when the price received for the higher BTU residue gas is greater than the price received for the ethane being sold as a liquid after fractionation. When ethane is recovered, the BTU content of the residue gas is lower, but a producer is then able to recover the value of the ethane sold as a separate NGL product. ETHANE REJECTION(1) ETHANE RECOVERY(1) 49 Marcellus – 28.4 Tcfe Utica – 7.6 Tcfe Upper Devonian – 4.6 Tcfe 40.7 Tcfe Gas – 34.5 Tcf Oil – 102 MMBbls NGLs – 924 MMBbls Marcellus – 33.7 Tcfe Utica – 8.6 Tcfe Upper Devonian – 5.1 Tcfe 47.4 Tcfe Gas – 32.0 Tcf Oil – 102 MMBbls NGLs – 2,459 MMBbls 15% Liquids 32% Liquids

Marcellus single Well Economics – In Ethane Rejection 50 DRY GAS LOCATIONS RICH GAS LOCATIONS HIGHLY RICH GAS LOCATIONS Assumptions Natural Gas – 12/31/2014 strip Oil – 12/31/2014 strip NGLs – 32.5% of Oil Price 2015-2016; 50% of Oil Price 2017+ NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL(2) ($/Bbl) 2015 $3.01 $56 $18 2016 $3.46 $63 $20 2017 $3.77 $67 $33 2018 $3.96 $69 $34 2019 $4.12 $70 $35 2020-24 $4.24-$4.65 $71-$72 $35-$36 Marcellus Well Economics and Total Gross Locations(1) Classification Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Modeled BTU 1313 1250 1150 1050 EUR (Bcfe): 20.8 18.8 16.8 15.3 EUR (MMBoe): 3.5 3.1 2.8 2.6 % Liquids: 33% 24% 12% 0% Lateral Length (ft): 9,000 9,000 9,000 9,000 Well Cost ($MM): $11.2 $11.2 $11.2 $11.2 Bcfe/1,000’: 2.3 2.1 1.9 1.7 Pre-Tax NPV10 ($MM): $12.5 $8.2 $1.5 $2.1 Pre-Tax ROR: 37% 27% 14% 15% Net F&D ($/Mcfe): $0.63 $0.70 $0.78 $0.86 Payout (Years): 2.0 2.8 5.9 5.7 Gross 3P Locations(3): 664 1,010 628 889 Well economics are based on 12/31/2014 strip pricing less basis differential and related transportation costs. Includes gathering, compression and processing fees, where applicable. Well costs are current estimates and include $1.2 million of pad, road and location costs, as well as the cost of production facilities. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 32.5% of WTI for 2015-2016 and 50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to projected in-service date of Mariner East II project allowing for a significant increase in AR NGL exports via ship. Undeveloped well locations as of 12/31/2014. 2015 Drilling Plan 664 1,010 628 889 37% 27% 14% 15% 0 150 300 450 600 750 900 1,050 0% 15% 30% 45% 60% Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR Locations ROR

UTICA single Well Economics – in Ethane Rejection 51 DRY GAS LOCATIONS RICH GAS LOCATIONS HIGHLY RICH GAS LOCATIONS Utica Well Economics and Gross Locations(1) Classification Condensate Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Modeled BTU 1275 1235 1215 1175 1050 EUR (Bcfe): 9.4 16.9 25.2 23.8 21.4 EUR (MMBoe): 1.6 2.8 4.2 4.0 3.6 % Liquids 35% 26% 21% 14% 0% Lateral Length (ft): 9,000 9,000 9,000 9,000 9,000 Well Cost ($MM): $12.3 $12.3 $12.3 $12.3 $12.3 Bcfe/1,000’: 1.0 1.9 2.8 2.7 2.4 Pre-Tax NPV10 ($MM): $1.0 $9.1 $14.7 $11.3 $11.8 Pre-Tax ROR: 13% 34% 45% 36% 39% Net F&D ($/Mcfe): $1.61 $0.89 $0.60 $0.64 $0.71 Payout (Years): 5.7 2.0 1.5 2.0 2.1 Gross 3P Locations(3): 248 139 94 254 289 Well economics are based on 12/31/2014 strip pricing less basis differential and related transportation costs. Includes gathering, compression and processing fees, where applicable. Well costs are current estimates and include $1.2 million of pad, road and location costs, as well as the cost of production facilities. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 32.5% of WTI for 2015-2016 and 50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to projected in-service date of Mariner East II project allowing for a significant increase in AR NGL exports via ship. Undeveloped well locations as of 12/31/2014. 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content. 2015 Drilling Plan Assumptions Natural Gas – 12/31/2014 strip Oil – 12/31/2014 strip NGLs – 32.5% of Oil Price 2015-2016; 50% of Oil Price 2017+ NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL(2) ($/Bbl) 2015 $3.01 $56 $18 2016 $3.46 $63 $20 2017 $3.77 $67 $33 2018 $3.96 $69 $34 2019 $4.12 $70 $35 2020-24 $4.24-$4.65 $71-$72 $35-$36 248 139 94 254 289 13% 34% 45% 36% 39% 0 50 100 150 200 250 300 0% 15% 30% 45% 60% Condensate Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR Locations ROR

52 Average Index Hedge Price(1) Hedged Volume Current NYMEX Strip(2) COMMODITY HEDGE POSITION ~$2.2 billion mark-to-market unrealized gain based on 3/31/2015 prices 2.4 Tcfe hedged from April 1, 2015 through year-end 2020 and 259 Bcf of TCO basis hedged from 2015 to 2017 $569 MM $591 MM $290 MM $399 MM $275 MM $61 MM Mark-to-Market Value(2) Largest Gas Hedge Position in U.S. E&P 94% of 2015 Guidance Hedged 52 Weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio; excludes impact of TCO basis hedges. 3,000 Bbl/d of oil and 23,000 Bbl/d of propane hedged for 2015. As of 3/31/2015; 2015 mark-to-market value reflects April-December hedges. Hedging is a key component of Antero’s business model due to the large, repeatable drilling inventory Antero has realized almost $1.1 billion of gains on commodity hedges over the past 7 years Gains realized in 27 of last 29 quarters $MM $/Mcfe $4 - $8 $5 $25 $34 $29 $28 $26 $12 $16 $17 $28 $29 $19 $25 $43 $80 $83 $59 $49 $48 $14 $47 $54 - $1 $1 $58 $78 $185 ($2.00) ($1.00) $0.00 $1.00 $2.00 $3.00 $4.00 ($40) $0 $40 $80 $120 $160 $200 Quarterly Realized Gains/(Losses) 1Q '08 - 1Q '15 1,316 1,415 900 1,193 1,348 850 $4.42 $4.14 $4.22 $4.40 $4.12 $3.85 $2.78 $ 3.09 $3.33 $3.42 $3.50 $3.61 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 0 200 400 600 800 1,000 1,200 1,400 9 Mths 2015 2016 2017 2018 2019 2020 BBtu/d $/MMBtu

Rapid growth in lpg exports and capacity 53 22% CAGR U.S. Total LPG Export Capacity vs. Export Volumes U.S. Total LPG Exports by Destination Includes 11.5 MBbl/d of ethane, 15 MBbl/d of butane, 35 MBbl/d of propane. 58% CAGR Excess export capacity to support growing LPG export volumes Marcus Hook LPG Exports - 2014 Antero access to export markets increases dramatically in late 2016 via 61.5 MBbl/d(1) firm transport on Mariner East II to Marcus Hook Source: Bentek 0 200 400 600 800 1000 1200 1400 1600 1800 MBbl/d Butane Exports Propane Exports Total Export Capacity 99 131 147 196 331 487 0 100 200 300 400 500 600 2009 2010 2011 2012 2013 2014 MBbl/d Africa Caribbean Central America North America Asia Europe South America Source: EIA Mexico/ Canada 18% South America 24% Central America 10% Caribbean 6% Europe 22% Asia 18% Africa 2% Europe 73% South America 2% Mexico/ Canada 23 % Africa 2% Source: Bentek

All-in Firm Transportation Costs(1) Firm transportation reduces Appalachian basis exposure 2013 Firm Transportation – 647 MMcf/d Average All-in FT Cost $0.25/MMBtu 2016 Firm Transportation – 3.1 Bcf/d Average All-in FT Cost $0.46/MMBtu + $0.18/MMBtu Antero’s firm transportation (FT) portfolio increases visibility on production growth and increases exposure to Gulf Coast and Midwest pricing, with little incremental cost per Mcf Reduces weighted average basis by $0.28 per MMBtu compared to 2014 basis – while significantly reducing Appalachian basis exposure Utilized portion included in cash production expense (fixed cost) Assumes full utilization of firm transportation capacity; page 55 assumes Antero targeted production figures. Represents accessible firm transportation and sales agreements. Based on current strip pricing as at 3/31/2015. Included in cash production expense (variable cost) $0.25 $0.28 $0.35 $0.46 2016 Basis(3) TCO – $(0.40)/MMBtu DOM S – $(1.06)/MMBtu 2016 Basis(3) Chicago – $(0.05)/MMBtu 2016 Basis(3) CGTLA – $(0.09)/MMBtu 54 Appalachia 35% Midwest 20% Gulf Coast 45% $0.14 $0.17 $0.23 $0.33 $0.11 $0.11 $0.12 $0.13 $0.00 $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 $0.70 2013A 2014A 2015E 2016E ($/MMBtu) Wtd. Avg. FT Demand ($/MMBtu) Wtd. Avg. FT Commodity/Fuel ($/MMBtu) Appalachia 49% Gulf Coast 51% 2013 Firm Transportation (1)(2)

Antero Firm Transportation Appropriately designed to accommodate growth 55 Assumes 1100 BTU residue sales gas. Represents excess firm transportation that is deemed marketable to 3rd parties based on a positive differential between the receipt and delivery points of the FT capacity, less variable transport cost. (BBtu/d) 2015 Net Production Target (MMcfe/d) 1,400 Net Gas Production Target (MMcf/d) 1,175 Net Revenue Interest Gross-up 80% Gross Gas Production Target (MMcf/d) 1,470 BTU Upgrade (1) x1.100 Gross Gas Production Target (BBtu/d) 1,615 Firm Transportation / Firm Sales (BBtu/d) 2,250 Estimated % Utilization of FT/FS 72% Marketable Firm Transport (BBtu/d) (2) 350 Estimated % Utilization of FT/FS (Including Marketable FT) 87% % FT Utilization (including marketable FT): Antero’s firm transport (FT) is well utilized during 2015 (72%) Excess FT for acquisitions and well productivity improvements A portion of the excess FT is highly marketable, further increasing utilization to 87% Expect to fully utilize FT portfolio by 2018 87% (2) 0 500 1,000 1,500 2,000 2,500 Marketable FT (BBtu/d) (3) Firm Transportation / Firm Sales (BBtu/d) Risked Gross Gas Production Target (Bbtu/d)

Positive ratings momentum Moody’s / S&P Historical Corporate Credit Ratings “We could raise the ratings due to our assessment of an improvement in the company's financial profile. An improvement in the financial profile would include maintaining FFO to debt of greater than 45% and narrowing the amount that the company outspends its cash flows by.” - S&P Credit Research, September 2014 "The upgrade reflects Moody's expectation that Antero will continue to report strong production growth and increasing reserves despite challenging market conditions and without a significant increase in leverage. Antero's low finding and development costs and significant commodity hedge position should allow the company to continue to prosper despite today's low commodity price environment.“ - Moody’s Credit Research, February 2015 Corporate Credit Rating (Moody’s / S&P) Ba3 / BB- B1 / B+ B2 / B B3 / B- 9/1/2010 2/24/2011 10/21/2013 9/4/2014 5/31/13 Ba2 / BB Ba1 / BB+ Caa1 / CCC+ (1) Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC. Baa3 / BBB- Moody’s Upgrade Rationale S&P Upgrade Criteria 56 3/31/2015 Ba2/BB Moody's S&P

Antero EBITDAX reconciliation 57 EBITDAX Reconciliation ($ in millions) Quarter Ended LTM Ended 3/31/2015 3/31/2015 EBITDAX: Net income (loss) including noncontrolling interest $399.2 $1,167.5 Commodity derivative fair value (gains) (759.6) (1,876.7) Net cash receipts (payments) on settled derivatives instruments 184.8 321.7 (Gain) loss on sale of assets - (40.0) Interest expense 53.2 181.9 Loss on early extinguishment of debt - 20.4 Income tax expense (benefit) 247.3 733.7 Depreciation, depletion, amortization and accretion 182.7 570.3 Impairment of unproved properties 8.6 22.4 Exploration expense 1.4 22.3 Equity-based compensation expense 27.8 110.9 State franchise taxes 0.2 1.6 Contract termination and rig stacking 9.0 9.0 Consolidated Adjusted EBITDAX $354.6 $1,245.0 EBITDAX: Net income from discontinued operations - 2.2 (Gain) on sale of assets - (3.6) Provision for income taxes - 1.4 Adjusted EBITDAX from discontinued operations - $0.0 Total Adjusted EBITDAX $354.6 $1,245.0

Cautionary Note The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates (collectively, “3P”). Antero has provided internally generated estimates for proved, probable and possible reserves in this presentation in accordance with SEC guidelines and definitions. The estimates of proved, probable and possible reserves as of December 31, 2014 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates as of December 31, 2014 assume ethane rejection and strip pricing. Actual quantities that may be ultimately recovered from Antero’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of Antero’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. In this presentation: “3P reserves” refer to Antero’s estimated aggregate proved, probable and possible reserves as of December 31, 2014. The SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. “EUR,” or “Estimated Ultimate Recovery,” refers to Antero’s internal estimates of per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules. “Condensate” refers to gas having a heat content between 1250 BTU and 1300 BTU in the Utica Shale. “Highly-Rich Gas/Condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1225 BTU and 1250 BTU in the Utica Shale. “Highly-Rich Gas” refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and 1225 BTU in the Utica Shale. “Rich Gas” refers to gas having a heat content of between 1100 BTU and 1200 BTU. “Dry Gas” refers to gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use. Regarding Hydrocarbon Quantities 58