Company Presentation November 2021 - cloudfront.net

Company Presentation
 November 2021

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 not under 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 those regarding expected results, future commodity prices, future production targets, completion of natural gas or natural gas liquids
 transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas
 marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans
 (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs and cost
 savings initiatives, future financial position, future technical improvements, future marketing and asset monetization opportunities, the amount and timing of any contingent
 payments, the participation level of our drilling partner and the financial and operational results to be achieved as a result of the drilling partnership, estimated Free Cash Flow
 and the key assumptions underlying its projection and AR’s environmental goals 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. Except as required by law, AR expressly
 disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.

 In addition, many of the standards and metrics used in preparing this presentation and the ESG Report continue to evolve and are based on management expectations and
 assumptions believed to be reasonable at the time of preparation but should not be considered guarantees. The standards and metrics used, and the expectations and
 assumptions they are based on, have not been verified by any third party. In addition, while we seek to align these disclosures with the recommendations of various third-party
 frameworks, such as the Task Force on Climate-Related Financial Disclosures ("TCFD"), we cannot guarantee strict adherence to these framework recommendations.
 Additionally, our disclosures based on these frameworks may change due to revisions in framework requirements, availability of information, changes in our business or
 applicable governmental policy, or other factors, some of which may be beyond our control. The calculation of methane leak loss rate disclosed in this release conforms with ONE
 Future protocol, which is based on the EPA Greenhouse Gas Reporting Program. With respect to its Scope 1 emissions goal, Antero Resources anticipates achieving Net Zero
 Scope 1 emissions by 2025 through operational efficiencies and the purchase of carbon offsets.

 AR cautions you that these forward-looking statements are subject to all of the risks and uncertainties incident to the exploration for and the development, production, gathering
 and sale of natural gas, NGLs and oil, most of which are difficult to predict and many of which are beyond AR’s control. 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, impacts of world health events, including the COVID-19 pandemic, cybersecurity risks 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, 2020.

 Any forward looking statement speaks only as of the date on which such statement is made and AR undertakes no obligation to correct or update any forward looking statement
 whether as a result of new information, future events or otherwise, except as required by applicable law.

 This presentation and the ESG Report contain statements based on hypothetical or severely adverse scenarios and assumptions, and these statements should not necessarily
 be viewed as being representative of current or actual risk or forecasts of expected risk. These scenarios cannot account for the entire realm of possible risks and have been
 selected based on what we believe to be a reasonable range of possible circumstances based on information currently available to us and the reasonableness of assumptions
 inherent in certain scenarios; however, our selection of scenarios may change over time as circumstances change. While future events discussed in this presentation or the report
 may be significant, any significance should not be read as necessarily rising to the level of materiality of certain disclosures included in Antero Resources' SEC filings

 This presentation also includes (i) Free Cash Flow, (ii) Adjusted EBITDAX, (iii) Net Debt and (iv) leverage which are a financial measures that are not calculated in accordance
 with U.S. generally accepted accounting principles (“GAAP”). Please see “Antero Non-GAAP Measures” for definitions of these measures as well as certain additional information
 regarding these measures.

 Antero Resources Corporation is denoted as “AR” in the presentation and Antero Midstream Corporation is denoted
 as “AM”, which are their respective New York Stock Exchange ticker symbols.

• Antero Resources | May 2019 Presentation 2

Antero Resources Snapshot
 Denver, CO Antero Resources Acreage Map
 HEADQUARTERS Antero Marcellus Rig
 Industry Marcellus Rig

 $8.8 B Industry Utica Rig
 Antero Acreage
 ENTERPRISE VALUE (1) SW Marcellus Core
 Ohio Utica Core
 5th Largest
 U.S. GAS PRODUCER (2)

 2nd Largest
 U.S. NGL PRODUCER (2)

 Own 38%
 OF CORE LIQUIDS-RICH UNDRILLED
 LOCATIONS IN APPALACHIA(3)

 ~950
 ADDITIONAL DRY GAS LOCATIONS
 IN DRILLING INVENTORY (3)
 Core Liquids-Rich Appalachian
 $900 MM+ Undrilled Locations(3)

 Forecast Free Cash Flow in 2021 (4)
 )

 29% Midstream
 AR Peers
 ~38% ~62%

 AM VALUE HELD BY AR $1.5 B
 Note: Rigs on map as of 9/30/21, per Rig data. AM value based on 11/01/21 share
 price.
1) AR share price as of 11/01/2021 and indebtedness as of 9/30/2021.
2) Natural gas and NGL rankings based on 3Q21 reported production.
3)
4)
 AR drilling inventory as of 12/31/2020. Industry location count based on Antero technical analysis of undeveloped acreage in the core of the Marcellus and Ohio Utica Shales.
 Free Cash Flow is a Non-GAAP metric. Please see appendix for additional disclosures, definitions, and assumptions. 3

Antero Family at a Glance

 50/50 JV

Exploration & Gathering & Natural Gas C3+ NGL
 Production Compression Processing Fractionation

 Water Delivery
 & Blending

 4

Recent Credit Enhancements
 Received corporate ratings upgrades from Moody’s and S&P Global to Ba2 and
 BB, respectively (10/6/21 - 10/8/21)

 Extended credit facility to 2026, with a borrowing base increase to $3.5 B and
 lender commitments of $1.5 B (10/26/2021)

 Letters of credit have been reduced by $127 MM as a result of ratings upgrades
 and recently released FT capacity (Oct-21)

 Replaced $80 MM of letters of credit with surety bonds, further enhancing
 liquidity (10/27/21)

 Credit Facility + Pro Forma Liquidity Summary
 $3,500
 $3,500
 Pro forma 9/30/21
 $3,000 liquidity:
 $2,500 ~$743 MM (1) Borrowing
 Base
 $2,000
 $1,500
 Liquidity Lender
 $1,000 Commitments
 Revolver: $222
 $500
 LCs: $535 $1,500
 $0
 Revolver Borrowings Credit Facility
 + LCs
1) Pro forma liquidity represents borrowing availability under AR’s credit facility based on $1.5 B of lender commitments and $535 MM of letters of credit. ~$222 MM of borrowings as of 9/30/2021 pro forma for the
 redemption of $116 MM of the 2029 Senior Notes at $107.625, plus accrued and unpaid interests. 5

Antero Strategy Evolution
 Antero’s business strategy has evolved to match the U.S. shale industry life cycle
 AR Net Production (Right Axis) & Capital Investment (Left Axis)
 ($MMs) (1) (MMcfe/d)
 We are
 $3,500 Production (MMcfe/d) Capital Spend here 4,000
 $3,000 3,500

 $2,500 3,000
 2,500
 $2,000
 2,000
 $1,500
 1,500
 $1,000 1,000
 $500 500
 $0 -
 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021E 2022E
 Shale 1.0 Shale 2.0 Shale 3.0
 • Acquire acreage • Grow production • Maintain production
 • Support infrastructure • Aggressively hedge • Generate Free Cash Flow
 through long-term • Consolidate acreage • Reduce debt &
 commitments commitments
 • Innovate through drilling and
 • Delineate resource • Sustain low leverage
 completion techniques
 • Maintain commodity
 • Access low cost capital
 exposure
 • Optimize FT
 • Return capital
 • Prioritize ESG
1) Represents drilling and completion + leasehold capital expenditures. 6

Positioned for Success in Shale 3.0 World
 Antero is well positioned with a strong balance sheet and differentiated
 operating leverage to higher commodity prices

 Peer-leading
 6 ESG Performance

 Supportive
 5 Commodity
 Fundamentals

 Optimal
 4 Takeaway Capacity

 Deep Liquids-Rich
 3 Inventory

 Sustainable
 2 Development and
 Free Cash Flow

 Strong
1 Balance Sheet
 7

1 Peer Leading Debt & Leverage Reduction
 Sustainable long-term leverage reduction is achieved only through absolute debt
 reduction, not just EBITDA expansion in a commodity price upswing
 Year-over-Year Change in Total Debt (1)
 $3,000
 $2,450
 Absolute
 $2,500 Debt
 $2,000 $1,793
 $1,500
 $1,000
 $500
 $0 EBITDA
 ($500) ($312) ($224)
 ($1,000) ($817)
 AR RRC CNX SWN EQT

 Y-O-Y LTM EBITDAX Change ($MM) (2) Net Debt to LTM EBITDAX (9/30/2021)(3)
$700 $652 3.0x 2.7x 2.8x 2.8x
$600
 $498 2.0x
$500 2.0x
 $381 1.6x
$400 $323
$300
 $181 1.0x
$200
$100
 $0 0.0x
 SWN AR EQT RRC CNX AR CNX EQT SWN RRC
Source: Company public filings and press releases.
Note: Please see appendix for additional disclosures, definitions, and assumptions.
1) As of 9/30/2021. Excludes contribution for announced acquisitions not yet closed.
2)
3)
 Represents year-over-year change in LTM EBITDAX from 3Q 2020 to 3Q 2021. Excludes contribution for announced acquisitions not yet closed.
 As of 9/30/2021. Excludes contribution for announced acquisitions not yet closed. 8

1 Strong and Sustainable Balance Sheet

 AR has no near-term senior note maturities and has reset debt levels to insulate
 leverage against a downside commodity price scenario

 Antero Resources Debt Term Structure (Pro Forma 9/30/2021) (1)
 AR Senior Notes
 $2,000 AR Convertible Notes
 $1,800 AR Credit Facility Commitments
 $1,600
 $1,400
 $1,200
 No near-term maturities
 $1,000
 $800
 $590 $584 $600
 $600
 $222
 $400 $82
 $200 $325
 5.00% 8.375% 7.625% 5.375%
 $0
 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

 $2.0 Billion Absolute Debt Target is Designed to Limit Leverage
 in the Event of a Commodity Cycle Downturn

 9
Note: Please see appendix for additional disclosures, definitions, and assumptions.
1) Pro forma for credit facility extension to 2026 on October 26, 2021. Pro forma for the redemption of $116 MM of the 2029 Senior Notes at $107.625, plus accrued and unpaid interests.

2 Significant Commodity Price Leverage
 As one of the largest natural gas and NGL producers in the U.S., Antero has
 significant cash flow upside in a rising commodity price environment
 Top 5 U.S. Natural Gas Producers (MMcf/d) Top 5 U.S. NGL Producers (MBbls/d)
 6,000 250
 5,050 5th largest U.S. Natural 219
 2nd largest NGL
 5,000 Gas producer
 200 producer
 159 158 157
 4,000 148
 150
 MMcf/d

 2,945 48
 3,000 2,728 2,701 Ethane
 2,232 100 112
 2,000
 C3+
 50 NGLs
 1,000

 - -
 EQT CTRA SWN XOM AR OXY AR EOG PXD DVN

 AR Leverage to Natural Gas Prices ($MM) (1) AR Leverage to C3+ NGL Prices ($MM) (2)
 $450 $450
 $407 $407
 Every $0.10 per Every $2 per Bbl move
 $400 $400
 MMBtu move in natural in C3+ NGL prices results
 $350 gas prices results in an $326 $350 $326
 in a $81 MM unhedged
 $300 $81 MM unhedged $300 annual revenue impact (2)
 annual revenue impact (1) $244 $244
 $250 $250
 $200 $200
 $163 $163
 $150 $150
 $100 $81 $100 $81

 $50 $50
 $0 $0
 +$0.10 / +$0.20 / +$0.30 / +$0.40 / +$0.50 / +$2.00 / +$4.00 / +$6.00 / +$8.00 / +$10.00 /
 MMBtu MMBtu MMBtu MMBtu MMBtu Bbl Bbl Bbl Bbl Bbl
Note: Natural gas and NGL producer rankings reflect company 3Q21 reports and public filings.
1) Assumes 3Q 2021 natural gas production of 2.2 Bcf/d. 2.2 Bcf/d of AR natural gas volumes are hedged through 2021 at a weighted average of $2.77/MMBtu and 1.2 Bcf/d hedged in 2022 at a weighted average

 10
 price of $2.50/MMBtu.
2) Assumes 3Q 2021 C3+ NGL production of 112 MBbl/d.

2 Enhanced Free Cash Flow Profile
 Antero expects to generate over $6.0 B of Free Cash Flow through 2025

 Free Cash Flow (Before Changes in Working Capital) ($MM)
 2021E – 2025E Free Cash Flow:
 Free Cash Flow Outspend 10/25/2021 Strip Pricing (1) 5-Year Avg. Strip
 $7,000 Through YE 2025
 NYMEX: $3.75/MMBtu
 $6,000+ WTI: $68/Bbl
 $6,000 C3+ NGLs: $43/Bbl

 $5,000

 $4,000

 $3,000 We Are Here

 $2,000

 $900+
 $1,000

 $0

 ($1,000)
 2018A 2019A 2020A 2021E 2022E 2021E - 2025E
 Cumulative FCF
 (5-year strip)

Note: Free Cash Flow, which is shown before changes in working capital, is a Non-GAAP metric. Excludes $51 MM contingent payment that was received in 2Q 2021 upon meeting certain volume thresholds. Please
see appendix for additional disclosures, definitions, and assumptions.
1) Assumes strip pricing as of 10/25/2021. 2021 strip pricing reflects NYMEX natural gas average price of $3.88/MMBtu, WTI oil price of $68/Bbl and Mont Belvieu C3+ NGL pricing of ~$50/Bbl . 2022 – 2025 strip
 pricing reflects NYMEX natural gas average price of $3.71/MMBtu, WTI oil price of $68/Bbl and Mont Belvieu C3+ NGL pricing of ~$41/Bbl. 11

2 Well Positioned Financially vs Appalachian Peers
 Appalachian Leading YTD 2021 Free Cash Flow…(1)
 ($MM)
 $700 $612
 $600
 $500
 $400 $324
 $300
 $200 $143
 $84
 $100
 $0
 ($100)
 ($200)
 ($300) ($202)
 AR CNX RRC SWN EQT

 Drives $600 MM of Absolute Debt Reduction (2) …and Reduces Leverage Well Below Peers (3)
 ($B)
 $8.0 12/31/2020 9/30/2021 12/31/2020 9/30/2021
 $7.2
 6.0x
 $7.0 5.2x
 $6.0 5.0x
 $4.9
 $5.0 4.0x 3.5x
 $3.8 3.1x 3.2x
 $4.0 2.7x 2.8x 2.8x
 $3.0 $3.0 $2.7 $3.1 3.0x 2.6x
 $3.0 $2.4 $2.2 $2.3 2.0x
 2.0x 1.6x
 $2.0
 $1.0 1.0x
 $0.0 0.0x
 CNX AR RRC SWN EQT AR CNX EQT SWN RRC
Source: Company reports.
1) Represents nine months ended 9/30/2021. Please see appendix for additional disclosures, definitions, and assumptions.

 12
2) Represents net debt as of 12/31/2020 and 9/30/2021, respectively. Excludes contribution for announced acquisitions not yet closed.
3) Represents net debt / LTM EBITDAX as of 12/31/2020 and 9/30/2021, respectively. Excludes contribution for announced acquisitions not yet closed..

2 Best Positioned to Return Capital in Appalachia
 Antero currently has the highest Free Cash Flow to Enterprise Value yield (1) and the
 most advanced debt reduction program among its Appalachian peers
 2021E – 2023E Cumulative Corporate FCF Yield vs 1.0x Leverage Threshold
 40%
 (1)

 39%
 Cumulative 2021E – 2023E FCF as % of Enterprise Value

 35%
 Peer 3
 AR is projected to achieve ≤1.0x
 30% 30%
 leverage by 1Q 2022 (2)
 27% 26%
 Peer 1 Peer 2
 25%
 24% Peer 4

 20% Consensus Price Forecast
 (2021E – 2023E) (2):
 WTI - $66.50/Bbl
 15% Henry Hub - $3.81/MMBtu

 10%

 5%

 0%
 2023+
 1.0x Net Debt / LTM EBITDAX

Note: Represents Factset consensus estimates as of 11/1/2021. 1.0x Net Debt / LTM EBITDAX
1) Free Cash Flow Yield represents consensus cumulative 2021E – 2023E divided by Enterprise value as of 11/1/2021. Current balance sheet data as of 9/30/2021 pro forma for any acquisitions announced to date.

2)
 Free Cash Flow is a Non-GAAP metric. Please see appendix for more information.
 Assumes consensus price forecast as of 11/1/2021. 13

3 Peer Leading Premium Core Drilling Inventory
 Antero’s technical and management teams have performed an extensive update on acreage
 positions, undrilled locations, well performance and EURs across the basin
 – Led to division of the SW Marcellus and Ohio Utica into Premium Core and Tier 2 Core acres

 Premium Core Marcellus Inventory: SW Appalachia Core
 • ~5,200 undeveloped locations
 • AR holds ~1,865 locations, or 36% Utica Core
 Premium Core Utica Inventory:
 • ~1,100 undeveloped locations
 • AR holds ~210 locations, or 19%

 Premium Liquids-Rich
 Core Undrilled Locations

 Peers
 62%
 AR
 38%

 Tier 2 Core Marcellus Inventory:
 • ~1,600 undeveloped locations SW Marcellus
 • AR holds ~150 locations, or 9% Core

 Antero Leasehold & Minerals
 Drilled Wells
Notes: AR drilling inventory as of 12/31/2020. Industry location count based on Antero technical analysis of undeveloped acreage in the core of the Marcellus and Ohio Utica Shales. 14

4 Right-Sizing Firm Takeaway Commitments
• AR’s under-utilized firm transportation commitments are expected to decline by over 1.0
 Bcf/d by year-end 2025, resulting in a >$100+ MM reduction in annualized net marketing
 expense and an optimized takeaway position to premium demand markets
 – Released 400 MMcf/d in commitments year-to-date, reducing annual transportation
 demand fees by $60 MM
 Firm Transportation (Year-End)
 AR Gross Residue Gas Forecast
 BBtu/d
 200 MMcf/d, or $45 MM annualized,
 4,500 of unutilized Midwest capacity
 4,147 rolled off October 2021 Appalachia
 4,000 Regional FT
 3,757
 3,652
 3,500 3,377 3,330
 3,130
 3,000
 TCO
 2,500
 Midwest
 2,000
 Premium
 1,500
 FT
 1,000 U.S. Gulf Coast

 500
 Atlantic Seaboard
 -
 12/31/19 12/31/20 12/31/21 12/31/22 12/31/23 12/31/24 12/31/25
Note: Please see appendix for additional disclosures, definitions, and assumptions. 15

4 Diversity of Product & Destination
 Antero’s liquids-rich strategy and diversified firm transportation portfolio allows
 it to capture commodity price upside both domestically and internationally
 Leader in Liquids Production Leader in Premium Natural Gas
 and Realized Pricing Takeaway and Realized Pricing (2)
 Liquids Production (MBbl/d) (1) Percent Sold Out of Basin
 200 120%
 171 AR leaves ~150 MBbl/d 100%
 of incremental ethane 100%
 in the gas stream 83%
 150
 80%
 107 104 61% 56%
 100 60% 49%
 50 40%
 50
 17 20%
 - 0%
 AR RRC SWN EQT CNX AR RRC SWN EQT CNX

 C2+ NGL Price as % of WTI (1) Price Differential to NYMEX (3)
 60% $0.40 $0.28
 53%
 55%
 48% $0.20
 50% 45%
 45% 43% $0.00
 40%
 40% ($0.20)
 35% ($0.25) ($0.30)
 ($0.40)
 30% ($0.37)
 25% ($0.60)
 20% ($0.80) ($0.74)
 AR CNX RRC EQT SWN AR CNX RRC EQT SWN
Source: Company presentation and filings.
1) Represents YTD 2021 results as of 9/30/2021. Liquids production includes C2+ NGLs and oil.
2)
3)
 Based on company disclosure of firm transportation commitments.
 Represents YTD 2021 results as of 9/30/2021. AR price differential excludes $0.13/Mcf positive impact from 1Q21 WGL settlement. 16

4 FT Protects Basis and Provides Flow Assurance
 AR’s firm transportation portfolio provides price stability, production flow
 assurance, and premium pricing vs. Appalachia-dependent producers
 Antero Basis vs. Appalachia Basis ($/Mcf)
 (1) (2)
 Appalachia Differentials Antero Realized Differential
 Appalchian Average Basis Antero Average Basis

 AR’s 3Q21 realized price was an $0.30/Mcf
 $2.00
 Since the beginning of 2018, AR had premium to NYMEX vs. an average
 Appalachian discount of ($0.77)/Mcf
 Antero Basis
 access to its entire FT portfolio and
 has realized an average $0.13/Mcf
 $1.50 premium to NYMEX over that time
 • Low volatility, high
 reliability
 $1.00
 • Premium to NYMEX
 AR • “Insurance policy” for
 +$0.13
 3Q21: consistent production
 $0.50 +$0.30
 flow
 • Ability to hedge NYMEX
 $0.00 Henry Hub index
 Appalachia
 ($0.50) 3Q21:
 ($0.82) ($0.77) Appalachia Basis
 ($1.00)
 • High volatility, low
 reliability
 ($1.50) • Significant discount to
 NYMEX
 ($2.00) • Frequent shut-ins
 • Less liquid hedge
 markets
Note: Pricing reflects pre-hedge pricing.
1)
2)
 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. Includes BTU adjustment for 1100 BTU gas. 17

5 Strong Natural Gas and NGL Price Momentum
 – Natural gas and NGL prices have strengthened as global demand continues to increase
 while supply flattens
 – Propane storage levels at five year lows provide a bullish set up for winter 2021/2022
 U.S. Natural Gas U.S. NGLs
 Supply Supply
 • The U.S. is forecast to be undersupplied natural gas • U.S. NGL supply remains flat despite high prices as
 for the second consecutive year in 2021 driven by barriers to entry remain high (ie: capital
 moderated drilling activity in shale oil basins commitments for processing & infrastructure)

 • Flat production from gas producers who are • U.S. producer discipline is expected to continue in
 focused on capital discipline 2022, resulting in an insufficient supply response

 • Natural gas directed rig counts are ~45% below the • Record setting LPG exports have led to propane
 peak in 2019, moderating the supply growth outlook inventories 18% below the 5-year average

 Demand Demand
 • LNG feedgas demand has increased to over 11 Bcf/d • Resilient domestic and international demand from
 petrochem and residential/commercial sectors
 • Mexican exports remain elevated at over 6 Bcf/d
 • Rising living standards in developing countries,
 • European natural gas storage is nearing historic particularly in Asia, create an inelastic demand pull
 lows for this time of year putting upward pressure
 on LNG pricing
 Outlook for NGLs
 • Resilient U.S. demand from higher res/com and • Excess U.S. export capacity incentivizes selling NGL
 power sectors barrels into premium priced international markets,
 Outlook for Natural Gas resulting in an undersupplied U.S. market
 • Bullish – Global demand growth and flat supply has
 • Bullish - $4.00/MMBtu+ backwardated strip in already driven C3+ pricing from $15/Bbl in 2Q 2020
 2022/2023 due to growing demand and flat supply to over $65/Bbl today
Sources: October EIA Short Term Energy Outlook, S&P Global Platts estimates and J.P. Morgan Commodities Strategy Team Research. LPG is comprised of NGL components propane and butane.
 18

5 Natural Gas Fundamentals Are Strong
 U.S. production growth has meaningfully slowed and exports
 have increased dramatically compared to 2018
 U.S. Dry Natural Gas Production – Lower 48 (Bcf/d)
 Jan-20: Dec-22E:
 100.0 94.3 Sep-21:
 Jan-21: 95.6
 95.0 Jan-19: 91.6 92.4
 90.0 87.9
 85.0 Jan-18:
 80.0 77.1
 Jan-17:
 75.0 69.6
 70.0
 65.0
 60.0

 U.S. LNG Exports (Bcf/d) Mexico Exports (Bcf/d)
 16.0 8.0
 14.3 6.8
 14.0 12.6 7.0
 6.0
 12.0 11.0 6.0 5.2
 5.0
 10.0 5.0 4.4 4.5
 8.0
 8.0 4.0
 6.0 4.6 3.0
 4.0 3.1 2.0
 2.0 1.0
 - -
 YE YE YE YE YE YE YE YE YE YE YE YE
 2017 2018 2019 2020 2021E 2022E 2017 2018 2019 2020 2021E 2022E
Source: Point Logic for U.S. dry natural gas production and Platts for LNG exports and NextEra for Mexico exports. Supply and export forecasts as of 11/01/2021. 19

5 2021 Supply/Demand Balance Detail
 The U.S. is forecast to be undersupplied in 2021 with demand outweighing supply by 1.4 Bcf/d
 − This backdrop should continue to support higher NYMEX prices
 − Weather remains a key variable to watch
 150 Total Supply
 97 93 96 95 95 96 95 96 97 97 98 98
 100
 Bcf/d

 50

 0
 Jan-21 Feb-21 Mar-21 Apr-21 May-21 Jun-21 Jul-21 Aug-21 Sep-21 Oct-21 Nov-21 Dec-21
 Onshore Prod Offshore Prod LNG Imports Canadian Imports Total Supply
 150
 122
 119 Total Demand 115
 97 102
 100 90 88 89 91 88
 83 84
 Bcf/d

 50

 0
 Jan-21 Feb-21 Mar-21 Apr-21 May-21 Jun-21 Jul-21 Aug-21 Sep-21 Oct-21 Nov-21 Dec-21
 Power Burn Industrial Res Comm Pipe Loss LNG Exports Mexican Exports Total Demand

 Jan-21 Feb-21 Mar-21 Apr-21 May-21 Jun-21 Jul-21 Aug-21 Sep-21 Oct-21 Nov-21 Dec-21 Avg.
Net (Supply -
 Demand)
 (22.0) (29.7) (1.3) 5.5 11.6 8.1 5.9 4.6 12.3 8.9 (4.3) (16.9) (1.4)

Source: S&P Global Platts.
 20

5 Propane Market Fundamentals
 A repeat of the same weekly withdrawals as last winter would result in the U.S.
 ending withdrawal season with only about 16 million barrels in storage,
 significantly below 5-year minimum storage level

 U.S. Propane Inventories (MMBbls)
 120
 2021 injection season
 projected to end at ~75
 100 MMBbls per industry
 estimates

 80
 Million Barrels

 2020
 60
 Repeating winter
 2021E
 2020-2021 weekly

 40 2021

 20
 2022E

 ...Results in ending withdrawal
 season at only ~16 MMBbls,
 0 or just 5 to 7 days of supply
 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

 5-Yr Range 2020 5-Yr Avg 2016-2020 2021 Actual 2021 Forecast 2022 Forecast

Source: EnVantage Inc. and Energy Information Administration (EIA) as of 10/22/21. 21

5 Propane Export Arb
 Despite the dramatic increase in domestic propane pricing in 2021, the export
 pricing arb has remained attractive, and has recently reached
 a yearly high of +6.25 cents per gallon

 Propane Export Arb (Cents per Gallon)
 (¢/Gallon)
 +7.00
 +6.25
 +6.00

 +5.00

 +4.00

 +3.00

 +2.00

 +1.00

 +0.00

. Note: Represents U.S. Gulf Coast export Houston closing prices. Includes all shipping fees 22

5 Strategy Transition For Commodity Price Exposure
 AR’s significant scale, strong balance sheet, commodity product diversity and
 development program flexibility allows AR to capture commodity price upside
 AR Hedges as a % of Guided Production at January 1 of Each Year
 100%
 80%
 60%
 40%
 20%
 0%
 2014 2015 2016 2017 2018 2019 2020 2021E 2022E 2023E

 Prudent Hedging Strategy Prudent Exposure Strategy
 • Single commodity product (dry gas only) • Diversity of product (NGLs & Oil)
 • Growth mode to achieve scale • Maintenance capital mode to harvest free
 • Unutilized FT and less flexible capital cash flow
 budget • Utilized FT and flexible capital budget to
 • Northeast basis exposure & shut-in risk commodity prices

 • Near-term maturities • NYMEX exposure & flow assurance

 • Contango futures prices • Pushed out maturities 4+ years
 • Backwardated futures prices
Note: Percent of production hedged assumes 2021 production guidance and maintenance mode, or flat
production thereafter. • Bullish supply / demand fundamentals 23

5 Peer Hedging Comparison
 Antero has not added any natural gas hedges in ~18 months and is essentially
 unhedged on its 4Q21 and going forward propane production

 % Hedged 2022 Total Production and Natural Gas Production (1)

 % Total Production Hedged % Natural Gas Production Hedged
 100% 95%
 88% 89%
 90%
 Peer average hedged natural
 80% gas production: 80%
 74%
 70% 70%
 Peer average hedged total
 63%
 59% production: 67%
 60%
 50% 50%
 50%

 40%
 34%
 30%

 20%

 10%

 0%
 AR RRC SWN EQT CNX

 24
1) Represents percent of hedged 2022 total production and natural gas production. 2022 production based on consensus production as of 10/27/2021. Hedge positions as of 9/30/2021 for AR, CNX, EQT and RRC
 based on company filings. Pro forma for any acquisitions announced to date.

6 ESG Momentum Continues
 Antero’s peer-leading ESG ranking reflects the internal efforts
 to prioritize ESG performance and disclosures

 2025 Goals Progress

 World Bank Zero Routine
 Flaring Initiative (1):
 COMMITMENT TO NO ROUTINE
 FLARING IN 2021
 Project Canary (July 2021):
 ANNOUNCED PILOT TO PURSUE
 RESPONSIBLY SOURCED GAS
 CERTIFICATION

 2020 ESG Report
 (October 2021):
 MSCI UPGRADE REPORT IS EXPECTED TO DRIVE
 (August 2021): FURTHER RATINGS
 UPSIDE
 BBB ESG RATING
1) Antero has not flared produced natural gas since the infancy of the Marcellus and Utica shale projects in West Virginia and Ohio. 25

6 Social Responsibility and Safety
 Exported approximately 60,000 Bbls/d of LPG in 2020, including approximately
 one-third to developing nations
 Paid approximately $375 million in lease and royalty payments to Ohio and West
 Virginia land owners
 Generated and paid property and severance taxes of $112 million in Ohio and West
 Virginia
 Invested $26 million on community road improvements
 Antero Foundation contributed over $682,000 in direct community donations in
 2020
 Reduced Total Recordable Incident Rate (TRIR) by 35% from 2016 to 2020 Reduced
 Lost Time Incident Rate (LTIR) by 68% from 2016 to 2020

 LPG Export by Destination Community Relations Inquiries

 Other
 67% Developing
 Tickets Created: 3,006
 98%
 Nations RESOLUTION
 33% RATE
 Tickets Closed: 2,959

 26

6 Environmental and Sustainability Leadership

 Total Direct GHG Emissions and Intensity (CO2e)

 Thousand Metric Tons Tons/MBOE
 3.4

 Antero has zero routine flaring of
 2.7
 457 produced gas and one of the lowest
 427
 2.3 GHG intensity metrics in the industry
 422
 2.0 (upstream independents and majors)
 398

 2017 2018 2019 2020

 Methane Leak Loss Rate (1)

 1%

 Industry leading methane leak loss
 rate – nearly half the industry peer
 average and well ahead of the ONE 0.28%
 0.09%
 Future cumulative industry 2025 goal 0.05%

 OF Industry Upstream 2019 OF AR 2020
 Target 2025 Sector Target Upstream
 Sector Avg.
Note: Antero has not flared produced natural gas since the infancy of the Marcellus and Utica shale projects in West Virginia and Ohio.
1) The methane leak loss rate is calculated by dividing methane emitted by the methane produced. The methane leak loss rate represented in this presentation conforms with the ONE Future calculation protocol. 27

6 Governance and Gender Diversity
 88% of the Board of Directors are independent

 43% of independent directors are female

 Established ESG Committee of Board of Directors

 Aligned executive compensation with ESG performance & launched ESG
 advisory council

 28

The Antero Investment Opportunity
 Antero is positioned to deliver sustainable Free Cash Flow,
 with a peer-leading leverage profile

 Strong • Leverage at 1.6x and targeting below 1.5x at YE 2021 (1)
 Balance • Absolute debt reduction of $800 MM in 2020 and over $1.0 B
 Sheet expected in 2021

 Scale and • 2nd Largest NGL Producer in the U.S.
 Operating • 5th Largest Natural Gas Producer in the U.S.
 Leverage • Differentiated operating leverage to higher commodity prices

 Sustainable • $900 MM+ of forecast Free Cash Flow in 2021 (2)
 • $6.0 B+ of forecast Free Cash Flow 2021 - 2025 (2)
 Business • Over 2,000 premium undeveloped premium core locations
 Model • ~$1.07/MMBtu natural gas breakeven price, unhedged (3)

 • One of the industry’s lowest GHG emission intensity metrics
 • No routine flaring – very low methane leak loss rate (0.046%)
 Leading
 • 84% of produced water generated was reused/recycled in 2020
 ESG Metrics • Partner with Project Canary for Responsibly Sourced Gas certification
 • Goal to reach Net Zero carbon emissions by 2025
1) Leverage is a non-GAAP metric, which represents approximate debt to LTM Adjusted EBITDAX level as of 9/30/2021
2) Free Cash Flow, which is shown before changes in working capital, is a non-GAAP metric. Excludes $51 MM contingent payment received in 2Q 2021 relating to the ORRI transaction. Please see appendix for
 additional disclosures, definitions, and assumptions.
3) Represents AR internal 2021-2022 weighted average breakeven price and is defined as full cycle pre-tax ROR of 15%. Assume WTI price of $82.81/Bbl and $77.45/Bbl in 2021 and 2022, respectively.
 Assumes C3+ NGL price of $56.31/Bbl and $52.60/Bbl in 2021 and 2022, respectively. 29

Appendix

Antero Guidance and Long-Term Target Assumptions
 Long-term Outlook Assumptions 2021 2021-2025
 NYMEX Henry Hub Natural Gas Price ($/MMBtu) (1) $3.88 $3.75
 NYMEX WTI Oil Price ($/Bbl) (1) $68.26 $68.08
 AR Weighted C3+ NGL Price ($/Bbl) (1) $50.53 $43.04
 Marcellus Well Costs ($MM / 1,000’ assuming 12,000 ft lateral) $660 / 1,000’ $635 / 1,000’
 AR ownership in AM (shares) and annual AM dividend per share (2) 139 MM shares ($0.90/share annual dividend)

 Current Plan (Maintenance Capital) Assumptions: 2021 2021-2025
 Annual Net Production (MMcfe/d) – Net to AR 3,300 – 3,400
 Wells Drilled – Net to AR 65 - 70 250
 Wells Completed – Net to AR 60 - 65 255
 Wells Drilled (Gross to AR/QL) 80 - 85 310
 Wells Completed (Gross to AR/QL) 65 - 70 315
 Cash Production & Net Marketing Expense ($/Mcfe) (3) – Net to AR $2.33 - $2.40 $2.14 – $2.19 (4)
 G&A Expense (before equity-based compensation) ($/Mcfe) – Net to AR $0.08 - $0.10

1) Represents Mont Belvieu strip pricing as of 10/25/2021 assuming C3+ NGL component barrel consists of 56% C3 (propane), 10% isobutane (Ic4), 17% normal butane (Nc4) and 17% natural gasoline (C5+).
2) AM dividend determined quarterly by the Board of Directors of Antero Midstream.
3)
4)
 Includes lease operating expense, gathering, compression, processing, transportation, production & ad valorem taxes and net marketing expense. Excludes cash G&A.
 Represents average cash production and net marketing expense for 2022 – 2025. Increase in expense is primarily due to increases in commodity pricing, resulting in higher ad valorem and fuel costs. 31

AR Drilling Partnership Announcement (2/17/2021)
 Announced Drilling Partnership With QL Capital Partners (“QL”), an Affiliate of
 Quantum Energy Partners
 • Entered into Drilling Partnership to fund drilling of 60 incremental wells between 2021 and 2024, enabling
 Antero to fill unutilized firm transportation and achieve LP incentive fee rebates from Antero Midstream
 • QL will fund 20% of total development capital spending in 2021 and between 15% to 20% of development
 capital on an annual basis from 2022 through 2024, $500 MM to $550 MM of capital to QL, in exchange for a
 proportionate working interest percentage in each well spud
 • QL will pay a drilling carry to Antero if certain return thresholds are achieved
 • Antero’s net capital spending, wells drilled and completed and net production will remain
 unchanged from maintenance capital level from 2021 – 2025 in the new development plan

 2021 Development Program (1) 2021-2024 Development Program (1)
 Drilled Completed Drilled Completed
 90 85 350 310 315
 80 70 70 300
 80 65 250 255
 70
 250
 60 65 65
 50 60 200
 40 150
 30
 100
 20
 50
 10
 0 0
 AR Drilling AR Drilling AR Drilling AR Drilling
 Maintenance Partnership Maintenance Partnership Maintenance Partnership Maintenance Partnership
Note: Assumes, among other things, current strip pricing and full participation by QL in the drilling partnership. Please see appendix for additional disclosures, definitions, and assumptions.
1) Drilling Partnership wells represent gross wells to the Partnership. On a net to Antero basis, wells drilled and completed will have no impact to the AR maintenance plan. 32

Continued Operational Momentum
 2021 D&C Capital Guidance of $590 MM (net to Antero)
 • Announced 2021 drilling and completion guidance of $590 MM in 2021, a 20% decrease from 2020 spending
 • $900+ MM of estimated 2021 Free Cash Flow (1)
 Reduced Cost Structure
 • 22% well cost reduction from initial 2020 AFE budget to $635/lateral foot expected in 2H 2021 (2)
 • >80% of well cost reductions were driven by sustainable process changes and cycle time efficiencies

 D&C Capital Spending ($MM) Marcellus Well Cost ($/Lateral Foot) (2)

 $1,600 $1,490 Well Completions $1,200

 $1,400 $1,270 $970
 $1,000
 $1,200 $1,150
 $810
 $1,000 $800 $715
 $675 $660 $635
 $800 $735
 $600
 $590
 $600
 $400
 $400

 $200 163 131 125 105 68 (3) $200

 $0
 $0
 2018A 2019A 2020 2020A 2021 (3)
 Jan-19 Initial Revised 2H 2020 Current 2H 2021
 Initial Budget Guidance
 Budget 2020 AFE 2020 AFE AFE 2021 AFE AFE
1) Free Cash Flow, which is shown before changes in working capital, is a non-GAAP measure. Excludes $51 MM contingent payment expected to be received in 2Q 2021 contingent on achieving certain volume
 thresholds relating to the ORRI transaction. Please see appendix for additional disclosures, definitions, and assumptions.
2) Well costs include ~$1 MM or ~$80/ft for facilities, pads and road costs per well assuming a 13,000’ lateral.
3) Drilling and completion capital is net to AR with Drilling Partnership and assumes 80% working interest. 2021 well completions based on midpoint of 65 to 70 wells. 33

Attractive Breakeven Well Economics
 • Antero has some of the lowest natural gas breakeven prices in Appalachia as highlighted in a recent
 JP Morgan research report
 – Breakeven gas prices for rich gas producers like AR are actually lower today due to higher liquids prices than
 assumed by JP Morgan (2)
 – AR’s internally calculated breakeven natural gas prices for its 2021 and 2022 development program is
 $0.89/MMBtu and $1.10/MMBtu, respectively (3)

 2021-2022 Natural Gas Unhedged Breakevens - 15% ROR Full Cycle Breakeven Prices(1)(2)
 AR Internal Breakevens
 Rich Gas Producers (2021) Dry Gas Producers (2021)
 $3.20 as of 10/29/2021 (3)
 Rich Gas Producers (2022) Dry Gas Producers (2022)

 $2.80 $2.63 $2.57
 $2.55 $2.50
 $2.42 $2.40 $2.40 $2.42 $2.48
 $2.40 $2.31
 $2.07
 $2.00
 $2.00

 $1.60

 $1.20 $1.10
 $0.89
 $0.80

 $0.40

 $0.00
 COG AR EQT GPOR RRC SWN
Breakeven analysis source: J.P. Morgan Equity Research estimates in December 8, 2020 report.
1) Breakeven price is defined as full cycle pre-tax ROR of 15%.
2)
3)
 JPM breakevens assume average WTI price of $45.22/Bbl and $44.63/Bbl in 2021 and 2022, respectively. JPM assumed Antero C3+ NGL price of $26.67/Bbl and $24.78/Bbl in 2021 and 2022, respectively.
 AR internal breakevens assume WTI price of $82.81/Bbl and $77.45/Bbl in 2021 and 2022, respectively. Assumes C3+ NGL price of $56.31/Bbl and $52.60/Bbl in 2021 and 2022, respectively. 34

Drilling & Completion Efficiencies
 Average Lateral Length per Well Lateral Drilling Feet per Day
 20,000 18,998 14,000
 12,118
 18,000 12,000

 Achieved February 2021
 New
 16,000
 U.S.

 Achieved June 2021
 10,000
 14,000 12,539 12,696 Record
 12,000 8,000 6,409 6,984
 10,000
 6,000
 8,000
 6,000 4,000
 4,000 2,000
 2,000
 - -

 Completion Stages per Day Drill Out Feet per Day
 6,017
 16.0 6,000
 13.8
 14.0
 5,000
 12.0 4,098

 Achieved March 2020
 Drill Out Feet/Day
 Achieved April 2021

 9.9 4,000 3,771
 10.0
 8.0
 8.0 3,000
 6.0 2,000
 4.0
 1,000
 2.0
 - -

 35
Note: Percentage increase arrows for average lateral length per well and drill out feet per day represent change in Marcellus data from 2014 through 3Q2021. Percentage increase arrows for lateral drilling feet per day
and completions stages per day represent change from 2020 to 3Q2021.

Natural Gas and NGLs Are Essential

 Antero plays a critical role in producing reliable energy for consumers

 5 Largest U.S. 2
 Largest U.S.
 Natural Gas
 NGL Producer
 Producer
 Natural Gas Natural Gas Liquids (NGLs)
 Natural gas is a low-cost, low-emission NGLs play an essential role in the domestic and
 hydrocarbon based fuel that can reduce GHG international industrial, residential, commercial
 emissions by more than half, as compared to coal and transportation industries

 Electricity Generation Transportation

 Heating & Cooking Recyclable food packaging

 Health Care Products &
 Industrial & Manufacturing Protective Equipment

Source: Natural gas and NGL rankings based on 3Q21 reported production. 36

NGL Price Strength
 NGL prices remain elevated on an absolute basis and relative
 to WTI due to sufficient export capacity and resilient global demand
 AR Monthly Realized C3+ NGL Price
 $/Bbl AR C3+ Realized Price ($/Bbl) WTI Price % of WTI 11/08/2021 AR Spot C3+ Price:
 $63.41/Bbl
 77% of WTI
$90 100%

$80 90%
 WTI Price
 80%
$70
 70%
$60
 % of WTI
 60%
$50
 50%
$40
 40%
$30
 30%
$20
 20%
 AR C3+ Price
$10 10%

 $0 0%

Source: Bloomberg actuals through October 2021. Forecasted C3+ pricing based ICE pricing and on Antero C3+ NGL component barrel consisting of 56% C3 (propane), 10% isobutane (Ic4), 17% normal butane
(Nc4) and 17% natural gasoline (C5+). Assumes blended sales of 50% domestic and 50% international. 37

Strong NGL Price Recovery
 Domestic and international LPG prices have improved on a relative basis to crude
 oil, driven by resilient global demand for LPG from petrochemicals and res/comm

 C3+ NGL Prices & % of WTI (1) Far East Index (FEI) Propane Prices & % of Brent
 (2)
 ($/Bbl) (2) ($/Bbl) % of Brent FEI Propane ($/Bbl)
 % of WTI Mont Belvieu Propane ($/Bbl)
 FEI Propane Price
 $70 C3+ Price as 100% $80 as % of Brent 100%
 Historical MB % of WTI 92%
 $65 C3+/WTI% 87% 90%
 90% $70 84% 83%
 5-year avg: 80%
 $60 79%
 ~62% 80%
 $55 77% 80%
 $60
 72% 67%
 $50 66% 70%
 70% 64%
 66% 65% 63%
 $45 $50
 60%
 58% 60%
 $40
 $40 50%
 $35 48% 50%
 C3+ NGL Price FEI Propane Price
 40%
 $30 $30
 40%
 $25 30%
 30% $20
 $20
 20%
 $15 20% $10
 10%
 $10
 10%
 $5 $0 0%

 $0 0%

Source: ICEdata Mont Belvieu, Far East Index, WTI and Brent strip pricing as of 10/28/2021.

 38
1) Based on Antero C3+ NGL component barrel consists of 56% C3 (propane), 10% isobutane (Ic4), 17% normal butane (Nc4) and 17% natural gasoline (C5+).
2) Forecasted C3+ NGLs represent ICEdata Mont Belvieu strip pricing as of 10/28/2021. Forecasted FEI propane represents ICEdata Far East Index propane strip pricing as of 10/28/2021.

Natural Gas Liquids Primer
NGLs play an essential role in the domestic and international industrial, residential,
 commercial and transportation industries

 Gas Linked Pricing Crude Linked Pricing

 Iso-
 Methane Ethane Propane Butane Butane Pentane

 Natural Gas C2 C3 C4 IC4 C5

 Industrial
 Primary Chemical Residential Industrial
 All Industrial Transportation
 Sectors Industrial Commercial, Transportation
 Chemical
 Heating,
 Ethylene Winter Alkylate feed
 Primary Crop drying, Gasoline blend
 Power Production Gasoline to produce
 Uses Commercial, and diluent
 (For plastics) Blending gasoline
 Propylene

 Higher Heating Value

 1000 BTU 4000 BTU
 39

Focus on Liquids Rich Drilling
 Antero currently recovers only 30% of the ethane in its rich gas stream while
 rejecting 70% of the ethane, sending it to pipeline sales in the natural gas stream
 Antero NGL Barrel Composition (2021 Guidance)
 Remaining 70% of ethane
 Natural Gas 1100 BTU Gas stays in natural gas stream
 Processing and enhances gas BTU Ethane (C2)
 ~128,000 Bbl/d of C2 50,000 Bbl/d

 165,000 Bbl/d C2+ NGLs
 1250 BTU Rich Gas

 AR recovers ~30% of ethane ~115,000 Bbl/d C3+ NGLs
 in its rich gas stream

 Ethane
 ~50,000 Bbl/d
 30% of Barrel

 Propane (C3) 56%
 Liquids
 Rich
 Production C3+ NGLs
 ~115,000 Bbl/d

 70% of Barrel Normal Butane (C4) 17%

 IsoButane (iC4) 10%

 Pentanes (C5+) 17%
 AR’s C2+ NGL Barrel
 Composition AR’s C3+ NGL Barrel
 Composition
 40
Note: Based on Antero 2021 production guidance. Antero C3+ NGL component barrel consists of 56% C3 (propane), 10% isobutane (Ic4),
17% normal butane (Nc4) and 17% natural gasoline (C5+).

Premium NGL Price Realizations
 Producer Disadvantaged: Producer Advantaged & Unconstrained:
E&Ps in Permian, Rockies, Mid-Con & Bakken Antero Resources in Appalachia

 AR is the largest C3+ producer
 with the most international
 exposure in Appalachia
 Mariner East Anchor shipper on ME2

 FROM ROCKIES Conway Who Captures the Arb at Marcus Hook?
 Answer: AR and other Appalachian E&P’s
 • Direct sales to most attractive international
 (ARA & FEI) & domestic markets
 • Fixed terminal rates
 • Local fractionation & marketing to sell purity
 products in-basin for local demand
 Results in “Mont Belvieu plus” pricing
 netbacks captured “at the dock” by AR

 Mont
 Belvieu Who Captures the Arb at the Gulf Coast?

 Answer: Midstream & LPG off-takers (not E&P’s)
 • No direct E&P access to international markets (i.e.
 producers only receive Mont Belvieu linked pricing)
 • No local fractionation to sell marketable purity
 products in-basin
 Results in “Mont Belvieu Minus” pricing
 “before the dock”

 41

Balance Capex with Cash Flow – Low Maintenance Capital
 Antero Average Development Well
 3,600
 Net Production Rate: 3.4 Bcfe/d Avg. Lateral Length per Well 13,000’
 3,400
 Bcfe/1,000’ 2.70
 3,200 Replacement Volume 198 Bcfe
 ~16% of 2022 Volume Wellhead Gas BTU 1265
 3,000
 Well Cost ($660/ft) $8.6 MM
 2,800
 2,600 Net F&D Cost $0.288 Mcfe

 2,400 C2 Recovery (1) 40%

 2,200 Well Spacing 830’

 2,000 First Year Recovery Volumes
 Gross (Bcfe) 6.05
 Net (Bcfe) 5.14

 Maintenance Capital Calculation Field and Operating Capital
 • The average AR rich Marcellus well • Roads
 produces 3.16 Bcfe net in the calendar • Working interest
 year when brought online mid-year optimization
 • Assume new wells average ½ year of • Pad construction costs
 production

 Production can be held flat with ~63 wells Maintenance Field
 $556 MM
 198 ÷ 3.16 
 Capital: Maintenance D&C
 = 63 
 Capital
 Maintenance D&C Capital ~$14 MM
 63 $8.6 =

 $542 MM
Note: Maintenance capital is net of VPP transaction. Net F&D cost assumes 85% net revenue interest. Net F&D is a non-GAAP financial measure, see the appendix for more information.
1) Reflects increased ethane volume with start up of Shell Cracker in 2022. Ethane sold at a premium to natural gas price.
 42
 42

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, contract termination and rig stacking costs, simplification
transaction fees, and gain or loss on sale of assets. Adjusted EBITDAX also includes distributions received with respect to limited partner interests in
Antero Midstream Partners 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 natural gas industry to measure operating performance without regard to items excluded from the
 calculation of such term, which may vary substantially from company to company depending upon accounting methods and the 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 and legal structure from its consolidated 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.
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effects of certain
recurring and non-recurring items that materially affect the Company’s net income or loss, 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.
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.
Leverage: Leverage is calculated as LTM Adjusted EBITDAX divided by net debt.

 43

Antero Non-GAAP Measures
Free Cash Flow:
Free Cash Flow is a measure of financial performance not calculated under GAAP and should not be considered in isolation or as a substitute for cash
flow from operating, investing, or financing activities, as an indicator of cash flow, or as a measure of liquidity. The Company defines Free Cash Flow
as Net Cash Provided by Operating Activities, less drilling and completion capital and leasehold capital plus earnout payments.

The Company has not provided projected Net Cash Provided by Operating Activities or a reconciliation of Free Cash Flow to projected Net Cash
Provided by Operating Activities, the most comparable financial measure calculated in accordance with GAAP. The Company is unable to project Net
Cash Provided by Operating Activities for any future period because this metric includes the impact of changes in operating assets and liabilities related
to the timing of cash receipts and disbursements that may not relate to the period in which the operating activities occurred. The Company is unable to
project these timing differences with any reasonable degree of accuracy without unreasonable efforts. See assumptions slide for more information
regarding key assumptions.

Free Cash Flow is a useful indicator of the Company’s ability to internally fund its activities and to service or incur additional debt. There are significant
limitations to using Free Cash Flow 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 Free Cash Flow reported by different companies. Free Cash Flow does 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.

 44

Antero Resources Adjusted EBITDAX Reconciliation
 LTM Adjusted EBITDAX Reconciliation Twelve
 Months Ended
 September 30,
 2021
 Reconciliation of net loss to Adjusted EBITDAX:
 Net loss and comprehensive loss attributable to Antero Resources Corporation $ (1,018,454)
 Net income and comprehensive income attributable to noncontrolling interests 1,637
 Unrealized commodity derivative losses 1,623,610
 Payments for derivative monetizations 13,635
 Amortization of deferred revenue, VPP (43,165)
 Gain on sale of assets (2,479)
 Interest expense, net 185,036
 Loss on early extinguishment of debt 82,239
 Loss on convertible note equitizations 50,777
 Provision for income tax benefit (313,883)
 Depletion, depreciation, amortization, and accretion 776,944
 Impairment of oil and gas properties 137,426
 Exploration expense 6,280
 Equity-based compensation expense 21,505
 Equity in (earnings) of unconsolidated affiliate (78,369)
 Dividends from unconsolidated affiliate 148,080
 Contract termination and rig stacking 6,278
 Transaction expense 3,684
 1,600,781
 Martica related adjustments (1) (104,419)
 Adjusted EBITDAX $ 1,496,362

1) Adjustments reflect noncontrolling interests in Martica not otherwise adjusted in amounts above.
 45

Antero Resources Adjusted EBITDAX Reconciliation

 Three Months Ended September 30, Nine Months Ended September 30,
 2020 2021 2020 2021
Reconciliation of net loss to Adjusted EBITDAX:
 Net loss and comprehensive loss attributable to Antero Resources Corporation $ (535,613) (549,318) (1,337,727) (1,088,284)
 Net loss and comprehensive loss attributable to noncontrolling interests (18,233) (17,257) (17,997) (23,846)
 Unrealized commodity derivative losses 748,791 834,334 875,811 1,774,410
 Payments for (proceeds from) derivative monetizations (18,073) — (18,073) 4,569
 Amortization of deferred revenue, VPP (5,175) (11,404) (5,175) (33,833)
 Loss on sale of assets — (539) — (2,827)
 Interest expense, net 48,043 45,414 152,956 138,120
 Loss (gain) on early extinguishment of debt (55,633) 16,567 (175,365) 82,836
 Loss on convertible note equitizations — — — 50,777
 Provision for income tax benefit (168,778) (158,656) (421,167) (337,568)
 Depletion, depreciation, amortization, and accretion 239,533 183,638 655,460 567,113
 Impairment of oil and gas properties 29,392 26,253 155,962 69,618
 Impairment of equity method investment — — 610,632 —
 Exploration expense 454 235 895 6,092
 Equity-based compensation expense 5,699 5,298 17,001 15,189
 Equity in (earnings) loss of unconsolidated affiliate (24,419) (21,450) 83,408 (57,621)
 Dividends from unconsolidated affiliate 42,755 31,285 128,267 105,325
 Contract termination and rig stacking 1,246 3,370 12,317 4,305
 Transaction expense 524 626 6,662 3,102
 290,513 388,396 723,867 1,277,477
 Martica related adjustments (1) (18,072) (30,197) (21,172) (80,436)
 Adjusted EBITDAX $ 272,441 358,199 702,695 1,197,041

 1) Adjustments reflect noncontrolling interests in Martica not otherwise adjusted in amounts above. 46

Free Cash Flow Reconciliation
 Working capital adjustments in 2021
 include $60.5 million in changes in current
 assets and liabilities and $35.9 million in
 accounts payable and accrued liabilities for
 additions to property and equipment. See
 the cash flow statement in this release for
 details.

 Three Months Ended
 September 30,
 2020 2021
 Net cash provided by operating activities $ 175,870 312,680
 Less: Net cash provided by (used in) investing activities 65,545 (202,577)
 Less: Proceeds from VPP sale, net (215,833) —
 Less: Distributions to non-controlling interests in Martica (17,249) (18,755)
 Free Cash Flow $ 8,333 91,348
 Changes in Working Capital (1) 63,305 30,651
 Free Cash Flow before Changes in Working Capital $ 71,638 121,999

1) Working capital adjustments in 2021 include $28.3 million in changes in current assets and liabilities and $2.3 million decrease in accounts payable and accrued liabilities for additions to property and
 equipment. See the cash flow statement in this release for details.
 47

Total Debt to Net Debt Reconciliation
Total Debt to Net Debt Reconciliation

 December 31, September 30,
 2020 2021
Credit Facility $ 1,017,000 97,500
5.125% senior notes due 2022 660,516 —
5.625% senior notes due 2023 574,182 —
5.000% senior notes due 2025 590,000 590,000
8.375% senior notes due 2026 — 325,000
7.625% senior notes due 2029 — 700,000
5.375% senior notes due 2030 — 600,000
4.250% convertible senior notes due 2026 287,500 81,570
Net unamortized premium (111,886) (28,780)
Net unamortized debt issuance costs (15,719) (24,257)
Consolidated total debt $ 3,001,593 2,341,033
 Less: Cash and cash equivalents — —
Net Debt $ 3,001,593 2,341,033

 48