Antero Resources 8K Regulation FD Disclosure | AR 6 Nov 18

Exhibit 99.2

Company Presentation November 2018

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 will file with the U.S. Securities and Exchange Commission (“SEC”) a registration statement on Form S-4, that will include 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 definitive joint proxy statement/prospectus will be sent 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 will be 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 WHEN IT BECOMES AVAILABLE 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, 2018, 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, 2018 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, 2018 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 november 2018 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 the expected sources of funding and timing for completion of the share repurchase program if at all, 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, the extent to which AR will be shielded from tax payments associated with the Transaction, pro forma AM dividend and DCF coverage targets, estimated pro forma AM dividend CAGR and leverage metrics, 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) Consolidated Adjusted Operating Cash Flow, (iv) Stand-Alone 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. 3 Antero Resources november 2018 Presentation

The Size and Scale to Capitalize on the Resource 4 Antero Resources November 2018 presentation Market Cap . ........... Enterprise Value . Corporate Debt Ratings Stand-Alone Debt/Adj. EBITDAX Net Production (2018E) ....... Liquids................................ 3P Reserves .. ........... C2+ NGLs(1)........................... Condensate......................... Net Acres . ... Core Drilling Locations . Hedge Mark to Market .. AR Midstream Ownership (53%) $5.0B $9.0B Ba2 / BB+ / BBB- 2.5x 2.7 Bcfe/d 130,000 Bbl/d 54.6 Tcfe 2,131 MMBbls 131 MMBbls 620,000 3,295 $1.2B $2.9B Note: Equity market data as of 10/31/18. Balance sheet data, hedge mark to market as of 9/30/18. Reserves as of 12/31/2017. Enterprise value excludes AM net debt. See 2018 Guidance in Appendix. (1) 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 ethane in the natural gas stream. Antero Resources Profile Antero Acreage SW Marcellus Core Ohio Utica Core

Rover Pipeline Uplift and Optionality 5 Unlocks development optionality between Marcellus and Utica and provides further Chicago & Gulf Coast exposure Rover Sherwood Lateral recently received approval to be placed into service in November Rover Pipeline Map Chicago via Rover ($/MMBtu) 2019 Chicago Price ($/MMbtu)(1) $2.62 Approximate Variable Cost $(0.06) Netback Price $2.56 TETCO M2 Price $(2.15) Uplift vs. TETCO M2(1) $0.41 Gulf Coast via ANR ($/MMbtu) 2019 Gulf Coast Price ($/MMbtu)(1) $2.71 Approximate Variable Cost $(0.04) Netback Price $2.67 TETCO M2 Price $(2.15) Uplift vs. TETCO M2(2) $0.52 Ability to utilize 800 MMcf/d Rover capacity with both Marcellus production (Sherwood Processing Plant) and Utica production (Seneca Processing Plant) Rover Phase 1A (in-service) Rover Phase 1B (in-service) Rover Laterals (3Q18-4Q18) Natural Gas Pricing Hub Futures prices as of 9/30/18. Based on 2019 TETCO-M2 futures prices and includes $0.14 of variable cost Antero Resources November 2018 presentation AR 800 MMcf/d FT AR 600 MMcf/d FT Gulf Coast AR 200 MMcf/d FT Chicago

Special Committee Process Objectives Achieve a “Win-Win-Win” Transaction Across the Antero Family Improve the financial profile and deliver value to all three Antero equities including AR, AM and AMGP Maintain target distributions to AM unitholders including AR, with strong coverage Simplify the Structure and Unlock Shareholder Value Simplify the structure for current and future investors Eliminate the eventual IDR drag on AM cash flow growth and cost of capital Maintain Antero’s Integrated Strategy & Long-Term Outlook Maintain senior management’s long-term vision to build the most integrated NGL and natural gas business in the U.S. Further Align the Interest of All Antero Equity Holders and Management Remove the perceived alignment of interest questions related to management/PE sponsor ownership of GP/IDRs relative to AR shareholders 1 2 3 4 While evaluating potential alternatives to increase shareholder value, there were a number of key objectives: Return Capital to AR Shareholders Capitalize on opportunity to repurchase shares at a discount to both intrinsic value and relative value of comparable elite operators Return Capital while maintaining trajectory to IG rating profile at AR 5 6 Antero Resources November 2018 presentation

Status Quo Structure Antero Simplified Pro Forma Structure Simplified Pro Forma Structure 53% 100% Incentive Distribution Rights (IDRs) Sponsors/ Management Public Public 27% 73% Sponsors/ Management Public 59% 41% 47% 27% 73% 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 25% 7 Series B Profits Interest (1) 44% 1) Series B profits interest held by Antero management. New AM 508 MM shares 188 MM units 186 MM shares Antero Resources November 2018 presentation

Financially Disciplined Repurchase Program Disciplined share repurchase plan maintains financial flexibility and balance sheet strength with leverage ≤ 2.25x in 4Q 2018 and ≤ 2.0x by YE 2019 AR Standalone Net Debt / LTM EBITDAX(1) Based on 12/31/2017 strip pricing and the long-term plan announced at Antero’s January 2018 analyst day. Stand-alone financial leverage is calculated by dividing year-end stand-alone net debt by last twelve months stand-alone EBITDAX. For additional information regarding these measures, please see “Antero Definitions” and “Antero Non-GAAP Measures” in the. Includes $500 million of maintenance and discretionary land spend through 2022. Includes $300 million in proceeds from midstream simplification transaction. Leverage Threshold Return of Capital Potential 8 Announced $600 million share repurchase plan Capacity to return $1.3 billion during 18 month share repurchase period(2) Leverage maintained at or below 2.0x from 1Q19-1Q20 Capacity to return $3.0 to $3.5 billion of capital over the next four years Represents 60% to 70% of current market cap Share Repurchase Details Antero Resources November 2018 presentation

Natural Gas Liquids Update: Leading Position

Largest Liquids-rich Drilling Inventory in Appalachia 10 Holds 40% of Core Undrilled Liquids-Rich Locations Based on Antero analysis of undeveloped acreage in the core of the Marcellus and Utica plays. Peers include Ascent, CHK, CNX, CVX, EQT, GPOR, HG, RRC and SWN. Largest core undeveloped liquids-rich inventory Over 2.5X the closest competitor Largest Undrilled Core Liquids-Rich Inventory(1) Rich Gas Locations Natural Gas Liquids Update leading position 11,475’ 8,723’ 8,548’ 8,912’ 8,279’ 8,231’ 7,999’ 7,140’ 7,656’ 9,028’ Lateral Length

Leader in Leverage to NGL Prices 11 Top NGL Producers in the U.S. Source: Bloomberg consensus, SEC filings and company press releases. Note: Volumes represent consensus as of 10/31/2018. 3Q 2018 realized prices are weighted average including ethane (C2) where applicable. DVN, MRO, OXY and PXD percent revenue and realized prices represent 2Q 2018 actuals. 3Q 2018 actual NGL revenue percentage based on unhedged product revenue. * Denotes consensus inclusive of international NGL production. NGLs Generate 37% of AR Revenue (1) 3Q 2018 $30.97 $30.09 $27.16 $24.10 $39.16 $32.17 $28.87 $25.62 $28.58 $28.83 Antero Delivers Highest Exposure to Rising NGL Prices Pre-hedged Realized NGL Price ($/Bbl) Pre-Hedge NGL % of Total Product Revenues * * * * Natural Gas Liquids Update leading position

Rapidly Growing NGL Production 12 Antero NGL Production Growth by Purity Product Note: Excludes condensate. See Appendix for further assumptions around long-term targets. C2 ethane volumes in 2018 reflect adjustment for timing of Borealis contract start date from 10/1/18 to 11/1/18. Total (Bbl/d) C5+ iC4 nC4 C3 93% CAGR in 2014 – 2016 NGL Production 20% CAGR from 2017A – 2022E NGL Production C3+ Production C2 C2 Ethane 17,476 C2 Ethane 26,500 C2 Ethane 39,000 Natural Gas Liquids Update leading position

Appalachia: Geographic & Infrastructure NGL Advantaged Mid-Continent Appalachia 31 Permian Rockies Bakken/Williston Mariner East TEPPCO Cornerstone Exports to International Markets Mont Belvieu Conway Appalachia In-basin fractionation Transport marketable purity products out-of-basin Sufficient fractionation capacity Fixed fractionation fees Producer controls product destination and captures pricing uplift Rail Purity Products Rail Purity Products 13 Permian, Rockies, Mid-Continent & Bakken Transport Y-grade for out-of-basin fractionation at Mont Belvieu and Conway Severely constrained fractionation, Y-grade transportation and NGL storage capacity Rapidly rising spot fractionation fees Midstream controls product destination and captures pricing uplift Natural Gas Liquids Update leading position

Antero’s Ethane Exposure: All Upside 14 Antero’s ethane has a natural gas pricing “floor” and purity ethane “ceiling”; increases in ethane purity prices are all upside Antero’s balanced approach to ethane sales results in 50% of contracts tied to purity ethane prices vs. natural gas value Ethane Revenue Uplift ($MM) Ethane sensitivity: +$0.10/gallon x 2019 production target x ~50% exposure to Mt. Belvieu = ~$40MM incremental 2019 ethane revenue 55 MBbl/d 55 MBbl/d Note: Forward prices use strip as of 9/30/2018. Ethane prices reflect realized price to Antero and assume $(0.05)/gallon discount to Mt. Belvieu prices based on 2018 Antero guidance. 2019 volumes are assumptions only, based on ME2 in-service and an increase in de-eth capacity expected to come on-line in 4Q18. +$0.10/Gal C2 price change = $40MM incremental revenue +$90 - $130MM Natural Gas Liquids Update leading position

1. Q418 represents strip pricing as of 9/30/2018. Volumes based on midpoint of guidance. Antero has 26 MBbl/d of propane hedged at $0.76 per gallon for the remainder of 2018 and no C3+ hedges beyond 2018. Antero’s C3+ NGL Exposure: Highly Leveraged Antero’s NGL price directly benefits from the recent strengthening of NGL prices at Mont Belvieu NGL fundamentals remain constructive and support higher prices despite illiquid and backwardated NGL futures prices Antero C3+ Barrel Composition by Product – Mont Belvieu Pricing Mont Belvieu Pricing (Pre-differential & ME2) Antero C3+ Barrel 9 mos. ‘18 Avg. Price Balance 2018 Variance 57% $0.90 $0.88 $(0.02) 16% $0.92 $1.01 +$0.09 10% $1.15 $1.03 $(0.12) 17% $1.49 $1.41 $(0.08) C3+ $/Gal $1.03 $1.01 $(0.02) C3+ $/Bbl $43.26 $42.42 $0.84 Volume (Bbl/d) 71,250 82,000 +10,750 15 Natural Gas Liquids Update leading position

Pre-Hedge Revenue Sensitivity to C3+ NGL Pricing ($MM) Note: Represents 9/30/2018 strip Mont Belvieu pricing. 2019 volumes assume 20% liquids growth vs. 2018 C3+ guidance of 77,500 Bbl/d. Assumes C3+ barrel weightings of: propane 57%, normal butane 16%, isobutane 10%, pentanes 17% and reflects differential of $(6.00)/Bbl. Initial ME2 in-service 11/1/18 moving Antero’s fully contracted “Full ME2” 50,000 Bbl/d of contracted volumes. Powerful C3+ NGL Pricing Upside Exposure 93 MBbl/d Full ME2 93 MBbl/d Full ME2 Compounded pricing leverage from increasing volumes, prices, and Mariner East 2 uplift drives cash flow growth For every $5.00/Bbl increase in NGL prices, Antero generates an incremental $170MM in Revenue +$5/Bbl change = +$170MM in revenue +$310 - $480MM 16 Natural Gas Liquids Update leading position

Antero’s NGL Pricing Uplift from Mariner East 2 31 Mont Belvieu Conway Europe Netback 2019 NWE Price ($/Gal) $1.15 Pipeline, Terminal & Shipping Cost (1) $(0.24) NWE Netback $0.91 Blended Conway / MB Netback $0.77 Uplift vs. YTD 2018 Average Differential +$0.14 Asia Netback 2019 FEI Price ($/Gal) $1.24 Pipeline, Terminal & Shipping Cost (1) $(0.33) Asia Netback $0.91 Blended Conway / MB Netback $0.77 Uplift vs. YTD 2018 Average Differential +$0.14 ME2 Rail To Europe NWE Index Rail To Asia FEI Index International Markets Domestic Markets Marcus Hook Antero Blended Netback 2019 Conway/Mt. Belvieu Price ($/Gal) $0.93 Average YTD 2018 Differential $(0.16) Blended Conway/MB Netback $0.77 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 09/30/18. 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): Committed volumes 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 will allow AR to access international LPG markets and realize a ~$5.88/Bbl uplift on its exported barrels 50,000 Bbl/d Mariner East 2 commitment equates to over $107 MM of incremental annual cash flow 4Q 2018 17 Today Natural Gas Liquids Update leading position

Liquids-Rich Resource + Capital Efficiency = Free Cash Flow

19 Drilling and Completion Efficiencies Average Lateral Feet per Day Drilling Days Average Lateral Length per Well Completion Stages per Day Liquids resource + capital efficiency = free cash flow cost efficiency drivers 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%

Declining Well Costs → Longer Laterals the Next Step 20 Liquids resource + capital efficiency = free cash flow Cost Efficiency Drivers: Longer Laterals Note: Well costs reflect 2,000 pound per foot completions. See Appendix for further assumptions. Historical Well Costs 41% 43% Lower Costs Marcellus Utica reduction in well costs from 2014 to 2017 for a 9,000’ lateral 54% from efficiencies 45% from service costs 9% 10% Cost Benefit Marcellus Utica reduction in well cost per 1,000’ lateral going from 9,000’ to 12,000’ laterals 41% Reduction 43% Reduction 9% Reduction 10% Reduction

Capital Discipline Leads to Free Cash Flow 21 Stand-Alone Adjusted Cash Flow Alongside D&C Capital Expenditures D&C Capital Investment Fully Funded with Cash Flow Note: Stand-alone adjusted cash flow from operations 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 2015 water drop down transaction. Estimates assume strip pricing as of 12/31/2017. (1) D&C maintenance capital represents $590MM per year to hold production flat at 2.3 Bcfe/d which was year-end 2017 exit rate. (2) Free cash flow definition includes $175MM of maintenance land spending, but excludes $175MM discretionary land spending. 48% reduction in D&C capital budget and 15 rig reduction since 2014 Future D&C capital budgets that are measured and within cash flow Free Cash Flow(2) Liquids resource + capital efficiency = free cash flow Sustainable Cash FloW Growth D&C Capex down 48% D&C Maintenance Capital(1)

Near Term Free Cash Flow Inflection Point Free Cash Flow(1) Antero Is Approaching a Free Cash Flow Inflection Point (1) For additional information regarding Non-GAAP Measures please see the Appendix. Estimates assume strip pricing as of 12/31/2017. Capital discipline to reduce completion crews and D&C capex in 4Q18 Production growth and strong liquids prices drives free cash flow in 4Q18 and beyond Cash Outspend Free Cash Flow Generation Q4 2018 represents a free cash flow inflection point 2019E – 2022E Q3 2018 Q4 2018 $1.6B in Free Cash Flow Delevering & $600 MM Return of Capital 22 Liquids resource + capital efficiency = free cash flow Sustainable Cash FloW Growth

23 Market Premium for Free Cash Flow Yield Industry Leading Free Cash Flow Yield in 2019 Free Cash Flow is a “Prove It” story and has been rewarded by the market 29% 4% Leading E&P for FCF Yield Note: 1H18 used as a proxy for proven free cash flow story. Cash flow yield defined as free cash flow divided by market capitalization. AR estimate is based on Bloomberg consensus 2019 estimates, adjusted for Stand-Alone metrics. Peer FCF per Bloomberg consensus estimates. E&P’s with established FCF yield tend to trade in the 5% to 8% range on a FCF yield basis Liquids resource + capital efficiency = free cash flow Sustainable Cash FloW Growth

Integrated Business Strategy Drives Peer Leading Margins

Well Hedged at High Prices Relative to Strip Integrated business strategy drives peer leading margins Productivity Drivers Average Index Hedge Price(1) Hedged Volume Current NYMEX Strip(2) Mark-to-Market Value(2) Weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio. Includes 26,000 Bbl/d of propane hedged at $0.76/gallon and 6,000 Bbl/d of oil hedged at $56.99/Bbl for 2018 only. As of 9/30/18. $1.2B Mark-to-Market Commodity Hedge Position ~$1.2B Mark-To-Market Unrealized Gains Based On 9/30/2018 Prices 2.2 Tcfe hedged through 2023 at $3.32/MMBtu $4.0B of realized gains on hedges since 2008 25 ~100% of 2018 and 2019 Target Gas Production Hedged at ~$3.50/MMBtu ($/MMBtu)

26 Integrated business strategy drives peer leading margins Firm Transportation & Hedge Book A Paired Trade – Hedges Support Firm Commitments Hedge Gains More than Offset Marketing Expense – Hedges Support FT Commitments Firm Transportation Portfolio Allows Antero to achieve: Effectively Hedge NYMEX Index A key advantage as our product is delivered to NYMEX-related markets Premium Price Certainty Less volatility and greater surety in realized prices 5-Year Cumulative: Hedge Gains: $1,350 Marketing Expense: ($461) Net Uplift: $889 Hedge Portfolio Supports Firm Commitments

Midstream Driving Value for AR Since Inception 27 Takeaway assurance and reliable project execution Antero Midstream (NYSE: AM) provides a customized midstream solution for AR (AR owns 53% of AM) Owning and controlling the midstream infrastructure is crucial to consistent long-term development Return on AM Investment for AR (Pre-tax) Midstream Ownership Benefits 4.7x ROI(1) Never missed a completion with fresh water delivery system Unparalleled downstream visibility Attractive return on investment $MM Just-in-time capital investment Integrated business strategy drives peer leading margins midstream driving value Midstream proceeds received by AR to date plus market value of AR’s 53% ownership of AM at 9/30/18 divided by the approximate $1.3B of AR capital invested at time of AM IPO. Includes proceeds from AM IPO, sale of water business (2015), all sales of AM units and all AM distributions received by AR to date. Cumulative value includes total proceeds to-date, expected earnout payments in 2019 and 2020 and the pre-tax value of AM units held by AR at 10/31/2018 market pricing. (2) (3)

Source: Public data from company 10-Ks and 10-Qs. Peers include CNX, COG, EQT, RRC and SWN. All-in realized natural gas equivalent pricing includes liquids and hedge realizations for the period. Hedge realizations is the stippled top portion of each bar. The Leader in All-In Realized Pricing in Appalachia 28 Integrated business strategy drives peer leading margins Profitability Drivers Antero Has Been the Leader in Natural Gas Equivalent Prices For Almost Six Years ($/Mcfe) Nymex Henry Hub All-In Realized Pricing ($/Mcfe) – Appalachian Peers (Includes Liquids and Hedge Realizations) Antero’s integrated strategy has resulted in peer-leading all-in realized prices amongst the peer group Consistent results through the price cycles

EBITDAX Margin ($/Mcfe) 29 Consistent Leader in EBITDAX Margin On a Stand-Alone EBITDAX Margin Basis, Antero has Consistently Outperformed its Appalachian Peers Through Up and Down Commodity Cycles Source: SEC filings and company press releases. AR 2017 margins exclude $0.10/Mcfe negative impact from WGL and SJR natural gas contract disputes. Peers include CNX, COG, EQT, RRC & SWN. AR and EQT EBITDAX include distributions from midstream ownership. Cash costs for AR and EQT represent stand-alone GPT, production taxes, LOE and cash G&A. Post-hedge and post net marketing expense where applicable. WTI Price ($/Bbl) WTI Oil Price ($/Bbl) Leader in EBITDAX Margin Integrated business strategy drives peer leading margins EBITDAX margins Antero’s integrated strategy has resulted in peer-leading EBITDAX margins for ~6 years Sustainable margins through the price cycles

Antero Midstream At A Glance – Status Quo 30 Market Cap ....... Enterprise Value ......... . LTM Adjusted EBITDA(1) .. % Gathering/Compression % Water .. .. .. .. .. Net Debt/LTM EBITDA .... Corporate Debt Rating . $5.6B $7.1B $665 MM 65% 35% 2.3x Ba2 / BB+ /BBB- Note: Equity market data as of 10/31/2018. Balance sheet data as of 9/30/2018. LTM Adjusted EBITDA as of 9/30/18. Adjusted EBITDA is a non-GAAP measure. For additional information regarding this measure, please see “Antero Midstream Non-GAAP Measures” in the Appendix. Antero Midstream | NOVEMBER 2018 Presentation AM Highlights AMGP Highlights Market Cap ....... Net Debt/LTM EBITDA... . $3.0B – Antero Midstream Utica Assets Antero Midstream Marcellus Assets Compressor Station: In Service Antero Clearwater Facility Processing Facility Compressor Station: 2018 Gathering Pipeline Fresh Water Pipeline Stonewall Pipeline Sherwood Processing Facility – 2.0 Bcf/d Existing Capacity Antero Clearwater Treatment Facility 60,000 Bbl/d Capacity Stonewall JV Pipeline New Smithburg JV Processing Facility – Civil Work Under Way

Long-Term Distribution and Coverage Targets 31 Distribution Guidance (Mid-point) Long-Term Distribution Targets and DCF Coverage Unchanged capital investment philosophy with disciplined financial policies result in ability to target peer-leading distribution growth through 2022 Distribution Target (Mid-point) DCF Coverage Targets 28% - 30% CAGR 20% Annual Note: Implied yield based on AM unit price as of 10/31/18. Represents status quo AM distribution and coverage targets (not pro forma for simplification transaction). Implied Yield 9.4% 5.8% AM: Peer Leading Distribution Growth and Coverage

Northeast Value Chain Opportunity 32 ~$1.9B Organic Project Backlog ~$800MM JV Project Backlog FRESH WATER Delivery(1) Treatment(1) WASTE WATER Services(1) PRODUCED WATER WELL PAD LOW PRESSURE GATHERING HIGH PRESSURE GATHERING COMPRESSION GAS PROCESSING (50% INTEREST) REGIONAL GATHERING PIPELINE (15% INTEREST) FRACTIONATION TERMINALS & STORAGE Y-GRADE PIPELINE (ETHANE, PROPANE, BUTANE) NGL PRODUCT PIPELINES LONG HAUL PIPELINE INTERCONNECT END USERS PDH PLANT >$1.0B Downstream Investment Opportunity Set Note: Third party logos denote company operator of respective asset. AM Assets AM/MPLX JV Assets Potential AM Opportunities Upstream Downstream 5-year identified project inventory of $2.7B plus an additional $1.0B of potential downstream opportunities Outlook: Organic Project Backlog with Peer-Leading Returns

33 Antero Profile Should Drive Multiple Expansion Approaching an Elite Group of E&Ps With Scale, Double Digit Growth, Low Leverage & Free Cash Flow Generation Source: Bloomberg & Antero Estimates as of 10/31/18. Adjusted EBITDAX and Adjusted Operating Cash Flow are non-GAAP measures. AR EV/EBITDAX multiple also reflects an enterprise value that excludes AR ownership of AM, and EBITDAX excludes AM distributions received by AR, for comparative purposes with peer E&P multiples. 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 # of Companies Median Debt/ Adjusted EBITDAX Median EV/ 2019 Adj. EBITDAX 52 2.1x 4.8x 38 1.7x 4.9x 16 1.6x 5.3x 8 1.6x 5.9x 6 1.2x 6.3x 5 0.9x 6.5x EOG CXO PXD AR 2019E unhedged EBITDAX Multiple: 3.5x Scale Growth Low Leverage Permian & Appalachia FCF Generation COG CLR in 2019 in 2018 Premium for:

Most Integrated Natural Gas & NGL Business in the U.S. 34 World Class E&P Operator in Appalachia 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 53% Ownership Antero resources summary A Leading Northeast Infrastructure Platform

Appendix

Appendix 2018 guidance Updated 2018 Guidance Stand-Alone Consolidated Net Daily Production (Bcfe/d) ~2.7 Net Liquids Production (BBl/d) ~130,000 Natural Gas Realized Price Differential to Nymex $0.05 to $0.10 Premium C3+ NGL Realized Price (% of Nymex WTI) 57.5% – 62.5% Cash Production Expense ($/Mcfe) $2.05 – $2.15 $1.60 – $1.70 Marketing Expense ($/Mcfe) (10% Mitigation Assumed) $0.10 – $0.125 G&A Expense ($/Mcfe) (before equity-based compensation) $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) $1,550 - $1,600 $1,350 - $1,400 Land Capital Expenditures ($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. Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes. 36

Appendix 5-Year Assumptions Antero Guidance and Long-Term Target Assumptions Stand-Alone 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 $0.05 to $0.10 Premium (2018) $0.00 to $0.10 Premium (2019 – 2022) C3+ NGL Realized Price (% of Nymex WTI) 57.5% – 62.5% (2018) 69% (2019+) – ME2 Fees Booked to Transport Costs Realized Oil Price Differential to WTI ($5.00) – ($6.00) Cash Production Expense ($/Mcfe)(1) $2.05 - $2.15 (2018) $2.10 – $2.25 (2019 – 2022) $1.60 - $1.70 (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) $0.125 – $0.175 (2018 – 2019) $0.10 – $0.15 (2020 – 2022) $0.15 - $0.20 (2018 – 2019) $0.10 – $0.15 (2020 – 2022) Cash Interest Expense ($/Mcfe) $0.175 – $0.225 (2018 – 2019) $0.10 – $0.15 (2020 – 2021) <$0.10 (2022) $0.25 – $0.30 (2018 – 2019) $0.20 – $0.25 (2020 – 2022) Well Costs ($MM / 1,000’) (Assumes 12,000’ completions at 2,000 lbs. per foot of proppant) Marcellus: $0.95 MM Utica: $1.07 MM Marcellus: $0.80 MM Utica: $0.95 MM Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes. 37

38 Appendix 5-Year Assumptions Antero Guidance and Long-Term Target Assumptions (Cont.) Stand-Alone E&P Consolidated Adjusted Operating Cash Flow(1) $10.4B (Cumulative 2018 – 2022) N/A Annual D&C Capital Expenditures ($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. 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”). Includes leasehold capital expenditures required to achieve targeted working interest percentage.

39 Appendix project assumptions Antero Long-Term Target Project Assumptions In-Service Date Rover Phase 2 4Q 2018 Mariner East 2 4Q 2018 WB Xpress West 4Q 2018 WB Xpress East 4Q 2018 Mountaineer Xpress / Gulf Xpress 1Q 2019 Note: Based on publicly available information.

Compelling Full Cycle Well Economics 40 Single Well Economics Bridge to Corporate Level Returns Fully Burdened Corporate Level Well Economics are Outstanding Note: See company presentation on Antero Resources investor relations website for further detail behind full cycle and half cycle single well economics; WACC calculated using CAPM. ROR (D&C only) burdened with 60% of AM fees to give credit for AM ownership/distributions and variable firm transportation fees only (i.e. excluding sunk demand costs). Incremental 40% of AM fees represent the full midstream fees AR pays to AM on complete stand-alone basis (i.e. no credit for midstream ownership). Includes increase in D&C capital to account for full water fees paid to AM. (3) 2.4 bcfe/1,000’ EUR assumes ethane rejection. AR WACC ≈ 8% appendix Attractive Well Economics Drive Growth Fully burdened pre-hedge well economics support investment Corporate ROR well in excess of cost of capital (1) (2) Half cycle ROR Full cycle ROR Well Assumptions 12,000’ Lateral 1250 BTU Wellhead Gas 2.4 Bcfe/1,000’ EUR(3) 6/30/2018 Strip Pricing

9/30/2018 Debt Maturity Profile Liquidity & Debt Term Structure AR Credit Facility AM Credit Facility AR Senior Notes AM Senior Notes New credit facilities for AR and AM have allowed Antero to extend its average debt maturity out to 2022 41 Appendix consolidated liquidity and balance sheet No maturities until 2021

Deleveraging is Driving Ratings Momentum 42 Appendix Trending towards investment grade Corporate Credit Ratings History Corporate Credit Rating (Moody’s / S&P / Fitch) Ba3 / BB- B1 / B+ B2 / B B3 / B- Ba2 / BB Ba1 / BB+ Caa1 / CCC+ / CCC Baa3 / BBB- 2010 Investment Grade Rating: BBB- Fitch Jan. 2018 Stable through commodity price crash Credit Markets Have a Strong Appreciation for Antero Momentum Investment Grade Rating from Fitch (BBB-) & Recent Upgrade from S&P (BB+) Stable Credit Ratings with Consistent Upgrades from the Beginning of the Decade Through the Downturn 2011 2012 2013 2014 2015 2016 2017 2018 Upgrade to BB+ S&P Feb. 2018 Investment Grade Outlook to Positive Moody’s Feb. 2018

Operating Evolution Continues 43 Based on Marcellus 11,000 foot lateral and 2,000 pounds per foot AFE. Assumes nine wells per pad. Drilling Efficiency (25%) 42% Decline in well costs since 2014 54% Permanent cost efficiencies 46% Vendor-related cost reductions Efficiencies Expected to Offset Service Cost Inflation Completion Spreads 25% Drilling Rigs & Services 21% Completion Services 24% 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 and easier access More wells per pad Automated completion equipment to increase stages per day Sand 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 Fit-for-purpose rigs improves cycle times Enhanced walking and dual operation capabilities Concurrent operations Larger pads allowing for production at one end and drilling at the other More wells per pad Automated completion equipment → increase stages per day Reduced cluster spacing → higher potential recoveries 100 Mesh Sand → easier pumping with fewer screenouts and less cost Self-Sourcing Sand → reduce supply cost Improved Drillout Efficiency 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 in 2018 as Higher Rig Rate Contracts Roll Off Achievements to Date 2018 Marcellus Well Cost(1) Next Steps in Efficiency Evolution Appendix Operating Technologies evolve

44 Appendix Cost Efficiency Drivers: Well cost Reduction Dramatically Lower F&D Cost F&D Cost per Mcfe(1)(2) Ethane rejection assumed. F&D cost is defined as current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 85% NRI in Marcellus and 81% NRI in Utica. Please see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix. Dramatic Improvement in Operating Efficiencies, Lower Service Costs and Higher Well Recoveries Have Driven F&D Costs Materially Lower 52% 42% Lower F&D in Marcellus Utica (2014 – 2017)

Core of the Core Development Programs 45 Appendix Understanding the Resource EUR Regime BTU Range 2018 Well Completions 2019 Well Completions Half Cycle Well Economics (Strip Price) Total Undrilled Locations Average Lateral Length Marcellus Highly-Rich Gas Condensate 1275-1350 14 30 200% 447 12,500’ Highly-Rich Gas 1200-1275 106 101 89% 935 11,500’ Rich Gas 1100-1200 0 4 32% 495 11,150’ Ohio Utica Condensate 1250-1300 19 2 59% 206 9,950’ Rich Gas 1100-1200 3 9 39% 102 11,550’ Dry Gas 1050 3 9 36% 187 10,450’ Total(1) 145 155 Program Stats: 93% 98% Strip $70 Oil ROR 1,253 BTU Average Program Stats: 102% 106% Strip $70 Oil ROR 1,248 BTU Average High-Grade Inventory Totals: 2,372 High-Grade Inventory Averages: 11,400’ 1) Wells completed reflects midpoint of targeted completions per year.

Antero Assumptions: Single Well Economics 46 Appendix 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 (Economics based on first production at 7/1/2018) Realized Pricing Commodity price assumptions 06/30/2018 strip pricing (weighted) SWEs exclude marketing expenses and related commodity hedge contracts that support Antero’s firm transportation portfolio

47 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 “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). Free Cash Flow: Represents Stand-alone 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. 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 “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 “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).

48 Antero Non-GAAP Measures Consolidated Adjusted EBITDAX, Stand-Alone Adjusted EBITDAX, Consolidated Adjusted Operating Cash Flow, Stand-Alone 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 Adjusted EBITDAX The GAAP financial measure nearest to Consolidated Adjusted EBITDAX is net income or loss including non-controlling interest that will be reported in Antero’s 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 Consolidated 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. 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 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 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

Appendix disclosures & reconciliations Antero Non-GAAP Measures Antero has not included a reconciliation of Consolidated Adjusted EBITDAX or Stand-Alone Adjusted EBITDAX to their nearest GAAP financial measures for 2018 because it cannot do so without unreasonable effort and any attempt to do so would be inherently imprecise. Antero is able to forecast the following reconciling items between Consolidated Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX to net income from continuing operations including noncontrolling interest: Antero has a significant portfolio of commodity derivative contracts that it does not account for using hedge accounting, and forecasting unrealized gains or losses on this portfolio is impracticable and imprecise due to the price volatility of the underlying commodities. Antero is also forecasting no impact from franchise taxes, gain or loss on early extinguishment of debt, or gain or loss on sale of assets, for 2018. For income tax expense (benefit), Antero is forecasting a 2018 effective tax rate of 18% to 19%. (in thousands) Consolidated Stand-Alone Low High Low High Interest expense $250,000 $300,000 $200,000 $220,000 Depreciation, depletion, amortization, and accretion expense 950,000 1,050,000 800,000 900,000 Impairment expense 100,000 125,000 100,000 125,000 Exploration expense 5,000 15,000 5,000 15,000 Equity-based compensation expense 95,000 115,000 70,000 90,000 Equity in earnings of unconsolidated affiliate 30,000 40,000 N/A N/A Distributions from unconsolidated affiliates 40,000 50,000 N/A N/A Distributions from limited partner interest in Antero Midstream N/A N/A 166,000 170,000 49

Antero Resources Adjusted EBITDAX Reconciliation Appendix disclosures & reconciliations AR Stand-Alone and Consolidated Adjusted EBITDAX Reconciliation 50 Stand-Alone Consolidated Three months ended September 30, Three months ended September 30, (in thousands) 2017 2018 2017 2018 Net (loss) attributable to Antero Resources Corporation $ (135,063) (154,419) $ (135,063) (154,419) Net Income attributable to noncontrolling interest — — 45,063 76,447 Commodity derivative fair value (gains) losses 65,957 (57,020) 65,957 (57,020) Gains on settled commodity derivatives 61,479 71,144 61,479 71,144 Marketing derivative fair value losses — 43 — 43 Losses on settled marketing derivatives — (16,060) — (16,060) Interest expense 60,906 57,633 70,059 74,528 Income tax expense (benefit) (45,078) 18,953 (45,078) 18,953 Depletion, depreciation, amortization, and accretion 177,070 205,408 207,626 243,897 Impairment of unproved properties 41,000 221,095 41,000 221,095 Impairment of gathering systems and facilities — — — 1,157 Exploration expense 1,599 666 1,599 666 Gain on change in fair value of contingent acquisition consideration (2,556) (4,020) — — Equity-based compensation expense 19,248 11,674 26,447 16,202 Equity in earnings of unconsolidated affiliates — — (7,033) (10,706) Distributions from unconsolidated affiliates — — 4,300 11,765 Equity in (earnings) loss of Antero Midstream Partners LP 4,874 23,363 — — Distributions from Antero Midstream Partners LP 34,839 41,031 — — Adjusted EBITDAX 284,275 419,491 336,356 497,692 Interest expense (60,906) (57,633) (70,059) (74,528) Exploration expense (1,599) (666) (1,599) (666) Changes in current assets and liabilities 38,129 5,505 29,899 (2,053) Proceeds from derivative monetizations 749,906 — 749,906 — Other non-cash items 101 315 719 1,013 Net cash provided by operating activities $ 1,009,906 367,012 $ 1,045,222 421,458 Adjusted EBITDAX $ 284,275 419,491 $ 336,356 497,692 Production (MMcfe) 213,159 250,046 213,159 250,046 Adjusted EBITDAX margin per Mcfe $ 1.33 1.68 $ 1.58 1.99

Antero Resources Adjusted EBITDAX Margin Reconciliation Appendix disclosures & reconciliations AR Stand-Alone and Consolidated Adjusted EBITDAX Margin Reconciliation Stand-Alone Consolidated Three months ended September 30, Three months ended September 30, 2017 2018 2017 2018 Adjusted EBITDAX margin ($ per Mcfe): Realized price before cash receipts for settled derivatives $ 3.10 3.70 $ 3.10 3.70 Gathering, compression, and water handling and treatment revenues N/A N/A 0.01 0.02 Distributions from unconsolidated affiliates N/A N/A 0.02 0.05 Distributions from Antero Midstream 0.15 0.18 N/A N/A Gathering, compression, processing and transportation costs (1.73) (1.77) (1.32) (1.31) Lease operating expense (0.11) (0.14) (0.11) (0.15) Marketing, net (1) (0.13) (0.31) (0.13) (0.31) Production and ad valorem taxes (0.10) (0.12) (0.11) (0.12) General and administrative (excluding equity-based compensation) (0.14) (0.14) (0.17) (0.17) Adjusted EBITDAX margin before settled commodity derivatives 1.04 1.40 1.29 1.71 Cash receipts for settled commodity derivatives 0.29 0.28 0.29 0.28 Adjusted EBITDAX margin ($ per Mcfe): $ 1.33 1.68 $ 1.58 1.99 (1)Includes cash payments for settled marketing derivative losses of $0.06 per Mcfe in 2018. Includes marketing revenues of $89.6 million and marketing expense of $151.8 million. 51

Antero Resources Stand-alone Adjusted EBITDAX Per Mcfe Appendix disclosures & reconciliations 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 52 Standalone Adjusted EBITDAX per Mcfe Reconciliation (Annual)

Antero Resources Standalone Adjusted EBITDAX Reconciliation Standalone LTM Adjusted EBITDAX Reconciliation Appendix disclosures & reconciliations 53 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 Standalone Adjusted EBITDAX Reconciliation Standalone LTM Adjusted EBITDAX Reconciliation Appendix disclosures & reconciliations 54 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 (AR) 8-KRegulation FD Disclosure