Howard Weil 46 th Annual Energy Conference MARCH 26, 2018

Howard Weil 46 th Annual Energy Conference MARCH 26, 2018

Cautionary Statement This presentation includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond AR s control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments AR expects, believes or anticipates will or may occur in the future, such as those regarding future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, Consolidated Adjusted EBITDAX, Stand-Alone E&P Adjusted EBITDAX, Consolidated Adjusted Operating Cash Flow, Stand-Alone Adjusted Operating Cash Flow, Free Cash Flow, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs, future financial position, future technical improvements and future marketing opportunities, are 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 forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. AR 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 the AR s control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs 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 "Item 1A. Risk Factors" in AR s Annual Report on Form 10-K for the year ended December 31, 2017. 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. This presentation includes certain financial measures that are not calculated in accordance with U.S. generally accepted accounting principles ( GAAP ). These measures include (i) Consolidated Adjusted EBITDAX, (ii) Stand-Alone E&P Adjusted EBITDAX, (iii) Consolidated Adjusted Operating Cash Flow, (iv) Stand-Alone E&P Adjusted Operating Cash Flow, (v) Free Cash Flow. Please see Antero Definitions and Antero Non-GAAP Measures for the definition of each of these measures as well as certain additional information regarding these measures, including the most comparable financial measures calculated in accordance with GAAP. Antero Resources Corporation is denoted as AR in the presentation, Antero Midstream Partners LP is denoted as AM and Antero Midstream GP LP is denoted as AMGP, which are their respective New York Stock Exchange ticker symbols. ANTERO RESOURCES HOWARD WEIL 46 TH ANNUAL ENERGY CONFERENCE

Antero Has Reached An Inflection Point Announced New Long Lateral Development Plan Averaging 11,500 Step Change in Capital Efficiency Reduces 5-Year D&C Capex by $2.9B Sustainable Cash Flow Growth Generating 5-Year Free Cash Flow of $1.6B at YE Strip & $2.8B at $60 Oil Joining an Elite E&P Group With: Scale Double Digit Growth Highest Leverage to NGL Prices Among Top NGL Producers The Size & Scale to Capitalize on Resource Disciplined Returns Focus 28% Full Cycle Returns 23% 5-Year Debt-Adjusted Production CAGR per share 22% 5-Year Cash Flow CAGR per share Low Leverage Free Cash Flow 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 discretionary land spending. VALUE PROPOSITION CAPITAL DISCIPLINE AND DELEVERAGING 3

Feet New Long Lateral Development Plan (Number of locations) 5-Year Plan Averages 11,500 59% of Inventory Now 10,000 Lateral Length Average Lateral Length per Completed Well Core Drilling Inventory by Lateral Length 14,000 12,000 10,000 8,000 6,000 4,000 12,700 1,600 1,400 1,200 1,000 800 600 400 10,800 Average Inventory Lateral Length 498 1,450 2,000 200 0 Wells Completed (1) 2018 2019 2020 2021 2022 145 155 160 165 165 0 <6,000' 6,000' - 8,000' 8,000' - 10,000' Feet 10,000' - 12,000' 12,000' 1) Wells completed reflects midpoint of targeted completions per year. SCALE & GROWTH COST EFFICIENCY DRIVERS: LONGER LATERALS 4

$ Billions Step Change in Capital Efficiency Bcfe/d Consolidated Drilling & Completion Capital Expenditures Production Targets As of December 2016 As of December 2017 As of December 2016 $2.5 $2.0 $1.5 $1.0 $0.5 $2.4 $2.2 $2.0 $1.7 $1.7 $1.6 $1.4 $1.3 $1.3 $1.3 $2.9B Capex Reduction Over 5 Years Cumulative Reduction in Drilling & Completion Capital Same Production Targets 20% Production CAGR 2018-2020 15% Production CAGR 2021-2022 6.0 5.0 4.0 3.0 2.0 1.0 2.7 2.7 As of December 2017 4.6 4.5 4.0 3.9 3.3 3.3 5.2 5.2 $0.0 2018 2019 2020 2021 2022 0.0 2018 2019 2020 2021 2022 Same Production Growth With Much Less Capital Spending VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW SIGNIFICANT CAPITAL REDUCTION 5

MBbl/d Highest Leverage to NGL Prices Among Top Producers NGL % of Product Revenues Top NGL Producers in the U.S. 115.0 4Q17 Daily NGL Production Including Recovered Ethane NGL % of Product Revenues Pre-hedged Realized Price ($/Bbl) 45% 105.0 95.0 85.0 32% 37% NGLs Generate 37% of AR Revenue 4Q 2017 40% 35% 30% 25% 75.0 20% 65.0 55.0 45.0 14% 14% 12% 13% 11% 10% 9% 6% $18.46 $16.93 $30.11 $34.99 $22.38 $28.41 $27.77 $21.64 $28.54 $27.74 RRC DVN AR EOG APC COP NBL PXD CHK OXY 15% 10% 5% 0% Antero Has The Highest NGL Price Exposure Among Top NGL Producers Pre-hedged Realized Price ($/Bbl) Source: SEC filings and company press releases. Note: Realized prices are weighted average including ethane (C2) where applicable. Percent of total product revenues is calculated on a pre-hedge basis. SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY TOP U.S. NGL PRODUCER 6

The Size and Scale to Capitalize on the Resource Antero Resources Profile Market Cap.... Enterprise Value... Corporate Debt Ratings Stand-Alone Leverage.. Net Production (2018E)... Liquids... 3P Reserves..... Net Acres.... Core Drilling Locations. Hedge Mark to Market.. AR Midstream Ownership (53%) $6.5B $10.1B Ba2 / BB+ / BBB- 2.9x 2.7 Bcfe/d 130,000 Bbl/d 54.6 Tcfe 620,000 3,295 $1.3B $2.7B Note: Equity market data as of 3/16/18. Balance sheet data, hedge mark to market, and reserves as of 12/31/17. Enterprise value excludes AM net debt. See 2018 Guidance in Appendix. ANTERO RESOURCES HOWARD WEIL 46 TH ANNUAL ENERGY CONFERENCE 7

Outstanding Corporate Level Well Economics Well Economics Support Investment ROR Well in Excess of Cost of Capital 28% Corporate Level ROR 2018 & 2019 Full Cycle Returns Assumes YE 2017 Strip & Excludes Hedging Impact Single Well Economics Excluding Hedges Full Cycle ROR at $60/Bbl Flat 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Full Cycle ROR 2018 Completion Program Half Cycle ROR Half Cycle ROR at $60/Bbl Flat AR Cash Cost Returns 82% to 90% AR Corporate Level Returns 28% to 33% 2019 Completion Program $60 Oil Strip Pricing AR WACC 8% Note: Half cycle burdened with 60% of AM fees to give credit for AM ownership/distributions and firm transportation variable fees. Full cycle burdened with G&A, land costs, 100% of AM fees and full FT costs. See Appendix for detailed assumptions for full cycle and half cycle single well economics; WACC calculated using CAPM. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW ATTRACTIVE WELL ECONOMICS DRIVE GROWTH 8

Lower Capital & Higher Liquids Free Cash Flow D&C Capital Investment Fully Funded with Cash Flow $1.6B of Targeted Free Cash Flow Over the Next 5 Years $1,500 $1,000 $500 Stand-Alone E&P Free Cash Flow Outspend We Are Here Stand-Alone Free Cash Flow: $60 Oil / $2.85 Gas Case Strip Pricing Base Case $50 Oil / $2.85 Gas Case 5-Year Cumulative Free Cash Flow $2.8B $1.6B $0 $1.0B ($500) ($1,000) ($1,500) 2014A 2015A 2016A 2017A 2018 Guidance 2019 Target 2020 Target 2021 Target 2022 Target Resource Capture & Delineation Harvest Mode 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. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW SUSTAINABLE CASH FLOW GROWTH 9

Cash Flow Growth Deleveraging Profile Stand-Alone Financial Leverage 12/31/17 Strip Pricing (Base Case) $60 Oil / $2.85 Gas $50 Oil / $2.85 Gas 5.0x 4.5x 4.0x 3.5x 3.0x 2.5x 3.9x 3.6x Leverage targets inclusive of $500 MM of maintenance and discretionary land capex from 2018-2022 2.8x 2.9x S&P Upgrade to BB+ Moody s Ba2 Outlook Positive BBB- Rating Fitch Recently Rated AR Investment Grade 23% Debt-Adjusted Production CAGR Generates Free Cash Flow 2.0x 1.5x 1.0x 0.5x Deleveraging Supported By: 2.5 Tcfe Hedge Position 4.7 Bcf/d FT Portfolio $1.4B of Targeted AM Distributions Balance Sheet Deleveraging & Optionality 0.0x 2014A 2015A 2016A 2017A 2018 2019 Guidance Target 2020 Target 2021 Target 2022 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. CAPITAL DISCIPLINE AND DELEVERAGING CASH FLOW DRIVES LOW LEVERAGE 10

Shareholder Interests in Focus: 5-Year Cash Priorities Priorities for Cash Sustain Asset Base Disciplined Growth Investments Optionality Return of Capital Debt Reduction Further Land Consolidation $10.4B Cumulative Stand-Alone E&P Adjusted Operating Cash Flow $5.9B D&C Growth Capital $1.6B Free Cash Flow for Deployment $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. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW SUSTAINABLE CASH FLOW GROWTH 11

Antero Profile Should Drive Multiple Expansion # of Companies Median Debt/ Adjusted EBITDAX Median EV/ 2018 Adj. EBITDAX U.S. Publicly Traded E&Ps AR 2018E EBITDAX Unhedged Multiple: 5.4x 52 2.6x 6.3x Leverage < 3.0x Premium for: Enterprise Value Scale > $10B 34 1.7x 6.4x 18 1.9x 7.2x Growth Production Growth >15% 10 1.4x 8.5x Low Leverage Leverage <2.0x in 2019 7 1.2x 9.2x FCF Generation Free Cash Flow in 2018 EOG CXO PXD FANG COG Permian & Appalachia 6 1.1x 9.2x Joining an Elite Group of E&Ps With Scale, Double Digit Growth, Low Leverage & Free Cash Flow Generation Source: Bloomberg & Antero Estimates as of 3/6/18. (1) 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. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW ATTRACTIVE VALUATION 12

Total (Bbl/d) Rapidly Growing NGL Production Antero NGL Production Growth by Purity Product 250,000 Natural Gasoline (C5+) Normal Butane (nc4) Ethane (C2) IsoButane (ic4) Propane (C3) C3+ Production 245,000 200,000 C2 150,000 100,000 C2 Ethane 26,500 C2 Ethane 44,000 C3 50,000 C2 Ethane 17,476 nc4 ic4 0 2014 2015 2016 2017 2018E Guidance 2019E Target 2020E Target 2021E Target C5+ 2022E Target Note: Excludes condensate. See Appendix for further assumptions around long-term targets. SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY GROWING NGL PRODUCTION 13

$/Gallon C3+ NGLs: Price Improvement Mont Belvieu C3+ Spot Price $2.00 $1.80 $1.60 Balance 2018 (1) C3 $0.78 / Gal C3+ $0.92 / Gal $1.40 $1.20 $0.90/gal $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 2010 2011 2012 2013 2014 2015 2016 2017 2018 Tightening Inventories and Increasing Exports, Along With an Increase in Global Product Prices, Have Resulted in an Improvement in C3+ Prices Source: Intercontinental Exchange (ICE) pricing data. Assumes C3+ barrel weightings of: propane 57%, normal butane 16%, Isobutane 10%, pentanes 17%. 1) Balance 2018 represents strip pricing as of 3/22/2018. C3+ assumes C3+ barrel weightings of: propane 57%, normal butane 16%, Isobutane 10%, pentanes 17%. NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS MARKET DYNAMICS 14

Antero Leverage to Liquids Prices 29% Liquids as a Percent of Total Volume $1.5B Liquids Revenue Natural Gas NGLs Crude Product GAS C2 C3+ Oil Volumes (Guidance) 1,925 MMcf/d Realized Price Revenues % of Product Revenue $2.85/Mcf $2.0B 57% 44 MBbl/d $10/Bbl $0.2B 6% 77.5 MBbl/d $39/Bbl $1.1B 31% 9.5 MBbl/d $54/Bbl $0.2B 6% 43% 38% Pre- Post- Hedge Liquids as Percent of Revenue Hedges N/A $0.45/Mcfe $0.4B N/A 2,700 MMcfe/d $4.00/Mcfe $3.9B 100% Note: See Appendix for key assumptions NATURAL GAS LIQUIDS LEVERAGE TO LIQUIDS PRICES 15

Days of Supply Strong Propane Fundamentals MMBbls Current propane days of supply are 26% below last year and 35% below the 5-year average Propane Days of Supply Material reduction in U.S. propane inventories relative to the 5-year average U.S. Propane Inventories 80 120 70 100 60 50 80 40 60 30 40 20 10 20 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 5-Yr Range 2018 2017 5-Yr Avg 2013-2017 Source: EnVantage Inc. and Energy Information Administration (EIA). 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 5-Yr Range 2017 2018 5-Yr Avg 2013-2017 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS LPG FUNDAMENTALS 16

LPG: Marcus Hook vs. Mont Belvieu Mariner East 2 is Expected to go In-service Mid-year 2018 and to Deliver a $0.06 to $0.09 per Gallon Uplift to Antero s Propane Netback Pricing LPG Shipping Routes and 2H 2018 Propane Netbacks ($/Gallon) Antero Netback 2H2018 Marcus Hook NWE Northwest Europe (NWE) C3 Price ($/Gal) $0.94 Transport & Terminal Fees (1) $(0.22) Antero ME2 Netback (Houston, PA) $0.72 Mont Belvieu 2H18 Strip Price $0.81 Antero 2H17 Differential to Mont Belvieu $(0.18) Antero 2H18 Implied Local Netback $0.63 2H18 ME2 Uplift ($/Gal) $0.09 FEI FEI To Asia via Panama Canal Antero Netback 2H 2018 Far East Index (FEI) C3 Price ($/Gal) $1.00 Transport & Terminal Fees (1) $(0.31) Antero ME2 Netback (Houston, PA) $0.69 Mont Belvieu 2H18 Strip Price $0.81 Antero 2H17 Differential to Mont Belvieu $(0.18) 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) Includes assumed shipping fees. Antero 2H18 Implied Local Netback $0.63 2H18 ME2 Uplift ($/Gal) $0.06 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS LPG FUNDAMENTALS 17

C3+ NGL Cash Flow ($MM) Powerful C3+ NGL Pricing Upside Exposure Significant Upside to C3+ NGL Pricing (2018 vs. 2017) $900 C3+ Cash Flow Incremental C3+ Cash Flow $840 $800 $700 $600 $656 $184 $500 $400 $374 $300 $200 $100 $0 $30.48/Bbl C3+ 2017A $51 Oil 60% of WTI $39.00/Bbl C3+ 2018E $60 Oil 65% of WTI $46.00/Bbl C3+ 2018E $70 Oil 65% of WTI Antero Expects Significant Cash Flow Growth in 2018 From the Improvement in NGL Pricing With Attractive Upside to Further Increases in Liquids Pricing Note: C3+ NGL cash flow represents revenue from C3+ NGL production, less processing, transportation and all other operating costs associated with C3+ NGL production and sales. NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS C3+ PRICING UPSIDE EXPOSURE 18

Positioned in the Core of the Core Antero Acreage Antero Marcellus Wells Industry Marcellus Wells Antero Marcellus Rig Industry Marcellus Rig > 1,300 lb/ft Completions Northern Rich High-Graded Core ~283,000 acres 2.24 Bcfe/1,000 Avg. EUR 67% Undeveloped Southern Rich High-Graded Core ~487,000 acres 2.24 Bcfe/1,000 Avg. EUR 70% Undeveloped AR Holds 61% of Undeveloped Dry Gas High-Graded Core ~1,051,000 acres 2.30 Bcfe/1,000 Avg. EUR 78% Undeveloped AR Holds 13% of Undeveloped High- Graded Core Areas Most Active Operators Percent Undeveloped Advanced Completions (>1,300 lbs/ft) Bcfe / 1,000 Wells Southwest Marcellus Core ~2.9 Million Acres ~78% Undeveloped Northern Rich RRC, CNX, HG 67% 2.24 474 Southern Rich AR, EQT, SWN 70% 2.24 517 Dry Gas EQT, CVX, RRC, CNX 78% 2.30 747 Antero is Very Well Positioned in the Core of the Core Note: Excludes 600,000 urban acres. EURs assume full ethane rejection. Based on Antero reserve engineering of most recent state and internal production data. SCALE & GROWTH CORE OF THE CORE 19

Undrilled Locations Largest Undrilled Core Drilling Inventory Core Marcellus & Utica Drilling Locations (1) 4,000 Marcellus & Utica Liquids Rich Locations SW Marcellus & Utica Dry Locations NE Pennsylvania Dry Locations 3,500 3,000 3,295 Who Can Consistently Drill Long Laterals? Who Has the Running Room? 2,500 2,000 2,333 1,930 Antero Holds 40% of Core Undrilled Liquids-Rich Locations Largest Inventory in Appalachia 1,500 1,259 1,000 500 720 714 663 588 583 556 544 Lateral Length: - 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 (1) Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG, RRC and SWN. Based on Antero analysis of undeveloped acreage in the core of the Marcellus and Utica plays. SCALE & GROWTH CORE OF THE CORE 20

Longer Laterals Scale the Resource EUR (Bcfe) EURs by Marcellus Lateral Lengths 45 EUR in Bcfe/1,000' 2.3 Bcfe/1,000' R 2 =.73 40 35 30 A 1:1 Proportional Increase in EURs with Longer Laterals Antero well results show no evidence of degradation in recovery per foot of completed lateral out to over 14,000 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 ethane rejection. SCALE & GROWTH COST EFFICIENCY DRIVERS: LONGER LATERALS 21

The Longer, the Better Single Well Economics by Lateral Lengths PV-10 ($MM) ROR (%) $25.0 100% $20.0 74% 79% 80% $15.0 50% 67% $15.9 $20.4 60% $10.0 $11.4 40% $5.0 $6.8 20% $- 6,000' Lateral 9,000' Lateral 12,000' Lateral 15,000' Lateral 0% ~60% Improvement in ROR from a 6,000 Lateral to a 15,000 Lateral Note: Represents half cycle economics at strip pricing. See Appendix for further assumptions on single well economics. SCALE & GROWTH COST EFFICIENCY DRIVERS: LONGER LATERALS 22

Operating Evolution Continues Achievements to Date 2018 Marcellus Well Cost (1) Next Steps in Efficiency Evolution 42% Decline in well costs since 2014 46% Vendor-related cost reductions Sand 12% Flowback Water 5% Completion Spreads 25% Facilities, Pad & Road Allocation 9% Drilling Efficiency (25%) Tubulars 4% Completion Services 24% Drilling Rigs & Services 21% Drilling Rigs/Services Fit-for-purpose rigs with dual operation capabilities to improve cycle times Improved drillout efficiency Penetration rates still increasing with new downhole motors Completion Spreads/Services Concurrent operations with larger pads allowing simultaneous drilling and completion More wells per pad Automated completion equipment to increase stages per day 54% Permanent cost efficiencies 100% of Completion Spreads Under Contract Through 2019 Antero has 100% of 2018 Rigs and 50% of 2019 Rigs Under Fixed Rate Contracts with Average Rig Rates Declining Towards $17,500/day as Higher Rig Rate Contracts Roll Off Sand Efficiencies Expected to Offset Service Cost Inflation 100 mesh sand for easier pumping & fewer screenouts Self-sourcing sand to reduce supply cost Regional sand mines in the Permian expected to reduce demand for Northern White sand (1) Based on Marcellus 11,000 foot lateral and 2,000 pounds per foot AFE. Assumes nine wells per pad. SCALE & GROWTH OPERATING TECHNOLOGIES EVOLVE 23

Diversified Natural Gas Market Mix Antero Firm Transportation Portfolio in 2018 Antero Producing Areas Local Markets 10% of FT Portfolio $(0.53)/Mcf Differential Index Differential % of Gas Production Gulf Coast $(0.14) 41% Midwest $(0.13) 27% TCO $(0.27) 16% TETCO M2 $(0.53) 10% Mid-Atlantic $(0.34) 6% Weighted Average vs. NYMEX: BTU Uplift $0.24 All-in vs. NYMEX +$0.03 $(0.21) 100% Forecasting +$0.00 - $0.05 Premium to NYMEX after BTU uplift Forecasting Premium Price to NYMEX Including Btu Uplift Note: Based on 2018 strip pricing as of 12/31/2017. See Appendix for further assumptions. TRANSITION TO FREE CASH FLOW & LOW LEVERAGE PROFITABILITY DRIVERS 24

MMcfe/day Well Hedged at High Prices Relative to Strip Commodity Hedge Position 2,400 1,900 1,400 900 400 Hedged Volume Average Index Hedge Price (1) Current NYMEX Strip (2) Mark-to-Market Value (2) ~100% of 2018 and 2019 Target Gas Production Hedged at $3.50/MMBtu 2,141 $3.66 2,330 $3.50 $3.5B of realized gains on hedges since 2008 $3.25 1,418 $3.00 $3.00 $450 MM $584 MM $225 MM $38 MM $35 MM $0 MM 90 710 2.8 Tcfe hedged through 2023 at $3.39/MMBtu ~19 MBbl/d of propane hedged in 2018 at $0.75/Gal 850 $2.91 $2.84 $2.81 $2.82 $2.85 $2.89 $2.93 ($/MMBtu) $5.00 $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50-100 2018 2019 2020 2021 2022 2023 ~$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 for 2018 only. (2) As of 12/31/17. $- TRANSITION TO FREE CASH FLOW & LOW LEVERAGE HEDGE PROTECTION 25

$ Millions A Paired Trade Hedges Support Firm Commitments $600 $585 $0.48/Mcfe Net Marketing Expense (High End) Net Marketing Expense (Low End) Hedge Gains Hedge Portfolio Supports Firm Commitments $500 $400 $469 $0.45/Mcfe 5-Year Cumulative: Hedge Gains: $1,350 Marketing Expense: ($461) Net Uplift: $889 Firm Transportation Portfolio Allows Antero to achieve: $300 $200 $100 $0 $0.125/Mcfe $0.10/ Mcfe 2018 Guidance $0.20/Mcfe $0.15/ Mcfe < $0.10/ Mcfe $224 $0.15/Mcfe $37 $35 $0 $0 2019 Target 2020 Target 2021 Target 2022 Target Premium Price Certainty Less volatility and greater surety in realized prices Effectively Hedge NYMEX Index A key advantage as our product is delivered to NYMEXrelated markets Hedge Gains More than Offset Marketing Expense Hedges Support FT Commitments TRANSITION TO FREE CASH FLOW & LOW LEVERAGE FIRM TRANSPORTATION & HEDGE BOOK 26

Antero Midstream Overview: Disciplined Capital Efficient Business Model

Antero Midstream At A Glance Market Cap... $5.0B Enterprise Value.... LTM Adjusted EBITDA (1).. % Gathering/Compression % Water Net Debt/LTM EBITDA... Corporate Debt Rating. Gross Dedicated Acres (2). $6.1B $529 MM 67% 33% 2.3x Ba2 / BB+ /BBB- 705,000 Note: Equity market data as of 3/16/2018. Balance sheet data as of 12/31/2017. 1. LTM Adjusted EBITDA as of 12/31/17. Adjusted EBITDA is a non-gaap measure. For additional information regarding this measure, please see Antero Midstream Non-GAAP Measures in the Appendix. 2. Represents acres dedicated for gathering and compression. Excludes 156,000 gross acres dedicated to third parties for gathering and compression services. ANTERO MIDSTREAM HOWARD WEIL 46 TH ANNUAL ENERGY CONFERENCE 28

Antero Midstream Asset Overview Year End 2017 Midstream Infrastructure (YE 2017) Gathering Pipelines (Miles) 366 Compression Capacity (MMcf/d) 1,590 JV Processing Complex (MMcf/d) 600 JV Fractionation Plant (Bbl/d) 20,000 JV Stonewall Pipeline (Bcf/d) 1.4 Fresh Water Pipelines (Miles) 323 Fresh Water Impoundments 38 Antero Clearwater Facility (Bbl/d) 60,000 Antero Clearwater Facility Sherwood Processing Complex Compressor Station Antero Clearwater Facility Sherwood Processing Complex Stonewall Pipeline Gathering Pipelines Freshwater Delivery Pipelines Antero Rig PREMIER INTEGRATED APPALACHIAN MIDSTREAM ASSETS 29

Capital Efficiency Drives Free Cash Flow Generation ~$500MM in Capital Efficiencies With No Change to Throughput Volumes Leverage existing asset base and realization of full build-out EBITDA multiples Over $2.4 billion of Free Cash Flow from 2018 2022 Before Distributions $1,400 $1,200 $1,000 $800 $600 $400 $200 $0 ($200) ($400) ($600) ($800) AM Cash Flow Outspend Before Distributions Earn-out Payments from Water Drop Down AM Free Cash Flow Before Distributions We Are Here 2014A 2015A 2016A 2017A 2018 Guidance 2019 Target Note: Includes water earnings and capital invested on a recast basis prior to drop down and excludes drop down purchase price AM Throughput Growth 2020 Target 2021 Target Free Cash Flow is a non-gaap measure. For additional information regarding this measure, please see Antero Midstream Non-GAAP Measures in the Appendix.. 2022 Target DISCIPLINED CAPITAL EFFICIENT BUSINESS MODEL 30

Distribution Per Unit AM Long-Term Distribution and Coverage Targets DCF Coverage Ratio Unchanged capital investment philosophy with disciplined financial policies result in ability to target peer-leading distribution growth through 2022 AM Long-Term Distribution Targets and DCF Coverage $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 Distribution Guidance (Mid-point) 1.8x $1.03 1.4x $1.33 1.3x $1.72 2016A 2017A 2018 Guidance 1) 8% yield based off AM unit price of $26.49 as of 3/16/2018. Distribution Target (Mid-point) 8% yield (1) $2.21 2019 Target 5-YEAR OUTLOOK: LEVERAGING EXISTING CORE ASSET BASE $2.85 2020 Target $3.42 2021 Target DCF Coverage Targets $4.10 2022 Target 2.0x 1.8x 1.6x 1.4x 1.2x 1.0x 0.8x 0.6x 0.4x 0.2x 0.0x 31

AMGP Attractive Valuation Proposition Visible distribution growth provides attractive long-term yield and valuation proposition AMGP Long-Term Distribution Targets and Implied Yield $2.50 Distribution Per Share AMGP Forward Yield 13.2% 14.0% $2.00 10.4% $2.22 12.0% $1.50 8.0% $1.74 10.0% 8.0% $1.00 5.3% $1.34 6.0% 3.2% $0.89 4.0% $0.50 $0.00 1.8% $0.30 4Q17 Annualized $0.54 2018 Guidance 2019 Target 2020 Target 2021 Target 2022 Target 2.0% 0.0% Based on AMGP Share price of $16.80 as of 3/16/18. Note: distributions per share represent midpoint of target range. 5-YEAR OUTLOOK: AMGP 32

Most Integrated Natural Gas & NGL Business in the U.S. 53% of LP Units World Class E&P Operator in Appalachia A Leading Northeast Infrastructure Platform Contiguous Core Acreage Position Allows for Long Lateral Drilling and Significant Capital Efficiencies Largest NGL Producer in the U.S. Leads to Peer Leading Cash Flow Margins Optimized 5-Year Plan Results in High Return Drilling & Free Cash Flow Midstream Ownership & Integration Delivers Value and Just-in-Time Infrastructure Buildout ANTERO RESOURCES MOST INTEGRATED NATURAL GAS & NGL BUSINESS 33

Appendix 34

Organizational Structure A $17B Integrated Natural Gas and NGL Business Sponsors (1) Public Sponsors (1) Public 27% 73% 67% 33% NYSE: AR E&P Enterprise Value: $7.5B Corp Ratings: Ba2 / BB+ / BBB- 53% 100% Incentive Distribution Rights (IDRs) NYSE: AMGP Enterprise Value: $3.1B No Ratings Public 47% NYSE: AM Enterprise Value: $6.1B Corp Ratings: Ba2 / BB+ / BBB- Note: Enterprise value as of 3/16/18. AR E&P enterprise value excludes $2.6 Bn of ownership value in AM and AM net debt. (1) Sponsors represent Warburg Pincus, Yorktown & senior management. APPENDIX ORGANIZATIONAL STRUCTURE 35

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 & $2.85 Nymex Henry Hub gas prices for 2019-2022 ($/Bbl) $65.00 Oil and Gas Strip Commodity Prices (12/31/17) $2.82 $2.81 $2.82 $2.85 $2.89 ($/MMBtu) $3.00 $60.00 $59.62 $56.19 $55.00 $53.76 $52.29 $51.67 $50.00 $45.00 $40.00 $2.50 $2.00 $1.50 $1.00 $0.50 $35.00 2018 2019 2020 2021 2022 WTI Nymex $0.00 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) APPENDIX PRICING ASSUMPTIONS 36

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 Nymex C3+ NGL Realized Price (% of Nymex WTI) $0.00 to $0.05 Premium 62.5% 67.5% Cash Production Expense ($/Mcfe) $2.10 $2.20 $1.65 $1.75 Marketing Expense ($/Mcfe) (10% Mitigation Assumed) G&A Expense ($/Mcfe) (before equity-based compensation) $0.10 $0.125 $0.125 $0.175 $0.15 - $0.20 Adjusted EBITDAX $1,700 $1,800 $2,050 $2,150 Adjusted Operating Cash Flow $1,480 $1,600 $1,750 $1,900 Net Debt / LTM Adjusted EBITDAX Low 2x Mid 2x D&C Capital Expenditures ($MM) $1,500 $1,300 Land Capital Expenditures ($MM) $150 ($25MM Maintenance) $150 ($25MM Maintenance) Note: See Appendix for key definitions. Cash flow and EBITDAX guidance based on 12/31/2017 strip pricing. 2018 average NYMEX and WTI pricing was $2.83/MMBtu and $59.57/Bbl, respectively. (1) Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes. APPENDIX 2018 GUIDANCE 37

Antero Long-Term Target Project Assumptions In-Service Date Rover Phase 2 2Q 2018 (April 1) Mariner East 2 2Q 2018 WB Xpress West 4Q 2018 WB Xpress East 4Q 2018 Mountaineer Xpress / Gulf Xpress YE 2018 Note: Based on publicly available information. APPENDIX PROJECT ASSUMPTIONS 38

Antero Guidance and Long-Term Target Assumptions Stand-Alone E&P Consolidated Net Daily Production (MMcfe/d) 20% CAGR through 2020 and 15% Growth in each of 2021 and 2022 Natural Gas Realized Price Differential to Nymex $0.00 to $0.05 Premium (2018) $0.00 to $0.10 Premium (2019 2022) C3+ NGL Realized Price (% of Nymex WTI) 62.5% 67.5% (2018) 72% (2019+) ME2 Fees Booked to Transport Costs Realized Oil Price Differential to WTI ($5.00) ($6.00) Cash Production Expense ($/Mcfe) (1) $2.10 - $2.20 (2018) $2.10 $2.25 (2019 2022) $1.65 - $1.75 (2018) $1.65 $1.75 (2019 2022) Marketing Expense ($/Mcfe) $0.10 - $0.125 (2018) $0.15 $0.20 (2019) <$0.10 (2020) $0.00 (2021 2022) G&A Expense ($/Mcfe) (before equity-based compensation) Cash Interest Expense ($/Mcfe) Well Costs ($MM / 1,000 ) (Assumes 12,000 completions at 2,000 lbs. per foot of proppant) $0.125 $0.175 (2018 2019) $0.10 $0.15 (2020 2022) $0.175 $0.225 (2018 2019) $0.10 $0.15 (2020 2021) <$0.10 (2022) Marcellus: $0.95 MM Utica: $1.07 MM $0.15 - $0.20 (2018 2019) $0.10 $0.15 (2020 2022) $0.25 $0.30 (2018 2019) $0.20 $0.25 (2020 2022) Marcellus: $0.80 MM Utica: $0.95 MM (1) Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes. APPENDIX 5-YEAR ASSUMPTIONS 39

Antero Guidance and Long-Term Target Assumptions (Cont.) Adjusted Operating Cash Flow (1) Stand-Alone E&P $10.4B (Cumulative 2018 2022) Consolidated N/A Annual D&C Capital Expenditures ($MM) $1,500 $1,600 (2018 2020) $1,700 $2,000 (2021 2022) $1,300 $1,400 (2018 2021) $1,600 $1,700 (2022) Land Maintenance Expenditures ($MM) (2) ~$200 (Cumulative 2018 2022) Free Cash Flow (1) $1.6B (Cumulative 2018 2022) N/A Leasehold Growth Capital Expenditures ($MM) ~$300 (Cumulative 2018 2022) Number of Well Completions 790 well completions Marcellus EUR per 1,000 of Lateral 2.0 Bcf/1,000 ; 2.5 Bcfe/1,000 (25% ethane recovery) Utica EUR per 1,000 of Lateral 2.0 Bcfe/1,000 (ethane rejection) Note: See Appendix for key definitions. Cash flow guidance is based on 12/31/2017 strip pricing. Average NYMEX pricing was $2.83/MMBtu, $2.81/MMBtu, $2.82/MMBtu, $2.85/MMBtu and $2.89/MMBtu in 2018, 2019, 2020, 2021 and 2022. Average WTI pricing was $59.57/Bbl, $56.19/Bbl, $53.76/Bbl, $52.29/Bbl and $51.67/Bbl for 2018, 2019, 2020, 2021 and 2022. (1) Adjusted Operating Cash Flow and Free Cash Flow are non-gaap financial measures. For additional information regarding these measures, please see the following pages ( Antero Definitions and Antero Non-GAAP Measures ). (2) Includes leasehold capital expenditures required to achieve targeted working interest percentage. APPENDIX 5-YEAR ASSUMPTIONS 40

Breakdown of D&C Capex Savings D&C Capex Savings Capital Allocation Lateral Lengths Cycle Times & Enhanced Well Cost Savings Recoveries $0.4B Well Cost Savings $2.9B Capital Efficiencies Captured Within D&C Capex From New Development Program $0.5B Improved Cycle Times $1.1B Optimizing Capital Allocation Continued shift to highgraded Marcellus Related to reduced AFEs including lower flowback water handling cost due to Clearwater Facility and begin self-sourcing sand $0.9B Lateral Lengths Reduced drilling days, increase in stages per day and concurrent operations $0.09MM/1,000 savings from 9,000 to 12,000 Note: See appendix for further detail on D&C capital. APPENDIX COST EFFICIENCY DRIVERS 41

D&C Capital Transparency D&C Capital ($MM) 2018 2019 2020 Total Well Completions (I.e. First Sales) 145 155 160 Average Lateral 9,700 10,500 11,600 Adjusted Well Count (I.e. Based on Capital Timing) 155 157 150 Average Lateral 9,700 10,500 11,600 Total Adjusted Lateral Feet 1,503,500 1,648,500 1,740,000 Cost per Lateral Foot ($MM/1,000) - Lateral Savings ONLY $0.86 $0.83 $0.81 (1) Implied D&C $1,293 $1,368 $1,409 Savings from Concurrent Ops. / Increasing Stages per Day ($24) ($79) Adjusted Capital Cost $1,293 $1,344 $1,330 Implied Cost per Lateral Foot ($MM/1,000) $0.86 $0.82 $0.76 (1) Based on Marcellus AFE, which assumes inflation on consumable products (i.e. sand/chemicals). APPENDIX ASSUMPTIONS 42

AR Gathering and Compression Fees Analysis AR has Highly Competitive Gathering & Compression Fees with AM - AR s gathering and compression fees paid to AM are below the Appalachian average based on extensive internal analysis of 20 public and private midstream contracts or disclosed terms AR has Low or No Minimum Volume Commitments ( MVCs ) with AM - AR has absolutely no MVCs on any low pressure gathering with AM - AR only has MVCs on post AM IPO high pressure and compression assets - AR has 70% to 75% MVCs on compression and high pressure gathering, respectively, when a project is requested by AR - AR s MVC levels are determined by AR s production forecast and not the capacity of AM s infrastructure buildout - Antero Midstream may build infrastructure larger than requested for efficiency AR Receives Reliable and Timely Midstream Service from AM - AR has complete visibility and drives AM s planning and in-service timing for key infrastructure projects - AR is essentially AM s sole customer, which results in unmatched service - AR receives just-in-time customized and controlled midstream buildout. This is critical to AR s ability to execute on its development plan and optimize its capital efficiency APPENDIX GATHERING AND COMPRESSION FEES 43

Appalachia Gathering and Compression Fee Study AR Fees Paid to AM Converted to MMBtu $1.00 AR Contracted Gathering/Compression Fees to AM ($/Mcf) $0.66 BTU Conversion (Average BTU of 1250) 1.25 $0.90 Gathering/Compression Fees (Converted to $/MMBtu) $0.53 $0.80 $0.70 $0.60 NOTE: Most midstream fees are disclosed on a $/MMBtu basis. All other fees, including AR s fees, are converted from $/Mcf basis to $/MMBtu basis to appropriately compare to others Appalachian Study Average: $0.60/MMBtu $0.53 $0.50 $0.40 $0.30 $0.20 $0.10 $0.00 Public Private Note: All gathering & compression fees normalized to 1,250 Btu gas and two stage compression. Analysis based on public and private company disclosures for Appalachia midstream contracts. APPENDIX GATHERING AND COMPRESSION FEES 44

Guidance Summary - 2018 Guidance 2017 Guidance 2018 Guidance Change Net Income ($MM) $305 - $345 $435 - $480 +41% Adjusted EBITDA ($MM) $520 - $560 $705 - $755 +35% DCF ($MM) $405 - $445 $575 - $625 +41% Distribution Growth 28 30% 28 30% - DCF Coverage 1.30x 1.45x 1.25x - 1.35x -7% Maintenance Capex ($MM) $65 $65 0% Growth Capex ($MM) $735 $585-20% Total Capex ($MM) $800 $650-19% Adjusted EBITDA and Distributable Cash Flow are non-gaap measures. For additional information regarding these measures, please see Antero Midstream Non-GAAP Measures in the Appendix. APPENDIX: GUIDANCE 45

Propane Futures Have Not Been Good Indicator of Eventual Price Spot Propane Price ($ per Gallon) Propane Futures vs Actuals ($/Gal) Futures Price at 12/31/15 Futures Price at 12/31/16 Futures Price at 12/31/17 Actual Spot Price $1.20 $1.00 Average Year 1 Difference from 12/31/15 Futures: $0.11/gal, or 27% Average Year 1 Difference from 12/31/16 Futures: $0.10/gal, or 14% Actual Mont Belvieu Propane Price $0.80 12/31/17 Mont Belvieu Propane Futures $0.60 12/31/16 Mont Belvieu Propane Futures $0.40 12/31/15 Mont Belvieu Propane Futures $0.20 Thinly Traded Propane Futures Are Not a Good Predictor of Eventual Physical Prices $0.00 Over the Past Two Years, Propane Futures Pricing has Been 14% - 27% Below Actuals APPENDIX NATURAL GAS LIQUIDS 46

Attractive 2018 E&P Margins and Recycle Ratio Antero Fully Burdened Stand-Alone E&P Cash Margins ($/Mcfe) 3.4x Recycle Ratio (1) ($/Mcfe) $2.50 $2.00 $1.50 $1.00 $1.81 $1.81 $0.45 $0.21 Hedges $1.60 $0.45 Hedges 2.7x Unhedged Recycle Ratio (1) $0.50 $1.36 $1.15 $0.47 $0.00 Stand-Alone E&P EBITDAX Margin Interest expense Stand-Alone E&P Cash Margin 2018 F&D Cost 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. APPENDIX ATTRACTIVE MARGINS 47

2018 Stand-Alone E&P EBITDAX Margin Stand-Alone E&P EBITDAX Margin Waterfall ($/Mcfe) $4.50 $4.00 $3.50 $3.00 $2.50 AM Distributions $4.18 $0.17 $0.10 $0.11 $0.45 Hedges Revenues $0.65 Fully Burdened Stand-alone gathering fees $0.60 $0.10 $0.55 Liquids FT Gas FT $1.78B Stand- Alone E&P EBITDAX = $1.81/Mcfe X 2.7 Bcfe/d of production $2.00 $1.50 $3.56 $0.11 $0.15 $1.81 $0.45 Hedges $1.00 $0.50 $1.36 $0.00 Revenues, Hedges, AM Distributions Note: Based on 12/31/17 strip pricing. LOE and Production Taxes Gathering & Compression Fees Processing & Fractionation Expenses Firm Net Marketing Transportation Expense Expenses Cash G&A Stand-alone E&P EBITDAX Margin APPENDIX ATTRACTIVE MARGINS 48

Antero NGL Barrel (4Q 2017 Pricing) Antero realized $39.16/Bbl for its C3+ NGL barrels in the fourth quarter of 2017 71% of WTI oil price Including 21% ethane recovery, Antero realized $29.83 per barrel for its NGL barrels Antero is currently leaving approximately 123,000 Bbl/d of ethane in the gas stream NGL Barrel Composition & Pricing Ethane Rejection vs. Partial Recovery 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 1.5 GPM (1) Mont Belvieu 2.2 GPM 57% 16% 10% 17% Ethane Rejection Ethane (C2): Propane (C3): Butane (C4): IsoButane (IC4): $1.05/Gallon Pentane (C5): 4Q 2017 Pricing $0.25/Gallon $0.96/Gallon $1.02/Gallon $1.32/Gallon 34% 38% 10% 7% 11% 21% Recovery $43.67/Bbl Mont Belvieu Pricing $32.36/Bbl $(4.51)/Bbl Northeast Differential $(2.53)/Bbl $39.16/Bbl Antero Realized Price ($/Bbl) $29.83/Bbl 71% % of WTI 54% 1. GPM represents gallons of NGLs per wellhead unproccessed Mcf. APPENDIX ANTERO NGL BARREL 49

2018 C3+ NGL Pricing & Market Mix Antero 2018 C3+ NGL Production Netbacks 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Propane (C3) 56% Butane (C4) 16% IsoButane (IC4) 9% Pentane (C5) 19% Antero C3+ NGL Barrel Composition Weighted Average C3+ $/Bbl Pre-ME2 Post-ME2 Realized Pricing Location Houston, PA Marcus Hook Dock Mont Belvieu Price (1) $41.00 $41.00 Differential/Uplift Net of Cost (2) $(5.50) +$2.00 Antero Realized C3+ Price $35.50 $43.00 % of WTI 60% 72% 2018 Weighted Average 62.5% - 67.5% of WTI 2018 Weighted Average ~$39/Barrel 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. APPENDIX PROFITABILITY DRIVERS 50

Significant Value Derived from Midstream Ownership $ in MMs Antero Midstream Targeted Distributions to Antero Resources $450 $400 $350 $300 $250 $200 $150 $100 $89 $112 $132 $50 $- 2015A 2016A 2017A 2018E 2019E 2020E 2021E 2022E Note: Represents distribution growth targets for AR owned units through 2022. As of 12/31/17, AR owns 98.9 million AM units. APPENDIX SIGNIFICANT VALUE IN MIDSTREAM OWNERSHIP 51

Peer Leading Margins ($/Mcfe) ($/Mcfe) 4Q 2017 Stand-Alone E&P Adj. EBITDAX Margins (Pre-Hedge / Pre-Marketing Expense) (1) Margin Rank: 2 3 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $- #1 1 4 $3.77 $2.12 $3.28 $1.65 $1.65 $1.56 $1.46 4Q 2017 Stand-Alone E&P Adj. EBITDAX Margins (Post-Hedge / Post Marketing Expense) (1) Margin Rank: #1 2 3 4 5 $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $- Source: SEC filings and company press releases. AR margins exclude $0.15/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. (2) AR s EBITDAX excludes net marketing expense and the hedges put in place to support firm transportation. $1.63 $3.02 $1.46 $2.44 $2.21 $0.98 $1.21 AR A B C D Pre-Hedge EBITDAX GPT LOE Ad Valorem G&A Revenue Cash Costs $4.12 $2.25 $3.46 $1.87 $1.84 $1.63 $3.01 $1.46 $1.55 $1.49 $1.00 $2.47 $2.31 $0.99 $1.21 AR A B C D EBITDAX GPT LOE Ad Valorem G&A Net Marketing Revenue Cash Costs $1.10 APPENDIX ATTRACTIVE MARGINS 52

Antero Assumptions: Single Well Economics SWE Cost Type Description of Cost Half Cycle Full Cycle Well Costs Drilling and completion costs Assumes well costs for a 12,000 lateral, 2,000 lbs of proppant per lateral foot and both fresh and flowback water Utica Condensate regime assumes 1,500 lbs or proppant per lateral foot Marcellus: $10.6MM Utica South/Dry: $12.2MM Utica Beaver: $11.5MM (60% AM water fees) Marcellus: $11.4MM Utica South/Dry: $12.8MM Utica Beaver: $12.2MM (100% AM water fees) Working Interest / Net Royalty Interest Reflects Antero s average WI/NRI in the respective plays Marcellus: 100% / 85% Utica: 100% / 81% Midstream Gathering Fees Midstream low pressure, high pressure and compression fees 60% of AM gathering fees 100% of AM gathering fees Firm Transportation (1) FT costs may include both demand and variable fees associated with expected production Variable FT costs only of $0.06/Mcf (variable fees associated with expected production) Fully utilized FT costs of $0.54/Mcf (including both demand and variable fees) General & Administrative Costs General and administrative costs associated with Antero None $750,000 per well Land Assumes 12,000 well with 660 /1,000 spacing for Marcellus/Utica respectively and $3,600 per acre None Marcellus - $655,000 per well Utica - $1,087,000 per well Spud to FP Timing Provides a timeframe for initial spud to first production 184 days spud to FP Realized Pricing Commodity price assumptions 12/31 strip pricing (weighted) (1) SWEs exclude marketing expenses and related commodity hedge contracts that support Antero s firm transportation portfolio APPENDIX SINGLE WELL ECONOMICS 53

Antero Definitions Consolidated Adjusted EBITDAX: Represents net income or loss from continuing operations, including noncontrolling interests, before interest expense, interest income, derivative fair value gains or losses (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), taxes, impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, and gain or loss on sale of assets. Consolidated Adjusted EBITDAX also includes distributions from unconsolidated affiliates and excludes equity in earnings or losses of unconsolidated affiliates. See Non-GAAP Measures for additional detail. Consolidated Adjusted Operating Cash Flow: Represents net cash provided by operating activities before changes in current assets and liabilities. See Non-GAAP Measures for additional detail. Consolidated Drilling & Completion Capital: Represents drilling and completion capital as reported in AR s consolidated cash flow statements (i.e., fees paid to AM for water handling and treatment are eliminated upon consolidation and only operating costs associated with water handling and treatment are capitalized). Debt-Adjusted Shares: Represents ending period debt divided by ending share price plus ending shares outstanding. Forecasted debt-adjusted shares assumes AR share price of $19.87 per share as of January 12, 2018. F&D Cost: Represents 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. There is no directly comparable financial measure presented in accordance with GAAP for F&D Cost and therefore, a reconciliation to GAAP is not practicable. Free Cash Flow: Represents Stand-alone E&P Adjusted operating cash flow, less Stand-alone E&P Drilling and Completion capital, less Land Maintenance capital. See Non-GAAP Measures for additional detail. Land Maintenance Capital: Represents leasehold capital expenditures required to achieve targeted working interest percentage of 95% for 5-year development plan (i.e. historical average working interest), plus renewals associated with 5-year development plan. Leverage Ratio: Represents ending period net debt (debt adjusted for cash and cash equivalents) divided by LTM Adjusted EBITDAX. Leverage ratios for future years reflect projected net debt divided by period Adjusted EBITDAX. Maintenance Capital: Represents stand-alone E&P Drilling & Completion Capital expenditures that are estimated to be necessary to sustain production at current (2017) production levels (2.3 Bcfe/d). Stand-Alone E&P Adjusted EBITDAX: Represents income or loss from continuing operations as reported in the Parent column of AR s guarantor footnote to its financial statements before interest expense, interest income, derivative fair value gains or losses from exploration and production and marketing (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-alone E&P Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units. See Non-GAAP Measures for additional detail. Stand-Alone E&P Adjusted Operating Cash Flow: Represents net cash provided by operating activities as reported in the Parent column of AR s guarantor footnote to its financial statements before changes in current assets and liabilities, plus the AM cash distributions payable to AR, plus the earn out payments expected from Antero Midstream associated with the water drop down transaction that occurred in 2015. See Non-GAAP Measures on slide 18 for additional detail. Stand-Alone Drilling & Completion Capital: Represents drilling and completion capital as reported in the Parent column of AR s guarantor footnote to its financial statements and includes 100% of fees paid to AM for water handling and treatment and excludes operating costs associated with AM s Water Handling and Treatment segment). APPENDIX DISCLOSURES & RECONCILIATIONS 54

Antero Non-GAAP Measures Consolidated Adjusted EBITDAX, Stand-alone E&P Adjusted EBITDAX, Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow are financial measures that are not calculated in accordance with U.S. generally accepted accounting principles ( GAAP ). The non-gaap financial measures used by the company may not be comparable to similarly titled measures utilized by other companies. These measures should not be considered in isolation or as substitutes for their nearest GAAP measures. The Stand-alone measures are presented to isolate the results of the operations of Antero apart from the performance of Antero Midstream, which is otherwise consolidated into the results of Antero. Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX The GAAP financial measure nearest to Consolidated Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero s consolidated financial statements. The GAAP financial measure nearest to Stand-alone E&P Adjusted EBITDAX is Stand-alone net income or loss that will be reported in the Parent column of Antero s guarantor footnote to its financial statements. While there are limitations associated with the use of Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX described below, management believes that these measures are useful to an investor in evaluating the company s financial performance because these measures: are widely used by investors in the oil and gas industry to measure a company s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; helps investors to more meaningfully evaluate and compare the results of Antero s operations (both on a consolidated and Stand-alone basis) from period to period by removing the effect of its capital structure from its operating structure; and is used by management for various purposes, including as a measure of Antero s operating performance (both on a consolidated and Stand-alone basis), in presentations to the company s board of directors, and as a basis for strategic planning and forecasting. Consolidated Adjusted EBITDAX is also used by the board of directors as a performance measure in determining executive compensation. Consolidated Adjusted EBITDAX, as defined by our credit facility, is used by our lenders pursuant to covenants under our revolving credit facility and the indentures governing the company s senior notes. There are significant limitations to using Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company s net income on a consolidated and Stand-alone basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX provide no information regarding a company s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. APPENDIX DISCLOSURES & RECONCILIATIONS 55