First Quarter 2016 Earnings Call Presentation April 28, 2016

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1 First Quarter 2016 Earnings Call Presentation April 28, 2016

2 FORWARD-LOOKING STATEMENTS This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Resources Corporation and its subsidiaries (collectively, the Company or Antero ) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words believe, expect, anticipate, plan, intend, estimate, project, foresee, should, would, could, or other similar expressions are intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forwardlooking statements contained in this presentation specifically include estimates of the Company s reserves, expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced under the heading Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015 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, 2015 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. 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. 1

3 HEDGE STRATEGY PRODUCES CONSISTENT RESULTS AND STABILITY Hedging is a key component of Antero s business model which includes development of a large, repeatable drilling inventory Locks in higher returns in a low commodity price environment and reduces the amount of time for well payouts, thereby enhancing liquidity Antero has realized $2.1 billion of gains on commodity hedges since 2009 Gains realized in 28 of last 29 quarters, or 97% of the quarters since 2009 Based on Antero s hedge position and strip pricing as of 3/31/2016, the unrealized commodity derivative value is $3.1 billion Significant additional hedge capacity remains under the credit facility hedging covenant for period Quarterly Realized Hedge Gains / (Losses) $350 $300 Realized $2.1 Billion in Hedge Gains Since 2009 $3.1 Billion in Projected Hedge Gains Through Tcfe Hedged at average price of $3.71/Mcfe through 2022 $6.00 $5.00 $MM $250 $200 $150 $3.91 (1) $3.57 $3.91 $3.70 $3.66 $3.36 $3.24 $4.00 $3.00 ($/MMBtu) $100 $2.00 $50 $1.00 $0 $0.00 Realized Hedge Gains Projected Hedge Gains NYMEX Natural Gas Historical Spot Prices NYMEX Natural Gas Futures Prices 03/31/16 Average Hedge Prices ($/MMBtu) 2 1. Represents average hedge price for nine months ending 12/31/2016.

4 PROJECTED INCREMENTAL EBITDA FROM STONEWALL Pre Post In-Service In-Service Projected 2016 Average Volume (BBtu/d) DOMS Priced Sales TETCO M2 Priced Sales TCO Priced Sales 0 54 Firm Sales (TCO / Nymex) Total Strip Pricing ($/MMBtu) DOMS (1) $1.31 N/A TETCO M2 (1) $1.29 N/A TCO (1) N/A $2.04 Firm Sales (TCO / Nymex) (2) N/A $1.94 Annual Revenue ($MM) DOMS $157.1 $0.0 TETCO M TCO Pool Sales (1) Firm Sales (TCO / Nymex) (2) $308.7 $463.1 Incremental Revenue $154.3 Less: Incremental Firm Transport Costs: (28.7) Projected Incremental EBITDA $ DOMS Strip: $1.31 Variance to Nymex ($0.87) Variance to TCO ($0.73) 2016 TETCO M2 Strip: $1.29 Variance to Nymex ($0.88) Variance to TCO ($0.75) Existing TCO capacity of 582 MMcf/d with additional 1.1 Bcf/d of Stonewall transportation and sales has eliminated all Marcellus swing gas sales to Dominion South and TETCO M2 thus far in 2016 and is expected for the full year of Strip pricing as of March 31, Blended price based on contracted firm sales volumes with third parties. 3

5 HIGHEST EBITDAX & MARGINS AMONG PEERS Quarterly Appalachian Peer Group EBITDAX ($MM) (1) $500 $400 $300 $355 $269 AR has ranked first for both the highest EBITDAX and EBITDAX margin among Appalachian peers for the second straight quarter $291 $308 $355 Y-O-Y AR: $0MM Peer Avg: $170MM NYMEX Gas: 30% NYMEX Oil: 32% $200 $100 $0 $3.00 $2.50 $2.00 P5 P2 AR P4 P3 P1 $2.56 P5 AR P2 P3 P4 P1 1Q Q 2015 $1.90 P5 AR P3 P2 P4 P1 $1.97 3Q 2015 Quarterly Appalachian Peer Group EBITDAX Margin ($/Mcfe) (1) AR P5 P3 P2 P4 P1 AR P5 P1 P3 P2 P4 4Q Q 2016 AR Peer Group Ranking Improving Over Time #3 #2 #2 #1 #1 $2.03 $2.03 TBA TBA TBA Y-O-Y AR: 21% Peer Avg: 46% NYMEX Gas: 30% NYMEX Oil: 32% $1.50 $1.00 $0.50 $0.00 P2 AR P5 P3 P4 P1 AR P3 P4 P2 P5 P1 1Q Q 2015 AR P3 P5 P4 P2 P1 3Q 2015 AR P3 P2 P1 P5 P4 AR P1 P5 P3 P2 P4 4Q Q 2016 AR Peer Group Ranking Top Tier #2 #1 #1 #1 #1 Note: AR and EQT EBITDAX margin excludes EBITDA from midstream MLP associated with noncontrolling interest. AR consolidated EBITDAX margin for 1Q 2016 was $2.22/Mcfe. CNX excludes EBITDAX contribution from coal operations. 1. Source: Public data from form 10-Qs and 10-Ks. Peers include COG, CNX, EQT, RRC and SWN. TBA TBA TBA 4

6 CONTINUED MEASURED GROWTH Antero continues to grow its production and cash flow through the commodity price downturn while also maintaining prudent leverage metrics 20% 10% 0% -10% -20% -30% -40% -50% 17% 15% 12% 2016E EBITDAX and Production Growth (1) 19% 3% 2% 2016E Production Growth 2016E EBITDAX Growth Antero is the only one of its (6%) Appalachian (5%) (11%) peers that is growing cash flow in line with production (27%) (66%) growth (44%) AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 6.0x 5.0x 4.0x 3.0x 3.7x 3.8x 2015 vs. 2016E Year-End Net Debt / LTM EBITDAX (1),(2) YE 2015 Leverage YE 2016E Leverage 5.6x 4.9x 4.6x 3.0x 2.4x 3.4x 9.8x 2.0x 1.0x 0.6x 1.3x 1.5x 0.0x AR (3) Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 NOTE: Peers include CNX, COG, EQT, RRC and SWN and 2016E production and EBITDAX per Bloomberg Street Consensus estimates. Peer E production and EBITDAX per company issued press release E Debt to EBITDAX assumes year-end 2016E debt divided by 2016E EBITDAX. 2016E debt calculated as 2015 YE debt, less free cash flow. Free cash flow is equal to 2016E EBITDAX, less 2016E interest expense per Bloomberg consensus estimates, less 2016 capital spending guidance per company press releases. 3. AR pro forma for secondary offering of 8.0 million AM units on 3/24/2016 for net proceeds of $178 million. 5

7 LOW MAINTENANCE CAPITAL PROVIDES FLEXIBILITY AND UPSIDE Antero can achieve 17% year-over-year net production growth for 2016 by spending only $675 million, or approximately $500 million less than the $1.2 billion of expected hedge revenues for the year (1) Incremental growth capital of $625 million in 2016 positions Antero to achieve its 20% year-over-year targeted net production growth in 2017, while only having to spend $875 million in 2017 $MM $1,600 $1,400 $1,200 $1,000 Driven by the DUC inventory, continued capital efficiency and volumes sold forward at attractive prices, Antero is positioned to achieve its 2016 guidance and 2017 production target with modest outspend Hedge Revenues $1,156MM (1) $1.3 Bn D&C Budget 2017 Growth Capital $625 Consensus EBITDAX (2) Contributes to 20% Y-O-Y Growth Target for Prior year DUCs completed D&C Capital DUCs ($MM) $125 $ Growth Capital TBD Consensus EBITDAX (2) (3) $800 $600 $400 $200 $0 17% Y-O-Y Growth 2016 Growth Capital $400 Maintenance Capital $275 0% Y-O-Y Growth of 1,493 MMcfe/d 20% Y-O-Y Growth Target for $875 MM Capex in Revenues represent annual mark-to-market value based on 3/31/2016 strip pricing, including 1Q 2016 actual hedge gain of $324 million. 2. Consensus EBITDAX as of 3/31/ Includes targeted drilling and completion cost improvements Growth Capital $375 Maintenance Capital $ Hedge Revenues $572MM (1) 0% Y-O-Y Growth of 1,750 MMcfe/d 6

8 FLEXIBILITY & UPSIDE As the most active operator in Appalachia, Antero has kept its workforce intact while also preserving the ability to accelerate efficiently when commodity prices recover Accelerated development is further enhanced by Antero s ability to flow incremental production to the most favorable price indices using Antero s firm transport portfolio Despite its large hedge position, Antero has tremendous leverage to natural gas and NGL prices due to scale of its 3P reserves and development infrastructure $45.0 $40.0 $35.0 $30.0 $25.0 $20.0 $15.0 $10.0 $5.0 $0.0 ($5.0) Optionality to Accelerate Development # of Antero Rigs MMcfe/d 25 Average Rigs 2,500 ($Bn) Ability to triple rig count from 2016 levels, as demonstrated by historical rig utilization AR Net Production AR Ownership in AM shares ($B) Hedge Value Pre-Tax PV-10 ($B) 3P Reserve/Hedge Pre-Tax PV-10 Upside Value (3) 3P Reserves Pre-Tax PV-10 ($B) $45 $41 $17.3 $16.1 $2.4 $0.9 $2.4 $9.2 $2.5 $2.4 $3.1 $11.2 $13.9 $3.7 Net 3P Reserve/Hedge pre-tax PV-10 plus AM ownership less net debt, Per Share (3) (2) $22.5 $2.4 $20.4 $27.6 $2.4 $26.7 ($0.3) ($1.6) SEC Pricing 12/31/2015 Strip $60 Oil $67.50 Oil $75 Oil $54 Oil; $3.23 Gas 2016 Guidance 2017 Target E 2017E $64 $83 $3.50 Gas $4.00 Gas $4.50 Gas Substantial Inventory Producing Wells at YE wells producing 1.5 Bcfe/d net (13%) Remaining Undeveloped 3P Locations (1) 3,609 85% 2016E Well Completions 110 (2%) Increase in pre-tax PV10 value does not include the addition of locations; represents upside in prices only on 12/31/15 locations Increase in reserve pre-tax PV-10 is well in excess of hedge PV-10 lost at higher prices Note: Assumes NGL prices equal to 37.5% of WTI for 2016 and 50% of WTI thereafter. All PV-10 values are on a pre-tax basis. 1. Total 3P locations of 3,719 less 110 planned completions in PV-10 of 3P reserves and hedges less $4.7 billion of net debt as of 3/31/2016, plus market value of Strip pricing as of December 31, 2015 for each of the first ten years and flat thereafter. million AM units owned by AR (as of 3/31/2016). 2,000 1,500 1,

9 SPRING 2016 BORROWING BASE REAFFIRMED Antero s $4.5 Billion borrowing base was reaffirmed by its lender group, representing one of only five public E&P companies that did not receive a reduction in its borrowing base thus far in the redetermination season (1) Driven by significant PDP reserve growth and increase in value of hedge position Borrowing Base Actions Borrowing Base Amount ($mm) $4,500 $4,000 $3,500 $3,000 $2,500 $2,000 $1,500 $1,000 $500 $0 $4,500 $4,000 $3,400 $3,200 $200 Antero was one of only five public E&P companies (one of three Appalachia operators) that did not receive a reduction in their borrowing base from March s redetermination process $3,250 $2,800 $450 $3,000 $4,000 $2,750 $1,250 $2,000 $2,000 $1,250 $1,525 $1,150 $2,600 $1,400 $1,050 $1,050 $1,025 $1,000 AR CHK COG CXO RRC WLL CNX SM OAS DNR EGN WPX MRD $750 $375 Red New Borrowing Base Borrowing Base Affirmed $ Amount of Reduction Appalachian Company $1,550 $350 $1,750 $725 Old Borrowing Base $4,500 $4,000 $3,400 $3,250 $3,000 $4,000 $2,000 $2,000 $1,525 $2,600 $1,400 $1,750 $1,000 New Borrowing Base $4,500 $4,000 $3,200 $2,800 $3,000 $2,750 $2,000 $1,250 $1,150 $1,050 $1,050 $1,025 $1,000 Result ($200) ($450) -- ($1,250) -- ($750) ($375) ($1,550) ($350) ($725) -- Average % change (6%) (14%) -- (31%) -- (38%) (25%) (60%) (25%) (41%) (1) Note: Represents Spring 2016 borrowing base actions for all public companies with a borrowing base greater than $1 billion prior to the redetermination. -- (30%) 8

10 PROVEN TRACK RECORD OF WELL COST REDUCTIONS Marcellus Well Cost Reductions for a 9,000 Lateral ($MM) (1) $MM $14 $12 $10 $8 $6 $4 $12.3 $8.3 $11.1 $10.8 $7.3 $7.4 DRILLING COST AFE COMPLETION COST AFE $10.2 $10.2 $0.95 / 1,000 $8.5 $7.0 $7.0 $5.4 32% Reduction in Marcellus well costs since Q % Reduction vs. well costs assumed in YE 2015 reserves $2 $- $4.0 $3.8 $3.4 $3.2 $3.2 $3.1 Q Q4 Q Q Q Q2 Q Q3 Q Q Q Q1 Utica Well Cost Reductions for a 9,000 Lateral ($MM) (2) $MM $16 $14 $12 $10 $8 $6 $4 $14.0 $8.7 $12.4 $7.8 DRILLING AFE COMPLETION AFE $12.9 $11.8 $11.8 $1.14 / 1,000 $10.3 $7.6 $7.1 $7.1 $5.6 29% Reduction in Utica well costs since Q % Reduction vs. well costs assumed in YE 2015 reserves $2 $5.3 $4.6 $5.3 $4.7 $4.7 $4.7 $- Q Q4 Q Q1 Q Q2 Q Q3 Q Q4 Q Q1 NOTE: Based on statistics for drilled wells within each respective period. 1. Based on 200 ft. stage spacing. 2. Based on 175 ft. stage spacing. 9

11 CONTINUOUS OPERATING IMPROVEMENT Operating Highlights Top 10 best drilling footage days in Marcellus since 2009 have all occurred in 2016, including 5,291 drilled in 24 hours in West Virginia on the Charleston 3H Recently drilled and cased longest lateral in company history at 14,024 feet Increased sand placement during completions to 98% in Q Stayed within targeted zone for 98% of lateral length drilled in Q Utilizing new floating casing procedure, reducing casing run time by over 12 hours Increased proppant loading and shorter stages in certain areas of the Marcellus Utica Shale Ohio Marcellus Shale Utica Marcellus Q Q vs Q Q vs Activity Levels Average Rigs Running (75%) (50%) Average Completion Crews (25%) (27%) Operational Improvements Drilling Days % % Average Lateral Length (Ft) 8,543 8,575 (2) 9,000 5% 8,052 8,910 (2) 9,000 12% Stages per Well % % Stage Length % % Stages per Day % % Well Cost & Performance Improvements D&C per 1,000' $1.55 $1.36 $1.14 (26%) $1.34 $1.18 $0.95 (29%) EUR per 1,000' (Bcf) (1) % % EUR per 1,000' (Bcfe) (1) % % 1. Based on statistics for wells completed within each respective period. 2. Year end 2016 forecast. 10

12 MARCELLUS PROPPANT PLACEMENT Increased Proppant Load by 25% While Increasing Proppant Placement to 98% 1,600 1,500 Pilot testing demonstrated improved recoveries while maintaining well density 1,418 1,480 1,500 Proppant Placed (lbs/ft) 1,400 1,300 1,200 1,100 1,000 1,194 1,128 1, ,031 1, ,084 1,126 1,274 1,304 1, Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar Plan 11

13 MARCELLUS IMPROVEMENTS DRIVING VALUE CREATION Antero Marcellus EUR vs. Lateral Length (1)(2) wells average 2.3 Bcfe/1,000 All Wells Q Wells TBD Current completions using 1,500 lbs/ft of sand and 39 Bbls/ft of water 25 EUR (Bcfe) % sand placement for 1,200 lbs/ft drove outperformance in 1Q 2016 compared to type curve 39 wells > 20 Bcfe High correlation of EURs to lateral length 10 5 Longer Laterals 33 wells > 10,000 lateral length and 43 wells waiting on completion ranging from 10,000 to 14,000 Better Well Economics 0 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 Lateral Length (Feet) 1. All 251 wells completed since 2014 when Antero transitioned to shorter stage length completions (SSL). 2. EUR s include NGL processing (C3+) but assume ethane rejection. 12

14 MARCELLUS UPSIDE POTENTIAL While we have not changed our 1.7 Bcf/1,000' Marcellus project-wide type curve, we are seeing stronger EURs per 1,000' in a significant portion of our Marcellus rich gas acreage as exhibited in our 2.0 Bcf/1,000' average for wells completed in the first quarter with at least 30 days of production history Assumptions Natural Gas 3/31/2016 strip Oil 3/31/2016 strip NGLs 37.5% of Oil Price 2016; 50% of Oil Price NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL (2) ($/Bbl) Pre-Tax PV-10 $15.0 $12.0 $9.0 $6.0 35% $8.7 Pre-Tax PV-10 45% $11.7 Pre-Tax ROR 2016 $2.26 $41 $16 $3.0 $ $2.77 $45 $ $2.87 $47 $24 $0.0 Highly-Rich Gas/Condensate Highly-Rich Gas 2019 $2.93 $49 $ Bcf/1,000' 2.0 Bcf/1,000' (4) 1.7 Bcf/1,000' 2.0 Bcf/1,000' (4) 2020 $3.03 $50 $ Bcfe/1,000' 2.7 Bcfe/1,000' 2.1 Bcfe/1,000' 2.5 Bcfe/1,000' $3.49 $51-$53 $ Development Plan: Completions Classification (1) Highly-Rich Gas/Condensate Highly-Rich Gas BTU Regime EUR (Bcfe): EUR (MMBoe) : % Liquids: 33% 33% 24% 24% Lateral Length (ft): 9,000 9,000 9,000 9,000 Well Cost ($MM): $8.5 $8.5 $8.5 $8.5 Bcf/1, Bcfe/1,000 : Net F&D ($/Mcfe): $0.48 $0.41 $0.53 $0.45 Pre-Tax NPV10 ($MM): $8.7 $11.7 $5.3 $7.7 Pre-Tax ROR: 35% 45% 24% 30% Payout (Years): Breakeven NYMEX Gas Price ($/MMBtu) (5) $1.67 $1.40 $2.31 $2.05 Gross 3P Locations (3) : /31/2016 pre-tax well economics based on a 9,000 lateral, 3/31/2016 natural gas and WTI strip pricing for , flat thereafter, NGLs at 37.5% of WTI for 2016 and 50% of WTI thereafter, and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates include $1.2 million for road, pad and production facilities. 2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 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 2 project allowing for a significant increase in AR NGL exports via ship. 3. Undeveloped well locations as of 12/31/ Represents actual results for 1Q Breakeven price for 15% pre-tax rate of return. 24% 45 30% $7.7 50% 40% 30% 20% 10% 0% Pre-Tax ROR 13

15 APPENDIX 14

16 ANTERO RESOURCES EBITDAX RECONCILIATION EBITDAX Reconciliation ($ in millions) Quarter Ended LTM Ended 3/31/2016 3/31/2016 EBITDAX: Net income including noncontrolling interest $10.7 $591.5 Commodity derivative fair value (gains) (279.9) (1,901.9) Net cash receipts on settled derivatives instruments Interest expense Income tax expense (benefit) Depreciation, depletion, amortization and accretion Impairment of unproved properties Exploration expense Equity-based compensation expense State franchise taxes 0.0 (0.1) Contract termination and rig stacking Consolidated Adjusted EBITDAX $355.4 $1,

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