2018 Analyst Day JANUARY 18, 2018 Cautionary Statement This - PowerPoint PPT Presentation

Core of the Core Acreage Position Antero Acreage Northern Rich Antero Marcellus Wells (1) High-Graded Core Industry Marcellus Wells (1) 2.24 Bcfe / 1,000’ EURs Antero Marcellus Rig 67% Undeveloped Industry Marcellus Rig Dry Gas High-Graded Core 2.30 Bcf / 1,000’ EURs 78% Undeveloped Southern Rich AR Holds 13% of Undeveloped High-Graded Core 2.24 Bcfe / 1,000’ EURs 70% Undeveloped AR Holds 61% of Undeveloped Southwest Marcellus Core ~2.9 Million Acres 78% Undeveloped Southwest Marcellus Core Has Been High-Graded for Best Well Performance Note: Excludes 600,000 urban acres. 1) Wells completed with ≥ 1,300 lb/ft of proppant. 10 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | SIZE & SCALE IN THE APPALACHIAN BASIN

New Long Lateral Plan 59% of Inventory Now 5- Year Plan Averages 11,500’ ≥ 10,000’ Lateral Length Average Lateral Length Core Inventory by Lateral Length per Completed Well 14,000 1,600 12,700 1,450 1,400 10,800’ 12,000 (No. of locations) 1,200 Average Inventory 10,000 Lateral Length 1,000 Feet 8,000 800 6,000 600 4,000 400 2,000 200 0 0 ≥12,000' <6,000' 6,000' - 8,000' - 10,000' - 2018 2019 2020 2021 2022 8,000' 10,000' 12,000' Wells 145 155 160 165 165 Feet Completed (1) 1) Wells completed reflects midpoint of targeted completions per year. 11 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | SIZE & SCALE IN THE APPALACHIAN BASIN

Why Are We Growing? Outstanding Well Economics Single Well Economics Full Cycle ROR: 28% Half Cycle ROR: 82% Well Economics Full Cycle ROR at $60/Bbl Flat: 33% Support Investment Half Cycle ROR at $60/Bbl Flat: 90% 100% 100% ROR Well in Excess of 90% 90% Cash Cost Economics $60 Oil Cost of Capital 80% 80% 70% 70% Strip Pricing 60% 60% 50% 50% 28% Corporate 40% 40% Level ROR AR Corporate Level 30% 30% Returns 2018 & 2019 Full Cycle 20% 20% Returns 10% 10% WACC ≈ 8% 0% 0% 2018 Completion 2018 Completion 2019 Completion 2019 Completion Program Program Program Program Note: Half cycle burdened with 60% of AM fees to give credit for AM ownership/distributions and variable firm transportation fees. See Appendix for further detail behind full cycle and half cycle single well economics; WACC calculated using CAPM. 12 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | ATTRACTIVE WELL ECONOMICS DRIVES GROWTH

Almost $3B Capital Reduction to 5-Year Plan Consolidated Drilling & Completion Capital Production Targets Expenditures As of December 2016 As of December 2017 As of December 2016 As of December 2017 $2.9B Capex $2.5 $2.4 6.0 $2.2 Reduction 5.2 5.2 $2.0 Cumulative Reduction in Drilling & 5.0 $2.0 4.6 4.5 Completion Capital $1.7 $1.7 4.0 $1.6 3.9 4.0 $1.5 $1.4 $ Billions 3.3 3.3 $1.3 $1.3 $1.3 Bcfe/d 3.0 2.7 2.7 $1.0 Same Production 2.0 Targets $0.5 20% Production CAGR 2018-2020 1.0 15% Production CAGR 2021-2022 0.0 $0.0 2018 2019 2020 2021 2022 2018 2019 2020 2021 2022 Same Production Growth With Much Less Capital Spending 13 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | ATTRACTIVE WELL ECONOMICS DRIVES GROWTH

New Development Plan $2.9B D&C Capex Savings Capital Allocation D&C Capex Lateral Lengths Cycle Times & Enhanced Well Cost Savings Savings Recoveries $0.4B Well Cost Savings Related to reduced AFEs including lower $1.1B flowback water handling cost due to Optimizing Capital Clearwater Facility $2.9B Allocation Capital Efficiencies Captured Within $0.5B Continued shift to high- D&C Capex From graded Marcellus New Development Improved Cycle Program Times Reduced drilling days, increase in stages per day and $0.9B concurrent operations Lateral Lengths $0.09MM/1,000’ savings from 9,000’ to 12,000’ 14 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | COST EFFICIENCY DRIVERS

Lower Capital & Higher Liquids → Free Cash Flow Over $1.6B of Targeted Free Cash Flow from 2018 to 2022 at Strip Pricing Including Maintenance Land Capital Expenditures 5-Year Stand-Alone Free Cash Flow: Cumulative $1,500 Stand-Alone E&P Free Cash Flow Outspend $60 Oil / $2.85 Gas Case Free Cash Strip Pricing at 12/31/17 (Base Case) Flow $50 Oil / $2.85 Gas Case $1,000 $2.8B We Are $500 Here $1.6B $1.0B $0 ($500) ($1,000) ($1,500) 2014A 2015A 2016A 2017E 2018 2019 2020 2021 2022 Guidance Target Target Target Target D&C Capital Investment Fully Funded with Cash Flow Note: See definitions for free cash flow and assumptions behind long-term targets in Appendix; free cash flow definition includes $200MM maintenance land spending, but excludes $300MM discretionary land spending. 15 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | SUSTAINABLE CASH FLOW GROWTH

Significant Exposure to Higher Liquids Prices $2.8B in Free Cash Flow at $60/Bbl from 2018 - 2022 $4.8B in Free Cash Flow at $70/Bbl from 2018-2022 Aggregate 5-Year Annual Free Cash Flow Upside Free Cash Flow Upside Strip Pricing at 12/31/17 $60 Oil / $2.85 Gas Strip Pricing at 12/31/17 $60 Oil / $2.85 Gas $3,000 $1,000 $60 Oil $900 $2,500 $800 $1.2B $700 $2,000 $600 Strip Pricing $500 $1,500 $400 $300 $1,000 $200 $500 $100 $0 $0 2018 2019 2020 2021 2022 Crude Price Scenarios Guidance Target Target Target Target Not Just a Natural Gas Producer Note: See definitions for free cash flow and assumptions behind long-term targets in Appendix. Cash flow assumes 62.5% to 67.5% of WTI Crude price for C3+ in 2018 and 72% in 2019+ (after ME2 in-service). ME2 fees included in transportation costs once in-service. 16 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | 5-YEAR OUTLOOK

Attractive Free Cash Flow Yield 9% AR 8% 8% FCF Yield (1) 7% Surpasses Industry Leading Peers, While Maintaining Strong Production 6% Growth FCF Yield 5% 4% 3% 2% 1% 0% 2018 2019 2020 Free Cash Flow Yields Exceed Both Best-In-Class Peers & Integrated Oil & Gas Companies Note: See definitions for free cash flow and assumptions behind long- term targets in Appendix. “Elite” group of peers includes COG, CXO, EOG, FANG, PXD, XEC; “Integrated” group includes XOM & CVX. Source: Bloomberg. Represents free cash flow yield for the base case at 12/31/17 strip pricing. (1) Represents free cash flow divided by current market capitalization as of 1/12/18. 17 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | 5-YEAR OUTLOOK

Shareholder Interests in Focus: 5-Year Cash Priorities Priorities Sustain Asset Disciplined Growth Optionality Base Investments for Cash Return of Capital Debt Reduction Land Acquisitions $1.6B Free Cash Flow for Deployment $10.4B $5.9B Cumulative Stand-Alone D&C Growth Capital E&P Adjusted Operating Cash Flow $0.2B Land Maintenance $2.7B D&C Maintenance Capital Significant Financial Flexibility with Cash Flow in Excess of Maintenance Capital Note: See Appendix for key definitions and assumptions. Adjusted stand-alone E&P operating cash flow includes $250MM in earn-out payments on water business. 18 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | SUSTAINABLE CASH FLOW GROWTH

Cash Flow Growth → Dramatic Delevering 12/31/17 Strip Pricing (Base Case) $60 Oil / $2.85 Gas $50 Oil / $2.85 Gas 5.0x 23% Debt-Adjusted Production Growth 4.5x Per Share Leverage targets inclusive of $500 MM 3.9x Stand-Alone Financial Leverage 4.0x 3.6x of maintenance and discretionary land capex from 2018 - 2022 3.5x 2.8x 2.8x 3.0x Generates Free 2.5x Cash Flow 2.0x <2.0x by 2019 1.5x Net Debt / LTM Stand-Alone E&P Adjusted EBITDAX 1.0x Balance Sheet Delevering & 0.5x Optionality 0.0x 2014A 2015A 2016A 2017E 2018 2019 2020 2021 2022 Guidance Target Target Target Target Note: See Appendix for key definitions and assumptions. Stand-alone financial leverage is calculated by dividing year-end stand-alone debt by last twelve months stand-alone EBITDAX. Note all free cash flow after land spending is assumed to be used for debt reduction. 19 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | CASH FLOW DRIVES LOW LEVERAGE

Antero Profile To Drive Multiple Expansion Median Debt/ Median EV/ # of Adjusted 2018 Adj. Companies EBITDAX EBITDAX AR 2018E 51 3.1x 7.1x U.S. Publicly Traded E&Ps EBITDAX Multiple: 5.1x  23 1.5x 7.8x Leverage < 3.0x Premium for: Enterprise Value  18 1.9x 8.9x Scale > $10B Production Growth  10 1.5x 9.7x Growth >15% Leverage 6 1.3x 11.1x  Low Leverage <2.0x in 2019 EOG FANG Free  6 1.3x 11.1x CXO COG FCF Generation Cash in 2018 PXD XEC Flow Permian & Appalachia Joining an Elite Group of E&Ps With Scale, Double Digit Growth, Low Leverage & Free Cash Flow Generation Source: Bloomberg & Antero Estimates as of 1/12/18. Adjusted EBITDAX and Adjusted Operating Cash Flow are non-GAAP measures. For additional information regarding these measures, please see “Antero Definitions” and “Antero Non - GAAP Measures” in the Appendix. (1) 20 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | ATTRACTIVE VALUATION

Scale & Growth: Liquids-Rich Resource Meets Capital Efficiency & PAUL RADY GLEN WARREN Chairman & CEO President & CFO 21

A Deep Understanding of the Appalachian Basin 10 NE Marcellus Rigs Core Liquids-Rich Appalachia Undrilled Locations (1) 22 Utica Rigs J B H F I 5% 3% 2% 3% 7% D 7% K 36 SW Marcellus Rigs 7% AR 40% C 13% A 68 Total Rigs 13% 40% of Core Undrilled Liquids-Rich Locations are Held by Antero Note: Core outlines are based upon Antero geologic interpretation, well control, drilling activity, well economics and peer acreage positions; undrilled location count net of acreage allocated to publicly disclosed joint ventures. Rig information per RigData as of 12/8/2017. (1) Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG, RRC and SWN. 22 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE

Defining the Resource: Appalachia Basin Core Analysis • A deep database of peer information and analysis is maintained in house 9,600 Wells – Acreage positions: developed and undeveloped Horizontal Wells Analyzed Since Basin Inception – Well locations, lateral lengths, completions & production results – Optimal undrilled location inventory based on operator well density 7.8 MM Acres • Reservoir engineers assign reserves per well Acreage Analyzed by Antero Teams – Determined EURs on over 9,600 horizontal wells (8,200 Marcellus and 1,400 Utica) via decline curve analysis • Geologists map structure, rock quality and 27,000 Locations pressure Future Locations Plotted on Antero Maps • Core area maps reflect the collective work of our technical teams – Geologists map core areas based on the well data provided by 30 Professionals engineers Involved Team of Geologists, Reservoir – Both productivity and well economics are factored into core Engineers, Land and GIS outlines Cross-Functional Team Works Together to Define Core Boundaries and Competitor Positions In Basin 23 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE

Who Has the Running Room? Undrilled Core Marcellus & Utica Locations (1) Marcellus & Utica Liquids Rich Locations SW Marcellus & Utica Dry Locations NE Pennsylvania Dry Locations 4,000 3,500 Who Can Drill 3,295 Long Laterals? 3,000 Who Has the Undrilled Locations Running Room? 2,500 2,333 We Have 40% of Liquids-Rich Locations 1,930 2,000 Largest Inventory in Appalachia 1,500 1,259 1,000 720 714 663 588 583 556 544 500 - AR A B C D E F G H I J 10,848’ 9,563’ 6,775’ 7,731’ 7,723’ 8,639’ 6,040’ 9,583’ 8,905’ 8,396’ 9,398’ Lateral Length: Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG, RRC and SWN. (1) 24 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE

Core of the Core Antero Acreage Antero Marcellus Wells Northern Rich Industry Marcellus Wells High-Graded Core ~283,000 acres Antero Marcellus Rig 2.24 Bcfe/1,000 ’ Avg. Wellhead EUR Industry Marcellus Rig 67% Undeveloped > 1,300 lb/ft Completions Dry Gas Southern Rich High-Graded Core High-Graded Core ~1,051,000 acres ~487,000 acres 2.30 Bcf/1,000 ’ Avg. Wellhead EUR 2.24 Bcfe /1,000’ Avg. Wellhead EUR 78% Undeveloped 70% Undeveloped AR Holds 13% of Undeveloped AR Holds 61% of Undeveloped Advanced Completions High- Graded Most Active Percent (>1,300 lbs/ft) Core Areas Operators Undeveloped Bcfe / 1,000’ Wells Southwest Marcellus Core Northern Rich RRC, CNX, HG 67% 2.24 474 ~2.9 Million Acres Southern Rich AR, EQT, SWN 70% 2.24 517 ~78% Undeveloped EQT, CVX, Dry Gas 78% 2.30 747 RRC, CNX Recently Expanded Core & High-Graded Core Reflecting Well Performance Note: Excludes 600,000 urban acres. EURs on ethane rejection basis. 25 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE

Core of the Core Development Programs Half Cycle Total Average BTU 2018 Well 2019 Well Well EUR Regime Undrilled Lateral Range Completions Completions Economics Locations Length (Strip Price) Marcellus Highly-Rich Gas 12,500’ 1275-1350 14 30 168% 447 Condensate 11,500’ Highly-Rich Gas 1200-1275 106 101 74% 935 11,150’ Rich Gas 1100-1200 0 4 30% 495 Ohio Utica 9,950’ Condensate 1250-1300 19 2 50% 206 11,550’ Rich Gas 1100-1200 3 9 29% 102 10,450’ Dry Gas 1050 3 9 37% 187 Total (1) 145 155 Program Stats: Program Stats: High-Grade High-Grade Inventory Inventory 78% | 86% 86% | 93% Totals: Averages: Strip | $60 Oil ROR Strip | $60 Oil ROR 11,400’ 2,372 1,253 BTU Average 1,248 BTU Average 1) Wells completed reflects midpoint of targeted completions per year. 26 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE

5-Year Core of the Core Program Highly-Rich Gas Rich Gas Highly-Rich Gas Condensate 1200 – 1275 BTU 1100 – 1200 BTU 1275 BTU+  Well Inventory: 935  Well Inventory: 495  Well Inventory: 447  Avg. Lateral Length: 12,522  Avg. Lateral Length: 11,502  Avg. Lateral Length: 11,158 25 Producing Wells 2.7 Bcfe /1,000’ Average 14 Producing Wells 2.8 Bcfe /1,000’ Average 15 Producing Wells 2.7 Bcfe /1,000’ Average 5-Year Program Producing Wells Antero Marcellus Rig Antero Acreage Note: EUR results include processed volumes and 25% ethane recovery. Includes well results completed with more than 1,500 pound s of proppant per foot. Well volumes based on 12,000’ lateral at 2.0 Bcf /1,000’ wellhead type curve by BTU regime mid-point. See Appendix for further details. 27 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE

A Pioneer in Drilling Longer Laterals in Appalachia Antero Historical & Future Lateral Length Program 300 # of Avg. Lateral Antero Wells Length Total Drilling Program 250 945 8,275 to Date 103 2018-2022 Program (2) 790 11,425 57 Well Count 200 Wells to Date 245 10,700 13 ≥10,000’ 12 93 150 107 100 76 113 81 50 93 78 85 77 22 12 10 4 0 ≤ 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 > 15,000 Lateral Length (1) (1) All laterals rounded to the nearest thousand. (2) Represents wells placed to sales. 28 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: LONGER LATERALS

Lateral Lengths Up 29% in 5-Year Plan Average Lateral Length per Completed Well 2017 Plan 2018 Plan 14,000 12,700 12,400 Average Lateral Length (in feet) 11,600 12,000 10,500 9,700 10,000 9,300 9,200 9,100 9,000 8,600 8,500 8,000 6,000 4,000 2,000 0 2017 2018 2019 2020 2021 2022 Lateral Lengths per Year Increasing by 2,500’ in New Plan (1) Represents 2017 YTD average as of 12.10.2017. 29 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: LONGER LATERALS

Longer Laterals Scale the Resource EURs by Marcellus Lateral Lengths EUR in Bcfe/1,000' 2.3 Bcfe/1,000' R 2 = .73 45 A 1:1 Proportional 40 Increase in EURs with Longer Laterals 35 Antero well results show no evidence of degradation in recovery per foot of completed lateral out to over 14,000’ 30 EUR (Bcfe) 25 20 15 10 5 0 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 16,000 Lateral Length (ft) Note: Assumes 25% ethane recovery. 30 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: LONGER LATERALS

The Longer, the Better… Single Well Economics by Lateral Lengths PV-10 ($MM) ROR (%) $25.0 100% 79% 74% $20.0 67% 80% $20.4 50% $15.0 60% $15.9 $10.0 40% $11.4 $6.8 $5.0 20% $- 0% 6,000' Lateral 9,000' Lateral 12,000' Lateral 15,000' Lateral Note: Represents half cycle economics at strip pricing. See Appendix for further assumptions on single well economics. 31 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: LONGER LATERALS

Well Costs → Longer Laterals is the Next Step Historical Well Costs Utica Marcellus 41% | 43% 2014 2017 2014 2017 Lower Costs $2.20 $2.60 Marcellus | Utica reduction in well costs $2.40 from 2014 to 2017 for a 9,000 ’ lateral $2.00 - 54% from efficiencies $2.20 - 45% from service costs $1.80 $2.00 $MM/1,000 ft of lateral $MM/1,000 ft of lateral $1.60 $1.80 $1.60 $1.40 Reduction 9% | 10% Reduction 43% 41% $1.40 Cost Benefit $1.20 $1.20 Marcellus | Utica reduction in well cost per 1,000’ lateral going from $1.00 9,000 ’ to 12,000’ laterals $1.00 $0.80 $0.80 10% 9% Reduction Reduction $0.60 $0.60 3,000 6,000 9,000 12,00015,000 3,000 6,000 9,000 12,000 15,000 Lateral Length (ft) Lateral Length (ft) Note: Well costs reflect 2,000 pound per foot completions. See Appendix for further assumptions. 32 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: LONGER LATERALS

Reduced Cycle Times Lead to Lower Well Costs Drilling Days Completion Stages per Day 59% | 34% Marcellus Utica Marcellus Utica 45 10.0 Decline in Drilling Days in 7.0 the Marcellus | Utica 40 6.0 35 31 29 29 4.8 30 5.0 Stages per Day Drilling Days 4.2 24 4.0 4.0 25 4.0 3.7 3.5 3.2 3.2 20 18 17 3.0 15 31% | 25% 15 12 2.0 Improvement in 10 8 Marcellus | Utica Stages Per Day 1.0 5 0.0 0 2014 2015 2016 2017 Record 2014 2015 2016 2017 Record Drilling Longer Laterals with Dramatically Fewer Drilling Days and More Stages per Day 33 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: CYCLE TIMES

Operating Evolution Continues Total Well Cost Savings Next Steps in D&C Evolution in the Marcellus (1) • Automated completion equipment 100% 42% → increase stages per day Drilling Vendor Reduction (3%) Decline in well costs 90% • since 2014 Program wide implementation of higher proppant loading, zipper 80% stimulations and longer laterals Completion Vendor % of Total Well Cost Savings Reduction (43%) 70% • Reduced cluster spacing → higher potential recoveries 60% 46% 50% • Sand Vendor-related cost Drilling • 100 mesh efficiency → easier reductions 40% Efficiency (25%) pumping with fewer screenouts • Self-sourcing initiative → reduce 30% supply risk and cost 20% • Fit-for-purpose rigs improves cycle Completion 54% times Efficiency (29%) 10% • Enhanced walking and dual operation Permanent cost capabilities efficiencies 0% • Concurrent operations (“ ConOps ”) • Plan to implement in 2019 (1) Based on Marcellus 9,000 foot lateral and 2,000 pounds per foot AFE. 34 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | OPERATING TECHNOLOGIES EVOLVE

Continuous Design Improvement in Operations Average Wells per Pad by Year Current Well Pads 10 150% Generation 1.0 9 increase in wells 8 Wells per Pad per pad 7 6 5 4 3 2 2010 2011 2012 2013 2014 2015 2016 2017 2018 Map View Pad Size: 3-4 Acres Average Lateral Lengths by Year 12 Well Pad 10,000 Pad Construction 9,000 Drilling 8,000 Feet 70% 7,000 increase in lateral Completion 6,000 lengths 5,000 Production 2010 2011 2012 2013 2014 2015 2016 2017 2018 Rig Wellheads 35 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | OPERATING TECHNOLOGIES EVOLVE

Concurrent Operations Boost Returns ConOps Concurrent vs. Batch (1) 110% Theoretical Best 100% Rate of Return 90% Concurrent Operations 80% 70% Batch Drill Then Complete 60% 2 4 6 8 10 12 Wells per Pad ConOps: Improved Cycle Times Lift Returns “Batch Drill Then Complete” is defined as drilling and completing all wells prior to drill out and subsequent production on a s ingle pad, consistent with Antero’s current approach. “Theoretical Best” assumes drill, (1) complete and put first well on production prior to drilling the second well, etc.; not possible with current wellhead configurat ion of pad. “Concurrent Operations” or ConOps envisions drilling half of the wells on a given pad, and completion and production occurring on the first batch of wells concurrently with drilling activity on the second batch of wells. 36 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | OPERATING TECHNOLOGIES EVOLVE

Pad Designs Support Concurrent Operations New Pads Designed for ConOps Generation 2.0 Completions Fleet Operations 200 Feet Map View Pad Size: Approximately 7 Acres 12 Well Pad Pad Construction Drilling 1 st Six Wells Drilling 2 nd Six Wells Completion Completion Rig Production Wellheads Production Frac Fleet Separation of Wellheads Allows For Drilling to Continue at One End of the Pad, While Completions and Then Production are Underway at the Other End 37 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | OPERATING TECHNOLOGIES EVOLVE

Advanced Completions Drive EURs Higher Increasing EUR per 1,000 ’ (1)(2) Proppant Per Foot Higher Proppant Marcellus Utica per Foot Marcellus Utica 3,000 3.0 has contributed to higher 3.0 2,757 recoveries 2,530 2,500 Processed EUR per 1,000' of Lateral (Bcfe) 2,375 2.4 2.5 2.3 2.3 Pounds of Proppant Per Foot 2,094 2,000 1.9 2.0 1,702 1.8 1.8 1,648 1.7 1.6 1.5 1,500 1,267 1,298 1.5 Marcellus 1,165 1,163 EURs +33% 1,000 1.0 500 0.5 - 0.0 2014 2015 2016 2017 Record 2014 2015 2016 2017 Record Dramatically Improved Well Recoveries From Advanced Completions (1) Based on statistics for wells completed within each respective period. (2) Ethane rejection assumed for Ohio Utica and 25% ethane recovery assumed in 2016-2017 for Marcellus. 38 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: ENHANCED RECOVERIES

Result in Dramatically Lower F&D Cost F&D Cost per Mcfe (1)(2) Marcellus Utica 52% | 42% $1.40 $1.28 Lower F&D $1.20 in Marcellus | Utica $1.00 $0.94 $0.88 $0.80 $0.74 $0.73 $0.73 $0.60 $0.51 $0.42 $0.40 $0.20 $0.00 2014 2015 2016 2017 Dramatic Improvement in Operating Efficiencies, Lower Service Costs and Higher Well Recoveries Have Driven F&D Costs Materially Lower (1) Ethane rejection assumed. F&D cost is defined as current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 85% NRI in Marcellus and 81% NRI in Utica. Please see “Antero Definitions” and “Antero Non - GAAP Measures” (2) in the Appendix. 39 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: WELL COST REDUCTION

Natural Gas Liquids: Leading Position & Strong Fundamentals DAVID CANNELONGO Oil & NGL Marketing Manager 40

Largest NGL Producer in the U.S. NGL Price Exposure Among Top NGL Producers 3Q17 Daily NGL Production Including Recovered Ethane 115.0 45% Pre-hedged Realized Price ($/Bbl) NGL % of Product Revenues 105.6 40% 105.0 35% NGL % of Product Revenues 34% 95.0 34% of AR Q3 2017 30% 30% Revenue from NGLs 85.0 MBbl/d 25% 20% 75.0 15% 65.0 13% 13% 12% 12% 12% 11% 10% 8% 7% 55.0 5% $23.11 $16.93 $15.15 $31.07 $22.38 $20.72 $21.83 $18.96 $22.91 $22.99 45.0 0% AR RRC DVN APC EOG COP CHK PXD NBL OXY Antero Has The Highest NGL Price Exposure Among Top NGL Producers Pre-hedged Realized Price ($/Bbl) Source: SEC filings and company press releases. Note: Realized prices are weighted average including ethane (C2) where applicable. 41 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LEADING THE WAY AS THE LARGEST U.S. NGL PRODUCER

Rapidly Growing NGL Production Antero NGL Production Growth by Purity Product Natural Gasoline (C5+) IsoButane (iC4) 250,000 245,000 Normal Butane (nC4) Propane (C3) C3+ Production Ethane (C2) 200,000 C2 Total (Bbl/d) 150,000 C2 Ethane C3 44,000 100,000 C2 Ethane 26,500 C2 Ethane 17,476 nC4 50,000 iC4 C5+ 0 2014 2015 2016 2017 2018E 2019E 2020E 2021E 2022E Guidance Target Target Target Target Note: Excludes condensate. See Appendix for further assumptions around long-term targets. 42 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LEADING THE WAY AS THE LARGEST U.S. NGL PRODUCER

Current Propane Market Fundamentals U.S. propane exports exceeded excess Resulting in a material reduction in domestic supply in 2016 and 2017 U.S. propane inventories U.S. Propane: Excess Supply vs. Net Exports U.S. Propane Inventories 120,000 Excess Supply Net (Imports) / Exports 5-year Range 2016 2017 800 700 In 2016 U.S. exports 100,000 exceed excess supply by 600 ~120MBbl/d 80,000 500 MBbl MBbl/d 400 60,000 300 40,000 200 2017 inventory is 36% below 2016 inventory levels 100 20,000 - 0 (100) Jan FebMar Apr May Jun Jul Aug Sep Oct Nov Dec 2010 2011 2012 2013 2014 2015 2016 2017 43 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

C3+ NGLs: Absolute & Relative Price Improvement Mt. Belvieu C3+ Price Mont Belvieu C3+ to WTI Price Ratio $2.00 100% $1.80 90% 72% of WTI $1.60 80% $1.40 70% $1.05/gal $1.20 60% $/Gallon % of WTI $1.00 50% $0.80 40% $0.60 30% $0.40 20% $0.20 10% $0.00 0% Tightening Inventories and Increasing Exports, Along With an Increase in Global Product Prices, Resulted in Improvement in C3+ Prices on Both an Absolute and Relative Basis Source: Intercontinental Exchange (ICE) pricing data. Assumes C3+ barrel weightings of: propane 56%, normal butane 16%, Isobutane 9%, pentanes 19%. 44 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

Significant Investment in LPG Infrastructure U.S. LPG Export Capacity Global VLGC Ship Fleet 300 1,400 1,200 250 1,000 200 Vessels 800 MBbl/d 150 600 100 400 50 200 0 0 2012 2013 2014 2015 2016 2017 2012 2013 2014 2015 2016 2017 In response to subdued domestic NGL prices and attractive arbitrage opportunities from 2014 - 2016, a significant investment was made in LPG export and shipping capacity Source: Poten Partners. S&P Global Platts. 45 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

The New Norm: Tighter U.S. Differentials to Global Prices Mont Belvieu vs. Far East Index Baltic LPG Shipping Rates Differential 100 $0.00 90 ($0.20) 80 ($0.40) 70 $/Metric Ton 60 ($0.60) $/Gallon 50 ($0.80) 40 30 ($1.00) 20 ($1.20) 10 ($1.40) 0 2012 2013 2014 2015 2016 2017 2012 2013 2014 2015 2016 2017 As a result of the significant investment, Mont Belvieu transforms from a constrained domestic pricing hub into a globally accepted pricing hub and U.S. differentials shrank Source: Intercontinental Exchange (ICE) pricing data. S&P Global Platts. 46 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

Propane and Butane: U.S. Supply Growth by Region C3+ supply growth from low cost basins: Supply increases ~475 MBbl/d Appalachia (+59%) and Permian (+22%) over the next 3 years to ~2,475 MBbl/d Bakken Supply Mid Continent 400 200 BAKKEN/ 31 +29% WILLISTON 36 MBbl/d 200 100 0 0 +59% 2014 2017 2020 2014 2017 2020 165 MBbl/d NORTHEAST +4% +13% 9 MBbl/d 39 MBbl/d Rockies Supply Appalachia Supply ROCKIES 300 600 MID-CONTINENT 200 400 100 200 PERMIAN 0 0 2014 2017 2020 GULF COAST 2014 2017 2020 +22% Permian and Gulf 226 MBbl/d Coast Supply 2,000 0 Note: Bubbles reflect growth over the next five years (2017-2022). Supply includes field production and refinery production. Excludes imports. 2014 2017 2020 Source: U.S. Energy Information Administration and S&P Global Platts. 47 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

Propane and Butane: U.S. Demand Growth by Sector U.S. Propane & Butane Demand 1,600 1,400 ~145 MBbl/d of U.S. demand growth over 1,200 Refinery/Blending/Other the next 3 years 1,000 MBbl/d 800 Residential/Commercial ~60% of total demand growth 600 driven by petrochemical 400 Petrochemical demand 200 0 2017E 2018E 2019E 2020E Source: S&P Global Platts & U.S. Energy Information Administration 48 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

The Result? The Need for More LPG Exports U.S. Butane & Propane Supply vs. Demand 3,000 U.S. supply growth over 3 years exceeds domestic demand growth 2,500 by ~365 Mbbl/d (including 35 MBbl/d of imports) 2,000 MBbl/d 2017 Exports 1,500 Growth in LPG waterborne exports 1,000 needed to clear the U.S. NGL Market Total U.S. Demand 500 0 2017E 2018E 2019E 2020E Source: S&P Global Platts & U.S. Energy Information Administration 49 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

LPG Exports & Export Capacity – Then vs. Now U.S. has U.S. has Sufficient But is export Then: Now: excess NGL excess NGL export constrained supply supply capacity U.S. LPG Exports vs. Capacity (MBbl/d) Sufficient Historically 1,800 Near-Term Export 1,600 Capacity Constrained 1,400 1,200 1,000 800 600 400 Export Capacity @ 85% Utilization 200 - 2012A 2013A 2014A 2015A 2016A 2017E 2018E 2019E 2020E Source: S&P Global Platts & U.S. Energy Information Administration 50 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

LPG Shipping Fleet Continues to Support Global Trade Ship capacity sufficient to VLGC fleet continues to expand with support global LPG trade ~50 new build VLGC orders through 2020 through 2020 Global VLGC Shipping Fleet vs. Baltic Rates Global LPG Shipping Supply/Demand 350 100 250 Baltic Rates Ship Supply Ship Demand 90 300 80 200 250 70 Baltic Rate ($/ton) 150 VLCG’s 60 200 VLGC’s 50 100 150 40 30 100 50 20 Current VLGC Confirmed 50 Fleet New Builds 10 0 0 0 201220132014201520162017201820192020 Source: Poten Partners 51 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

U.S. Exports Displacing Middle East Exports Northeast Asia LPG Imports by Exporting Region 700 U.S. Middle East Northeast Asia U.S. Share: imported more U.S. 51% 600 LPG cargos than Middle East cargos 513 497 500 for the first time ever in 2017 400 MBbl/d 300 Middle East LPG cargos have remained flat due to 200 strategy of keeping LPG purity products 100 at home and OPEC oil production cuts 0 2013 2014 2015 2016 2017 October 2017 52 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

LPG: Significant Long Term Demand Growth LPG Import Demand Growth by Region Global LPG import China LPG Import (MBbl/d) Japan/S. Korea/Taiwan (MBbl/d) demand increases by Demand LPG Import Demand 1,000 1,000 ~415 MBbl/d from 2017 - 2020 500 500 - - 2017 2020 2017 2020 Asia accounts for ~70% of forecasted worldwide LPG import demand growth through 2020 LPG Import Growth (MBbl/d) (MBbl/d) India LPG Import Demand 2017 - 2020 Indonesia LPG Import (MBbl/d) 1,000 Demand 1,000 Total Asia/Pacific ~300 Europe/Mediterranean ~85 500 500 Latin America ~30 - - Total ~415 2017 2020 2017 2020 Note: Import demand is shown net of domestic production (i.e. country supply/demand imbalance) Source: S&P Global Platts. 53 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

India and China: A Detailed Look at Demand India China  Demand growing with  Aggressive government government initiatives to initiatives to replace wood and displace solid biofuels in rural HOME animal waste with propane in areas households relying on open fires  Build-out of PDH plants from 1  Last planned refinery startup in 2013 to 15 by 2020 accounts (Paradip) marks last major Industrial for roughly half of total Chinese domestic supply addition, in-turn LPG growth supporting further future imports  Upgrade of emissions standards  Increased gasoline taxes have similar to Europe and the U.S. resulted in an uptick in LPG Travel auto-gas demand  Processing plants using butane-  Non-subsidized market Misc./ rich LPG as feedstock Other continues to grow and is price receptive Source: Poten Partners and Dorian LPG 54 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

Global LPG Demand Growth Absorbs Supply Growth LPG Import/Export Growth by Region (MBbl/d) Europe/Med Russia 2017 2020 - 2,000 N. America/Carib (1,000) 1,000 2,000 (2,000) - 2017 2020 1,000 - Middle East 2017 2020 Asia Pacific 2,000 2017 2020 To Asia via Panama 1,000 (500) Canal (1,500) - (2,500) 2017 2020 Africa 2,000 Latin America 2017 2020 - 1,000 (1,000) - 2017 2020 (2,000) Short LPG Long LPG (-415) +415 Source: Poten Partners. 55 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

C3+ NGLs: Northeast Market Dynamics and Supply ~165 MBbl/d of Northeast C3+ demand vs. Northeast C3+ NGL Takeaway ~350 MBbl/d of Northeast supply in 2017 - Resulted in 47% of production consumed locally - Remainder moved primarily by rail Midwest/ Conway Mariner East II provides Mariner East 1 additional “baseload demand” Cornerstone 70 MBbl/d and access to international LPG Mariner East 2 Export markets 275 MBbl/d – 2Q 2018 Markets Mariner East 2X: 250 MBbl/d 1Q 2019 Northeast C3+ NGL Supply 700 600 U.S. Gulf Pentanes 500 Coast IsoButane 400 Butane 300 200 Propane 100 0 Antero’s C3+ differential to Mt. Belvieu is expected to improve in 2018 with the Mariner East 2 export takeaway and ability to access international markets Source: S&P Global Platts 56 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

C3+ NGLs: Northeast Supply & Demand Northeast C3+ NGL Supply vs. Demand & Takeaway Capacity Excluding Rail (MBbl/d) Long Local Demand and Short Local Demand & Sufficient 800 Pipeline Capacity Pipeline Capacity Pipeline Mariner East 2 = Tight Differentials = Wide Differentials Capacity = Tight Expansions ~$(2.00)/Bbl vs. Mont ~$(6.00)/Bbl vs. Mont 700 Differentials Belvieu Belvieu 600 500 400 Mariner East 2 Rail fills short 300 term gaps Cornerstone Mariner East 1 200 100 Local Demand & TEPPCO 0 Northeast C3+ markets became oversupplied in 2015 and forced to ship via more expensive rail, which is relieved by Mariner East 2 and other potential projects Source: S&P Global Platts 57 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

LPG: Marcus Hook vs. U.S. Gulf Coast Shipping Appalachia is geographically advantaged for Northwest Europe cargos and at parity with Gulf Coast for Asia destination cargos LPG Shipping Routes and 2018 Propane Netbacks ($/Gallon) Antero Netback 2018 Antero Netback 2018 NWE Price ($/Gal) $0.97 FEI Price ($/Gal) $1.04 Pipeline & Terminal (1) $(0.19) Pipeline & Terminal (1) $(0.19) Shipping $(0.05) Shipping $(0.14) NWE Netback $0.73 Marcus Netback $0.71 Uplift vs. $0.25/Gal Hook $0.13 Uplift vs. $0.25/Gal Rail to Mt. Belvieu $0.11 Rail to Mt. Belvieu U.S. Gulf Coast FEI FEI To Asia via Panama Canal Source: Poten Partners. Note: Based on Baltic forward shipping rates and propane strip prices as of 12/31/17. Includes associated port and canal fees and charges. (1) Based on Wall Street research. 58 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

2018 Guidance: Transition to Free Cash Flow & Low Leverage MICHAEL KENNEDY SVP of Finance & CFO, Antero Midstream 59

2018 Guidance Overview 2018 Guidance: Generating Free Cash Flow Stand-Alone E&P Consolidated Adjusted EBITDAX (1) $1,700 - $1,800 $2,050 - $2,150 ($220) – ($200) ($300) – ($250) - Interest Expense Adjusted Operating Cash Flow (2) $1,480 - $1,600 $1,750 - $1,900 - D&C CapEx & Land ($1,525) N/A Maintenance Expenditures Free Cash Flow Before Change in $15 N/A Working Capital & Land (at Midpoint) Note: See Appendix for definitions of non-GAAP terms. Adjusted EBITDAX and Adjusted Operating Cash Flow are non-GAAP financial measures. For additional information regarding these m easures, please see “Antero Definitions” and “Antero Non - GAAP Measures” in the (1) Appendix. (2) Before change in working capital. 60 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | GUIDANCE

2018 Product Revenue Buildup Volumes Realized % of Total Product Revenues (Guidance) Price Volume 38% Liquids as a Percent Natural Gas NGLs Crude 1,925 of Total Volume $2.85/Mcf $2.0B 52% GAS MMcf/d 44 MBbl/d $10/Bbl $0.2B 5% C2 $1.5B Liquids Revenue 77.5 MBbl/d $39/Bbl $1.1B 28% C3+ 9.5 MBbl/d $54/Bbl $0.2B 5% Oil Hedges 43% | 38% N/A $0.45/Mcfe $0.4B 10% Pre- | Post- Hedge Liquids as Percent of 2,700 Revenue $4.00/Mcfe $3.9B 100% MMcfe/d Note: See Appendix for key assumptions 61 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS

2018 Natural Gas Market Mix Antero Firm Transportation Portfolio in 2018 % of Gas Index Differential Sold TETCO M2 $(0.53) 10% Local Mid-Atlantic $(0.34) 6% Markets TCO $(0.27) 16% Gulf Coast $(0.14) 41% 10% of FT Portfolio $(0.53)/Mcf Midwest $(0.13) 27% Differential Weighted Average $(0.21) 100% vs. NYMEX: Antero BTU Uplift $0.24 Producing Areas All-in vs. NYMEX +$0.03 +$0.00 - $0.05 forecasted premium to NYMEX after BTU uplift 90% of Antero Gas Is Sold In Favorably Priced Markets Note: Based on 2018 strip pricing as of 12/31/2017. See Appendix for further assumptions. 62 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS

Well Hedged at High Prices Relative to Strip Commodity Hedge Position Average Index Hedge Price (1) Current NYMEX Strip (2) Hedged Volume Mark-to-Market Value (2) 2.8 Tcfe hedged through 2,330 2,400 $5.00 $3.5B of gains on 2023 at $3.39/MMBtu 2,141 $4.50 ~19 MBbl/d of propane hedges since 2008 1,900 hedged in 2018 at $0.75/Gal $4.00 $3.66 $3.50 $3.50 $3.25 $3.00 $3.00 $2.91 1,400 $3.00 $2.93 $2.89 $2.84 $2.85 $2.82 $2.81 $2.50 1,418 850 900 $2.00 710 $1.50 400 $1.00 $450 MM $584 MM $225 MM $38 MM $35 MM $0 MM 90 $0.50 -100 $- 2018 2019 2020 2021 2022 2023 ~ 100% of 2018 and 2019 Target Gas Production Hedged ~$1.3B Mark-To-Market Unrealized Gains Based On 12/31/2017 Prices (1) Weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio. Includes 19,000 Bbl/d of propane hedged at $0.75/gallon and 4,000 Bbl/d of oil hedged at $55.97/Bbl in 2018 (2) As of 12/31/17. 63 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PRODUCTIVITY DRIVERS

2018 C3+ NGL Pricing & Market Mix Antero 2018 C3+ NGL Production Netbacks 100% 90% Weighted Average C3+ $/Bbl Pre-ME2 Post-ME2 80% Marcus Realized Pricing Location Houston, PA Hook Dock 70% Propane (C3) – 56% Mont Belvieu Price (1) $41.00 $41.00 60% 50% Differential/Uplift Net of Cost (2) $(5.50) +$2.00 40% Antero Realized C3+ Price $35.50 $43.00 Butane (C4) – 16% 30% % of WTI 60% 72% IsoButane (IC4) – 9% 20% 2018 Weighted Average 62.5% - 67.5% of WTI 10% Pentane (C5) – 19% 0% 2018 Weighted Average ~$39/Barrel Antero C3+ NGL Barrel Composition Antero projects C3+ NGL price to be ~62.5% to 67.5% of WTI in 2018 Note: Based on 2018 strip pricing as of 12/31/17. (1) Based on weighted average Antero C3+ NGL barrel composition times individual purity product price. (2) Uplift assumes strip NGL pricing for Northwest Europe and Far East Index before ME2 fees, which will be included in the GPT expense item. 64 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS

Significant Value Derived from Midstream Ownership Antero Midstream Targeted Distributions to Antero Resources $450 $400 $350 $300 $ in MMs $250 $200 $132 $150 $112 $89 $100 $50 $- 2015A 2016A 2017A 2018E 2019E 2020E 2021E 2022E Note: Represents distribution growth targets for AR owned units through 2022. As of 9/30/17, AR owns 98.9 million AM units. 65 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK

2018 Stand-Alone E&P EBITDAX Margin Stand-Alone E&P EBITDAX Margin Waterfall ($/Mcfe) AM Distributions $4.50 Fully Burdened $4.18 Stand-alone gathering fees $0.10 $0.17 $1.75B Stand- $0.11 $4.00 $0.45 Alone E&P Hedges $0.65 $3.50 EBITDAX Revenues = $1.80/Mcfe X 2.7 $0.60 $3.00 Bcfe/d of production Liquids FT $0.10 $2.50 Gas FT $0.55 $1.80 $0.13 $2.00 $0.15 $3.56 $0.45 $1.50 Hedges $1.00 $1.34 $0.50 $0.00 Revenues, LOE and Gathering & Processing & Firm Net Marketing Cash G&A Stand-alone Hedges, Production Compression Fractionation Transportation Expense E&P EBITDAX AM Taxes Fees Expenses Expenses Margin Distributions 66 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | ATTRACTIVE MARGINS

Midstream Driving Value for AR Since Inception Antero Midstream Return on Investment for AR (Pre-tax) (1) $7,000 $6,117 $3,112 $6,000 4.7x Cash Proceeds (SMM) ROI $5,000 $4,000 $250 $321 $2,756 $311 $3,000 $179 $795 $2,000 $1,150 $1,000 $0 AM IPO (2014) Sale of Water Sale of AM Sale of AM AM Total Proceeds Expected Pre-tax Value Pre-tax Business Units (2016) Units (9/6/17) Distributions to Date Earnout of AM Units Cumulative (2015) Received as of Payments Held by AR @ Value of Antero 12/31/17 (2019E-2020E) $31.75 Midstream (01/12/18) Takeaway Downstream Return on Assurance Visibility Investment (1) Midstream proceeds received by AR to date plus market value of AR’s 53% ownership of AM at 1/12/18 divided by the approx imate $1.3B of AR capital invested at time of AM IPO. 67 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | ATTRACTIVE MARGINS

Understanding Liquids Uplift and Processing Costs Antero Processing Benefit vs. Cost Benefits Costs 1250 BTU ($/Mcfe) $0.75 / Mcfe 2.75 GPM $1.60 Uplift from liquids (Partial Ethane $1.45 production, net of Recovery) $1.40 processing and liquids $0.19 $1.26 transport fees $1.20 $0.60 C3+ $1.00 $0.75 $0.10 $0.80 $1.11 $0.60 $0.40 $0.20 Ethane $0.15 $0.00 NGL Uplift Oil Uplift Processing Cost Transportation Cost Net Gas Equivalent Price (Net of Liquids Transport) Note: Based on 2018 strip pricing as of 12/31/17. 68 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | LIQUIDS UPLIFT

Price Certainty Gained from Firm Transportation Natural Gas Price Differentials Relative to NYMEX Appalachia (1) Antero Realized Differential (2) 3-Year Appalchian Average 3-Year Antero Realized Basis $0.50 Antero – Low Volatility Price Certainty ($0.03) $0.00 ($0.50) Limited ($1.03) ($1.00) Northeast Pricing Exposure ($1.50) Floating – High Volatility ($2.00) Limited Volatility ($2.50) (1) Reflects discount to NYMEX for Appalachia in-basin pricing at Dominion South & TETCO M2 indices. (2) Represents simple average discount to NYMEX for Antero firm transportation capacity. 69 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK

Significant Value Derived from Firm Transportation Natural Gas Price Realization Relative to Appalachia In-Basin Pricing AR Price Realization In-Basin Price(1) AR Prices Net of FT & Net Marketing Expense (Excluding Hedges) $4.50 $4.10 $4.00 Realized $491 MM price, net of $3.82 all FT costs $3.50 Total Value Created from FT $3.82 exceeds in- $3.18 Portfolio Since 2014 basin prices $3.27 $3.00 $/Mcf $2.50 $2.37 $2.50 $2.39 $2.39 $2.24 $2.00 $1.80 $1.80 $1.70 $1.70 $1.50 $1.49 $1.47 $1.00 $0.50 $173MM $148MM $109MM $62MM $0.00 2014 2015 2016 YTD 2017(2) (1) Assumes Dominion South annual averages for Appalachia in-basin pricing. (2) YTD through September 2017, adjusted for contractual disputes on natural gas firm sales. 70 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK

2018 Guidance: Understanding FT, Marketing & Hedge Benefits $0.34/Mcfe Uplift Firm Hedge Book in Realized Gas Prices vs. Local Transportation Dominion South index (1) Benefits Costs $3.30 $3.50 $0.45 $2.85 $0.55 $3.00 $2.75 $2.63 $0.13 $0.56 $2.50 $2.29 $0.34 $2.00 $/Mcf $1.50 $1.00 $0.50 $0.00 Dominion South Firm Hedge Gains Firm Net Marketing Net Uplift to Strip Pricing Transportation Transportation Expense Dominion South Pricing Uplift Cost Strip Pricing Note: Based on strip pricing as of 12/31/17. 71 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK

Attractive Gas Marketing Plan Hedge Portfolio Supports Net Marketing Expense (High End) Firm Commitments Net Marketing Expense (Low End) Hedge Gains $585 $0.48/Mcfe $600 $469 5-Year Cumulative: $0.45/Mcfe Firm Transportation Portfolio $500 Hedge Gains: $1,350 Allows Antero to achieve: Marketing Expense: ($472) $400 Net Uplift: $878 $ Millions $300 $224 $0.20/Mcfe $0.15/Mcfe Effectively $200 Premium Price Hedge NYMEX $0.15/Mcfe Certainty Index $0.15/ $100 Less volatility and < $0.10/ A key advantage as Mcfe $37 $35 greater surety in $0.10/ Mcfe our product is Mcfe realized prices $0 $0 delivered to NYMEX- $0 related markets 2018 2019 Target 2020 Target 2021 Target 2022 Target Guidance Hedge Gains More than Offset Marketing Expense – Hedges Support FT Commitments 72 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK

Understanding G&A: Most Productive Employees Production Per Employee (MMcfe/d) (1) Production per Employee Peer Average AR A B C D E F G H I J K L 5.00 528 241 576 762 467 1,469 1,080 1,809 856 994 850 1,085 3,604 4.00 3.5 3.0 3.0 2.3x 3.00 2.0 1.8 More Productive Employees 1.5 2.00 1.5 1.2 1.1 Based on Daily Production 1.1 0.9 0.9 0.8 1.00 0.4 0.00 AR A B C D E F G H I J K L EBITDAX Per Employee ($MM) 2.9x Peer Average Peer Average $3.5 More Productive Employees $2.9 $3.0 on an EBITDAX Basis $2.5 $1.7 $1.7 $1.5 $2.0 $1.5 $1.2 $1.0 $1.0 $0.9 $0.9 $0.8 $0.7 $0.5 $0.5 $1.0 $1.0 $0.5 $0.0 AR A B C D E F G H I J K L Note: Peer group includes: Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG Energy, RICE, RRC and SWN. (1) Based on 2016 actuals. 73 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PRODUCTIVITY

Peer Leading Margins: Before NGL Price Uptick 3Q 2017 Stand-Alone E&P Adj. EBITDAX Margins (Pre-Hedge / Pre-Marketing Expense) (1) #1 4 3 2 5 Margin Rank: $4.00 $3.47 $3.50 $2.79 $2.78 $3.00 $2.24 ($/Mcfe) $2.50 $2.05 $2.00 $2.09 $1.75 $1.56 $1.50 $0.99 $1.23 $1.00 $1.38 $1.25 $1.22 $0.50 $1.04 $0.82 $- AR A B C D Adjusted EBITDAX GPT LOE Ad Valorem G&A Revenue Cash Costs 3Q 2017 Stand-Alone E&P Adj. EBITDAX Margins (Post-Hedge / Post Marketing Expense) (1) #1 2 4 3 5 Margin Rank: $3.76 $4.00 $3.50 $2.86 $2.87 $3.00 $2.27 $2.50 $2.13 ($/Mcfe) $2.22 $1.75 $2.00 $1.54 $1.50 $1.25 $1.00 $1.00 $1.54 $1.33 $1.27 $1.11 $0.50 $0.88 $- AR A B C D $(0.50) Adjusted EBITDAX GPT LOE Ad Valorem G&A Net Marketing Revenue Cash Costs Source: SEC filings and company press releases. AR margins exclude $0.21/Mcfe negative impact from WGL and SJR natural gas contract disputes. Peers include COG, EQT, RRC & SWN. (1) AR and EQT EBITDAX include distributions from midstream ownership. Cash costs for AR and EQT represent stand-alone GPT, production taxes, LOE and cash G&A. AR’s EBITDAX excludes net marketing expense and the hedges put in place to support firm transportation. (2) 74 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | ATTRACTIVE MARGINS

Attractive 2018 E&P Margins and Recycle Ratio Antero Fully Burdened Stand-Alone E&P Cash Margins ($/Mcfe) ($/Mcfe) $2.50 3.4x $2.00 $1.80 $1.80 Recycle Ratio (1) $1.59 $0.21 $0.45 $1.50 $0.45 Hedges Hedges $1.00 2.7x Unhedged $1.34 $1.13 $0.47 $0.50 Recycle Ratio (1) $0.00 Stand-Alone E&P Interest Stand-Alone E&P 2018 F&D Cost EBITDAX expense Cash Margin Margin Note: Assumes $0.17/Mcfe in distributions from AM. Based on EURs from Antero 2018 development program. (1) Represents stand-alone, fully burdened E&P basis, based on 2018 development program. Unhedged recycle ratio excludes net marketing expense of $0.125. 75 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | ATTRACTIVE MARGINS

Antero Consolidated and Stand-Alone Enterprise Value ($MM) $12,000 $10,801 $1,077 $10,000 Net Debt $2,796 $8,000 $4,529 $6,928 ~$1,300 21% tax on $6,000 Hedge MTM value of AM units (net of NOLs) Market $4,000 E&P Value Assets 99MM units $6,272 owned and AM $5,628 $2,000 market price of $31.75/unit $0 Consolidated Antero Midstream After Tax Value of AM AR Stand-alone Enterprise Value Net Debt Owned Units E&P Value Note: Data as of 9/30/17, except AM unit price as of 1/12/18 and hedge mark-to-market as of 12/31/17. See Appendix for further details on Antero trading multiples. 76 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | VALUE CREATION

5-Year Outlook: Disciplined Growth Drives Equity Upside GLEN WARREN President & CFO 77

Financial Policy Overview Fund drilling & completion capital with stand-alone upstream cash Free Cash Flow flow from operations (including AM distributions and earn-out payments from water business sale in 2015) Maintain conservative leverage profile below 3.0x near-term (on a Leverage stand-alone basis) with a medium-term target of below 2x Continue to hedge over a rolling five to six year period to support Hedge Program consistent production development into long-term processing and firm transportation commitments, smoothing volatile oil & gas prices Maintain stand-alone AR liquidity of at least ~$1B on a $2.5B credit Liquidity facility Investment Accelerate trend towards investment grade quality – current Grade Debt corporate ratings Ba2/BB/BBB- 78 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE

Commodity Outlook Outlook Factors + Strip weighed upon by wind power hedging and upstream acquisition hedging + Operators drilling up their best gas inventory in U.S. Constructive Mid-Term, over next several years Natural Gas Positive Long-term + Strong demand growth – LNG, Mexico, coal displacement, petchem, etc. - Associated gas growth from Permian + Solid global demand growth with aligned global economic growth + E&P capital discipline Oil Positive + OPEC / Russia production compliance - Permian activity level + Long-term Asian residential / commercial demand growth correlated to GDP growth + Flat to declining LPG exports from Mid-East + Export terminal buildouts continue NGLs Positive + Some incremental LPG demand growth awaiting FID and not counted by research - High growth in U.S. NGL supply from Permian and Appalachia Note: See Appendix for key definitions. 79 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | 2018 OUTLOOK

Looking to the Future: Disciplined Growth 2,500 ’ Average Increase 365 Fewer Completions $2.9B Cumulative Savings, in Lateral Length Per Well than Previous Plan Same Production Targets Planned Antero Well Completions by Year (2018-2022) Lateral Length January 2017 Plan January 2018 Plan (Low-End) 400 365 Lateral Length January 2018 Plan (High-End) Cumulative Well Count Reduction 350 290 300 255 240 230 250 190 190 175 200 170 170 160 165 150 150 160 160 155 150 140 80 100 45 50 8,500 9,100 9,700 9,000 10,500 8,600 11,600 9,200 12,400 12,700 0 2018 2019 2020 2021 2022 Drilling & Completion Capital Budget and Targets 2018 – 2020 Targets 2021 – 2022 Targets Consolidated Drilling & Completion ($MM) ~$1.3B Annually $1.4 - $1.7B Annually Stand-Alone Drilling & Completion ($MM) (1) ~$1.5 - $1.6B Annually $1.7 - $2.0B Annually % Production Growth Target 20% CAGR ~15% Growth Annually (1) Includes full water fees paid to Antero Midstream for water handling and treatment services (fees are eliminated in consolidated financials). 80 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | CAPITAL DISCIPLINE

Capital Budget Discipline Historical Consolidated D&C Capital Spend vs. Initial Guidance Initial Guidance Actual $2,000 $1,800 + 4% Within Initial +3% D&C Targets Set at $1,600 Outset of the Year +2% $1,400 Capital Spend ($MM) (4%) $1,200 $1,000 $800 $600 $400 $200 $0 2015 2016 2017 2018 2019 2020 2021 2022 A Proven Track Record of Meeting D&C Capital Guidance 81 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | CAPITAL DISCIPLINE

Same Production Growth With Much Less Capital Spending Consolidated Drilling & Completion Production Targets Capital Expenditures As of December 2016 As of December 2017 As of December 2016 As of December 2017 $2.5 $2.4 6.0 $2.2 5.2 5.2 $2.0 5.0 $2.0 4.6 4.5 $1.7 $1.7 4.0 $1.6 3.9 4.0 $ Billions $1.5 $1.4 3.3 3.3 $1.3 $1.3 $1.3 Bcfe/d 3.0 2.7 2.7 $1.0 2.0 $0.5 1.0 $0.0 0.0 2018 2019 2020 2021 2022 2018 2019 2020 2021 2022 82 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | CAPITAL DISCIPLINE

Attractive Debt-Adjusted Production Driving Cash Flow 23% CAGR in 22% CAGR in Net Production per Debt-Adjusted Share (Mcfe/share) $10.00 Debt-Adjusted Production Discretionary Cash Flow 6.0 Per Share Through 2022 Per Share Through 2022 Discretionary Cash Flow Per Share $8.00 5.0 4.0 $6.00 3.0 $4.00 2.0 $2.00 1.0 0.0 $0.00 2017E 2018 2019 2020 2021 2022 Guidance Target Target Target Target Production Per Share Cash Flow Per Share Accelerating Debt-Adjusted Production Per Share Drives Cash Flow Per Share Growth Note: Debt-adjusted production per share assumes Antero (AR) share price of $19.87, per 1/12/18 closing price. 83 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | SUSTAINABLE CASH FLOW GROWTH

Low Maintenance Capital: Key to FCF Generation Maintenance Capex Growth Capex $10.4B projected cash flow $3,000 ~800 wells completed $2,500 $5.9B growth capex $2,000 ~560 wells completed $MM $1,500 $2.9B maintenance (including land) $590 MM per year Growth Capex $1,000 $500 $1.6B projected free cash flow Maintenance Capex at YE 2017 Strip Pricing $0 (~$55 Oil / $2.84 Gas) 2018 2019 2020 2021 2022 Delivers $1.6B Projected Free Cash Flow Net of Maintenance and Growth Capital Note: See Appendix for key assumptions and definitions. 84 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | SUSTAINABLE CASH FLOW GROWTH

Liquidity & Debt Term Structure 9/30/2017 Debt Maturity Profile AR Credit Facility AM Credit Facility AR Senior Notes AM Senior Notes $1,800 $1,600 AR 2025 Notes (1) Yielding 4.4% $427 AM 2024 Notes (1) Yielding 4.4% $1,400 New credit facilities for AR and AM have allowed $1,200 Antero to extend its average $25 $1,000 debt maturity out to 2022 $1,000 $1,100 $750 $800 $650 $600 $600 $400 $200 $0 2017 2018 2019 2020 2021 2022 2023 2024 2025 (1) As of 1/12/18 85 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | FINANCIAL PERFORMANCE & PRINCIPLES

Positive Ratings Momentum Historical Corporate Credit Ratings Corporate Credit Rating (Moody’s / S&P / Fitch) Investment Grade Baa3 / BBB- Rating: BBB- Fitch January 2018 Ba1 / BB+ Ba2/BB Moody’s/S&P Ba2 / BB Ba3 / BB- B1 / B+ Stable through B2 / B commodity price crash B3 / B- Caa1 / CCC+ 10/21/2013 9/4/2014 3/31/2015 9/1/2010 2/24/2011 5/31/2013 12/31/2016 12/1/2017 Fitch Moody's S&P Antero Has Enjoyed Positive Debt Ratings Momentum Since 2010 86 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | ACCELERATED FOCUS TOWARDS INVESTMENT GRADE

Key Takeaways Announcing New Long Joining an Lateral Development Plan Averaging 11,500’ Elite Group With: Sustainable Cash Flow Growth Scale Step Change in Capital Generating 5-Year Free Cash Efficiency Reducing 5-Year Flow of $1.6B at Strip & $2.8B at $60 Oil D&C Capex by $2.9B Double Digit Growth Largest NGL Producer in Disciplined Returns U.S. With Highest Leverage Low Focus to Rising NGL Prices Leverage → 28% Full Cycle Returns → 23% 5-Year Debt-Adjusted Production CAGR per share → 22% 5-Year Cash Flow Free Cash CAGR per share Size & Scale to Flow Capitalize on Resource Note: See definitions for free cash flow and assumptions behind long-term targets in Appendix; free cash flow definition includes maintenance land spending, but excludes growth land spend. 87 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | VALUE PROPOSITION

Appendix I Supplemental Materials 88

What Drives NGL Product Pricing? Gas Linked Crude Linked Ethane Propane Butane IsoButane Pentane (C2) (C3) (C4) (IC4) (C5) Heating, Alkylate feed to Ethylene Winter gasoline Gasoline blend Primary Use Crop drying, produce Production Blending and diluent Commercial gasoline Pet Chem Refineries/ Flexible Pet Limited by facilities that Blenders, Pet Price Makers Chem and Alkylate Refineries can consume Chem and exports production crude exports Ethane Only Heating fuel Commercial DilBit Price Takers Refineries Pet Chem consumers users producers Crude Crude Crude Crude (via winter Limited ceiling (Naptha derived Crude Price Ceiling (via winter gasoline, Global due to requiring ethylene & Naptha heating) LPG prices, Alkylate in production) propane) RBOB Gasoline & Natural Gas Ethane Price Propane Price Refined Refined Price Floor Price (Ethylene (Ethylene Products Price products (Rejection) switching) switching) price 89 APPENDIX I | SUPPLEMENTAL MATERIALS

Ethane: Northeast Market Dynamics & Supply Ethane Rejection and Transportation Rates by Region West of Appalachia Bakken Rejection Appalachia 100 78 31 BAKKEN/WILLISTON 46 50 4 0 0 2012 2017 2022 Rockies Rejection NORTHEAST 142 3 150 123 ROCKIES 100 2 Appalachia Rejection 50 19 294 300 0 158 2012 2017 2022 200 TEXAS & GULF COAST 100 1 0 1 2012 2017 2022 Texas & Gulf Coast Rejection 200 103 100 45 U.S Gulf 5 0 Coast 2012 2017 2022 Source: S&P Global Platts and EnVantage 90 APPENDIX I | ETHANE FUNDAMENTALS

Ethane: Significant Demand Growth On Horizon Incremental U.S. Ethylene Plant Demand Over 1.0 MM MBbl/d of barrels per day of Ethane incremental ethane 1,200 demand, including ~167 MBbl/d in the 1,028 Northeast 1,000 173 855 “First Wave” 750 800 105 Ethylene crackers under 657 92 construction will add ~855MBbl/d of ethane 600 165 demand by the end of 492 2021 400 309 “Second Wave” 183 Ethylene crackers under 200 consideration in 2022+ 183 with potential to add additional 173 MBbl/d - of ethane demand 2017 2018 2019 2020 2021 2022+ 91 APPENDIX I | ETHANE FUNDAMENTALS

Ethane: Northeast Market Dynamics & Supply ~190 MBbl/d of ethane current rejected in Northeast Ethane Takeaway and Capacities Northeast (~48% of potentially recoverable ethane) Antero is an anchor supplier to Shell’s Shell Cracker cracker expected in 2021 105 MBbl/d Mariner West 50 Mbbl/d Utopia East Mariner East PTT evaluating a world scale cracker with 75 MBbl/d 70 MBbl/d expected FID 2018 1Q18 Mariner East 2X: Northeast Ethane Supply (MBbl/d) TBD MBbl/d 1Q19 800 Actual Ethane Recovery Announced De-ethanization 700 Full Ethane Recovery Capacity (MBbl/d) 500 600 390 390 357 400 500 ME2X 270 300 400 Shell Cracker 177 200 128 103 300 Mariner East 0 40 100 Utopia 0 200 0 Mariner West 100 ATEX 0 Antero’s Ethane Has a Natural Gas Value Pricing Floor; Pricing Improvements at Mont Belvieu and Additional Petrochemical or Takeaway Demand is All “Upside” Source: S&P Global Platts 92 APPENDIX I | ETHANE FUNDAMENTALS

Credit Facility Update: October 2017 Old Facility New Facility Borrowing Base $4,750 MM $4,500 MM Commitments $4,000 MM $2,500 MM Maturity 5/5/2019 5 Years (2022) Same as existing, until at least one of Moody’s or First-priority, perfected liens and security interests S&P assigns the Borrower a Senior Unsecured on substantially all assets including oil and gas Security Rating > Baa3 or BBB-, at which time the Borrower properties comprising no less than 80% of the may elect to enter into a “Release Period”, effectively total value of the Borrowing Base properties. going unsecured Borrowing Libor margin Commitment Borrowing Base Libor margin Commitment fee Base Utilization (bps) fee (bps) Utilization (bps) (bps) < 25% 150.0 37.5 < 25% 125.0 30.0 > 25%, < 50% 175.0 50.0 > 25%, < 50% 150.0 30.0 Pricing > 50%, < 75% 200.0 50.0 > 50%, < 75% 175.0 35.0 > 75%, < 90% 225.0 50.0 > 75%, < 90% 200.0 37.5 > 90% 250.0 50.0 > 90% 225.0 37.5 Below Investment Grade Period: Below Investment Grade Period: • • Current Ratio of > 1.0x Current Ratio of > 1.0x • • Interest Coverage Ratio of > 2.50x Interest Coverage Ratio of > 2.50x During Investment Grade Period: Covenants • Current Ratio of > 1.0x • Leverage Ratio of < 4.25x • PV-9 / Total Debt > 1.50x (1) Antero Recently Closed on a New Credit Facility That Reduced Commitments From $4.0B to $2.5B and Added Investment Grade Fall-Away Covenants (1) Only applicable upon going unsecured with only one investment grade rating and until the second investment grade rating is achieved. 93 APPENDIX I | CREDIT FACILITY UPDATE

3Q 2017 Segment EBITDAX & Capital Expenditures Gathering and compression fees paid to Antero Midstream are included in Gathering, Processing & 1 Transportation expense on stand-alone basis (eliminated on consolidated basis); Gathering and compression operating expenses borne by AM on stand-alone basis (included in GPT on consolidated basis) Water fees paid to Antero Midstream included in Drilling & Completion capital expenditures on stand-alone 2 basis; water operating expenses borne by AM on stand-alone basis and AR on consolidated basis ($MMs) Stand-Alone Water Elimination of Adjusted EBITDAX Exploration & Gathering & Handling & Intersegment Consolidated : $284 Million (1) Production Processing Treatment Marketing Transactions Total : $128 Million Revenues: Third-Party $660 $7 $0 $51 - $718 Intersegment 1 98 93 - (191) - Gains on settled derivatives 61 - - - - 61 Total Revenue $722 $105 $93 $51 (191) $780 Cash operating expenses: Lease operating $24 - $52 - ($52) $23 Gathering, Processing & Transp. (3rd party) 272 - - - - 272 Gathering, Processing & Transp. (AM fees) 98 10 - - (98) 10 Production Taxes 22 0 1 - - 23 G&A (before equity-based comp) 29 4 3 - (0) 36 Marketing - - - 79 - 79 Total Cash Operating Expenses $445 $15 $55 $79 ($150) $443 Segment Adjust EBITDAX $278 $90 $38 ($28) ($41) $336 On consolidated basis, water fees are eliminated from D&C Capital Expenditures: capital, but water operating expenses are capitalized D&C (excluding water) $265 - - - - $265 D&C (including water) 93 - - - (41) 52 Land / Acquisitions 57 - - - - 57 G&C / Water Infrastructure - 99 48 147 Total CapEx $415 $99 $48 $0 ($41) $522 (1) AR stand-alone EBITDAX represents E&P EBITDAX plus ~$35 million in distributions from AM ownership less net marketing expense. 94 APPENDIX I | SUPPLEMENTAL MATERIALS

Appendix II Guidance Material & Cautionary Language 95

2018 Guidance Stand-Alone E&P Consolidated Net Daily Production (Bcfe/d) ~2.7 Net Liquids Production (BBl/d) ~130,000 Natural Gas Realized Price Differential to $0.00 to $0.05 Premium Nymex C3+ NGL Realized Price 62.5% – 67.5% (% of Nymex WTI) $2.10 – $2.20 $1.65 – $1.75 Cash Production Expense ($/Mcfe) Marketing Expense ($/Mcfe) $0.10 – $0.15 (10% Mitigation Assumed) G&A Expense ($/Mcfe) $0.125 – $0.175 $0.15 - $0.20 (before equity-based compensation) $1,700 – $1,800 $2,050 – $2,150 Adjusted EBITDAX $1,480 – $1,600 $1,750 – $1,900 Adjusted Operating Cash Flow Net Debt / LTM Adjusted EBITDAX Low 2x Mid 2x D&C Capital Expenditures ($MM) $1,500 $1,300 $150 $150 Land Capital Expenditures ($MM) ($25MM Maintenance) ($25MM Maintenance) Note: See Appendix for key definitions. (1) Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes. 96 APPENDIX II | 2018

Highly Visible 2018 D&C Budget Drilling Marcellus Utica Total Rigs 5 1 6 Wells Spud 106 11 117 Average Lateral 10,046 11,855 10,216 Drilling Cost/1,000' of Lateral $0.28 $0.30 $0.28 Total Drilling Capex ($MM) $293 $38 $331 Completion Marcellus Utica Total Completion Crews 4 1 5 Wells Completed 120 25 145 Average Lateral 9,282 11,613 9,684 Completion Cost/1,000' of Lateral $0.60 $0.59 $0.59 Total Completion Capex ($MM) $663 $170 $833 D&C Capex Per 1,000' of Lateral $0.87 $0.88 $0.87 Preset wells, pad construction & other drilling maintenance ($MM) $130 Total D&C Capex Budget ($B) $956 MM $208 MM $1.3B Transparent Operating Plan and Expenditures Remove Uncertainty in D&C Budget 97 APPENDIX II | GUIDANCE MATERIALS

Maintenance Capital Drops with Longer Laterals 2018 Maintenance Capex at 9,000’ and 12,000’ Laterals Marcellus Utica $700 $613 $600 $552 Maintenance Capital ($MM) $500 $400 $300 $200 $100 $0 9,000 ft lateral 12,000 ft lateral Note: See Appendix for maintenance capital definition as well as further assumptions. 98 APPENDIX II | GUIDANCE MATERIALS

Antero Long-Term Target Pricing Assumptions Commodity prices: All forecasts reflect the following commodity price cases: • Base case: Strip commodity pricing at 12/31/17 ($54.71 WTI crude oil & $2.84 Nymex Henry Hub) for 2018 - 2022 • Upside case: 12/31/17 Strip for 2018 and $60 WTI crude oil & $2.85 Nymex Henry Hub gas prices for 2019 - 2022 • Downside case: 12/31/17 Strip for 2018 $50 WTI crude oil & $2.85 Nymex Henry Hub gas prices for 2019 - 2022 Oil and Gas Strip Commodity Prices (12/31/17) ($/Bbl) ($/MMBtu) $2.89 $2.85 $65.00 $3.00 $2.82 $2.82 $2.81 $59.62 $60.00 $2.50 $56.19 $53.76 $55.00 $2.00 $52.29 $51.67 $50.00 $1.50 $45.00 $1.00 $40.00 $0.50 $35.00 $0.00 2018 2019 2020 2021 2022 WTI Nymex Current Hedging Arrangements • 80% Hedged on natural gas production through 2020 at $3.44/MMBtu and 52% hedged on natural gas production through 2022 at $3.34/MMBtu • 23% hedged on C3+ NGL production in 2018 at $0.75/gallon (Propane volume only) 99 APPENDIX II | PRICING ASSUMPTIONS