2018 Analyst Day JANUARY 18, 2018 Cautionary Statement This - - PowerPoint PPT Presentation

2018 Analyst Day

JANUARY 18, 2018

Cautionary Statement

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 release regarding activities, events or developments AR expects, believes or anticipates will or may occur in the future, such as those regarding future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, Consolidated Adjusted EBITDAX, Stand-Alone E&P Adjusted EBITDAX, Consolidated Adjusted Operating Cash Flow, Stand-Alone Adjusted Operating Cash Flow, Free Cash Flow, 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, future financial position, future technical improvements and future marketing opportunities, 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 release. Although Antero 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

• f 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, 2016. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no

• bligation 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 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 E&P Adjusted EBITDAX, (iii) Consolidated Adjusted Operating Cash Flow, (iv) Stand-Alone E&P 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 | 2018 ANALYST DAY

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.

Agenda

Value Proposition: High Return Portfolio & Free Cash Flow

PAUL RADY AND GLEN WARREN | CO-FOUNDERS

Scale & Growth: Liquids-Rich Resource Meets Capital Efficiency

PAUL RADY | CHAIRMAN & CEO GLEN WARREN | PRESIDENT & CFO

Natural Gas Liquids: Leading Position & Strong Fundamentals

DAVID CANNELONGO | OIL & NGL MARKETING MANAGER

2018 Guidance: Transition to Free Cash Flow & Low Leverage

MICHAEL KENNEDY | SVP OF FINANCE & CFO, ANTERO MIDSTREAM

5-Year Outlook: Disciplined Growth Drives Equity Upside

GLEN WARREN | PRESIDENT & CFO

2

ANTERO RESOURCES | 2018 ANALYST DAY

Antero Resources at a Glance

3

ANTERO RESOURCES | 2018 ANALYST DAY

Market Cap……….……....... Stand-Alone Enterprise Value Corporate Debt Ratings…… Stand-Alone Leverage……. Net Production (4Q 2017)… Liquids............................. 3P Reserves………..…........ Net Acres………….…...…… AR Midstream Ownership…. $6.3B $9.7B Ba2 / BB / BBB- 2.6x 2,347 MMcfe/d 107,000 Bbl/d 53.0 Tcfe 630,000 $3.1B

Note: Equity market data as of 1/12/18. Balance sheet data as of 9/30/17.

An $18B Family Valuation

Simplified Organizational Structure

4

ANTERO RESOURCES | 2018 ANALYST DAY

Note: Enterprise value as of 1/12/18. (1) Sponsors represent Warburg Pincus, Yorktown & senior management.

100% Incentive Distribution Rights (IDRs)

NYSE: AMGP Enterprise Value: $3.9B No Ratings NYSE: AM Enterprise Value: $7.0B Corp Ratings: Ba2 / BB / BBB- NYSE: AR Enterprise Value: $9.7B Corp Ratings: Ba2 / BB / BBB-

68% 32%

Sponsors(1) Sponsors(1)

53% 27% 73% 47%

Public Public Public

Senior Management is Well Aligned with Antero Shareholders

0.1% 0.1% 0.2% 0.2% 0.2% 0.3% 0.4% 0.4% 0.4% 0.7% 0.8% 1.0% 1.1% 1.2% 1.4% 1.7% 8.8% 9.0% 13.1% 13.4% 0% 2% 4% 6% 8% 10% 12% 14% 16% 18% 20%

ECA COP APC MRO APA OXY EOG FANG DVN EQT NFX PXD CXO NBL COG XEC HES AR PE RSPP CLR

Co-Founders & Significant Owners

5

ANTERO RESOURCES | 2018 ANALYST DAY

Current Management Ownership

• Management Owns ~$550 MM of

Antero (AR) Stock

• 9% of Company Shares
• $400 MM More Than Peer Median

Source: Bloomberg & Company Research

78%

U.S. E&Ps ≥ $6B Market Cap

Compensation Structure is Moving to Best Practices

6

ANTERO RESOURCES | 2018 ANALYST DAY

Proposed Compensation Plan Going Forward (Incorporates Recent Shareholder Outreach Program)

Intends to target median compensation of industry peers Short-term incentive plan would focus on four metrics:

• Free cash flow
• Debt-adjusted production per share
• Leverage
• Health, safety and environmental

Long-term incentive plan is expected to focus solely on equity and performance shares Performance shares would be tied to a combination of absolute and relative stock price return with an ROCE component

   

Note: Subject to compensation committee and final board approval.

Broad Compensation Plan Changes Further Align Management and AR Shareholders

Value Proposition: High Return Portfolio & Free Cash Flow

PAUL RADY & GLEN WARREN

Co-Founders

7

Why Are We Here Today? Antero is at an Inflection Point

8

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | OVERVIEW

Step Change in Capital Efficiency Reduces 5-Year D&C Capex by $2.9B Size & Scale to Capitalize on Resource Announcing New Long Lateral Development Plan Averaging 11,500’ Largest NGL Producer in U.S. With Highest Leverage to Rising NGL Prices

Sustainable Cash Flow Growth

Generating 5-Year Free Cash Flow of $1.6B at YE Strip & $2.8B at $60 Oil

Joining an Elite Group With: Scale Double Digit Growth Free Cash Flow Low Leverage

Disciplined Returns Focus

→28% Full Cycle Returns →23% 5-Year Debt-Adjusted Production CAGR per share →22% 5-Year Cash Flow CAGR per share

Note: See definitions for free cash flow and assumptions behind long-term targets in Appendix; free cash flow definition includes maintenance land spending, but excludes growth land spending.

A Transformational History: From Ambition to Results

9

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | OVERVIEW

2001-2010

Antero 1.0 A Shale Pioneer

• Early success in

the Barnett

• Identified a large

resource base in the Marcellus

• Key acreage

acquisitions

• Confirmed

resource with initial well tests

• Built out initial

infrastructure

2011-2014

Antero 2.0 Scaling Up for Strong Growth

• Intensified acreage

expansion & infill

• Implemented

marketing plan with hedge portfolio & firm transportation to key gas markets

• Built competitive

advantage with midstream assets

• Brought liquids into

focus with processing commitments

2015-2017

Antero 3.0 Optimizing

Development Program

• Dramatic drilling

efficiencies

• Advanced

completions

• Sustained

development momentum through downturn

• Improved balance

sheet

2018-

Antero 4.0 Disciplined Returns Focus

• Capitalizing on

critical mass and cash flow engine

• Maintaining

discipline in capital investment

• Sustaining cost

efficiencies and reliable execution

• Delivering free

cash flow

• Reducing leverage

Core of the Core Acreage Position

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VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | SIZE & SCALE IN THE APPALACHIAN BASIN

Southwest Marcellus Core Has Been High-Graded for Best Well Performance

Dry Gas

High-Graded Core 2.30 Bcf / 1,000’ EURs 78% Undeveloped AR Holds 13% of Undeveloped

Northern Rich

High-Graded Core 2.24 Bcfe / 1,000’ EURs 67% Undeveloped

Southwest Marcellus Core ~2.9 Million Acres 78% Undeveloped

Antero Acreage Antero Marcellus Wells(1) Industry Marcellus Wells(1) Antero Marcellus Rig Industry Marcellus Rig

Southern Rich

High-Graded Core 2.24 Bcfe / 1,000’ EURs 70% Undeveloped AR Holds 61% of Undeveloped

Note: Excludes 600,000 urban acres. 1) Wells completed with ≥ 1,300 lb/ft of proppant.

New Long Lateral Plan

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VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | SIZE & SCALE IN THE APPALACHIAN BASIN

59% of Inventory Now ≥ 10,000’ Lateral Length 5-Year Plan Averages 11,500’

Average Lateral Length per Completed Well Core Inventory by Lateral Length

10,800’

Average Inventory Lateral Length 12,700 2,000 4,000 6,000 8,000 10,000 12,000 14,000 2018 2019 2020 2021 2022 145 155 160 165 165 Wells Completed(1) 1,450 200 400 600 800 1,000 1,200 1,400 1,600 <6,000' 6,000' - 8,000' 8,000' - 10,000' 10,000' - 12,000' ≥12,000' Feet Feet (No. of locations)

1) Wells completed reflects midpoint of targeted completions per year.

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2018 Completion Program 2019 Completion Program Full Cycle ROR at $60/Bbl Flat: 33% Half Cycle ROR at $60/Bbl Flat: 90% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2018 Completion Program 2019 Completion Program Full Cycle ROR: 28% Half Cycle ROR: 82%

Why Are We Growing? Outstanding Well Economics

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VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | ATTRACTIVE WELL ECONOMICS DRIVES GROWTH

Well Economics Support Investment

ROR Well in Excess of Cost of Capital

28% Corporate Level ROR

2018 & 2019 Full Cycle Returns

Single Well Economics

Note: Half cycle burdened with 60% of AM fees to give credit for AM ownership/distributions and variable firm transportation fees. See Appendix for further detail behind full cycle and half cycle single well economics; WACC calculated using CAPM.

Cash Cost Economics AR Corporate Level Returns

WACC ≈ 8% $60 Oil Strip Pricing

Almost $3B Capital Reduction to 5-Year Plan

Consolidated Drilling & Completion Capital Expenditures Production Targets

2.7 3.3 4.0 4.6 5.2 2.7 3.3 3.9 4.5 5.2 0.0 1.0 2.0 3.0 4.0 5.0 6.0 2018 2019 2020 2021 2022 Bcfe/d As of December 2016 As of December 2017

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VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | ATTRACTIVE WELL ECONOMICS DRIVES GROWTH

$2.9B Capex Reduction

Cumulative Reduction in Drilling & Completion Capital

Same Production Targets

20% Production CAGR 2018-2020 15% Production CAGR 2021-2022

Same Production Growth With Much Less Capital Spending

$1.6 $1.7 $2.0 $2.2 $2.4 $1.3 $1.3 $1.3 $1.4 $1.7 $0.0 $0.5 $1.0 $1.5 $2.0 $2.5 2018 2019 2020 2021 2022 $ Billions As of December 2016 As of December 2017

New Development Plan $2.9B D&C Capex Savings

14

$2.9B

Capital Efficiencies Captured Within D&C Capex From New Development Program

$0.9B

Lateral Lengths

$0.5B

Improved Cycle Times

$1.1B

Optimizing Capital Allocation

$0.09MM/1,000’ savings from 9,000’ to 12,000’ Reduced drilling days, increase in stages per day and concurrent operations Continued shift to high- graded Marcellus

$0.4B

Well Cost Savings

Related to reduced AFEs including lower flowback water handling cost due to Clearwater Facility

D&C Capex Savings

Lateral Lengths Cycle Times Well Cost Savings Capital Allocation & Enhanced Recoveries

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | COST EFFICIENCY DRIVERS

($1,500) ($1,000) ($500) $0 $500 $1,000 $1,500 2014A 2015A 2016A 2017E 2018 Guidance 2019 Target 2020 Target 2021 Target 2022 Target

Lower Capital & Higher Liquids → Free Cash Flow

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | SUSTAINABLE CASH FLOW GROWTH

$60 Oil / $2.85 Gas Case Stand-Alone E&P Free Cash Flow Outspend Strip Pricing at 12/31/17 (Base Case)

D&C Capital Investment Fully Funded with Cash Flow

Note: See definitions for free cash flow and assumptions behind long-term targets in Appendix; free cash flow definition includes $200MM maintenance land spending, but excludes $300MM discretionary land spending.

Over $1.6B of Targeted Free Cash Flow from 2018 to 2022 at Strip Pricing Including Maintenance Land Capital Expenditures

$50 Oil / $2.85 Gas Case

$2.8B $1.0B $1.6B

We Are Here

5-Year Cumulative Free Cash Flow

15

Stand-Alone Free Cash Flow:

$0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 Crude Price Scenarios Strip Pricing at 12/31/17 $60 Oil / $2.85 Gas

Significant Exposure to Higher Liquids Prices

16

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | 5-YEAR OUTLOOK

Note: See definitions for free cash flow and assumptions behind long-term targets in Appendix. Cash flow assumes 62.5% to 67.5% of WTI Crude price for C3+ in 2018 and 72% in 2019+ (after ME2 in-service). ME2 fees included in transportation costs once in-service.

$2.8B in Free Cash Flow at $60/Bbl from 2018 - 2022

$0 $100 $200 $300 $400 $500 $600 $700 $800 $900 $1,000 2018 Guidance 2019 Target 2020 Target 2021 Target 2022 Target Strip Pricing at 12/31/17 $60 Oil / $2.85 Gas

Not Just a Natural Gas Producer Annual Free Cash Flow Upside Aggregate 5-Year Free Cash Flow Upside

$1.2B

$4.8B in Free Cash Flow at $70/Bbl from 2018-2022

$60 Oil Strip Pricing

17

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | 5-YEAR OUTLOOK

Attractive Free Cash Flow Yield

Note: See definitions for free cash flow and assumptions behind long-term targets in Appendix. “Elite” group of peers includes COG, CXO, EOG, FANG, PXD, XEC; “Integrated” group includes XOM & CVX. Source: Bloomberg. Represents free cash flow yield for the base case at 12/31/17 strip pricing. (1) Represents free cash flow divided by current market capitalization as of 1/12/18.

0% 1% 2% 3% 4% 5% 6% 7% 8% 9% 2018 2019 2020 FCF Yield

Free Cash Flow Yields Exceed Both Best-In-Class Peers & Integrated Oil & Gas Companies

AR 8% FCF Yield(1)

Surpasses Industry Leading Peers, While Maintaining Strong Production Growth

Shareholder Interests in Focus: 5-Year Cash Priorities

18

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | SUSTAINABLE CASH FLOW GROWTH

$10.4B

Cumulative Stand-Alone E&P Adjusted Operating Cash Flow

$2.7B

D&C Maintenance Capital Debt Reduction

$5.9B

D&C Growth Capital Return of Capital Land Acquisitions

Significant Financial Flexibility with Cash Flow in Excess of Maintenance Capital $1.6B Free Cash Flow for Deployment

Note: See Appendix for key definitions and assumptions. Adjusted stand-alone E&P operating cash flow includes $250MM in earn-out payments on water business.

$0.2B

Land Maintenance

Priorities for Cash Sustain Asset Base Disciplined Growth Investments Optionality

3.9x 3.6x 2.8x 2.8x 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x 4.0x 4.5x 5.0x 2014A 2015A 2016A 2017E 2018 Guidance 2019 Target 2020 Target 2021 Target 2022 Target Stand-Alone Financial Leverage 12/31/17 Strip Pricing (Base Case) $60 Oil / $2.85 Gas $50 Oil / $2.85 Gas

Cash Flow Growth → Dramatic Delevering

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | CASH FLOW DRIVES LOW LEVERAGE

23% Debt-Adjusted Production Growth Per Share Generates Free Cash Flow Balance Sheet Delevering & Optionality

Note: See Appendix for key definitions and assumptions. Stand-alone financial leverage is calculated by dividing year-end stand-alone debt by last twelve months stand-alone EBITDAX. Note all free cash flow after land spending is assumed to be used for debt reduction.

19

Leverage targets inclusive of $500 MM

• f maintenance and discretionary land

capex from 2018 - 2022

<2.0x by 2019

Net Debt / LTM Stand-Alone E&P Adjusted EBITDAX

20

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | ATTRACTIVE VALUATION

Antero Profile To Drive Multiple Expansion

U.S. Publicly Traded E&Ps Leverage < 3.0x Enterprise Value > $10B Production Growth >15% Leverage <2.0x Free Cash Flow

Joining an Elite Group of E&Ps With Scale, Double Digit Growth, Low Leverage & Free Cash Flow Generation

Source: Bloomberg & Antero Estimates as of 1/12/18. (1) Adjusted EBITDAX and Adjusted Operating Cash Flow are non-GAAP measures. For additional information regarding these measures, please see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix.

# of Companies Median Debt/ Adjusted EBITDAX Median EV/ 2018 Adj. EBITDAX 51 3.1x 7.1x 23 1.5x 7.8x 18 1.9x 8.9x 10 1.5x 9.7x 6 1.3x 11.1x 6 1.3x 11.1x

EOG CXO PXD

AR 2018E EBITDAX Multiple: 5.1x

Scale Growth Low Leverage

Permian & Appalachia

FCF Generation

  

FANG COG XEC

 

in 2019 in 2018

Premium for:

Scale & Growth: Liquids-Rich Resource Meets Capital Efficiency

PAUL RADY

Chairman & CEO

21

GLEN WARREN

President & CFO

&

40% of Core Undrilled Liquids-Rich Locations are Held by Antero

A Deep Understanding of the Appalachian Basin

22

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE

Core Liquids-Rich Appalachia Undrilled Locations(1) AR 40%

A 13% C 13% K 7% D 7% I 7% B 5% H 3% F 3% J 2%

Note: Core outlines are based upon Antero geologic interpretation, well control, drilling activity, well economics and peer acreage positions; undrilled location count net of acreage allocated to publicly disclosed joint ventures. Rig information per RigData as of 12/8/2017. (1) Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG, RRC and SWN.

36 SW Marcellus Rigs 22 Utica Rigs 10 NE Marcellus Rigs

68 Total Rigs

Cross-Functional Team Works Together to Define Core Boundaries and Competitor Positions In Basin

Defining the Resource: Appalachia Basin Core Analysis

23

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE

9,600 Wells

Horizontal Wells Analyzed Since Basin Inception

7.8 MM Acres

Acreage Analyzed by Antero Teams

30 Professionals

Involved Team of Geologists, Reservoir Engineers, Land and GIS

27,000 Locations

Future Locations Plotted on Antero Maps

• A deep database of peer information and

analysis is maintained in house

– Acreage positions: developed and undeveloped – Well locations, lateral lengths, completions & production results – Optimal undrilled location inventory based on operator well density

• Reservoir engineers assign reserves per well

– Determined EURs on over 9,600 horizontal wells (8,200 Marcellus and 1,400 Utica) via decline curve analysis

• Geologists map structure, rock quality and

pressure

• Core area maps reflect the collective work of
• ur technical teams

– Geologists map core areas based on the well data provided by engineers – Both productivity and well economics are factored into core

• utlines

3,295 2,333 1,930 1,259 720 714 663 588 583 556 544

• 500

1,000 1,500 2,000 2,500 3,000 3,500 4,000 AR A B C D E F G H I J Undrilled Locations

Marcellus & Utica Liquids Rich Locations SW Marcellus & Utica Dry Locations NE Pennsylvania Dry Locations

Who Has the Running Room?

24

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE

10,848’ 9,563’ 6,775’ 7,723’ 6,040’ 9,583’ 8,905’ 9,398’ 8,396’ 7,731’ 8,639’

We Have 40% of Liquids-Rich Locations

Largest Inventory in Appalachia

(1) Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG, RRC and SWN.

Who Can Drill Long Laterals? Who Has the Running Room? Undrilled Core Marcellus & Utica Locations(1)

Lateral Length:

Recently Expanded Core & High-Graded Core Reflecting Well Performance

25

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE

Core of the Core

Northern Rich

High-Graded Core ~283,000 acres 2.24 Bcfe/1,000’ Avg. Wellhead EUR 67% Undeveloped

Southern Rich

High-Graded Core ~487,000 acres 2.24 Bcfe/1,000’ Avg. Wellhead EUR 70% Undeveloped AR Holds 61% of Undeveloped

Southwest Marcellus Core ~2.9 Million Acres ~78% Undeveloped

Antero Acreage Antero Marcellus Wells Industry Marcellus Wells Antero Marcellus Rig Industry Marcellus Rig

Dry Gas

High-Graded Core ~1,051,000 acres 2.30 Bcf/1,000’ Avg. Wellhead EUR 78% Undeveloped AR Holds 13% of Undeveloped

> 1,300 lb/ft Completions High- Graded Core Areas Most Active Operators Percent Undeveloped Advanced Completions (>1,300 lbs/ft) Bcfe / 1,000’ Wells Northern Rich RRC, CNX, HG 67% 2.24 474 Southern Rich AR, EQT, SWN 70% 2.24 517 Dry Gas EQT, CVX, RRC, CNX 78% 2.30 747

Note: Excludes 600,000 urban acres. EURs on ethane rejection basis.

Core of the Core Development Programs

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SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | 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 30 168% 447 12,500’ Highly-Rich Gas 1200-1275 106 101 74% 935 11,500’ Rich Gas 1100-1200 4 30% 495 11,150’

Ohio Utica

Condensate 1250-1300 19 2 50% 206 9,950’ Rich Gas 1100-1200 3 9 29% 102 11,550’ Dry Gas 1050 3 9 37% 187 10,450’ Total(1) 145 155 Program Stats: 78% | 86% Strip | $60 Oil ROR 1,253 BTU Average Program Stats: 86% | 93% Strip | $60 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.

5-Year Core of the Core Program

27

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE

Highly-Rich Gas Condensate

1275 BTU+

• Well Inventory: 447
• Avg. Lateral Length: 12,522

Rich Gas

1100 – 1200 BTU

• Well Inventory: 495
• Avg. Lateral Length: 11,158

Highly-Rich Gas

1200 – 1275 BTU

• Well Inventory: 935
• Avg. Lateral Length: 11,502

25 Producing Wells 2.7 Bcfe/1,000’ Average 15 Producing Wells 2.7 Bcfe/1,000’ Average 14 Producing Wells 2.8 Bcfe/1,000’ Average

5-Year Program Producing Wells Antero Marcellus Rig

Note: EUR results include processed volumes and 25% ethane recovery. Includes well results completed with more than 1,500 pounds of proppant per foot. Well volumes based on 12,000’ lateral at 2.0 Bcf/1,000’ wellhead type curve by BTU regime mid-point. See Appendix for further details.

Antero Acreage

A Pioneer in Drilling Longer Laterals in Appalachia

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SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: LONGER LATERALS

(1) All laterals rounded to the nearest thousand. (2) Represents wells placed to sales.

Antero Historical & Future Lateral Length Program

113 85 22 12 10 4 12 13 57 103 93 107 76 81 78 77 93 50 100 150 200 250 300 ≤ 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 > 15,000 Well Count Lateral Length(1)

Antero

# of Wells

• Avg. Lateral

Length Total Drilling Program to Date 945 8,275 2018-2022 Program(2) 790 11,425 Wells to Date ≥10,000’ 245 10,700

Lateral Lengths Up 29% in 5-Year Plan

29

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: LONGER LATERALS

Average Lateral Length per Completed Well Lateral Lengths per Year Increasing by 2,500’ in New Plan

(1) Represents 2017 YTD average as of 12.10.2017.

9,100 9,000 8,600 9,200 8,500 9,700 10,500 11,600 12,400 12,700 2,000 4,000 6,000 8,000 10,000 12,000 14,000 2017 2018 2019 2020 2021 2022 Average Lateral Length (in feet) 2017 Plan 2018 Plan 9,300

5 10 15 20 25 30 35 40 45 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 16,000 EUR (Bcfe) Lateral Length (ft) EUR in Bcfe/1,000' 2.3 Bcfe/1,000'

Longer Laterals Scale the Resource

30

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: LONGER LATERALS

EURs by Marcellus Lateral Lengths

A 1:1 Proportional Increase in EURs with Longer Laterals

Antero well results show no evidence of degradation in recovery per foot of completed lateral out to over 14,000’

R2 = .73

Note: Assumes 25% ethane recovery.

The Longer, the Better…

31

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: LONGER LATERALS

Note: Represents half cycle economics at strip pricing. See Appendix for further assumptions on single well economics.

Single Well Economics by Lateral Lengths

$6.8 $11.4 $15.9 $20.4 50% 67% 74% 79% 0% 20% 40% 60% 80% 100% $- $5.0 $10.0 $15.0 $20.0 $25.0 6,000' Lateral 9,000' Lateral 12,000' Lateral 15,000' Lateral PV-10 ($MM) ROR (%)

$0.60 $0.80 $1.00 $1.20 $1.40 $1.60 $1.80 $2.00 $2.20 3,000 6,000 9,000 12,00015,000 $MM/1,000 ft of lateral Lateral Length (ft)

Marcellus

2014 2017

Well Costs → Longer Laterals is the Next Step

32

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | 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

$0.60 $0.80 $1.00 $1.20 $1.40 $1.60 $1.80 $2.00 $2.20 $2.40 $2.60 3,000 6,000 9,000 12,000 15,000 $MM/1,000 ft of lateral Lateral Length (ft)

Utica

2014 2017

43% Reduction 9% Reduction 10% Reduction

Drilling Longer Laterals with Dramatically Fewer Drilling Days and More Stages per Day

Reduced Cycle Times Lead to Lower Well Costs

Drilling Days Completion Stages per Day

33

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: CYCLE TIMES

59% | 34%

Decline in Drilling Days in the Marcellus | Utica

31% | 25%

Improvement in Marcellus | Utica Stages Per Day

29 24 15 12 8 29 31 17 18 5 10 15 20 25 30 35 40 45 2014 2015 2016 2017 Record Drilling Days Marcellus Utica 3.2 3.5 4.0 4.2 3.2 3.7 4.8 4.0 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 2014 2015 2016 2017 Record Stages per Day Marcellus Utica 10.0

Operating Evolution Continues

Total Well Cost Savings in the Marcellus(1) Next Steps in D&C Evolution

34

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | OPERATING TECHNOLOGIES EVOLVE

(1) Based on Marcellus 9,000 foot lateral and 2,000 pounds per foot AFE.

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% % of Total Well Cost Savings

Drilling Vendor Reduction (3%)

Completion Vendor Reduction (43%) Drilling Efficiency (25%) Completion Efficiency (29%)

• Automated completion equipment

→ increase stages per day

• Program wide implementation of

higher proppant loading, zipper stimulations and longer laterals

• Reduced cluster spacing → higher

potential recoveries

• Sand
• 100 mesh efficiency → easier

pumping with fewer screenouts

• Self-sourcing initiative → reduce

supply risk and cost

• Fit-for-purpose rigs improves cycle

times

• Enhanced walking and dual operation

capabilities

• Concurrent operations (“ConOps”)
• Plan to implement in 2019

42%

Decline in well costs since 2014

54%

Permanent cost efficiencies

46%

Vendor-related cost reductions

Continuous Design Improvement in Operations

35

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | OPERATING TECHNOLOGIES EVOLVE

Average Wells per Pad by Year Current Well Pads

Drilling Production

2 3 4 5 6 7 8 9 10 2010 2011 2012 2013 2014 2015 2016 2017 2018 Wells per Pad

Completion

Map View Pad Size: 3-4 Acres

Rig Wellheads

12 Well Pad

Average Lateral Lengths by Year

Generation 1.0

150%

increase in wells per pad

5,000 6,000 7,000 8,000 9,000 10,000 2010 2011 2012 2013 2014 2015 2016 2017 2018 Feet

70%

increase in lateral lengths Pad Construction

Concurrent Operations

ConOps: Improved Cycle Times Lift Returns

Concurrent Operations Boost Returns

36

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | OPERATING TECHNOLOGIES EVOLVE

60% 70% 80% 90% 100% 110% 2 4 6 8 10 12 Rate of Return Wells per Pad

Theoretical Best Batch Drill Then Complete

ConOps Concurrent vs. Batch(1)

(1) “Batch Drill Then Complete” is defined as drilling and completing all wells prior to drill out and subsequent production on a single pad, consistent with Antero’s current approach. “Theoretical Best” assumes drill, complete and put first well on production prior to drilling the second well, etc.; not possible with current wellhead configuration of pad. “Concurrent Operations” or ConOps envisions drilling half of the wells on a given pad, and completion and production occurring on the first batch of wells concurrently with drilling activity on the second batch of wells.

200 Feet

Pad Designs Support Concurrent Operations

37

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | OPERATING TECHNOLOGIES EVOLVE

New Pads Designed for ConOps

Pad Size: Approximately 7 Acres

12 Well Pad

Separation of Wellheads Allows For Drilling to Continue at One End of the Pad, While Completions and Then Production are Underway at the Other End

Drilling 1st Six Wells Production Completion Drilling 2nd Six Wells Production Completion

Generation 2.0

Pad Construction

Map View

Rig Wellheads Frac Fleet

Completions Fleet Operations

Dramatically Improved Well Recoveries From Advanced Completions

Advanced Completions Drive EURs Higher

Proppant Per Foot Increasing EUR per 1,000’(1)(2)

38

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: ENHANCED RECOVERIES

Higher Proppant per Foot

has contributed to higher recoveries

Marcellus EURs +33%

1.8 1.9 2.3 2.4 3.0 1.5 1.8 1.6 1.7 2.3 0.0 0.5 1.0 1.5 2.0 2.5 3.0 2014 2015 2016 2017 Record Processed EUR per 1,000' of Lateral (Bcfe) Marcellus Utica 1,165 1,163 1,702 2,094 2,530 1,267 1,298 1,648 2,375 2,757

• 500

1,000 1,500 2,000 2,500 3,000 2014 2015 2016 2017 Record Pounds of Proppant Per Foot Marcellus Utica

(1) Based on statistics for wells completed within each respective period. (2) Ethane rejection assumed for Ohio Utica and 25% ethane recovery assumed in 2016-2017 for Marcellus.

$0.88 $0.73 $0.51 $0.42 $1.28 $0.94 $0.73 $0.74 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40 2014 2015 2016 2017 Marcellus Utica

39

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: WELL COST REDUCTION

Result in Dramatically Lower F&D Cost

F&D Cost per Mcfe(1)(2)

(1) Ethane rejection assumed. (2) 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

Natural Gas Liquids: Leading Position & Strong Fundamentals

DAVID CANNELONGO

Oil & NGL Marketing Manager

40

105.6 34% 30% 11% 13% 8% 12% 12% 12% 13% 7% 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 45.0 55.0 65.0 75.0 85.0 95.0 105.0 115.0 AR RRC DVN APC EOG COP CHK PXD NBL OXY NGL % of Product Revenues MBbl/d 3Q17 Daily NGL Production Including Recovered Ethane NGL % of Product Revenues

Largest NGL Producer in the U.S.

41

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LEADING THE WAY AS THE LARGEST U.S. NGL PRODUCER

NGL Price Exposure Among Top NGL Producers

Source: SEC filings and company press releases. Note: Realized prices are weighted average including ethane (C2) where applicable.

34% of AR Q3 2017 Revenue from NGLs

$23.11

Pre-hedged Realized Price ($/Bbl)

$16.93 $15.15 $31.07 $22.38 $20.72 $21.83 $18.96 $22.91 $22.99

Antero Has The Highest NGL Price Exposure Among Top NGL Producers

Pre-hedged Realized Price ($/Bbl)

50,000 100,000 150,000 200,000 250,000 2014 2015 2016 2017 2018E Guidance 2019E Target 2020E Target 2021E Target 2022E Target Natural Gasoline (C5+) IsoButane (iC4) Normal Butane (nC4) Propane (C3) Ethane (C2) 245,000

Rapidly Growing NGL Production

42

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LEADING THE WAY AS THE LARGEST U.S. NGL PRODUCER

Antero NGL Production Growth by Purity Product

Note: Excludes condensate. See Appendix for further assumptions around long-term targets.

Total (Bbl/d) C5+ iC4 nC4 C3 C3+ Production C2

C2 Ethane 17,476 C2 Ethane 26,500 C2 Ethane 44,000

Resulting in a material reduction in U.S. propane inventories U.S. propane exports exceeded excess domestic supply in 2016 and 2017

Current Propane Market Fundamentals

43

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS 20,000 40,000 60,000 80,000 100,000 120,000 Jan FebMar Apr May Jun Jul Aug Sep Oct Nov Dec MBbl 5-year Range 2016 2017

(100)

• 100

200 300 400 500 600 700 800 2010 2011 2012 2013 2014 2015 2016 2017

MBbl/d

Excess Supply Net (Imports) / Exports

U.S. Propane: Excess Supply vs. Net Exports U.S. Propane Inventories

2017 inventory is 36% below 2016 inventory levels In 2016 U.S. exports exceed excess supply by ~120MBbl/d

$0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40 $1.60 $1.80 $2.00 $/Gallon 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% % of WTI

C3+ NGLs: Absolute & Relative Price Improvement

44

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

Tightening Inventories and Increasing Exports, Along With an Increase in Global Product Prices, Resulted in Improvement in C3+ Prices on Both an Absolute and Relative Basis

• Mt. Belvieu C3+ Price

Mont Belvieu C3+ to WTI Price Ratio

Source: Intercontinental Exchange (ICE) pricing data. Assumes C3+ barrel weightings of: propane 56%, normal butane 16%, Isobutane 9%, pentanes 19%.

$1.05/gal 72% of WTI

Significant Investment in LPG Infrastructure

Global VLGC Ship Fleet

45

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

Source: Poten Partners. S&P Global Platts.

U.S. LPG Export Capacity

200 400 600 800 1,000 1,200 1,400 2012 2013 2014 2015 2016 2017 MBbl/d 50 100 150 200 250 300 2012 2013 2014 2015 2016 2017 Vessels

In response to subdued domestic NGL prices and attractive arbitrage opportunities from 2014 - 2016, a significant investment was made in LPG export and shipping capacity

46

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

The New Norm: Tighter U.S. Differentials to Global Prices

($1.40) ($1.20) ($1.00) ($0.80) ($0.60) ($0.40) ($0.20) $0.00 2012 2013 2014 2015 2016 2017 $/Gallon

Mont Belvieu vs. Far East Index Differential

Source: Intercontinental Exchange (ICE) pricing data. S&P Global Platts.

Baltic LPG Shipping Rates

10 20 30 40 50 60 70 80 90 100 2012 2013 2014 2015 2016 2017 $/Metric Ton

As a result of the significant investment, Mont Belvieu transforms from a constrained domestic pricing hub into a globally accepted pricing hub and U.S. differentials shrank

Supply increases ~475 MBbl/d

• ver the next 3 years to ~2,475 MBbl/d

C3+ supply growth from low cost basins: Appalachia (+59%) and Permian (+22%)

47

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

Propane and Butane: U.S. Supply Growth by Region

MID-CONTINENT NORTHEAST BAKKEN/ WILLISTON

31

PERMIAN ROCKIES

100 200 2014 2017 2020

Bakken Supply

100 200 300 2014 2017 2020

Rockies Supply

200 400 600 2014 2017 2020

Appalachia Supply

GULF COAST

200 400 2014 2017 2020

Mid Continent

2,000 2014 2017 2020

Permian and Gulf Coast Supply

Note: Bubbles reflect growth over the next five years (2017-2022). Supply includes field production and refinery production. Excludes imports. Source: U.S. Energy Information Administration and S&P Global Platts.

+13% 39 MBbl/d

+59% 165 MBbl/d

+29% 36 MBbl/d

+4% 9 MBbl/d

+22% 226 MBbl/d

200 400 600 800 1,000 1,200 1,400 1,600 2017E 2018E 2019E 2020E MBbl/d

48

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

Propane and Butane: U.S. Demand Growth by Sector

U.S. Propane & Butane Demand

Source: S&P Global Platts & U.S. Energy Information Administration

~145 MBbl/d of U.S. demand growth over the next 3 years

Petrochemical Residential/Commercial Refinery/Blending/Other

~60% of total demand growth driven by petrochemical demand

500 1,000 1,500 2,000 2,500 3,000 2017E 2018E 2019E 2020E MBbl/d

49

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

The Result? The Need for More LPG Exports

Source: S&P Global Platts & U.S. Energy Information Administration

Total U.S. Demand 2017 Exports

Growth in LPG waterborne exports needed to clear the U.S. NGL Market

U.S. Butane & Propane Supply vs. Demand

U.S. supply growth over 3 years exceeds domestic demand growth by ~365 Mbbl/d (including 35 MBbl/d of imports)

• 200

400 600 800 1,000 1,200 1,400 1,600 1,800 2012A 2013A 2014A 2015A 2016A 2017E 2018E 2019E 2020E

50

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

LPG Exports & Export Capacity – Then vs. Now

U.S. LPG Exports vs. Capacity (MBbl/d)

Source: S&P Global Platts & U.S. Energy Information Administration

Historically Export Constrained Sufficient Near-Term Capacity U.S. has excess NGL supply But is export constrained U.S. has excess NGL supply Sufficient export capacity

Now: Then:

Export Capacity @ 85% Utilization

LPG Shipping Fleet Continues to Support Global Trade

10 20 30 40 50 60 70 80 90 100 50 100 150 200 250 300 350 201220132014201520162017201820192020 Baltic Rate ($/ton) VLGC’s

Global VLGC Shipping Fleet vs. Baltic Rates

51

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

Source: Poten Partners

Current VLGC Fleet Confirmed New Builds

VLGC fleet continues to expand with ~50 new build VLGC orders through 2020

Global LPG Shipping Supply/Demand

50 100 150 200 250 VLCG’s Ship Supply Ship Demand

Ship capacity sufficient to support global LPG trade through 2020

Baltic Rates

52

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

U.S. Exports Displacing Middle East Exports

513 497 100 200 300 400 500 600 700 2013 2014 2015 2016 2017 October 2017 MBbl/d U.S. Middle East

Northeast Asia LPG Imports by Exporting Region Northeast Asia imported more U.S. LPG cargos than Middle East cargos for the first time ever in 2017 Middle East LPG cargos have remained flat due to strategy of keeping LPG purity products at home and OPEC

• il production cuts

U.S. Share: 51%

53

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

LPG: Significant Long Term Demand Growth

LPG Import Demand Growth by Region

• 500

1,000 2017 2020

India LPG Import Demand

• 500

1,000 2017 2020

China LPG Import Demand

• 500

1,000 2017 2020

Indonesia LPG Import Demand

• 500

1,000 2017 2020

Japan/S. Korea/Taiwan LPG Import Demand

(MBbl/d) (MBbl/d) (MBbl/d) (MBbl/d)

Asia accounts for ~70%

• f forecasted worldwide

LPG import demand growth through 2020

Source: S&P Global Platts.

Note: Import demand is shown net of domestic production (i.e. country supply/demand imbalance)

Global LPG import demand increases by ~415 MBbl/d from 2017 - 2020

LPG Import Growth (MBbl/d) 2017 - 2020

Total Asia/Pacific ~300 Europe/Mediterranean ~85 Latin America ~30 Total ~415

54

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

India and China: A Detailed Look at Demand

Source: Poten Partners and Dorian LPG

India  Aggressive government initiatives to replace wood and animal waste with propane in households relying on open fires  Last planned refinery startup (Paradip) marks last major domestic supply addition, in-turn supporting further future imports  Increased gasoline taxes have resulted in an uptick in LPG auto-gas demand  Non-subsidized market continues to grow and is price receptive China

HOME Travel Industrial Misc./ Other

 Demand growing with government initiatives to displace solid biofuels in rural areas  Build-out of PDH plants from 1 in 2013 to 15 by 2020 accounts for roughly half of total Chinese LPG growth  Upgrade of emissions standards similar to Europe and the U.S.  Processing plants using butane- rich LPG as feedstock

55

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

Global LPG Demand Growth Absorbs Supply Growth

Source: Poten Partners.

• 1,000

2,000 2017 2020

• N. America/Carib

(2,000) (1,000)

• 2017

2020

Latin America

• 1,000

2,000 2017 2020

Africa

• 1,000

2,000 2017 2020

Middle East

(2,000) (1,000)

• 2017

2020

Europe/Med

• 1,000

2,000 2017 2020

Russia

(2,500) (1,500) (500) 2017 2020

Asia Pacific

LPG Import/Export Growth by Region (MBbl/d)

Short LPG (-415) Long LPG +415

To Asia via Panama Canal

100 200 300 400 500 600 700

56

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

C3+ NGLs: Northeast Market Dynamics and Supply

Source: S&P Global Platts

Mariner East 1 70 MBbl/d Mariner East 2 275 MBbl/d – 2Q 2018 Mariner East 2X: 250 MBbl/d 1Q 2019

Midwest/ Conway U.S. Gulf Coast Export Markets

Cornerstone

Northeast C3+ NGL Takeaway

Propane Pentanes IsoButane Butane

~165 MBbl/d of Northeast C3+ demand vs. ~350 MBbl/d of Northeast supply in 2017

• Resulted in 47% of production consumed locally
• Remainder moved primarily by rail

Antero’s C3+ differential to Mt. Belvieu is expected to improve in 2018 with the Mariner East 2 export takeaway and ability to access international markets Northeast C3+ NGL Supply Mariner East II provides additional “baseload demand” and access to international LPG markets

100 200 300 400 500 600 700 800

57

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

C3+ NGLs: Northeast Supply & Demand

Northeast C3+ NGL Supply vs. Demand & Takeaway Capacity Excluding Rail (MBbl/d)

Source: S&P Global Platts

Northeast C3+ markets became oversupplied in 2015 and forced to ship via more expensive rail, which is relieved by Mariner East 2 and other potential projects

Local Demand & TEPPCO Mariner East 2 Mariner East 2 Expansions

Sufficient Pipeline Capacity = Tight Differentials Short Local Demand & Pipeline Capacity = Wide Differentials ~$(6.00)/Bbl vs. Mont Belvieu Long Local Demand and Pipeline Capacity = Tight Differentials ~$(2.00)/Bbl vs. Mont Belvieu Rail fills short term gaps

Cornerstone Mariner East 1

To Asia via Panama Canal

Marcus Hook U.S. Gulf Coast FEI NWE FEI

Antero Netback 2018 NWE Price ($/Gal) $0.97 Pipeline & Terminal (1) $(0.19) Shipping $(0.05) Netback $0.73 Uplift vs. $0.25/Gal Rail to Mt. Belvieu $0.13 Antero Netback 2018 FEI Price ($/Gal) $1.04 Pipeline & Terminal (1) $(0.19) Shipping $(0.14) Netback $0.71 Uplift vs. $0.25/Gal Rail to Mt. Belvieu $0.11

58

NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

LPG: Marcus Hook vs. U.S. Gulf Coast Shipping

LPG Shipping Routes and 2018 Propane Netbacks ($/Gallon)

Source: Poten Partners. Note: Based on Baltic forward shipping rates and propane strip prices as of 12/31/17. Includes associated port and canal fees and charges. (1) Based on Wall Street research.

Appalachia is geographically advantaged for Northwest Europe cargos and at parity with Gulf Coast for Asia destination cargos

2018 Guidance: Transition to Free Cash Flow & Low Leverage

MICHAEL KENNEDY

SVP of Finance & CFO, Antero Midstream

59

60

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | GUIDANCE

2018 Guidance Overview

2018 Guidance: Generating Free Cash Flow Stand-Alone E&P Consolidated

Adjusted EBITDAX(1)

$1,700 - $1,800 $2,050 - $2,150

• Interest Expense

($220) – ($200) ($300) – ($250)

Adjusted Operating Cash Flow (2)

$1,480 - $1,600 $1,750 - $1,900

• D&C CapEx & Land

Maintenance Expenditures

($1,525) N/A

Free Cash Flow Before Change in Working Capital & Land (at Midpoint)

$15 N/A

Note: See Appendix for definitions of non-GAAP terms. (1) Adjusted EBITDAX and Adjusted Operating Cash Flow are non-GAAP financial measures. For additional information regarding these measures, please see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix. (2) Before change in working capital.

Product Volumes (Guidance) Realized Price Revenues % of Total Volume 1,925 MMcf/d $2.85/Mcf $2.0B 52% 44 MBbl/d $10/Bbl $0.2B 5% 77.5 MBbl/d $39/Bbl $1.1B 28% 9.5 MBbl/d $54/Bbl $0.2B 5% N/A $0.45/Mcfe $0.4B 10% 2,700 MMcfe/d $4.00/Mcfe $3.9B 100%

61

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS

2018 Product Revenue Buildup

Natural Gas NGLs Crude

GAS C2 C3+ Oil

Hedges

$1.5B

Liquids Revenue

38%

Liquids as a Percent

• f Total Volume

43% | 38%

Pre- | Post- Hedge Liquids as Percent of Revenue

Note: See Appendix for key assumptions

62

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS

2018 Natural Gas Market Mix

Antero Firm Transportation Portfolio in 2018

10% of FT Portfolio $(0.53)/Mcf Differential

Local Markets Antero Producing Areas Index Differential % of Gas Sold TETCO M2 $(0.53) 10% Mid-Atlantic $(0.34) 6% TCO $(0.27) 16% Gulf Coast $(0.14) 41% Midwest $(0.13) 27% Weighted Average

• vs. NYMEX:

$(0.21) 100% BTU Uplift $0.24 All-in vs. NYMEX +$0.03

+$0.00 - $0.05

forecasted premium to NYMEX after BTU uplift

90% of Antero Gas Is Sold In Favorably Priced Markets

Note: Based on 2018 strip pricing as of 12/31/2017. See Appendix for further assumptions.

Well Hedged at High Prices Relative to Strip

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PRODUCTIVITY DRIVERS

2,141 2,330 1,418 710 850 90 $3.66 $3.50 $3.25 $3.00 $3.00 $2.91 $2.84 $2.81 $2.82 $2.85 $2.89 $2.93 $- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00

• 100

400 900 1,400 1,900 2,400 2018 2019 2020 2021 2022 2023

Average Index Hedge Price(1) Hedged Volume Current NYMEX Strip(2) Mark-to-Market Value(2)

(1) Weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio. Includes 19,000 Bbl/d of propane hedged at $0.75/gallon and 4,000 Bbl/d of oil hedged at $55.97/Bbl in 2018 (2) As of 12/31/17.

~ 100% of 2018 and 2019 Target Gas Production Hedged $450 MM $584 MM $225 MM $38 MM $35 MM $0 MM

Commodity Hedge Position ~$1.3B Mark-To-Market Unrealized Gains Based On 12/31/2017 Prices

2.8 Tcfe hedged through

2023 at $3.39/MMBtu

~19 MBbl/d of propane

hedged in 2018 at $0.75/Gal

$3.5B of gains on

hedges since 2008

63

64

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS

2018 C3+ NGL Pricing & Market Mix

Antero 2018 C3+ NGL Production Netbacks Antero projects C3+ NGL price to be ~62.5% to 67.5% of WTI in 2018

Note: Based on 2018 strip pricing as of 12/31/17. (1) Based on weighted average Antero C3+ NGL barrel composition times individual purity product price. (2) Uplift assumes strip NGL pricing for Northwest Europe and Far East Index before ME2 fees, which will be included in the GPT expense item.

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Antero C3+ NGL Barrel Composition

IsoButane (IC4) – 9% Butane (C4) – 16% Propane (C3) – 56% Pentane (C5) – 19%

Weighted Average C3+ $/Bbl Pre-ME2 Post-ME2 Realized Pricing Location Houston, PA Marcus Hook Dock Mont Belvieu Price(1) $41.00 $41.00 Differential/Uplift Net of Cost(2) $(5.50) +$2.00 Antero Realized C3+ Price $35.50 $43.00 % of WTI 60% 72% 2018 Weighted Average 62.5% - 67.5% of WTI 2018 Weighted Average ~$39/Barrel

65

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK

Significant Value Derived from Midstream Ownership

Antero Midstream Targeted Distributions to Antero Resources

Note: Represents distribution growth targets for AR owned units through 2022. As of 9/30/17, AR owns 98.9 million AM units.

$89 $112 $132 $- $50 $100 $150 $200 $250 $300 $350 $400 $450 2015A 2016A 2017A 2018E 2019E 2020E 2021E 2022E $ in MMs

$3.56 $1.34 $0.45 $0.11 $0.60 $0.55 $0.13 $0.15 $0.45 $0.17 $0.10 $0.10

$0.65

$4.18 $1.80

$0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50

Revenues, Hedges, AM Distributions LOE and Production Taxes Gathering & Compression Fees Processing & Fractionation Expenses Firm Transportation Expenses Net Marketing Expense Cash G&A Stand-alone E&P EBITDAX Margin

66

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | ATTRACTIVE MARGINS

2018 Stand-Alone E&P EBITDAX Margin

Stand-Alone E&P EBITDAX Margin Waterfall ($/Mcfe) $1.75B Stand- Alone E&P EBITDAX

= $1.80/Mcfe X 2.7 Bcfe/d of production

Hedges Revenues AM Distributions Gas FT Liquids FT Hedges

Fully Burdened Stand-alone gathering fees

$1,150 $2,756 $6,117 $795 $179 $311 $321 $250 $3,112

$0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000

AM IPO (2014) Sale of Water Business (2015) Sale of AM Units (2016) Sale of AM Units (9/6/17) AM Distributions Received as of 12/31/17 Total Proceeds to Date Expected Earnout Payments (2019E-2020E) Pre-tax Value

• f AM Units

Held by AR @ $31.75 (01/12/18) Pre-tax Cumulative Value of Antero Midstream

Cash Proceeds (SMM)

67

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | ATTRACTIVE MARGINS

Midstream Driving Value for AR Since Inception

Antero Midstream Return on Investment for AR (Pre-tax)(1) 4.7x ROI

Takeaway Assurance Return on Investment Downstream Visibility

(1) Midstream proceeds received by AR to date plus market value of AR’s 53% ownership of AM at 1/12/18 divided by the approximate $1.3B of AR capital invested at time of AM IPO.

68

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | LIQUIDS UPLIFT

Understanding Liquids Uplift and Processing Costs

Antero Processing Benefit vs. Cost

Note: Based on 2018 strip pricing as of 12/31/17.

$0.15 $0.75 $1.11 $0.19 $0.60 $0.10 $1.26 $1.45

$0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40 $1.60 NGL Uplift Oil Uplift Processing Cost Transportation Cost Net Gas Equivalent Price (Net of Liquids Transport)

Costs Benefits

Ethane C3+

$0.75 / Mcfe

Uplift from liquids production, net of processing and liquids transport fees

1250 BTU 2.75 GPM (Partial Ethane Recovery)

($/Mcfe)

($1.03) ($0.03) ($2.50) ($2.00) ($1.50) ($1.00) ($0.50) $0.00 $0.50

Appalachia (1) Antero Realized Differential (2) 3-Year Appalchian Average 3-Year Antero Realized Basis 69

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK

Price Certainty Gained from Firm Transportation

Natural Gas Price Differentials Relative to NYMEX

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

Floating – High Volatility Antero – Low Volatility

Price Certainty Limited Volatility Limited Northeast Pricing Exposure

$4.10 $2.37 $2.50 $3.18 $3.27 $1.47 $1.49 $2.24 $3.82 $1.80 $1.70 $2.39 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 2014 2015 2016 YTD 2017(2) AR Price Realization In-Basin Price(1) $3.82 $1.80 $1.70 $2.39

70

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK

Significant Value Derived from Firm Transportation

Natural Gas Price Realization Relative to Appalachia In-Basin Pricing

(1) Assumes Dominion South annual averages for Appalachia in-basin pricing. (2) YTD through September 2017, adjusted for contractual disputes on natural gas firm sales.

Realized price, net of all FT costs exceeds in- basin prices

$173MM $148MM $109MM $62MM

$491 MM

Total Value Created from FT Portfolio Since 2014 AR Prices Net of FT & Net Marketing Expense $/Mcf (Excluding Hedges)

71

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK

2018 Guidance: Understanding FT, Marketing & Hedge Benefits

$0.56 $0.45 $0.55 $0.13 $0.34 $2.29 $2.85 $3.30 $2.75 $2.63

$0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 Dominion South Strip Pricing Firm Transportation Pricing Uplift Hedge Gains Firm Transportation Cost Net Marketing Expense Net Uplift to Dominion South Strip Pricing $/Mcf

Costs Benefits

Firm Transportation $0.34/Mcfe Uplift

in Realized Gas Prices vs. Local Dominion South index(1)

Hedge Book

Note: Based on strip pricing as of 12/31/17.

$0.10/ Mcfe $0.15/ Mcfe < $0.10/ Mcfe $0 $0 $0.15/Mcfe $0.20/Mcfe $469 $0.45/Mcfe $585 $0.48/Mcfe $224 $0.15/Mcfe $37 $35 $0 $100 $200 $300 $400 $500 $600 2018 Guidance 2019 Target 2020 Target 2021 Target 2022 Target $ Millions Net Marketing Expense (High End) Net Marketing Expense (Low End) Hedge Gains

72

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK

Attractive Gas Marketing Plan

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

• ur 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: ($472) Net Uplift: $878

Hedge Portfolio Supports Firm Commitments

73

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PRODUCTIVITY

Understanding G&A: Most Productive Employees

$2.9 $1.7 $1.7 $1.5 $1.2 $1.0 $1.0 $0.9 $0.9 $0.8 $0.7 $0.5 $0.5 $1.0 $0.0 $0.5 $1.0 $1.5 $2.0 $2.5 $3.0 $3.5 AR A B C D E F G H I J K L Peer Average Peer Average

3.5 3.0 3.0 2.0 1.8 1.5 1.2 1.1 1.1 0.9 0.9 0.8 0.4 1.5 0.00 1.00 2.00 3.00 4.00 5.00 AR A B C D E F G H I J K L Production per Employee Peer Average

AR A B C D E F G H I J K L 528 241 576 762 467 1,469 1,080 1,809 856 994 850 1,085 3,604

2.3x

More Productive Employees Based on Daily Production

2.9x

More Productive Employees

• n an EBITDAX Basis

Production Per Employee (MMcfe/d)(1) EBITDAX Per Employee ($MM)

Note: Peer group includes: Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG Energy, RICE, RRC and SWN. (1) Based on 2016 actuals.

$1.38 $1.04 $1.22 $1.25 $0.82 $3.47 $2.79 $2.78 $2.24 $2.05 $2.09 $1.75 $1.56 $0.99 $1.23 $- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 AR A B C D ($/Mcfe) Adjusted EBITDAX GPT LOE Ad Valorem G&A Revenue Cash Costs 74

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | ATTRACTIVE MARGINS

Peer Leading Margins: Before NGL Price Uptick

3Q 2017 Stand-Alone E&P Adj. EBITDAX Margins (Pre-Hedge / Pre-Marketing Expense)(1)

Source: SEC filings and company press releases. AR margins exclude $0.21/Mcfe negative impact from WGL and SJR natural gas contract disputes. Peers include COG, EQT, RRC & SWN. (1) 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. (2) AR’s EBITDAX excludes net marketing expense and the hedges put in place to support firm transportation.

Margin Rank:

2 3 #1 4 5

$1.54 $1.11 $1.33 $1.27 $0.88 $3.76 $2.86 $2.87 $2.27 $2.13 $2.22 $1.75 $1.54 $1.00 $1.25 $(0.50) $- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 AR A B C D ($/Mcfe) Adjusted EBITDAX GPT LOE Ad Valorem G&A Net Marketing Revenue Cash Costs

Margin Rank:

3 4 #1 2 5

3Q 2017 Stand-Alone E&P Adj. EBITDAX Margins (Post-Hedge / Post Marketing Expense)(1)

75

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | ATTRACTIVE MARGINS

Attractive 2018 E&P Margins and Recycle Ratio

3.4x

Recycle Ratio(1)

2.7x Unhedged

Recycle Ratio(1)

Antero Fully Burdened Stand-Alone E&P Cash Margins ($/Mcfe)

Note: Assumes $0.17/Mcfe in distributions from AM. Based on EURs from Antero 2018 development program. (1) Represents stand-alone, fully burdened E&P basis, based on 2018 development program. Unhedged recycle ratio excludes net marketing expense of $0.125.

$1.34 $1.13 $0.47 $0.45 $0.21 $0.45 $1.80 $1.80 $1.59

$0.00 $0.50 $1.00 $1.50 $2.00 $2.50 Stand-Alone E&P EBITDAX Margin Interest expense Stand-Alone E&P Cash Margin 2018 F&D Cost Hedges Hedges

($/Mcfe)

$6,272 $5,628 $4,529 $1,077 $2,796 ~$1,300 $10,801 $6,928

$0 $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 Consolidated Enterprise Value Antero Midstream Net Debt After Tax Value of AM Owned Units AR Stand-alone E&P Value

76

2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | VALUE CREATION

Antero Consolidated and Stand-Alone Enterprise Value

Note: Data as of 9/30/17, except AM unit price as of 1/12/18 and hedge mark-to-market as of 12/31/17. See Appendix for further details on Antero trading multiples.

99MM units

• wned and AM

market price of $31.75/unit

Market Value Net Debt Hedge MTM E&P Assets

21% tax on value of AM units (net of NOLs)

($MM)

5-Year Outlook: Disciplined Growth Drives Equity Upside

GLEN WARREN

President & CFO

77

Financial Policy Overview

78

5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE

Fund drilling & completion capital with stand-alone upstream cash flow from operations (including AM distributions and earn-out payments from water business sale in 2015) Maintain conservative leverage profile below 3.0x near-term (on a stand-alone basis) with a medium-term target of below 2x

Free Cash Flow Leverage Hedge Program Liquidity Investment Grade Debt

Continue to hedge over a rolling five to six year period to support consistent production development into long-term processing and firm transportation commitments, smoothing volatile oil & gas prices Maintain stand-alone AR liquidity of at least ~$1B on a $2.5B credit facility Accelerate trend towards investment grade quality – current corporate ratings Ba2/BB/BBB-

Commodity Outlook

79

5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | 2018 OUTLOOK

Outlook Factors Natural Gas

Constructive Mid-Term, Positive Long-term

+ Strip weighed upon by wind power hedging and upstream acquisition hedging + Operators drilling up their best gas inventory in U.S.

• ver next several years

+ Strong demand growth – LNG, Mexico, coal displacement, petchem, etc.

• Associated gas growth from Permian

Oil

Positive

+ Solid global demand growth with aligned global economic growth + E&P capital discipline + OPEC / Russia production compliance

• Permian activity level

NGLs

Positive

+ Long-term Asian residential / commercial demand growth correlated to GDP growth + Flat to declining LPG exports from Mid-East + Export terminal buildouts continue + Some incremental LPG demand growth awaiting FID and not counted by research

• High growth in U.S. NGL supply from Permian and

Appalachia

Note: See Appendix for key definitions.

190 190 255 230 290 140 150 155 160 160 45 80 175 240 365 50 100 150 200 250 300 350 400

2018 2019 2020 2021 2022 January 2017 Plan January 2018 Plan (Low-End) Cumulative Well Count Reduction

Planned Antero Well Completions by Year (2018-2022)

Lateral Length Lateral Length 80

5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | CAPITAL DISCIPLINE

Looking to the Future: Disciplined Growth

Drilling & Completion Capital Budget and Targets 2018 – 2020 Targets 2021 – 2022 Targets

Consolidated Drilling & Completion ($MM) ~$1.3B Annually $1.4 - $1.7B Annually Stand-Alone Drilling & Completion ($MM) (1) ~$1.5 - $1.6B Annually $1.7 - $2.0B Annually % Production Growth Target 20% CAGR ~15% Growth Annually

365 Fewer Completions

than Previous Plan

$2.9B Cumulative Savings,

Same Production Targets

2,500’ Average Increase

in Lateral Length Per Well

(1) Includes full water fees paid to Antero Midstream for water handling and treatment services (fees are eliminated in consolidated financials).

9,100 9,700 9,000 10,500 8,600 11,600 9,200 8,500 12,700 12,400

150 160 165 170 170

January 2018 Plan (High-End)

Capital Budget Discipline

5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | CAPITAL DISCIPLINE

A Proven Track Record of Meeting D&C Capital Guidance

$0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 $2,000 2015 2016 2017 2018 2019 2020 2021 2022 Capital Spend ($MM) Initial Guidance Actual (4%) +2% +3%

Historical Consolidated D&C Capital Spend vs. Initial Guidance + 4% Within Initial

D&C Targets Set at Outset of the Year

81

Same Production Growth With Much Less Capital Spending

Consolidated Drilling & Completion Capital Expenditures Production Targets

2.7 3.3 4.0 4.6 5.2 2.7 3.3 3.9 4.5 5.2 0.0 1.0 2.0 3.0 4.0 5.0 6.0 2018 2019 2020 2021 2022 Bcfe/d As of December 2016 As of December 2017

82

5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | CAPITAL DISCIPLINE

$1.6 $1.7 $2.0 $2.2 $2.4 $1.3 $1.3 $1.3 $1.4 $1.7 $0.0 $0.5 $1.0 $1.5 $2.0 $2.5 2018 2019 2020 2021 2022 $ Billions As of December 2016 As of December 2017

22% CAGR in

Discretionary Cash Flow Per Share Through 2022

23% CAGR in

Debt-Adjusted Production Per Share Through 2022

Attractive Debt-Adjusted Production Driving Cash Flow

83

5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | SUSTAINABLE CASH FLOW GROWTH

Accelerating Debt-Adjusted Production Per Share Drives Cash Flow Per Share Growth

Note: Debt-adjusted production per share assumes Antero (AR) share price of $19.87, per 1/12/18 closing price.

$0.00 $2.00 $4.00 $6.00 $8.00 $10.00 0.0 1.0 2.0 3.0 4.0 5.0 6.0 2017E 2018 Guidance 2019 Target 2020 Target 2021 Target 2022 Target Discretionary Cash Flow Per Share Net Production per Debt-Adjusted Share (Mcfe/share) Production Per Share Cash Flow Per Share

Low Maintenance Capital: Key to FCF Generation

84

$2.9B maintenance (including land) $590 MM per year

Note: See Appendix for key assumptions and definitions.

$10.4B projected cash flow ~800 wells completed

Delivers $1.6B Projected Free Cash Flow Net of Maintenance and Growth Capital

$1.6B projected free cash flow

at YE 2017 Strip Pricing (~$55 Oil / $2.84 Gas)

$5.9B growth capex ~560 wells completed

5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | SUSTAINABLE CASH FLOW GROWTH

$0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 2018 2019 2020 2021 2022 $MM Maintenance Capex Growth Capex

Growth Capex Maintenance Capex

9/30/2017 Debt Maturity Profile

$1,000 $1,100 $750 $650 $600 $25 $427 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 2017 2018 2019 2020 2021 2022 2023 2024 2025

Liquidity & Debt Term Structure

85

5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | FINANCIAL PERFORMANCE & PRINCIPLES

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

(1) As of 1/12/18

AR 2025 Notes(1) Yielding 4.4% AM 2024 Notes(1) Yielding 4.4%

Positive Ratings Momentum

86

5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | ACCELERATED FOCUS TOWARDS INVESTMENT GRADE

Moody's S&P

Historical Corporate Credit Ratings

Corporate Credit Rating (Moody’s / S&P / Fitch)

Ba3 / BB- B1 / B+ B2 / B B3 / B-

2/24/2011 10/21/2013 9/4/2014 5/31/2013

Ba2 / BB Ba1 / BB+ Caa1 / CCC+ Baa3 / BBB-

3/31/2015

Ba2/BB Moody’s/S&P

12/31/2016 9/1/2010

Investment Grade Rating: BBB- Fitch January 2018

12/1/2017

Fitch

Stable through commodity price crash

Antero Has Enjoyed Positive Debt Ratings Momentum Since 2010

Key Takeaways

87

5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | VALUE PROPOSITION

Step Change in Capital Efficiency Reducing 5-Year D&C Capex by $2.9B Size & Scale to Capitalize on Resource Announcing New Long Lateral Development Plan Averaging 11,500’ Largest NGL Producer in U.S. With Highest Leverage to Rising NGL Prices

Sustainable Cash Flow Growth

Generating 5-Year Free Cash Flow of $1.6B at Strip & $2.8B at $60 Oil

Joining an Elite Group With: Scale Double Digit Growth Free Cash Flow Low Leverage

Disciplined Returns Focus

→28% Full Cycle Returns →23% 5-Year Debt-Adjusted Production CAGR per share →22% 5-Year Cash Flow CAGR per share

Note: See definitions for free cash flow and assumptions behind long-term targets in Appendix; free cash flow definition includes maintenance land spending, but excludes growth land spend.

Appendix I

Supplemental Materials

88

What Drives NGL Product Pricing?

89

APPENDIX I | SUPPLEMENTAL MATERIALS

Ethane (C2) Propane (C3) Butane (C4) IsoButane (IC4) Pentane (C5)

Primary Use

Ethylene Production Heating, Crop drying, Commercial Winter gasoline Blending Alkylate feed to produce gasoline Gasoline blend and diluent

Price Makers

Pet Chem facilities that can consume crude Flexible Pet Chem and exports Refineries/ Blenders, Pet Chem and exports Limited by Alkylate production Refineries

Price Takers

Ethane Only Pet Chem Heating fuel consumers Commercial users Refineries DilBit producers

Price Ceiling

Crude (Naptha derived ethylene production) Crude (via winter heating) Crude (via winter gasoline, Global LPG prices, propane) Crude Limited ceiling due to requiring Alkylate in RBOB Crude & Naptha

Price Floor

Natural Gas Price (Rejection) Ethane Price (Ethylene switching) Propane Price (Ethylene switching) Refined Products Price Gasoline & Refined products price

Gas Linked Crude Linked

90

APPENDIX I | ETHANE FUNDAMENTALS

Ethane: Northeast Market Dynamics & Supply

U.S Gulf Coast

NORTHEAST BAKKEN/WILLISTON

31

TEXAS & GULF COAST ROCKIES

West of Appalachia Appalachia

46 78 50 100 2012 2017 2022

Bakken Rejection

19 142 123 50 100 150 2012 2017 2022

Rockies Rejection

5 103 45 100 200 2012 2017 2022

Texas & Gulf Coast Rejection

1 158 294 100 200 300 2012 2017 2022

Appalachia Rejection

Source: S&P Global Platts and EnVantage

1 2 3 4 Ethane Rejection and Transportation Rates by Region

183 309 165 92 105 173 183 492 657 750 855 1,028

• 200

400 600 800 1,000 1,200 2017 2018 2019 2020 2021 2022+

91

APPENDIX I | ETHANE FUNDAMENTALS

Ethane: Significant Demand Growth On Horizon

Incremental U.S. Ethylene Plant Demand

MBbl/d of Ethane

“First Wave”

Ethylene crackers under construction will add

~855MBbl/d of ethane

demand by the end of 2021

“Second Wave”

Ethylene crackers under consideration in 2022+ with potential to add additional 173 MBbl/d

• f ethane demand

Over 1.0 MM

barrels per day of incremental ethane demand, including

~167 MBbl/d in the Northeast

100 200 300 400 500 600 700 800 92

APPENDIX I | ETHANE FUNDAMENTALS

Ethane: Northeast Market Dynamics & Supply

Antero’s Ethane Has a Natural Gas Value Pricing Floor; Pricing Improvements at Mont Belvieu and Additional Petrochemical or Takeaway Demand is All “Upside”

Source: S&P Global Platts

ATEX Mariner West Mariner East Utopia Actual Ethane Recovery Full Ethane Recovery Shell Cracker 0 40 103 128 177 270 357 390 390

100 200 300 400 500

Announced De-ethanization Capacity (MBbl/d)

Mariner East 70 MBbl/d Mariner East 2X: TBD MBbl/d 1Q19 Utopia East 75 MBbl/d 1Q18 Shell Cracker 105 MBbl/d

Mariner West 50 Mbbl/d

~190 MBbl/d of ethane current rejected in

Northeast (~48% of potentially recoverable ethane)

Northeast Ethane Takeaway and Capacities Northeast Ethane Supply (MBbl/d)

Antero is an anchor supplier to Shell’s cracker expected in 2021

ME2X

PTT evaluating a world scale cracker with expected FID 2018

Credit Facility Update: October 2017

93

APPENDIX I | CREDIT FACILITY UPDATE

Old Facility New Facility

Borrowing Base $4,750 MM $4,500 MM Commitments $4,000 MM $2,500 MM Maturity 5/5/2019 5 Years (2022) Security First-priority, perfected liens and security interests

• n substantially all assets including oil and gas

properties comprising no less than 80% of the total value of the Borrowing Base properties. Same as existing, until at least one of Moody’s or S&P assigns the Borrower a Senior Unsecured Rating > Baa3 or BBB-, at which time the Borrower may elect to enter into a “Release Period”, effectively going unsecured Pricing Borrowing Base Utilization Libor margin (bps) Commitment fee (bps) Borrowing Base Utilization Libor margin (bps) Commitment fee (bps) < 25% 150.0 37.5 < 25% 125.0 30.0 > 25%, < 50% 175.0 50.0 > 25%, < 50% 150.0 30.0 > 50%, < 75% 200.0 50.0 > 50%, < 75% 175.0 35.0 > 75%, < 90% 225.0 50.0 > 75%, < 90% 200.0 37.5 > 90% 250.0 50.0 > 90% 225.0 37.5 Covenants Below Investment Grade Period:

• Current Ratio of > 1.0x
• Interest Coverage Ratio of > 2.50x

Below Investment Grade Period:

• Current Ratio of > 1.0x
• Interest Coverage Ratio of > 2.50x

During Investment Grade Period:

• Current Ratio of > 1.0x
• Leverage Ratio of < 4.25x
• PV-9 / Total Debt > 1.50x (1)

Antero Recently Closed on a New Credit Facility That Reduced Commitments From $4.0B to $2.5B and Added Investment Grade Fall-Away Covenants

(1) Only applicable upon going unsecured with only one investment grade rating and until the second investment grade rating is achieved.

($MMs) Exploration & Production Gathering & Processing Water Handling & Treatment Marketing Elimination of Intersegment Transactions Consolidated Total Revenues: Third-Party $660 $7 $0 $51

• $718

Intersegment 1 98 93

• (191)
• Gains on settled derivatives

61

• 61

Total Revenue $722 $105 $93 $51 (191) $780 Cash operating expenses: Lease operating $24

• $52
• ($52)

$23 Gathering, Processing & Transp. (3rd party) 272

• 272

Gathering, Processing & Transp. (AM fees) 98 10

• (98)

10 Production Taxes 22 1

• 23

G&A (before equity-based comp) 29 4 3

• (0)

36 Marketing

• 79
• 79

Total Cash Operating Expenses $445 $15 $55 $79 ($150) $443 Segment Adjust EBITDAX $278 $90 $38 ($28) ($41) $336 Capital Expenditures: D&C (excluding water) $265

• $265

D&C (including water) 93

• (41)

52 Land / Acquisitions 57

• 57

G&C / Water Infrastructure

• 99

48 147 Total CapEx $415 $99 $48 $0 ($41) $522

3Q 2017 Segment EBITDAX & Capital Expenditures

94

APPENDIX I | SUPPLEMENTAL MATERIALS

1 2 Gathering and compression fees paid to Antero Midstream are included in Gathering, Processing & Transportation expense on stand-alone basis (eliminated on consolidated basis); Gathering and compression

• perating expenses borne by AM on stand-alone basis (included in GPT on consolidated basis)

Water fees paid to Antero Midstream included in Drilling & Completion capital expenditures on stand-alone basis; water operating expenses borne by AM on stand-alone basis and AR on consolidated basis

On consolidated basis, water fees are eliminated from D&C capital, but water operating expenses are capitalized Stand-Alone Adjusted EBITDAX : $284 Million(1) : $128 Million

(1) AR stand-alone EBITDAX represents E&P EBITDAX plus ~$35 million in distributions from AM ownership less net marketing expense.

Appendix II

Guidance Material & Cautionary Language

95

96

APPENDIX II | 2018

2018 Guidance

Stand-Alone E&P Consolidated

Net Daily Production (Bcfe/d) ~2.7 Net Liquids Production (BBl/d) ~130,000 Natural Gas Realized Price Differential to Nymex $0.00 to $0.05 Premium C3+ NGL Realized Price (% of Nymex WTI) 62.5% – 67.5% Cash Production Expense ($/Mcfe) $2.10 – $2.20 $1.65 – $1.75 Marketing Expense ($/Mcfe) (10% Mitigation Assumed) $0.10 – $0.15 G&A Expense ($/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) $1,500 $1,300 Land Capital Expenditures ($MM) $150 ($25MM Maintenance) $150 ($25MM Maintenance)

Note: See Appendix for key definitions. (1) Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes.

Highly Visible 2018 D&C Budget

97

APPENDIX II | GUIDANCE MATERIALS

Transparent Operating Plan and Expenditures Remove Uncertainty in D&C Budget

Drilling Marcellus Utica Total Rigs 5 1 6 Wells Spud 106 11 117 Average Lateral 10,046 11,855

10,216

Drilling Cost/1,000' of Lateral $0.28 $0.30 $0.28 Total Drilling Capex ($MM) $293 $38 $331 Completion Marcellus Utica Total Completion Crews 4 1 5 Wells Completed 120 25 145 Average Lateral 9,282 11,613

9,684

Completion Cost/1,000' of Lateral $0.60 $0.59 $0.59 Total Completion Capex ($MM) $663 $170 $833 D&C Capex Per 1,000' of Lateral $0.87 $0.88 $0.87 Preset wells, pad construction & other drilling maintenance ($MM) $130 Total D&C Capex Budget ($B) $956 MM $208 MM $1.3B

Maintenance Capital Drops with Longer Laterals

98

APPENDIX II | GUIDANCE MATERIALS

2018 Maintenance Capex at 9,000’ and 12,000’ Laterals

$613 $552 $0 $100 $200 $300 $400 $500 $600 $700 9,000 ft lateral 12,000 ft lateral Maintenance Capital ($MM) Marcellus Utica

Note: See Appendix for maintenance capital definition as well as further assumptions.

99

APPENDIX II | PRICING ASSUMPTIONS

Antero Long-Term Target Pricing Assumptions

Commodity prices: All forecasts reflect the following commodity price cases:

• Base case: Strip commodity pricing at 12/31/17 ($54.71 WTI crude oil & $2.84 Nymex Henry Hub) for 2018 - 2022
• Upside case: 12/31/17 Strip for 2018 and $60 WTI crude oil & $2.85 Nymex Henry Hub gas prices for 2019 - 2022
• Downside case: 12/31/17 Strip for 2018 $50 WTI crude oil & $2.85 Nymex Henry Hub gas prices for 2019 - 2022

Current Hedging Arrangements

• 80% Hedged on natural gas production through 2020 at $3.44/MMBtu and 52% hedged on natural gas production

through 2022 at $3.34/MMBtu

• 23% hedged on C3+ NGL production in 2018 at $0.75/gallon (Propane volume only)

Oil and Gas Strip Commodity Prices (12/31/17)

$59.62 $56.19 $53.76 $52.29 $51.67 $2.82 $2.81 $2.82 $2.85 $2.89 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $35.00 $40.00 $45.00 $50.00 $55.00 $60.00 $65.00 2018 2019 2020 2021 2022 WTI Nymex ($/Bbl) ($/MMBtu)

100

APPENDIX II | PROJECT ASSUMPTIONS

Antero Long-Term Target Project Assumptions

In-Service Date

Rover Phase 2 2Q 2018 (April 1) Mariner East 2 2Q 2018 WB Xpress West 4Q 2018 WB Xpress East 4Q 2018 Mountaineer Xpress / Gulf Xpress YE 2018

Note: Based on publicly available information.

101

APPENDIX II | 5-YEAR ASSUMPTIONS

Antero Guidance and Long-Term Target Assumptions

Stand-Alone E&P 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 $0.00 to $0.05 Premium (2018) $0.00 to $0.10 Premium (2019 – 2022) C3+ NGL Realized Price (% of Nymex WTI) 62.5% – 67.5% (2018) 72% (2019+) – ME2 Fees Booked to Transport Costs Realized Oil Price Differential to WTI ($5.00) – ($6.00) Cash Production Expense ($/Mcfe)(1) $2.10 - $2.20 (2018) $2.10 – $2.25 (2019 – 2022) $1.65 - $1.75 (2018) $1.65 – $1.75 (2019 – 2022) Marketing Expense ($/Mcfe) $0.10 - $0.15 (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

(1) Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes.

102

APPENDIX II | 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. (1) 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”). (2) Includes leasehold capital expenditures required to achieve targeted working interest percentage.

Single Well Economics: Marcellus – In Ethane Rejection

103

APPENDIX II | SINGLE WELL ECONOMICS

Classification Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

Modeled BTU 1313 1250 1150 1050 EUR (Bcfe): 32 29 26 24 EUR (MMBoe): 5.3 4.9 4.3 3.9 % Liquids: 33% 24% 11% 0% Well Cost ($MM): 10.6 10.6 10.6 10.6 Bcfe/1,000’: 2.7 2.5 2.2 2.0 Net F&D ($/Mcfe)(1): $0.40 $0.43 $0.49 $0.53 Net Direct Operating Expense ($/Mcfe): $1.26 $1.33 $1.39 $1.05 Transportation Expense ($/Mcfe): $0.04 $0.05 $0.06 $0.06 Pre-Tax NPV10 ($MM): 25.5 15.9 6.9 4.7 Pre-Tax ROR: 168% 74% 30% 23% Payout (Years): 1.1 1.7 3.1 4.0 Gross Core Locations in BTU Regime: 447 935 495 874

Cumulative Volumes Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas Gas (Mmcf) Oil (Mbbl) Gas (Mmcf) Oil (Mbbl) Gas (Mmcf) Oil (Mbbl) Gas (Mmcf) Oil (Mbbl)

Year 1 4,300 116 4,300 24 4,300 4,300 Year 2 6,500 143 6,500 31 6,500 6,500 Year 3 7,900 152 7,900 36 7,900 7,900 Year 4 9,100 157 9,100 40 9,100 9,100 Year 5 10,200 161 10,200 44 10,200 10,200 Year 10 13,900 176 13,900 57 13,900 13,900 Year 20 18,500 194 18,500 73 18,500 18,500

Note: SWE cost assumptions reflect average costs per Mcfe on the first five years of the life of a well 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. Please see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix.

Antero Assumptions: Single Well Economics

104

APPENDIX II | 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 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’ spacing

and $3,600 per acre None $655,000 per well Spud to FP Timing

• Provides a timeframe for initial spud to

first production 184 days spud to FP Realized Pricing

• Commodity price assumptions

12/31 strip pricing (weighted)

(1) SWEs exclude marketing expenses and related commodity hedge contracts that support Antero’s firm transportation portfolio

EUR Recoveries (25% Ethane Recovery)

105

APPENDIX II | EUR RECOVERIES

Note: EUR results include processed volumes and 25% ethane recovery. Includes well results completed with more than 1,500 pounds of proppant per foot. Well volumes based on 12,000’ lateral at 2.0 Bcf/1,000’ wellhead type curve by BTU regime mid-point.

1275 BTU+ 1200 – 1275 BTU 1100 – 1200 BTU < 1100 BTU Gas Equivalent 34.6 Bcfe 31.8 Bcfe 28.0 Bcfe 24.0 Bcfe Gas 21 Bcf 22 Bcf 23 Bcf 24 Bcf C3+ 1.5 MMBbls 1.1 MMBbls 0.5 MMBbls

• Oil

200 MBbls 90 MBbls

• C2

0.5 MMBbls 0.5 MMBbls 0.4 MMBbls

106

APPENDIX II | 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). Debt-Adjusted Shares: Represents ending period debt divided by ending share price plus ending shares outstanding. Forecasted debt-adjusted shares assumes AR share price of $19.87 per share as of January 12, 2018. F&D Cost: Represents current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 85% NRI in Marcellus and 81% NRI in Utica. There is no directly comparable financial measure presented in accordance with GAAP for F&D Cost and therefore, a reconciliation to GAAP is not practicable. Free Cash Flow: Represents Stand-alone E&P 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. Leverage Ratio: Represents ending period net debt (debt adjusted for cash and cash equivalents) divided by LTM Adjusted EBITDAX. Leverage ratios for future years reflect projected net debt divided by period Adjusted EBITDAX. Maintenance Capital: Represents stand-alone E&P Drilling & Completion Capital expenditures that are estimated to be necessary to sustain production at current (2017) production levels (2.3 Bcfe/d). Stand-Alone E&P 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 E&P 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

• ut 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).

107

APPENDIX II | DISCLOSURES & RECONCILIATIONS

Antero Non-GAAP Measures

Consolidated Adjusted EBITDAX, Stand-alone E&P Adjusted EBITDAX, Consolidated Adjusted Operating Cash Flow, Stand-alone E&P 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

• f Antero Midstream, which is otherwise consolidated into the results of Antero.

Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX The GAAP financial measure nearest to Consolidated Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero’s consolidated financial statements. The GAAP financial measure nearest to Stand-alone E&P 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 E&P 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

• ther 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 E&P 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 E&P Adjusted EBITDAX provide no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.

108

APPENDIX II | DISCLOSURES & RECONCILIATIONS

Antero Non-GAAP Measures

Antero has not included a reconciliation of Consolidated Adjusted EBITDAX or Stand-alone E&P 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 E&P

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 E&P 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

109

APPENDIX II | DISCLOSURES & RECONCILIATIONS

Antero Non-GAAP Measures

Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow The GAAP financial measure nearest to Consolidated Adjusted Operating Cash Flow is cash flow from operating activities as reported in Antero’s consolidated financial statements. The GAAP financial measure nearest to Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow is Stand-alone cash flow from operating activities that will be reported in the Parent column of Antero’s guarantor footnote to its financial statements. Management believes that Consolidated Adjusted Operating Cash Flow and Stand-alone E&P Adjusted Operating Cash Flow are useful indicators of the company’s ability to internally fund its activities and to service or incur additional debt on a consolidated and Stand-alone basis. Management believes that changes in current assets and liabilities, which are excluded from the calculation of these measures, relate to the timing of cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred and generally do not have a material impact on the ability of the company to fund its

• perations. Management believes that Free Cash Flow is a useful measure for assessing the company’s financial performance and

measuring its ability to generate excess cash from its operations. There are significant limitations to using Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company’s net income on a consolidated and Stand-alone E&P basis, the lack of comparability of results

• f operations of different companies and the different methods of calculating Consolidated Adjusted Operating Cash Flow and Stand-

alone E&P Adjusted Operating Cash Flow reported by different companies. Consolidated Adjusted Operating Cash Flow and Stand- alone E&P Adjusted Operating Cash Flow do not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and

• bligations.

Antero has not included reconciliations of Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow to their nearest GAAP financial measures for 2018 because it would be impractical to forecast changes in current assets and liabilities. However, Antero is able to forecast the earn out payments expected from Antero Midstream associated with the water drop down transaction that occurred in 2015, each of which is a reconciling item between Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow, as applicable, and cash flow from operating activities as reported in the Parent column of Antero’s guarantor footnote to its financial statements. Antero forecasts these items to be $125 million in each of 2019 and 2020. Additionally, Antero is able to forecast lease maintenance expenditures and Stand-alone drilling and completion capital, each of which is a reconciling item between Free Cash Flow and its most comparable GAAP financial measure. For the 2018 to 2022 period, Antero forecasts cumulative lease maintenance expenditures of $200 million and cumulative Stand-alone E&P drilling and completion capital of $8.6 billion.

Antero Resources Stand-Alone E&P Adjusted EBITDAX Reconciliation

110

APPENDIX II | DISCLOSURES & RECONCILIATIONS

AR Stand-Alone E&P Adjusted EBITDAX Reconciliation

($ in millions) Three Months Ended LTM Ended 09/30/2017 09/30/2017 Operating loss $(114.1) $(235.8) Commodity derivative fair value losses 66.0 181.3 Net cash receipts on settled derivatives instruments 61.5 326.9 Depreciation, depletion, amortization and accretion 176.9 720.1 Impairment of unproved properties and accretion 41.0 198.8 Exploration expense 1.6 9.1 Change in fair value of contingent acquisitions consideration (2.6) (15.8) Equity-based compensation expense 19.2 78.6 Gain on sale of assets

• (93.8)

AM distributions net to AR ownership 34.8 126.8 Segment E&P Adjusted EBITDAX $284.3 $1,296.2

Antero Resources Consolidated Adjusted EBITDAX Reconciliation

111

Consolidated Adjusted EBITDAX Reconciliation

($ in millions) Quarter Ended LTM Ended 9/30/2017 9/30/2017 Net income including noncontrolling interest $(90.0) $(197.3) Commodity derivative fair value gains 66.0 181.3 Net cash receipts on settled derivatives instruments 61.5 326.9 Gain of sale on assets

• (97.6)

Interest expense 70.1 273.2 Loss on early extinguishment of debt

• 16.9

Income tax expense (45.1) (160.5) Depreciation, depletion, amortization and accretion 207.6 835.3 Impairment of unproved properties 41.0 198.8 Exploration expense 1.6 9.1 Equity-based compensation expense 26.4 105.7 Equity in earnings of unconsolidated affiliate (7.0) (11.3) Distributions from unconsolidated affiliates 4.3 17.8 Consolidated Adjusted EBITDAX $336.4 $1,498.3

APPENDIX II | DISCLOSURES & RECONCILIATIONS

Antero Resources Adjusted EBITDAX Reconciliation (4Q 2017)

112

APPENDIX II | DISCLOSURES & RECONCILIATIONS

AR Consolidated and Stand-Alone E&P Adjusted EBITDAX Reconciliation

($MM) Three Months Ended December 31, 2017 Consolidated Stand-alone E&P Low High Low High Net income including noncontrolling interest (1) $ 525,000 — $ 560,000 $ 490,000 — $ 510,000 Commodity derivative (gains) losses (175,000) — (180,000) (175,000) — (180,000) Gains (losses) on settled derivative instruments 76,000 — 78,000 76,000 — 78,000 Interest expense 62,000 — 64,000 50,000 — 55,000 Loss on early extinguishment of debt 1,000 — 2,000 1,000 — 2,000 Provision (benefit) for income taxes (390,000) — (430,000) (390,000) — (430,000) Depreciation, depletion, amortization, and accretion 210,000 — 218,000 176,000 — 191,000 Impairment of unproved properties 70,000 — 77,000 70,000 — 77,000 Impairment of fixed assets and other 22,000 — 24,000 — — — Exploration expense 3,000 — 4,000 3,000 — 4,000 Gain on change in fair value of contingent acquisition consideration — — — (3,000) — (4,000) Equity-based compensation expense 23,000 — 25,000 17,000 — 20,000 Equity in earnings of unconsolidated affiliate (6,000) — (8,000) — — — Distributions from unconsolidated affiliates 9,000 — 11,000 — — — Equity in (income) loss of Antero Midstream — — — 22,000 — 28,000 Distributions from limited partner interest in Antero Midstream . — — — 33,000 — 34,000 Adjusted EBITDAX $ 430,000 $ 445,000 $ 370,000 $ 385,000

Cautionary Note

Regarding Hydrocarbon Quantities

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates (collectively, “3P”). Antero has provided internally generated estimates for proved, probable and possible reserves in this presentation in accordance with SEC guidelines and definitions. The estimates of proved, probable and possible reserves as of December 31, 2016 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates as of December 31, 2016 assume ethane rejection and strip pricing. Actual quantities that may be ultimately recovered from Antero’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of Antero’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. In this presentation:

• “3P reserves” refer to Antero’s estimated aggregate proved, probable and possible reserves as of December 31,
• 2016. The SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the

SEC due to the different levels of certainty associated with each reserve category.

• “EUR,” or “Estimated Ultimate Recovery,” refers to Antero’s internal estimates of per well hydrocarbon quantities

that may be potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules.

• “Condensate” refers to gas having a heat content between 1250 BTU and 1300 BTU in the Utica Shale.
• “Highly-Rich Gas/Condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the

Marcellus Shale and 1225 BTU and 1250 BTU in the Utica Shale.

• “Highly-Rich Gas” refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale

and 1200 BTU and 1225 BTU in the Utica Shale.

• “Rich Gas” refers to gas having a heat content of between 1100 BTU and 1200 BTU.
• “Dry Gas” refers to gas containing insufficient quantities of hydrocarbons heavier than methane to allow their

commercial extraction or to require their removal in order to render the gas suitable for fuel use.

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APPENDIX II | DISCLOSURES & RECONCILIATIONS