Company Presentation MAY 2019 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, impacts of price realizations, AR’s expected ability to return capital to investors and targeted leverage metrics, 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, including 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 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2019.

This presentation includes certain financial measures that are not calculated in accordance with U.S. generally accepted accounting principles (“GAAP”). These measures include (i) Adjusted EBITDAX, (ii) Adjusted Net Cash Provided by Operating Activities, (iii) Free Cash Flow and (iv) Net Debt. 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 and Antero Corporation is denoted as “AM”, which are their respective New York Stock Exchange ticker symbols.

ANTERO RESOURCES | MAY 2019 PRESENTATION 2 The Size and Scale to Capitalize on the Resource

Antero Acreage Antero Resources Profile SW Marcellus Core Ohio Utica Core Market Cap……….……...... $2.3B Enterprise Value(1)….………… $5.8B Corporate Debt Ratings……… Ba2 / BB+ / BBB- Leverage(2) …...... 2.1x 2019 Net Production Guidance 3.15 - 3.25 Bcfe/d Liquids...... 144 -154 MBbl/d Proved Reserves…..…...... 18.0 Tcfe C2+ NGLs(3)...... 1,052 MMBbls Condensate...... 46 MMBbls Net Acres………….…...……… 612,000 Core Drilling Locations……….. 3,013 AR Ownership in AM (31%) $2.0B

Note: Equity market data as of 4/26/19. Reserves as of 12/31/2018. See 2019 Guidance page for production guidance details. (1) Includes ownership of $2.0 billion of Antero Midstream. (2) Leverage is debt divided by LTM Adjusted EBITDAX at 3/31/19. See appendix for details. (3) 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 | MAY 2019 PRESENTATION 3 Antero’s Integrated Strategy The Most Integrated Natural Gas and NGL Platform in the U.S. A World Class E&P Operator in Appalachia

NYSE: AR

$6 Billion Enterprise Value(1) Ba2 / BB+ / BBB- Corporate Debt Ratings

31%(1)

A Leading Northeast Infrastructure Platform

NYSE: AM

What’s new: Midstream simplification creating C-Corp and eliminating MLP and IDRs $9 Billion Enterprise Value(1) Ba2 / BB+ / BBB- Corporate Debt Ratings (AM)

1) Assumes 3/31/19 balance sheet and 4/26/19 equity prices. ANTERO RESOURCES | MAY 2019 PRESENTATION 4 Recent Developments/Near-Term Catalysts Midstream Simplification (Closed March 12, 2019) • Provided AR with $297 million in cash • AR no longer consolidates AM, but accounts for AM using the equity method, presenting better clarity for AR investors

Mariner East 2 In Service (First Antero Volumes Shipped in February 2019) • 50,000 Bbl/d commitment • Realized weighted average premium to Mont Belvieu of $0.17 per gallon on the approximately 50% of total February and March C3+ volumes that were shipped on Mariner East 2 and exported (61% of WTI) • 2019 C3+ NGL prices expected to be $4 per barrel higher than January implied guidance

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 16% - 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

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

(1) Drilling and completion capital spending expected to be at or less than Adjusted Net Cash Provided by Operating Activities assuming $50 per barrel WTI oil and $3.00 per MMBtu NYMEX . ANTERO RESOURCES | MAY 2019 PRESENTATION 5 Resilient and Flexible Development Plan Antero’s flexible development program through 2023 will be responsive to commodity prices to grow production and maximize free cash flow

Lower Prices: $50 Oil / $2.85 Gas Higher Prices: $65 Oil / $3.15 Gas

• 10% Production CAGR (2019-2023) • 15% Production CAGR (2019-2023) • <2x leverage by 2022 • <1x leverage by 2021 • Free Cash Flow(1) neutrality • $2.5 - $3.0 Bn of Free Cash Flow(1) • 100% hedged on 2019 gas • Appropriate mix of return of capital production guidance and 55%-60% and balance sheet deleveraging hedged on 2020 outlook

Higher Likely outcome Prices is somewhere in Lower between Prices Disciplined growth with expanding margins

Maintain balance sheet strength (1) Free Cash Flow is defined as Adjusted Net Cash Provided by Operating Activities less total capital spending including land. See appendix for additional Non-GAAP information. ANTERO RESOURCES | MAY 2019 PRESENTATION 6 Disciplined Development Plan Antero is poised to prudently grow production to maximize free cash flow, ultimately resulting in an appropriate mix of further delevering and return of capital

Production Growth Scenarios (2020 – 2023) 6,000 $2.5B - $3.0B Estimated Free Cash Flow Generation 5,000

4,000

3,000

2,000

Production(MMcfe/d) 1,000

0 2019 Guidance 2020E 2021E 2022E 2023E $65 / $3.15 15% Production CAGR <1x Leverage by 2021 $2.5 - $3.0 Bn Free Cash Flow

$50 /

Assumptions <2x Leverage by 2022 10% Production CAGR Free Cash Flow Neutrality Oil and Gas Price $2.85 or Sooner

Note: Production CAGR ranges apply to midpoint of 2019 production guidance. ANTERO RESOURCES | MAY 2019 PRESENTATION 7 Hedge Position Protects Downside Commodity Exposure In order to support its FT commitments, AR has consistently executed a comprehensive commodity hedging program

Antero Hedge Profile

(MMcf/d) ($/MMBtu)

2,500 2,330 NYMEX Collar Volume NYMEX Swap Volume $4.00 (1) $3.48 NYMEX Swap Price NYMEX Strip Price $3.50 $3.38 Ceiling 2,000 Hedges $3.00 $3.00 $3.00 $2.91 $3.00 Strip $2.69 $2.69 $2.66 $2.66 $2.73 $2.50 1,500 $2.50 Floor 1,418 Collar $2.00

1,000 1,149 850 $1.50 710 Swap at Swap at Swap at Swap at $1.00 500 $3.48/ $3.00/ $3.00/ $3.00/ MMbtu 30%MMbtu 30% MMbtu 30% MMbtu Swap Swap Swap $0.50 90 s$432 MM marks -to-market (2)s 0 $0.00 2019 2020 2021 2022 2023 1) Based on 4/26/2019 strip pricing. 2) Mark-to-market as of 3/31/2019. ANTERO RESOURCES | MAY 2019 PRESENTATION 8 Inflection Point in NGL Marketing and Pricing

With the opening of the ME2 pipeline in the first Diversified exposure to both international and domestic quarter, Antero now has the takeaway necessary markets results in Antero realizing a C3+ NGL to export NGLs for the first time in its history sales price in line or better than Mont Belvieu pricing

Domestic Markets International Markets 31 of

2019

Antero 2019 C3+ NGL Pricing Guidance (1) AR 1Q 2019 C3+ NGL Realized Pricing Monthly Breakdown (1) Domestic International Combined Jan ’19 Feb-Mar ‘19 1Q 2019 (Pre-ME2) (Post-ME2) Average Sales Point Hopedale Marcus Hook Blended Premium / (Discount) to % of AR 2019 C3+ Volume 50% 50% 100% ($0.09) + $0.03 ($0.01) Mont Belvieu ($/Gal) Expected Premium / (Discount) to ($0.075) – ($0.125) $0.10 - $0.15 ($0.01) - $0.04 Realized C3+ Price Mont Belvieu ($/Gal) $0.64 $0.82 $0.76 ($/Gallon) Mont Realized C3+ Price ($/Gallon) $0.69 – $0.74 $0.91 – $0.96 $0.80 – $0.85 Realized C3+ NGL Price ($/Bbl) $26.88Belvieu $34.32 $31.63 Realized C3+ NGL Price ($/Bbl) ~$34 – $36 NYMEX WTI Price ($/Bbl) $51.38 $56.55 $54.83 NYMEX WTI Price ($/Bbl) $61 % of WTI 52% 61% 58% % of WTI ~55% to 60% Note: 2020 blend of 70% international / 30% domestic assumes ME2 is fully in service with 275,000 Bbl/d of capacity. 1) Strip prices as of 4/26/2019, reflecting 2019 guidance assumptions. Antero C3+ NGL component barrel consists of 56% C3 (propane), 10% isobutane (Ic4), 17% normal butane (Nc4) and 17% natural gasoline (C5+).

ANTERO RESOURCES | MAY 2019 PRESENTATION 9 Antero’s First Ethane Export – November 2018

• Antero’s 11,500 Bpd C2 sales contract with Borealis commenced on November 1, 2018 • First ship departed Marcus Hook on November 26th with 337,000 barrels of ethane bound for Borealis’ steam cracker in Stenungsund, Sweden • Expect to load ~1 ship per month for duration of 10-year contract

ANTERO RESOURCES | MAY 2019 PRESENTATION 10 Firm Transportation Portfolio is a Strategic Advantage

2016A 2017A 2018A 2019E 2020E 2021E Realized Hedge Premium gas pricing plus realized hedge (1) Gains ($/Mcfe): $1.48 $0.26 $0.25 $0.20 $0.06 $0.02 - $0.03 profits more than offset the cost of Net Marketing carrying excess transportation capacity Expense ($0.16) ($0.16) ($0.13) ($0.175) – ($0.225) ($0.13) – ($0.18) ($0.05) – ($0.10) until production fills ($/Mcfe):(2)

Premium Unutilized 800 730 450 1,075 – 1,125 650 – 800 150 – 475 Capacity (BBtu/d)(4) AR’s premium FT expected • Antero’s FT portfolio has delivered Appalachia- to be filled by 2022 leading realized pricing quarter after quarter (excluding regional) (MMBtu/d) - Unutilized transport cost is manageable, can be reconfigured and is virtually eliminated by 2022 5,000 Total 4.7 Bcf/d Regional Appalachia (M2/Dom S.): 625 MMBtu/d markets and lowest 4,000 transport cost ($32 MM/year)

3,000 Other Premium Markets

2,000 With 2.1 Bcf/d of capacity to the Gulf Coast, Antero has significant exposure to the Gulf Coast 1,000 growing LNG market and increased NYMEX-based pricing commitments

0 20161/1/16 20171/1/17 20181/1/18 20191/1/19 1/1/202020 20211/1/21 20221/1/22 20231/1/23 Note: 2019 expected premium to NYMEX and net marketing expense based on previously disclosed guidance. 3) 2019 natural gas volume assumes midpoint of 2019 guidance and has been grossed up 1) Realized hedge gain per produced Mcfe ranges (where applicable) for 2019-2021 are based on strip pricing for remainder of 2019 for 84% average net revenue interest and an 1100 BTU factor. 2020 and beyond and a $2.85/MMBtu NYMEX price assumption for 2020-2021. Production assumes 10% to 15% annual production growth outlook. assume 10% or 15% year-over-year growth thereafter. 2) Unutilized firm transport cost, including historical mitigation, divided into estimated average net production. No mitigation assumed 4) Premium unutilized capacity excludes regional capacity. 2019 range based on 2019 gas for 2019 and beyond. production guidance range. 11 Expected Natural Gas Price Realization Improvement

Antero Firm Transport Index Breakdown

100% 6% decrease to 3% 10% Local Markets Local 90% 19% 80% 17% Midwest 1% increase to 70% Midwest Markets 18% 17% TCO 60% 3% increase to 50% TCO Market 40% Gulf Coast 30% 2% increase to Gulf 60% 56% Coast Markets 20% 10% 0% 2018A 2019E

Implied Premium to NYMEX(1) +$0.13 +$0.15 to +$0.20

Substantially All of Antero’s Gas Is Expected to be Sold in Favorably Priced in 2019

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. 1) 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 RESOURCES | MAY 2019 PRESENTATION 12 Sustainable and De-risked Business Model Antero Resources is 100% hedged on natural gas in 2019; Hedges and FT provide price stability to support sustainable long-term development

Hedge Portfolio Supports Antero Natural Gas Differentials vs. Appalachia Firm Pipeline Commitments Appalachia Antero Realized Differential 3-Year Appalchian Average 3-Year Antero Realized Basis $1.00

Antero: Resources Diversified – Low Volatility $0.50 Firm Transportation Portfolio $0.00 Allows Antero Resources to achieve: $0.01

($0.50)

($1.00) ($0.86)

Premium Price Effectively ($1.50) Certainty Hedge NYMEX Eliminates basis risk Index ($2.00) by delivering to Allows Antero to Appalachia: Floating – High Volatility NYMEX-related directly hedge the ($2.50) markets absolute price

(1) Reflects discount to NYMEX for Appalachia in-basin pricing at Dominion South & TETCO M2 indices. Note: Pricing reflects pre-hedge pricing. (2) Represents simple average discount to NYMEX for Antero firm transportation capacity.

ANTERO RESOURCES | MAY 2019 PRESENTATION 13 Repositioned With Simplified Structure Midstream simplification transaction results in ownership of one publicly traded midstream entity and better aligns management ownership between the two entities

Simplified Structure

Original Management Private Equity Public Investors

9% 9% 82%

309 MM shares NYSE: AR

Original Private Equity Management Investors

31% Public

10% 14% 45%

508 MM shares NYSE: AM

Note: Ownership levels as of April 30, 2018. ANTERO RESOURCES | MAY 2019 PRESENTATION 14 Leading NGL Position & Integrated Strategy Drive Peer-Leading Margins Prolific Underlying Resource Underpins Growth Antero Resources holds 40% of the core undrilled liquids-rich locations in Appalachia with attractive economics and low breakeven prices

Core Liquids-Rich Appalachian Undrilled Locations(1) B H J F I 5% 5% 2% 3% D 8% 3% K AR 7% ~40%

C 13% A 15%

Peers include Ascent, CNX, COG, CVX, Encino, EQT, GPOR, HG, RRC and SWN. Based on Antero analysis of undeveloped acreage in the core of the Marcellus and Ohio Utica Shales. Rigs as of 4/19/19, per RigData. Locations as of 12/31/18.

ANTERO RESOURCES | MAY 2019 PRESENTATION 16 Antero is the Largest NGL Producer in the U.S. Antero is the largest NGL producer in the U.S. and controls 40% of the core undrilled liquids-rich locations in Appalachia(2) Top U.S. C2+ NGL Producers - 2019E(1) Undrilled Core Liquids-rich Inventory(2)

(MBbls/d) 2,500 150 Most exposure 50% 140 45% 2,043 to NGL prices 2,000 Over 2.5x 130 40% Peer Avg. Pre-Hedge NGL % of Inventory of closest 35% Product Revenue Appalachian competitor 1,500 110 30% Rich Locations Rich - 29% 25% 1,000 90 20% 796

13% 15% 500 70 10% Liquids Undrilled

5% - 50 0% AR A B C D E F G H I J

(1) Antero C2+ NGL production represents the midpoint of 2019 guidance. Peer C2+ NGL production represents consensus as of 4/26/2019. Percentage of pre-hedge commodity revenues based on 4Q 2018 actuals. (2) 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. ANTERO RESOURCES | MAY 2019 PRESENTATION 17 Midstream Driving Value for AR Since Inception

Owning and controlling the infrastructure is critical to sustainable development; Antero Midstream provides a customized midstream solution Midstream Ownership Benefits AM Infrastructure Buildout

Takeaway assurance and reliable project execution

Never missed a completion date with fresh water delivery system 3rd Party Area of Dedication Just-in-time capital investment

Unparalleled downstream visibility Current Infrastructure Future Infrastructure

Processing Facility Attractive return on investment Antero Clearwater Facility (4.2x ROI for AR) (1)

(1) Based on value of AR’s stake in AM as of April 26, 2019. ANTERO RESOURCES | MAY 2019 PRESENTATION 18 Antero: Not Just a Natural Gas Producer Diversified Commodity Mix Enhances Value Proposition Compelling Investment Opportunity

Attractive Long-Term Leverage of 2.1x at Outlook Ability to grow Maintain 3/31/19 and generate free Strong Balance cash flow Sheet Just-in-time Appalachian leader for midstream Controlled 6 straight years Peer Leading investment by AM Resource Margins Low Cost Liquids-Rich Development Delivers premium 22% debt-adjusted Resource Base price realizations for growth per share natural gas and NGLs Strategic Liquids Disciplined in 2019 and Gas FT Focus on Portfolio Returns Top NGL producer 100% hedged on and #4 gas producer (1) Natural Gas and natural gas in 2019 Mitigated in the U.S. Liquids Resource Commodity Risk and Scale See appendix for Non-GAAP items and reconciliation. 1) 750,000 MMBtu/d of natural gas is hedged at a weighted average price of $3.34 and the remainder of expected production has a $2.50/MMBtu floor for the last three quarters of 2019 ANTERO RESOURCES | MAY 2019 PRESENTATION 19 Appendix Antero Capitalization – 3/31/19

As of March 31, 2019 ($MM) Antero Resources Cash $0

Debt Revolving Credit Facility $50 5.375% Senior Notes Due 2021 $1,000 5.125% Senior Notes Due 2022 $1,100 5.625% Senior Notes Due 2023 $750 5.000% Senior Notes Due 2025 $600 Net unamortized debt issuance costs ($24) Total Debt $3,476 Net Debt (Total Debt - Cash) $3,476

LTM Adjusted EBITDA $1,671 Debt / LTM Adjusted EBITDA 2.1x

Credit Facility Capacity $2,500 Liquidity(1) $1,763

(1) Net of $687 million in letters of credit as of March 31, 2019. APPENDIX | CAPITALIZATION 21 Antero Resources D&C Capital Through negotiating contracts and self sourcing sand, Antero was able to mitigate a majority of inflationary pressures on D&C capital for 2019

Antero Resources Marcellus Well Cost ($MM/1,000’ assuming 12,000’ Lateral)

Drilling, Re- Improved 100% of Lower water $1.10 water negotiated completion sand self truck staging hauling, and completion efficiencies sourced times and production contracts improved facility and self $1.05 operations at inflation sand Clearwater sourcing

$1.00 $0.03 $0.06 $0.01 $0.01 $0.95 $0.02 $0.01

$0.90 $0.97 $0.95 $0.93 $0.93 $0.85

$0.80 2018 Inflationary New Sand / Increased 2019 Increased Optimized Further 2019 Marcellus Costs Completion Stages per Budgeted Sand Self Water Increase in Target Well Cost Contracts Day Marcellus Sourcing Logistics Stages per Marcellus Well Cost Day Well Cost

Note: Antero’s well costs include all pad, production facility and flowback water costs. Assumes 2,000 pound per foot completion.

APPENDIX | DRILLING & COMPLETION CAPITAL 22 Drilling and Completion Efficiencies Continue Drilling Days Average Lateral Feet Drilled per Day

35 9,184 6,000 30 5,308 5,169 25 5,000

20 18 4,000 2,901 15 12 3,000 10 Drilling Days

10 8 Lateral Feet 2,000 5 1,000

0 - 2014 2015 2016 2017 2018 1Q 2019 RECORD 2014 2015 2016 2017 2018 1Q 2019 RECORD

Marcellus Utica Marcellus Utica Average Lateral Length Drilled per Well Completion Stages per Day

10.0 10.0 17,445 10.0 18,000 9.0 16,000 15,075 8.0 14,000 7.0 12,000 11,412 10,000 6.0 5.3 5.3 10,000 5.0 8,000 4.0

Lateral Feet 6,000 3.0 Stages per Day 4,000 2.0 2,000 1.0 - - 2014 2015 2016 2017 2018 1Q 2019 RECORD 2014 2015 2016 2017 2018 1Q 2019 RECORD Marcellus Utica Marcellus Utica

Note: Percentage increase and decrease arrows represent change in Marcellus data from 2014 to 1Q 2019. APPENDIX | COST EFFICIENCY DRIVERS 23 Liquidity & Debt Term Structure

3/31/2019 Debt Maturity Profile

Credit Facility Senior Notes $1,400 New credit facility has $1,200 allowed Antero to extend its $50 average debt maturity out to $1,100 $1,000 2022 $1,000

$800 $750 $600 $600

$400 No maturities

$200 until 2021

$0 2018 2019 2020 2021 2022 2023 2025

APPENDIX | CONSOLIDATED LIQUIDITY AND BALANCE SHEET 24 Deleveraging is Driving Ratings Momentum

Corporate Credit Ratings History

Stable Credit Ratings with Consistent Investment Grade Rating from Fitch Upgrades from the Beginning of the (BBB-) and Upgrade from S&P (BB+) Decade Through the Downturn

Investment Grade Fitch Reaffirms Corporate Credit Rating Ratings (Moody’s / S&P / Fitch) Upgrade to BB+ Rating: BBB- Fitch Jan. 2019 S&P Feb. 2018 Fitch Jan. 2018 Baa3 / BBB- Investment Grade Ba1 / BB+ Ba2 / BB

Ba3 / BB- B1 / B+ B2 / B Outlook to Positive Stable through Moody’s Feb. 2018 B3 / B- commodity price crash Caa1 / CCC+ / CCC 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Moody's S&P Fitch

Credit Markets Have a Strong Appreciation for Antero Momentum

APPENDIX | TRENDING TOWARDS INVESTMENT GRADE 25 Antero Definitions

Adjusted EBITDAX: Represents income or loss, including noncontrolling interests, 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 other than proceeds from derivative monetizations, income taxes, impairment, 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, gain or loss on changes in the fair value of contingent acquisition consideration , contract termination and rig stacking costs, and equity in earnings or loss of Antero Midstream. Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units prior to the closing of the simplification transaction on March 12, 2019.

Adjusted Net Cash Provided by Operating Activities: Represents net cash provided by operating activities excluding net cash provided by operating activities from Antero Midstream Partners consolidated from January 1, 2019 through March 12, 2019.

Free Cash Flow: Represents Adjusted Net Cash Provided by Operating Activities, less drilling and completion capital, less drilling and completion capital paid to Antero Midstream Partners consolidated through March 12, 2019, less land capital.

Net Debt: Net Debt is calculated as total debt less cash and cash equivalents. Management uses Net Debt to evaluate its financial position, including its ability to service its debt obligations.

APPENDIX | DISCLOSURES & RECONCILIATIONS 26 Antero Non-GAAP Measures

Adjusted EBITDAX

Adjusted EBITDAX as defined by the Company represents income or loss, including noncontrolling interests, 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 other than proceeds from derivative monetizations, income taxes, impairment, 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, gain or loss on changes in the fair value of contingent acquisition consideration, contract termination and rig stacking costs, and equity in earnings or loss of Antero Midstream. Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units prior to the closing of the simplification transaction on March 12, 2019. 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. While there are limitations associated with the use of Adjusted EBITDAX described below, management believes that this measure is useful to an investor in evaluating the Company’s financial performance because it: • is 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 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, 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 as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company’s net income, 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 provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.

APPENDIX | DISCLOSURES & RECONCILIATIONS 27 Antero Non-GAAP Measures Continued

Adjusted Net Cash Provided by Operating Activities and Free Cash Flow

Adjusted Net Cash Provided by Operating Activities as presented in this release represents net cash provided by operating activities excluding net cash provided by operating activities from Antero Midstream Partners consolidated from January 1, 2019 through March 12, 2019. Adjusted Net Cash Provided by Operating Activities 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. Adjusted Net Cash Provided by Operating Activities 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. Free Cash Flow as defined by the Company represents Adjusted Net Cash Provided by Operating Activities, less drilling and completion capital, less drilling and completion capital paid to Antero Midstream Partners from January 1 to March 12, 2019, less land capital. There are significant limitations to using Adjusted Net Cash Provided by Operating Activities 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, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted Net Cash Provided by Operating Activities and Free Cash Flow reported by different companies. Adjusted Net Cash Provided by Operating Activities 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. Adjusted Net Cash Provided by Operating Activities 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. Furthermore, we may calculate such measures differently from similarly titled measures used by other companies.

APPENDIX | DISCLOSURES & RECONCILIATIONS 28 Antero Resources Adjusted EBITDAX Reconciliation

LTM Adjusted EBITDAX Reconciliation

Twelve months ended (in thousands) March 31, 2019 Net income and comprehensive income attributable to Antero Resources Corporation $ 566,413 Commodity derivative fair value gains 187,399 Gains on settled commodity derivatives 238,863 Marketing derivative fair value gains 153 Losses on settled marketing derivatives (37,355) Gain on deconsolidation of Antero Midstream Partners LP (1,406,042) Interest expense 226,614 Income tax expense 150,733 Depletion, depreciation, amortization, and accretion 868,075 Impairment of unproved properties 580,145 Impairment of gathering systems and facilities 4,470 Exploration expense 3,199 Gain on change in fair value of contingent acquisition consideration 96,893 Equity-based compensation expense 40,822 Equity in (earnings) loss of Antero Midstream Partners LP (31,485) Equity in (earnings) loss of unconsolidated affiliates (1,817) Distributions from Antero Midstream Partners LP 169,562 Contract termination and rig stacking 8,360 Simplification transaction fees 6,297 Adjusted EBITDAX $ 1,671,299

APPENDIX | DISCLOSURES & RECONCILIATIONS 29 Antero Resources Adjusted EBITDAX Per Mcfe

Adjusted EBITDAX per Mcfe Reconciliation

2013 2014 2015 2016 2017 2018 Q1 2019(1) ($/Mcfe) Natural gas, oil, ethane and NGL sales $4.31 $4.74 $2.53 $2.60 $3.35 $3.70 $3.65 Realized commodity derivative gains (losses) $0.86 $0.37 $1.57 $1.48 $0.26 $0.25 $0.35 Distributions from Antero Midstream $0.00 $0.00 $0.16 $0.17 $0.16 $0.16 $0.17 Less: WGL + SJR Impact $0.10 All-In Revenue $5.17 $5.10 $4.27 $4.25 $3.77 $4.11 $4.17

Gathering, compression, processing, and transportation $1.25 $1.46 $1.56 $1.70 $1.75 $1.81 $1.92 Production and ad valorem taxes $0.24 $0.23 $0.14 $0.10 $0.11 $0.12 $0.12 Lease operating expenses $0.05 $0.08 $0.07 $0.07 $0.11 $0.14 $0.15 Net marketing expense / (gain) $0.00 $0.14 $0.23 $0.16 $0.13 $0.16 $0.26 General and administrative (before equity-based compensation) $0.26 $0.23 $0.20 $0.16 $0.15 $0.13 $0.13 Total Cash Costs $1.81 $2.14 $2.20 $2.19 $2.26 $2.37 $2.59 EBITDAX Margin (All-In) $3.36 $2.96 $2.07 $2.06 $1.61 $1.75 $1.59

Production Volumes (Bcfe) 191 368 545 676 822 989 279 $ Millions Natural gas, oil, ethane and NGL sales $821 $1,741 $1,379 $1,757 $2,751 $3,659 $1,019 Realized commodity derivative gains (losses) $164 $136 $857 $1,003 $214 $243 $97 Distributions from Antero Midstream $89 $112 $132 $159 $46 All-In Revenue $985 $1,877 $2,324 $2,872 $3,097 $4,061 $1,163

Gathering, compression, processing, and transportation $239 $537 $853 $1,146 $1,441 $1,793 $535 Production and ad valorem taxes $46 $86 $77 $69 $91 $122 $35 Lease operating expenses $9 $28 $36 $51 $94 $142 $43 Net marketing expense / (gain) $0 $50 $123 $106 $108 $154 $72 General and administrative (before equity-based compensation) $50 $86 $108 $110 $119 $132 $37 Total Cash Costs $345 $786 $1,196 $1,483 $1,853 $2,344 $722

1) General and administrative (before equity-based compensation) excludes $6.3 million related to the simplification transaction. APPENDIX | DISCLOSURES & RECONCILIATIONS 30