Legal Disclaimer No Offer or Solicitation This presentation includes a discussion of a proposed simplification transaction (the “Transaction”) between Antero Midstream and AMGP. This presentation is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended. Important Additional Information In connection with the Transaction, AMGP has filed with the SEC a registration statement on Form S-4, that includes a joint proxy statement of Antero Midstream and AMGP and a prospectus of AMGP. The Transaction will be submitted to Antero Midstream's unitholders and AMGP's shareholders for their consideration. Antero Midstream and AMGP may also file other documents with the SEC regarding the transaction. The registration statement on Form S-4 became effective on January 30, 2019, and the definitive joint proxy statement/prospectus will be delivered to Antero Midstream unitholders and AMGP shareholders of record as of January 11, 2019. This document is not a substitute for the registration statement and joint proxy statement/prospectus that has been filed with the SEC or any other documents that AMGP or Antero Midstream may file with the SEC or send to shareholders of AMGP or unitholders of Antero Midstream in connection with the transaction. INVESTORS AND SECURITY HOLDERS OF ANTERO MIDSTREAM AND AMGP ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS. Investors and security holders are able to obtain free copies of the registration statement and the joint proxy statement/prospectus and all other documents filed or that will be filed with the SEC by AMGP or Antero Midstream through the website maintained by the SEC at http://www.sec.gov. Copies of documents filed with the SEC by Antero Midstream will be made available free of charge on Antero Midstream’s website at https://www.anteromidstream.com/investors/sec-filings, or by directing a request to Investor Relations, Antero Midstream Partners LP, 1615 Wynkoop Street, Denver, Colorado 80202, Tel. No. (303) 357-7310. Copies of documents filed with the SEC by AMGP will be made available free of charge on AMGP's website at https://www.anteromidstreamgp.com/investors/sec-filings, or by directing a request to Investor Relations, Antero Midstream GP LP, 1615 Wynkoop Street, Denver, Colorado 80202, Tel. No. (303) 357-7310. 2 Antero Resources credit suisse annual energy summit

Legal Disclaimer Continued 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 presentation regarding activities, events or developments AR expects, believes or anticipates will or may occur in the future, such as 2019 and long-term financial and operational outlook, the expected sources of funding and timing for completion of the share repurchase program if at all, impacts of hedge monetizations, the expected consideration to be received in connection with the closing of the Transaction, the timing of the consummation of the Transaction, if at all, impacts of natural gas price realizations, AR’s expected ability to return capital to investors and targeted leverage metrics, AR’s estimated unhedged EBITDAX multiples, future plans for processing plants and fractionators, AR’s estimated production and the expected impact of Mariner East 2 on AR’s NGL pricing, 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 presentation. Although AR 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. 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 Adjusted EBITDAX, (iii) Stand-alone Adjusted Operating Cash Flow, (iv) 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. 3 Antero Resources credit suisse annual energy summit

The Size and Scale to Capitalize on the Resource 4 Antero Resources credit suisse annual energy summit Market Cap . ........... Enterprise Value(1) . Corporate Debt Ratings Stand-alone Leverage(2) ..... 2019 Net Production Guidance Liquids................................ 3P Reserves .. ........... C2+ NGLs(3)........................ Condensate......................... Net Acres . ... Core Drilling Locations .. AR Midstream Ownership (53%) $3.1B $6.7B Ba2 / BB+ / BBB- <2.2x 3.15 - 3.25 Bcfe/d 154 -164 MBbl/d 54.6 Tcfe 2,131 MMBbls 131 MMBbls 612,000 3,295 $2.5B Note: Equity market data as of 01/31/19. Balance sheet data, hedge mark to market as of 9/30/18 pro forma for $357 million hedge monetization on 12/18/2018 and share repurchases. Reserves as of 12/31/2017. Enterprise value excludes AM net debt. See 2019 Guidance page for production guidance details. Includes ownership of $2.4 billion of Antero Midstream units. Stand-alone leverage is Stand-alone debt divided by LTM Stand-alone Adjusted EBITDAX and represents 9/30/18, pro forma for the $357 hedge monetization. C2+ 3P Reserves contain 1,318 MMBbls of C3+ NGLs and 812 MMBbls of ethane. Assumes approximately 31% ethane recovery leaving 1,808 MMBbls of additional ethane in the natural gas stream. Antero Resources Profile Antero Acreage SW Marcellus Core Ohio Utica Core

Recent Developments/Near-Term Catalysts Antero Announces 2019 Capital Budget and Production Guidance (January 2019) Disciplined plan with >20% reduction in D&C capital spending relative to 2018, within cash flow(1), while targeting 17% - 20% year-over-year production growth in 2019 Long-term outlook of 10% to 15% production growth creates substantial flexibility to adjust future development plans based on commodity prices Midstream Simplification (Expected to close in March 2019) AR expected to receive at least $300 million in cash proceeds depending on the cash election of public AM unitholders (subject to the approval of Antero Midstream unitholders and AMGP shareholders) Hedge Restructuring & Deleveraging (December 2018) Generated proceeds of $357 million to repay debt Resulting hedge portfolio protects price on 100% of 2019 and >50% of 2020 expected natural gas production at ~$3.00/MMBtu Mariner East 2 In-service (December 2018) ME2 initial phase in-service on 12/29/18 (capacity to move AR’s 50,000 Bbl/d commitment) AR’s 11,500 Bbl/d ethane sales contract with Borealis was in-service 11/1/2018 and 5,000 Bbl/d ethane contract with Ineos in-service 1/1/2019 with exports out of Marcus Hook, PA on ME1 Share Repurchases (November/December 2018) Repurchased 9.1 million shares (3% of outstanding shares) for $129 million $471 million remaining in current $600 million share repurchase program Rover Sherwood Lateral In-service (November 2018) Enabled AR to shift ~550 MMcf/d of gas sales from Appalachian Basin pricing to premium Midwest pricing 6 Antero Resources credit suisse annual energy summit Stand-alone drilling and completion capital spending at approximately Stand-alone Adjusted Operating Cash Flow levels assuming $50 per barrel WTI oil and $3.00 per MMBtu NYMEX natural gas prices.

Resilient and Flexible Development Plan 7 Lower Prices Higher Prices Lower Prices: $50 Oil / $2.85 Gas 10% Production CAGR (2019-2023) <2x Stand-alone leverage by 2022 Free Cash Flow neutrality 100% hedged on 2019 production guidance and 55%-60% hedged on 2020 outlook Antero’s flexible development program through 2023 will be responsive to commodity prices to grow production and maximize free cash flow Higher Prices: $65 Oil / $3.15 Gas 15% Production CAGR (2019-2023) <1x Stand-alone leverage by 2021 $2.5 - $3.0 Bn of Free Cash Flow Appropriate mix of return of capital and balance sheet deleveraging Maintain balance sheet strength Disciplined growth with expanding margins Likely outcome is somewhere in between Antero Resources credit suisse annual energy summit

10% Production CAGR 8 Disciplined Development Plan Antero Resources credit suisse annual energy summit <2x Standalone Leverage by 2022 Free Cash Flow Neutrality $50 / $2.85 15% Production CAGR <1x Standalone Leverage by 2021 $2.5 - $3.0 Bn Free Cash Flow $65 / $3.15 Note: Production CAGR ranges apply to midpoint of 2019 production guidance. Based on midpoint of 2019 production guidance. Depending on the commodity price environment, Antero is poised to prudently grow production to maximize free cash flow, ultimately resulting in an appropriate mix of return of capital to shareholders and further deleveraging Production Growth Scenarios (2020 – 2023) 10% Growth CAGR ($50 Oil / $2.85) 15% Growth CAGR ($65 Oil / $3.15) $2.5 - $3.0 Bn Free Cash Flow Generation Oil and Gas Price Assumptions 0 1,000 2,000 3,000 4,000 5,000 6,000 2019 Guidance 2020E 2021E 2022E 2023E Production (MMcfe/d)

Status Quo Structure Antero Simplified Pro Forma Structure Simplified Pro Forma Structure 53% 100% Incentive Distribution Rights (IDRs) Sponsors/ Management Public Public 23% 77% Sponsors/ Management Public 57% 43% 47% 23% 77% 31% Midstream simplification transaction results in one publicly traded midstream entity and better aligns the interests of PE sponsors and management with AR shareholders Eliminates IDRs and the Series B profits interests related to the IDRs AR shareholders and PE sponsors / management will all own the same type of interest in the midstream entity (common stock) Public Public Sponsors/ Management Sponsors/ Management 24% 10 Series B Profits Interest (1) 45% 1) Series B profits interest held by Antero management. New AM 508 MM shares 188 MM units 186 MM shares Antero Resources credit suisse annual energy summit $300MM+ Cash

Antero’s NGL Pricing Uplift from Mariner East 2 31 Mont Belvieu Conway Europe Netback 2019 NWE Price ($/Gal) $0.80 Pipeline, Terminal & Shipping Cost (1) $(0.22) NWE Netback $0.58 Blended Conway / MB Netback $0.52 Uplift vs. YTD 2018 Average Differential +$0.06 Asia Netback 2019 FEI Price ($/Gal) $0.88 Pipeline, Terminal & Shipping Cost (1) $(0.29) Asia Netback $0.59 Blended Conway / MB Netback $0.52 Uplift vs. YTD 2018 Average Differential +$0.07 ME2 Rail To Europe NWE Index Rail To Asia FEI Index International Markets Domestic Markets Marcus Hook Antero Blended Netback 2019 Mt. Belvieu Price ($/Gal) $0.70 YTD 2018 Differential $(0.18) MB Netback $0.52 Source: Poten Partners. Prices reflect blended price of propane and butane based on Antero’s ME2 volume commitment. Note: Based on Baltic forward shipping rates and propane strip prices as of 01/31/18. Includes associated port and canal fees and charges. Based on Wall Street research. Antero cost may be lower. Mariner East 2 (“ME2”) Initial Capacity (4Q18): 145 MBbl/d Full Capacity (3Q19): 275 MBbl/d AR Commitments: 35 Mbbl/d C3 15 MBbl/d C4 AR Expansion Rights: 50 Mbbl/d C3/C4 Local Mariner East 2 allows AR to access international LPG markets and realize a ~$2 to $4/Bbl uplift on its exported barrels 50,000 Bbl/d Mariner East 2 export capability equates to ~$50 to $60 MM of incremental annual cash flow Online 12/29/18 12 Existing Option Antero Resources credit suisse annual energy summit

Firm Transportation Portfolio Provides Visibility 13 All of Antero Resources’ contracted firm capacity is now in-service, providing visible production growth and sales to diversified markets Antero Resources Firm Transportation Portfolio vs. Gross Gas Production (MMcf/d) Appalachia (M2/Dom S.) – 625 MMcf/d TCO Pool – 690 MMcf/d Gulf Coast – 2,100 MMcf/d Mid-Atlantic/NYMEX: 530 MMcf/d Midwest: 800 MMcf/d Premium Markets Outside of Appalachia Regional markets and lowest transport cost AR’s Firm Transport expected to be filled by 2022 (excluding regional) 10% Growth CAGR ($50 Oil / $2.85 Gas) Note: 2018 and 2019 expected premiums to NYMEX and net marketing expense based on previously disclosed guidance. 1) Based on expected sales volumes and $2.85/MMBtu NYMEX natural gas. Total 4.7 Bcf/d (MMcf/d) Antero Resources credit suisse annual energy summit Averaged a pre-hedge premium to NYMEX 2011 – 2018E(2) 15% Growth CAGR ($65 Oil / $3.15 Gas) 2) Unutilized firm transport cost, assuming no mitigation, divided into estimated average net production 3) 2019 natural gas volume assumes midpoint of 2019 guidance and has been grossed up for 83% net revenue interest and an 1100 BTU factor. Outer years assume 10% or 15% year-over-year growth thereafter. Production Target Range(3) Net Marketing Expense ($/Mcfe):(2) ($0.175) – ($0.225) ($0.13) – ($0.18) 2019E 2020E 2021E ($0.05) – ($0.10) Expected Premium to NYMEX:(1) $0.15 – $0.20 $0.10 – $0.15 $0.08 – $0.13 0 1,000 2,000 3,000 4,000 5,000 2016 2017 2018 2019 2020 2021 2022 2023

Note: Local index represents a blend of Dominion South and TETCO M2 pricing. Midwest index represents a blend of Chicago and MichCon pricing. Gulf Coast index represents a blend of Gulf and Nymex-based pricing. 2018 represents YTD actuals through November and projected volumes for December. 2018 pricing assumes a blend of actuals through November and first of month December pricing. 2018E implied premium to Nymex assumes a ~$0.29/Mcf Btu upgrade. 2019E premium to Nymex represents 2019 guidance and assumes a $0.30/Mcf Btu upgrade. Antero Firm Transport Index Breakdown Expected Natural Gas Price Realization Improvement ~100% of Antero Gas Is Expected to be Sold in Favorably Priced Markets Beginning December 2018 14 Implied Premium to Nymex(1)(2) +$0.15 +$0.15 - +$0.20 Local Midwest TCO Gulf Coast 2% increase to Gulf Coast Markets 1% increase to Midwest Markets 6% decrease to Local Markets Antero Resources credit suisse annual energy summit 3% increase to TCO Market (1) 58% 60% 15% 18% 18% 19% 9% 3% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2018E 2019E

Sustainable and De-risked Business Model 15 Firm Transportation Portfolio Allows Antero Resources to achieve: Effectively Hedge NYMEX Index Allows Antero to directly hedge the absolute price Premium Price Certainty Eliminates basis risk by delivering to NYMEX-related markets Hedge Portfolio Supports Firm Pipeline Commitments Antero Resources is 100% hedged on natural gas through 2019; Hedges and FT provide price stability to support sustainable long-term development Appalachia: Floating – High Volatility Antero: Resources Diversified – Low Volatility Antero Natural Gas Differentials vs. Appalachia Reflects discount to NYMEX for Appalachia in-basin pricing at Dominion South & TETCO M2 indices. Represents simple average discount to NYMEX for Antero firm transportation capacity. Dec-18 Note: Pricing reflects pre-hedge pricing Antero Resources credit suisse annual energy summit ($0.88) $0.00 ($2.50) ($2.00) ($1.50) ($1.00) ($0.50) $0.00 $0.50 $1.00 Appalachia Antero Realized Differential 3-Year Appalchian Average 3-Year Antero Realized Basis

Vertical Integration is Critical in Shale Development 16 Antero’s integrated strategy has resulted in peer-leading realized prices and margins for 6 straight years and consistent results through commodity cycles All-in Pricing Realizations ($/Mcfe) Stand-alone E&P Adjusted EBITDAX Margins ($/Mcfe) Source: SEC filings and press releases. Peers include: CNX, COG, EQT, RRC & SWN. See appendix for detailed calculations. +36% vs. Peer Avg. from 2013 - 2018 +28% vs. Peer Avg. from 2013 - 2018 Antero Resources credit Suisse annual energy summit $5.17 $5.10 $4.09 $4.08 $3.61 $3.98 $2.83 $3.65 $4.41 $2.66 $2.46 $3.11 $2.96 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 2013 2014 2015 2016 2017 3Q 18 AR Peer Average NYMEX Henry Hub Gas $3.36 $2.97 $2.07 $2.06 $1.61 $1.68 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 2013 2014 2015 2016 2017 3Q 18 AR Peer Average

Antero is the Largest NGL Producer in the U.S. Undrilled Core Liquids-rich Inventory(2) Top U.S. C2+ NGL Producers - 2019E(1) Antero is the largest NGL producer in the U.S. and controls 40% of the core undrilled liquids-rich locations in Appalachia(2) Over 2.5x Inventory of closest Appalachian competitor Most exposure to NGL prices Antero C2+ NGL production represents the midpoint of 2019 guidance. Peer C2+ NGL production represents consensus as of 1/31/2019. Percentage of pre-hedge commodity revenues based on 3Q 2018 actuals. Based on Antero analysis of undeveloped acreage in the core of the Marcellus and Utica plays. Peers include Ascent, CHK, CNX, CVX, Equinor , EQT, GPOR, HG, RRC and SWN. 18 Peer Avg. Pre-Hedge NGL % of Product Revenue Antero Resources credit suisse annual energy summit (MBbls/d) 2,043 796 - 500 1,000 1,500 2,000 2,500 AR A B C D E F G H I J Undrilled Liquids - Rich Locations 150 37% 17% 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 50 60 70 80 90 100 110 120 130 140 150

U.S. Gas Supply and Base Decline 20 Current(1): 85 Bcf/d Source: S&P Global Platts. Note: Platts supply forecast through 2023 is within a 2% tolerance of EIA’s supply forecast over the same period. Current 2018 year end volumes represent Platts modeled 4Q 2018 average volumes and are not yet finalized. Top five basins/plays that are included in the Rest of U.S. Base decline calculated using 4Q over 4Q forecast production rates for all wells producing as of year-end 2018 based on Platts bottoms up well by well analysis. See appendix for detailed calculations. Includes: Gulf Coast/GOM, SCOOP/STACK, Green River, Barnett, Anadarko(2) Permian Appalachia Greater Haynesville DJ Bakken Eagle Ford 23 Bcf/d of new supply needed just to offset 2019 U.S. Base Decline of 27%(3) Maintenance Production Level Base Decline Antero Resources credit suisse annual energy summit Significant U.S. base decline requires substantial new supply just to maintain flat production 32% 9% 36% 13% 6% 2% 2% % Contribution to Current Supply 18% 13% 11% Rest of U.S. 9%

U.S. Gas Supply and New Supply Wedge 21 Current(1): 85 Bcf/d Source: S&P Global Platts. Platts supply forecast through 2023 is within a 2% tolerance of EIA’s supply forecast over the same period. Current 2018 year end volumes represent Platts modeled 4Q 2018 average volumes and are not yet finalized. Top five basins/plays that are included in the Rest of U.S. Base decline calculated using 4Q over 4Q forecast production rates for all wells producing as of year-end 2018 based on Platts bottoms up well by well analysis. See appendix for detailed calculations. Permian Appalachia Greater Haynesville DJ Bakken Eagle Ford Marketed Dry Gas Production Forecast Base Decline Permian Appalachia Antero Resources credit suisse annual energy summit Rest of US(3) Material demand growth through 2023 requires even more new supply YE 2023E: 96 Bcf/d 32% 9% 36% 13% 6% 2% 2% Includes: Gulf Coast/GOM, SCOOP/STACK, Green River, Barnett, Anadarko(2) Rest of U.S. % Contribution to Supply 77 Tcf

New Gas Supply Breakdown 22 Rest of US Permian Appalachian Rich Greater Haynesville DJ Eagle Ford Bakken 47% of new gas supply needed in the 2019-2023 period is forecast to come from plays with breakeven gas prices that are higher than the long-term 2020-2023 strip ~$2.67/MMBtu Economic Non-Economic SW Marcellus Dry Utica Dry Haynesville Eagle Ford Dry Permian NE Marcellus (Susquehanna) SW Marcellus Rich DJ Bakken SCOOP/STACK Antero Resources credit suisse annual energy summit 77 Tcf New Supply Needed Through 2023 (1) Platts Analytics forecasted supply growth. Breakeven analysis source: J.P. Morgan Equity Research estimates. Defined as half cycle pre-tax ROR of 25%. Assumes $50/Bbl WTI crude oil. New Supply Contribution by Basin Economic vs Non-Economic New Supply Appalachian Dry Higher Gas Prices Needed to Incentivize the Drilling Required to Meet New Supply Forecasts Breakeven Price Yields Pre-tax ROR of 25%(2) Non-Economic = Breakeven Price > $2.67 Strip 77 Tcf New Supply Needed Through 2023 (1) 16% 15% 14% 28% 16% 3% 2% 6% 53% 47%

Antero Natural Gas Breakeven Prices 23 Breakeven analysis based on same parameters as J.P. Morgan Equity Research calculation with the exception of the WTI oil price, Antero uses strip WTI. Antero drilling inventory as of 12/31/18. Breakeven price is defined as half cycle pre-tax ROR of 25%. Assumes average strip WTI oil price of $53/Bbl. Antero half cycle well economics assume 12,000’ lateral lengths and 69% of AM fees paid to account for AR’s midstream dividend stream from AM. 2020-2023 average NYMEX Henry Hub price as of 01/31/19. Antero Resources credit suisse annual energy summit The majority of Antero future drilling locations have a breakeven gas price (25% ROR threshold) below the 2020-2023 NYMEX gas strip ($2.67/MMBtu) 1,679 drilling locations have a ROR >25% at the current $2.67/MMBtu average 2020-2023 strip Breakeven Price $2.67 (2020-2023 Strip) Antero Drilling Inventory – Half Cycle Breakeven Prices at 25% ROR(1)(2) (3) 59 1,175 59 281 38 67 43 360 1,017 Undrilled Locations 1,679 premium drilling locations: breakeven < $2.67/MMBtu (13+ year low breakeven drilling inventory) $1.23 $2.09 $2.10 $2.38 $2.58 $2.64 $2.74 $2.87 $2.93 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 Marcellus Highly- Rich Gas/Cond. (1313 Btu) Marcellus Highly Rich-Gas (1250 Btu) Utica Highly-Rich Gas/Cond. (1235 Btu) Utica Condensate (1275 Btu) Utica Dry Gas (1050 Btu) Utica Highly-Rich Gas (1215 Btu) Utica Rich Gas (1175 Btu) Marcellus Rich Gas (1150 Btu) Marcellus Dry Gas (1050 Btu) Natural Gas Breakeven Price ($/MMBtu) 2020-2023 Strip

Does Natural Gas Strip Reflect Current Fundamentals? 24 Nymex Natural Gas Pricing (2017-2023) Nymex natural gas prices averaged ~$3.10/MMBtu in 2017 and 2018 $2.72/MMBtu average Nymex gas strip price from 2019-2023 not expected to stimulate enough drilling to meet the forecasted demand growth Antero Resources credit suisse annual energy summit 1) 2019E – 2023E represents strip pricing as of 01/31/2019. $3.10/MMBtu average (2017-2018) $2.93 $2.72 $2.61 $2.63 $2.71 Antero’s gas price outlook is higher than current strip prices due to the substantial new supply needed to address base decline + demand growth Antero Outlook Range $3.15 $2.85 The Futures Strip Could be “Oversold” Waves of gas hedges put in place by wind project developers Significant gas hedges put in place by merchant power developers Large gas hedges have been put on for gas asset acquisitions Reduced number of financial counterparties to execute hedge transactions (1) $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 $/MMBtu 2017A-2018A 2019E - 2023E AR Outlook - Low End AR Outlook - High End

Long Track Record Of Success 26 Distributable Cash Flow(1): $53 MM $680 MM - $730 MM $67 MM $870 MM - $920 MM Adjusted EBITDA(1): +1,201% +1,235% New AM Dividend Per Share and DCF Coverage Since IPO IPO Year - 2014 2019 Guidance 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. Historical dividends adjusted for pending simplification transaction based on 1.832x share exchange ratio assuming 100% equity consideration for public AM unitholders on announcement date of October 9, 2018. Based on share price of $13.42 per unit as of 1/31/2019. 4) DCF coverage ratio represents of guidance. Dividend represents actual declared dividends. Antero Midstream has delivered a 27% dividend CAGR through the downturn and exceeded DCF coverage targets by 22% on average since the IPO IPO DCF Coverage Midpoint Target 1.15x (2) IPO 9.2% Yield(3) 27% Dividend CAGR (4) Antero Midstream │credit suisse annual energy summit $0.37 $0.43 $0.56 $0.72 $0.94 $1.24 0.4x 0.6x 0.8x 1.0x 1.2x 1.4x 1.6x 1.8x 2.0x $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40 4Q' 14 Annualized 2015A 2016A 2017A 2018A Guidance (Midpoint) 2019 Guidance (Midpoint) Dividend DCF Coverage

Long-Term Outlook – New AM 27 18% Distributable Cash Flow CAGR Declining Leverage Profile to low to mid 2x Supports Previously Communicated Dividend Growth Targets $50 / $2.85 25% Distributable Cash Flow CAGR Declining Leverage Profile to low to mid 2x Supports Previously Communicated Dividend Growth Targets $65 / $3.15 (1) Based on AR’s flexible long-term outlook, AM is targeting an 18% - 25% distributable cash flow (DCF) CAGR from 2020 to 2022 Note: Distributable cash flow is a non-GAAP metric – see appendix for details. DCF CAGR ranges apply to midpoint of 2019 production guidance. 1) Based on the midpoint of 2019 distributable cash flow guidance. New AM Distributable Cash Flow Growth Scenarios (2020 – 2022) 18% DCF CAGR ($50 Oil / $2.85 Gas) 25% DCF CAGR ($65 Oil / $3.15 Gas) Oil and Gas Price Assumptions Antero Midstream │credit suisse annual energy summit $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 2019 Guidance 2020E 2021E 2022E Millions

DCF Profile Supports Growing Return of Capital 28 Distributable Cash Flow vs. Growth Capex ($MM) Antero Midstream’s distributable cash flow growth, self-funding business model, and leverage profile supports an increase in return of capital to shareholders 25% DCF CAGR Target Note: Distributable Cash Flow is a Non-GAAP measures. For additional information regarding these measures, please see appendix. Dividends and DCF targets pro forma for simplification transaction expected to close in March 2019. 1. Growth capex based on FactSet consensus estimates as of 1/31/2019. Excess DCF available for: Deleveraging and capital retention Dividend growth Share repurchases Organic growth capex 18% DCF CAGR Target Growth Capex(1) 1.1x-1.2x DCF Coverage Guidance in 2019 2019 Dividends (Midpoint) ($MM) Antero Midstream │credit suisse annual energy summit $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 2019 2020 2021 2022

Antero: Not Just a Natural Gas Producer Diversified Commodity Mix Enhances Value Proposition Top NGL producer in the U.S. Controlled Resource Development Mitigated Commodity Risk Just-in-time midstream Investment by AM 100% hedged on natural gas in 2019 @ $3.00/MMBtu floor on average Disciplined Focus on Returns 9.1 MM shares repurchased in 4Q 2018 Maintain Strong Balance Sheet Attractive Long-Term Outlook Peer Leading Margins 22% debt-adjusted growth per share in 2019 Appalachian leader for 6 straight years Ability to generate significant free cash flow <2.2x Pro Forma 9/30/18 Net Debt(1) Shareholder Value Low Cost Liquids-Rich Resource Base Return of Capital 29 See appendix for Non-GAAP items and reconciliation. 1) 9/30/18 net debt pro forma for $357 million hedge monetization. Antero Resources credit Suisse annual energy summit Liquids-Rich Resource and Scale

Antero Capitalization – Pro forma as of 9/30/18 Status Quo Pro Forma Antero Resources credit suisse annual energy summit 31 As of September 30, 2018 ($MM) Antero Midstream Antero Resources (Standalone) Antero Resources (Consolidated) Cash $0 $0 $0 Debt Revolving Credit Facility $875 $547 $1,422 5.375% Senior Notes Due 2021 $1,000 $1,000 5.125% Senior Notes Due 2022 $1,100 $1,100 5.625% Senior Notes Due 2023 $750 $750 5.375% Senior Notes Due 2024 $650 $650 5.000% Senior Notes Due 2025 $600 $600 Net unamortized debt issuance costs ($8) ($27) ($35) Total Debt $1,517 $3,970 $5,487 Net Debt (Total Debt - Cash) $1,517 $3,970 $5,487 LTM Adjusted EBITDA $665 $1,615 $1,891 Debt / LTM Adjusted EBITDA 2.3x 2.5x 2.9x Credit Facility Capacity $1,500 $2,500 Liquidity $625 $1,953 Publicly Announced Pro Forma Adjustments to Net Debt Since September 30, 2018 ($MM) Antero Midstream Antero Resources (Standalone) Antero Resources (Consolidated) Cash Consideration for Simplification Transaction $598 ($297) $301 Hedge Portfolio Monetization ($357) ($357) Antero Resources Share Repurchase Program $129 $129 Total Adjustments to Nebt Debt: Increase / (Decrease) $598 ($525) $73 Pro Forma Net Debt $2,115 $3,445 $5,560 Pro Froma Debt / LTM Adjusted EBITDA 3.2x 2.1x 2.9x Credit Facility Capacity $2,000 $2,500 Liquidity $527 $2,478

Antero Resources credit suisse annual energy summit 2019 Capital Plan and Guidance Stand-alone Consolidated Net Production (Bcfe/d) 3.15 – 3.25 Net Natural Gas Production (Bcf/d) 2.225 – 2.275 Net Liquids Production (Bbl/d) 154,000 – 164,000 Net Oil, C3+ and Ethane Production (Bbl/d) Oil: 8,500 – 9,500 C3+: 97,500 – 102,500 C2: 48,000 – 52,000 Natural Gas Realized Price Differential to Nymex ($/Mcf) $0.15 to $0.20 Premium C3+ NGL Realized Price (% of Nymex WTI) 60% – 65% Cash Production Expense ($/Mcfe)(1) $2.15 – $2.25 $1.65 – $1.75 Marketing Expense ($/Mcfe) $0.175 – $0.225 G&A Expense ($/Mcfe) (before equity-based compensation) $0.10 – $0.14 $0.125 - $0.175 D&C Capital Expenditures ($MM) $1,300 - $1,450 $1,100 - $1,250 Land Capital Expenditures ($MM) $75 – $100 Average Operated Rigs, Average Completion Crews & Operated Wells Completed Rigs: 5 Completion Crews: 4 Wells Completed: 115 – 125 Note: See Appendix for key definitions. 2019 average NYMEX and WTI pricing was $3.00/MMBtu and $50.00/Bbl, respectively. Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes. 32 Released on January 8, 2019

Antero Resources D&C Capital 33 Antero Resources Stand-alone Marcellus Well Cost ($MM/1,000’ assuming 12,000’ Lateral) Through negotiating contracts and self sourcing sand, Antero was able to mitigate a majority of inflationary pressures on D&C capital for 2019 Drilling, water hauling, and production facility inflation Re-negotiated completion contracts and self sand sourcing Improved completion efficiencies 100% of sand self sourced Lower water truck staging times and improved operations at Clearwater Note: Assumes 2,000 pound per foot completion. Antero Resources credit suisse annual energy summit $0.95 $0.97 $0.93 $0.93 $0.06 $0.03 $0.01 $0.01 $0.02 $0.01 $0.80 $0.85 $0.90 $0.95 $1.00 $1.05 $1.10 2018 Stand-alone Marcellus Well Cost Inflationary Costs New Sand / Completion Countracts Increased Stages per Day 2019 Budgeted Stand-alone Marcellus Well Cost Increased Sand Self Sourcing Optimized Water Logistics Further Increased Stages per Day 2019 Target Stand-alone Marcellus Well Cost

34 Drilling and Completion Efficiencies Average Lateral Feet per Day Drilling Days Average Lateral Length per Well Completion Stages per Day Antero Resources credit suisse annual energy summit 8,206 72% Increase 28% Increase 228% Increase Note: Utica 3Q 2018 results reflect YTD results, as Antero is not operating any rigs in the Utica during 2H18. Note: Percentage increase and decrease arrows represent change in Marcellus data from 2014 to 3Q 2018. Marcellus Down 59% 4,321 2,983 5,169 - 1,000 2,000 3,000 4,000 5,000 6,000 2014 2015 2016 2017 3Q 2018 RECORD Lateral Feet Marcellus Utica 10,407 15,075 11,044 17,445 - 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 2014 2015 2016 2017 3Q 2018 RECORD Lateral Feet Marcellus Utica 4.6 5.5 9.0 3.6 10.0 - 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 2014 2015 2016 2017 3Q 2018 RECORD Stages per Day Marcellus Utica 12 8 20 10 0 5 10 15 20 25 30 35 2014 2015 2016 2017 3Q 2018 RECORD Drilling Days Marcellus Utica

35 Appendix disclosures & reconciliations 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 “Antero 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 “Antero 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). 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 Adjusted operating cash flow, less Stand-alone E&P Drilling and Completion capital, less Land Maintenance capital. See “Antero 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. Stand-alone 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 “Antero Non-GAAP Measures” for additional detail. Stand-alone 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 “Antero Non-GAAP Measures” on slide 35 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).

36 Antero Non-GAAP Measures Stand-alone Adjusted Operating Cash Flow and Free Cash Flow Free Cash Flow as presented in this release and defined by the Company represents Stand-alone Adjusted Operating Cash Flow, less Stand-alone Drilling and Completion capital, less Land Maintenance Capital. Stand-alone Adjusted Operating Cash Flow represents net cash provided by operating activities that will be reported in the Parent column of Antero’s guarantor footnote to its financial statements before changes in working capital items. Stand-alone Adjusted Operating Cash Flow is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt. Stand-alone Adjusted Operating Cash Flow is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Management believes that Stand-alone Adjusted Operating Cash Flow and Free Cash Flow are useful indicators of the company’s ability to internally fund its activities and to service or incur additional debt on a Stand-alone basis. Management believes that changes in current assets and liabilities, which are excluded from the calculation of these measures, relate to the timing of cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred and generally do not have a material impact on the ability of the company to fund its operations. There are significant limitations to using Stand-alone Adjusted Operating Cash Flow and Free Cash Flow 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 Stand-alone basis, the lack of comparability of results of operations of different companies and the different methods of calculating Stand-alone Adjusted Operating Cash Flow and Free Cash Flow reported by different companies. Stand-alone Adjusted Operating Cash Flow and Free Cash Flow do not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations. Stand-alone Adjusted Operating Cash Flow and Free Cash Flow are not measures of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity. Total Debt, Net Debt and Stand-alone Net Debt Net Debt is calculated as total debt less cash and cash equivalents. Management uses Consolidated Net Debt and Stand-alone Net Debt to evaluate its financial position, including its ability to service its debt obligations. Appendix disclosures & reconciliations

37 Antero Non-GAAP Measures Continued Adjusted EBITDAX and Stand-alone Adjusted EBITDAX Adjusted EBITDAX as defined by the Company represents net income or loss, including noncontrolling interests, before interest expense, interest income, derivative fair value gains or losses, but including net cash receipts or payments on derivative instruments included in derivative fair value gains or losses, taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, and gain or loss on sale of assets. Adjusted EBITDAX also includes distributions from unconsolidated affiliates and excludes equity in earnings or losses of unconsolidated affiliates. Stand-alone Adjusted EBITDAX as defined by the Company represents income or loss as reported in the Parent column of Antero's guarantor footnote to its financial statements before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative gains or losses, income taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, equity in earnings or loss of Antero Midstream and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-alone Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units. The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero's condensed consolidated financial statements. The GAAP financial measure nearest to Stand-alone 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 Adjusted EBITDAX and Stand-alone 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. Adjusted EBITDAX is also used by the board of directors as a performance measure in determining executive compensation. 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 Adjusted EBITDAX and Stand-alone 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, Adjusted EBITDAX and Stand-alone Adjusted EBITDAX provide no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Antero has not included reconciliations of Stand-alone Adjusted Operating Cash Flow and Free Cash Flow to their nearest GAAP financial measures because it cannot do so without unreasonable effort and any attempt to do so would be inherently imprecise. Appendix disclosures & reconciliations

Antero Resources Standalone Adjusted EBITDAX Reconciliation Stand-alone LTM Adjusted EBITDAX Reconciliation Appendix disclosures & reconciliations 38 Stand-alone Twelve months ended September 30, (in thousands) 2018 Net income attributable to Antero Resources Corporation $ 210,898 Commodity derivative fair value gains (334,617) Gains on settled commodity derivatives 344,917 Marketing derivative fair value gains (72,687) Gains on settled marketing derivatives 78,098 Interest expense 219,206 Loss on early extinguishment of debt 1,205 Income tax benefit (397,638) Depletion, depreciation, amortization, and accretion 787,598 Impairment of unproved properties 482,568 Impairment of gathering systems and facilities 4,470 Exploration expense 7,050 Gain on change in fair value of contingent acquisition consideration (15,645) Equity-based compensation expense 57,496 Equity in (earnings) loss of Antero Midstream 92,545 Distributions from Antero Midstream 149,292 Adjusted EBITDAX $ 1,614,756

Antero Resources Stand-alone Adjusted EBITDAX Per Mcfe Appendix disclosures & reconciliations 39 Stand-alone Adjusted EBITDAX per Mcfe Reconciliation (Annual) 2013 2014 2015 2016 2017 1Q2018 2Q2018 3Q2018 ($/Mcfe) Natural Gas, Oil, Ethane and NGL sales 4.31 $ 4.74 $ 2.53 $ 2.60 $ 3.35 $ 3.56 $ 3.35 $ 3.70 $ Realized commodity derivative gains (losses) 0.86 $ 0.37 $ 1.57 $ 1.48 $ 0.26 $ 0.47 $ 0.42 $ 0.28 $ Distributions from Antero Midstream - $ - $ 0.16 $ 0.17 $ 0.16 $ 0.17 $ 0.17 $ 0.16 $ All-In E&P Revenue 5.17 $ 5.10 $ 4.27 $ 4.25 $ 3.77 $ 4.21 $ 3.94 $ 4.15 $ Gathering, compression, processing, and transportation 1.25 $ 1.46 $ 1.56 $ 1.70 $ 1.75 $ 1.80 $ 1.79 $ 1.77 $ Production and ad valorem taxes 0.24 0.23 0.14 0.10 0.11 0.12 0.11 0.12 Lease operating expenses 0.05 0.08 0.07 0.07 0.11 0.15 0.14 0.14 Net Marketing Expense / (Gain) - 0.14 0.23 0.16 0.13 (0.27) 0.30 0.31 General and administrative (before equity-based compensation) 0.26 0.23 0.20 0.16 0.15 0.15 0.15 0.14 Total E&P Cash Costs 1.81 $ 2.14 $ 2.20 $ 2.19 $ 2.26 $ 1.93 $ 2.48 $ 2.48 $ E&P EBITDAX Margin (All-In) 3.36 $ 2.96 $ 2.07 $ 2.06 $ 1.61 $ 2.28 $ 1.46 $ 1.68 $ Production Volumes (Bcfe) 191 368 545 676 822 214 229 250 $ Millions Natural Gas, Oil, Ethane and NGL sales 821 $ 1,741 $ 1,379 $ 1,757 $ 2,751 $ 762 $ 768 $ 925 $ Realized commodity derivative gains (losses) 164 136 857 1,003 214 101 96 71 Distributions from Antero Midstream 89 112 132 36 39 41 All-In E&P Revenue 985 $ 1,877 $ 2,324 $ 2,872 $ 3,097 $ 900 $ 903 $ 1,037 $ Gathering, compression, processing, and transportation 239 537 853 1,146 1,441 384 410 443 Production and ad valorem taxes 46 86 77 69 91 25 25 29 Lease operating expenses 9 28 36 51 94 31 32 35 Net Marketing Expense / (Gain) - 50 123 106 108 (59) 69 78 General and administrative (before equity-based compensation) 50 86 108 110 119 31 33 34 Total E&P Cash Costs 345 $ 786 $ 1,196 $ 1,483 $ 1,853 $ 413 $ 569 $ 619 $

Antero Midstream Non-GAAP Measures 40 The following table reconciles net income to Adjusted EBITDA for the twelve months ended September 30, 2018 as used in this presentation (in thousands): The following table reconciles consolidated total debt to consolidated net debt (“Net Debt”) as used in this presentation (in thousands): September 30, 2018 Bank credit facility $ 875,000 5.375% AM senior notes due 2024 650,000 Net unamortized debt issuance costs (8,146) Consolidated total debt $ 1,516,854 Cash and cash equivalents — Consolidated net debt $ 1,516,854 Twelve Months Ended September 30, 2018 Net income $ 401,491 Interest expense 53,307 Impairment of property and equipment expense 29,202 Depreciation expense 138,279 Accretion of contingent acquisition consideration 15,644 Accretion of asset retirement obligations 101 Equity-based compensation 23,453 Equity in earnings of unconsolidated affiliate (35,139) Distributions from unconsolidated affiliates 39,735 Gain on sale of asset – Antero Resources (583) Adjusted EBITDA $ 665,490 Appendix disclosures & reconciliations