Legal Disclaimer NO OFFER OR SOLICITATION This presentation includes a discussion of a proposed business combination transaction (the “Transaction”) between AM 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 U.S. Securities and Exchange Commission (“SEC”) a registration statement on Form S-4, that includes a joint proxy statement of AM and AMGP and a prospectus of AMGP. The Transaction will be submitted to AM’s unitholders and AMGP’s shareholders for their consideration. AM and AMGP may also file other documents with the SEC regarding the Transaction. The registration statement on Form S-4 has not been declared effective by the SEC, and the definitive joint proxy statement/prospectus has not yet been delivered to the shareholders of AMGP and unitholders of AM. 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 AM may file with the SEC or send to shareholders of AMGP or unitholders of AM 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 will be able to obtain free copies of the registration statement and the joint proxy statement/prospectus (when available) and all other documents filed or that will be filed with the SEC by AMGP or AM through the website maintained by the SEC at http://www.sec.gov. Copies of documents filed with the SEC by AM will be made available free of charge on AM’s website at http://investors.anteromidstream.com/investor-relations/AM, under the heading “SEC Filings,” or by directing a request to Investor Relations, Antero Midstream Partners LP, 1615 Wynkoop Street, Denver, Colorado 75219, 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 http://investors.anteromidstreamgp.com/Investor-Relations/AMGP or by directing a request to Investor Relations, Antero Midstream GP LP, 1615 Wynkoop Street, Denver, Colorado 75219, Tel. No. (303) 357-7310. PARTICIPANTS IN THE SOLICITATION AMGP, AM, AR and the directors and executive officers of AMGP and AM’s respective general partners and of AR may be deemed to be participants in the solicitation of proxies in respect to the Transaction. Information regarding the directors and executive officers of AM’s general partner is contained in AM’s 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2019, and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC’s website at http://www.sec.gov or by accessing AM’s website at http://www.anteromidstream.com. Information regarding the executive officers and directors of AMGP’s general partner is contained in AMGP’s 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2019 and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC’s website at www.sec.gov or by accessing the AMGP’s website at http://www.anteromidstream.com. Information regarding the executive officers and directors of AR is contained in AR’s 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2019 and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC’s website at www.sec.gov or by accessing the AMGP’s website at http:// www.anteroresources.com. Investors may obtain additional information regarding the interests of those persons and other persons who may be deemed participants in the Transaction by reading the joint proxy statement/prospectus regarding the Transaction when it becomes available. You may obtain free copies of this document as described above. 2 Antero Resources February 2019 Presentation

Legal Disclaimer 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, 2018. 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 February 2019 Presentation

The Size and Scale to Capitalize on the Resource 4 Antero Resources February 2019 Presentation Market Cap . ........... Enterprise Value(1) . Corporate Debt Ratings Stand-alone Leverage(2) ..... 2019 Net Production Guidance Liquids................................ Proved Reserves .. ........... C2+ NGLs(3)........................ Condensate......................... Net Acres . ... Core Drilling Locations .. AR Midstream Ownership (53%) $2.9B $6.7B Ba2 / BB+ / BBB- 2.2x 3.15 - 3.25 Bcfe/d 154 -164 MBbl/d 18.0 Tcfe 1,052 MMBbls 46 MMBbls 612,000 3,013 $2.5B Note: Equity market data as of 02/12/19. Reserves as of 12/31/2018. 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 12/31/18. See appendix for details. C2+ proved reserves contain 498 MMBbls of C3+ NGLs and 554 MMBbls of ethane. Assumes approximately 415 MMBbls of additional ethane are left in the natural gas stream. Antero Resources Profile Antero Acreage SW Marcellus Core Ohio Utica Core

Recent Developments/Near-Term Catalysts Midstream Simplification (Expected to close in March 2019) Expected to provide AR with at least $300 million in cash depending on the cash election of public AM unitholders (subject to the approval of Antero Midstream unitholders and AMGP shareholders) AR will no longer consolidate AM beginning in 1Q 2019, but will account for New AM using the equity method, presenting better clarity for AR investors 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 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) at an average price of $14.10/share Approximately $470 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 February 2019 Presentation 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.

10% Production CAGR 8 Disciplined Development Plan Antero Resources February 2019 Presentation <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)

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/Bbl 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 10 Existing Option Antero Resources February 2019 Presentation

Firm Transportation Portfolio Provides Visibility 12 All of Antero Resources’ contracted firm capacity is now in service, providing visible production growth and premium pricing to NYMEX 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 February 2019 Presentation 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 premium to NYMEX includes a ~$0.27/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 Substantially All of Antero’s Gas Is Expected to be Sold in Favorably Priced in 2019 13 Implied Premium to NYMEX(1) +$0.13 +$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 February 2019 Presentation 3% increase to TCO Market 56% 60% 17% 18% 17% 19% 10% 3% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2018A 2019E

Sustainable and De-risked Business Model 14 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 in 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 February 2019 Presentation ($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

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% 16 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 February 2019 Presentation $300MM+ Cash

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. 19 Peer Avg. Pre-Hedge NGL % of Product Revenue Antero Resources February 2019 Presentation (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

Integration is Critical in Shale Development 21 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%(1) vs. Peer Avg. from 2013 - 2017 +31%(1) vs. Peer Avg. from 2013 - 2017 Antero Resources February 2019 Presentation $5.17 $5.10 $4.09 $4.08 $3.61 $3.94 $3.65 $4.41 $2.66 $2.46 $3.11 $3.09 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 2013 2014 2015 2016 2017 2018 AR Peer Average NYMEX Henry Hub Gas $3.36 $2.97 $2.07 $2.06 $1.61 $1.74 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 2013 2014 2015 2016 2017 2018 AR Peer Average

As of December 31, 2018 ($MM) Antero Midstream Antero Resources (Stand-alone) Antero Resources (Consolidated) Cash $0 $0 $0 Debt Revolving Credit Facility $990 $405 $1,395 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) ($25) ($33) Total Debt $1,632 $3,830 $5,462 Net Debt (Total Debt - Cash) $1,632 $3,830 $5,462 LTM Adjusted EBITDA $717 $1,717 $2,037 Debt / LTM Adjusted EBITDA 2.3x 2.2x 2.7x Credit Facility Capacity $1,500 $2,500 Liquidity $510 $2,095 Publicly Announced Pro Forma Adjustments to Net Debt Since December 31, 2018 ($MM) Antero Midstream Antero Resources (Stand-alone) Antero Resources (Consolidated) Cash Consideration for Simplification Transaction $598 ($297) $301 Total Adjustments to Net Debt: Increase / (Decrease) $598 ($297) $301 Pro Forma Net Debt $2,230 $3,533 $5,763 Pro Forma Debt / LTM Adjusted EBITDA 3.1x 2.1x 2.8x Credit Facility Capacity $2,000 $2,500 Liquidity $412 $2,392 Antero Capitalization – Pro forma as of 12/31/18 Status Quo Pro Forma Appendix Pro Forma Capitalization 24

Appendix 2019 Guidance 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. 25 Released on January 8, 2019

Antero Resources D&C Capital 26 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. Appendix Drilling & Completion Capital $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

27 Drilling and Completion Efficiencies Average Lateral Feet per Day Drilling Days Average Lateral Length per Well Completion Stages per Day Appendix cost efficiency drivers 8,206 78% Increase 24% Increase 286% Increase Note: Utica 4Q 2018 results reflect YTD results, as Antero did not operate any rigs in the Utica during 2H18. Note: Percentage increase and decrease arrows represent change in Marcellus data from 2014 to 4Q 2018. Marcellus Down 59% 5,081 2,901 5,169 - 1,000 2,000 3,000 4,000 5,000 6,000 2014 2015 2016 2017 4Q 2018 RECORD Lateral Feet Marcellus Utica 10,093 15,075 11,412 17,445 - 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 2014 2015 2016 2017 4Q 2018 RECORD Lateral Feet Marcellus Utica 4.6 5.7 9.0 3.6 4.9 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 4Q 2018 RECORD Stages per Day Marcellus Utica 12 8 18 10 0 5 10 15 20 25 30 35 2014 2015 2016 2017 4Q 2018 RECORD Drilling Days Marcellus Utica

30 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).

31 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

32 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 Stand-alone Adjusted EBITDAX Reconciliation Stand-alone LTM Adjusted EBITDAX Reconciliation Appendix disclosures & reconciliations 33 Stand-alone Twelve months ended (in thousands) December 31, 2018 Net (loss) and comprehensive (loss) attributable to Antero Resources Corporation $ (397,517) Commodity derivative fair value (gains) losses 87,594 Gains on settled commodity derivatives 243,112 Marketing derivative fair value gains (94,081) Gains on settled marketing derivatives 72,687 Interest expense 224,977 Income tax benefit (128,857) Depletion, depreciation, amortization, and accretion 845,136 Impairment of unproved properties 549,437 Impairment of gathering systems and facilities 4,470 Exploration expense 4,958 Gain on change in fair value of contingent acquisition consideration 93,019 Equity-based compensation expense 49,341 Equity in (earnings) loss of Antero Midstream Partners LP 3,664 Distributions from Antero Midstream Partners LP 159,181 Adjusted EBITDAX $ 1,717,121

Antero Resources Stand-alone Adjusted EBITDAX Per Mcfe Appendix disclosures & reconciliations 34 Stand-alone Adjusted EBITDAX per Mcfe Reconciliation (Annual) 2013 2014 2015 2016 2017 1Q2018 2Q2018 3Q2018 4Q2018 ($/Mcfe) Natural Gas, Oil, Ethane and NGL sales $ 4.31 $ 4.74 $ 2.53 $ 2.60 $ 3.35 $ 3.56 $ 3.35 $ 3.70 $ 4.05 Realized commodity derivative gains (losses) $ 0.86 $ 0.37 $ 1.57 $ 1.48 $ 0.26 $ 0.47 $ 0.42 $ 0.28 $ (0.09) Distributions from Antero Midstream $ - $ - $ 0.16 $ 0.17 $ 0.16 $ 0.17 $ 0.17 $ 0.16 $ 0.15 Less: WGL + SJR Impact $ 0.10 All-In E&P Revenue $ 5.17 $ 5.10 $ 4.27 $ 4.25 $ 3.77 $ 4.21 $ 3.94 $ 4.15 $ 4.11 Gathering, compression, processing, and transportation $ 1.25 $ 1.46 $ 1.56 $ 1.70 $ 1.75 $ 1.80 $ 1.79 $ 1.77 $ 1.88 Production and ad valorem taxes 0.24 0.23 0.14 0.10 0.11 0.12 0.11 0.12 0.15 Lease operating expenses 0.05 0.08 0.07 0.07 0.11 0.15 0.14 0.14 0.15 Net Marketing Expense / (Gain) - 0.14 0.23 0.16 0.13 (0.27) 0.30 0.31 0.22 General and administrative (before equity-based compensation) 0.26 0.23 0.20 0.16 0.15 0.15 0.15 0.14 0.11 Total E&P Cash Costs $ 1.81 $ 2.14 $ 2.20 $ 2.19 $ 2.26 $ 1.93 $ 2.48 $ 2.48 $ 2.51 E&P EBITDAX Margin (All-In) $ 3.36 $ 2.96 $ 2.07 $ 2.06 $ 1.61 $ 2.28 $ 1.46 $ 1.68 $ 1.61 Production Volumes (Bcfe) 191 368 545 676 822 214 229 250 296 $ Millions Natural Gas, Oil, Ethane and NGL sales $ 821 $ 1,741 $ 1,379 $ 1,757 $ 2,751 $ 762 $ 768 $ 925 $ 1,197 Realized commodity derivative gains (losses) 164 136 857 1,003 214 101 96 71 (25) Distributions from Antero Midstream 89 112 132 36 39 41 44 All-In E&P Revenue $ 985 $ 1,877 $ 2,324 $ 2,872 $ 3,097 $ 900 $ 903 $ 1,037 $ 1,216 Gathering, compression, processing, and transportation 239 537 853 1,146 1,441 384 410 443 556 Production and ad valorem taxes 46 86 77 69 91 25 25 29 43 Lease operating expenses 9 28 36 51 94 31 32 35 44 Net Marketing Expense / (Gain) - 50 123 106 108 (59) 69 78 66 General and administrative (before equity-based compensation) 50 86 108 110 119 31 33 34 33 Total E&P Cash Costs $ 345 $ 786 $ 1,196 $ 1,483 $ 1,853 $ 413 $ 569 $ 619 $ 742

Antero Midstream Non-GAAP Measures 35 The following table reconciles net income to Adjusted EBITDA for the twelve months ended December 31, 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): December 31, 2018 Bank credit facility $ 990,000 5.375% AM senior notes due 2024 650,000 Net unamortized debt issuance costs (7,853) Total debt $ 1,632,147 Cash and cash equivalents — Net debt $ 1,632,147 Appendix disclosures & reconciliations Twelve Months Ended December 31, 2018 Net income $ 585,944 Impairment of property and equipment 5,771 Change in fair value of contingent acquisition consideration (106,275) Adjusted Net Income $ 485,440 Interest expense 61,906 Depreciation expense 130,013 Accretion of contingent acquisition consideration 13,256 Accretion of asset retirement obligation 135 Equity-based compensation 21,073 Equity in earnings of unconsolidated affiliates 40,280 Distributions from unconsolidated affiliates 46,415 Gain on asset sale (583) Adjusted EBITDA $ 717,375