2018 Analyst Day JANUARY 18, 2018

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1 2018 Analyst Day JANUARY 18, 2018

2 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 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 of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in AR s Annual Report on Form 10-K for the year ended December 31, Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. This presentation 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 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. ANTERO RESOURCES 2018 ANALYST DAY

3 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 ANTERO RESOURCES 2018 ANALYST DAY 2

4 Antero Resources at a Glance Market Cap.... $6.3B Stand-Alone Enterprise Value Corporate Debt Ratings Stand-Alone Leverage. Net Production (4Q 2017) Liquids... 3P Reserves..... Net Acres.... AR Midstream Ownership. $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. ANTERO RESOURCES 2018 ANALYST DAY 3

5 Simplified Organizational Structure An $18B Family Valuation Sponsors (1) Public Sponsors (1) Public 27% 73% 68% 32% NYSE: AR Enterprise Value: $9.7B Corp Ratings: Ba2 / BB / BBB- 53% 100% Incentive Distribution Rights (IDRs) NYSE: AMGP Enterprise Value: $3.9B No Ratings Public 47% NYSE: AM Enterprise Value: $7.0B Corp Ratings: Ba2 / BB / BBB- Note: Enterprise value as of 1/12/18. (1) Sponsors represent Warburg Pincus, Yorktown & senior management. ANTERO RESOURCES 2018 ANALYST DAY 4

6 Co-Founders & Significant Owners Current Management Ownership CLR RSPP PE AR HES XEC COG NBL CXO PXD NFX EQT DVN FANG EOG OXY APA MRO APC COP ECA 1.7% 1.4% 1.2% 1.1% 1.0% 0.8% 0.7% 0.4% 0.4% 0.4% 0.3% 0.2% 0.2% 0.2% 0.1% 0.1% 9.0% 8.8% Management Owns ~$550 MM of Antero (AR) Stock 9% of Company Shares $400 MM More Than Peer Median 13.4% 13.1% U.S. E&Ps $6B Market Cap 78% 0% 2% 4% 6% 8% 10% 12% 14% 16% 18% 20% Senior Management is Well Aligned with Antero Shareholders Source: Bloomberg & Company Research ANTERO RESOURCES 2018 ANALYST DAY 5

7 Compensation Structure is Moving to Best Practices 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 Broad Compensation Plan Changes Further Align Management and AR Shareholders Note: Subject to compensation committee and final board approval. ANTERO RESOURCES 2018 ANALYST DAY 6

8 Value Proposition: High Return Portfolio & Free Cash Flow PAUL RADY & GLEN WARREN Co-Founders 7

9 Why Are We Here Today? Antero is at an Inflection Point Announcing New Long Lateral Development Plan Averaging 11,500 Step Change in Capital Efficiency Reduces 5-Year D&C Capex by $2.9B Largest NGL Producer in U.S. With Highest Leverage to Rising NGL Prices Size & Scale to Capitalize on Resource Sustainable Cash Flow Growth Generating 5-Year Free Cash Flow of $1.6B at YE Strip & $2.8B at $60 Oil Disciplined Returns Focus 28% Full Cycle Returns 23% 5-Year Debt-Adjusted Production CAGR per share 22% 5-Year Cash Flow CAGR per share Joining an Elite Group With: Scale Double Digit Growth Low Leverage Free Cash Flow 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. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW OVERVIEW 8

10 A Transformational History: From Ambition to Results Antero 1.0 A Shale Pioneer Antero 2.0 Scaling Up for Strong Growth Antero 3.0 Optimizing Development Program Antero 4.0 Disciplined Returns Focus 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 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 Dramatic drilling efficiencies Advanced completions Sustained development momentum through downturn Improved balance sheet 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 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW OVERVIEW 9

11 Core of the Core Acreage Position Antero Acreage Antero Marcellus Wells (1) Industry Marcellus Wells (1) Antero Marcellus Rig Industry Marcellus Rig Northern Rich High-Graded Core 2.24 Bcfe / 1,000 EURs 67% Undeveloped Southern Rich High-Graded Core 2.24 Bcfe / 1,000 EURs 70% Undeveloped AR Holds 61% of Undeveloped Dry Gas High-Graded Core 2.30 Bcf / 1,000 EURs 78% Undeveloped AR Holds 13% of Undeveloped Southwest Marcellus Core ~2.9 Million Acres 78% Undeveloped Southwest Marcellus Core Has Been High-Graded for Best Well Performance Note: Excludes 600,000 urban acres. 1) Wells completed with 1,300 lb/ft of proppant. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW SIZE & SCALE IN THE APPALACHIAN BASIN 10

12 Feet New Long Lateral Plan (No. of locations) 5-Year Plan Averages 11,500 Average Lateral Length per Completed Well 59% of Inventory Now 10,000 Lateral Length Core Inventory by Lateral Length 14,000 12,000 10,000 8,000 6,000 12,700 1,600 1,400 1,200 1, ,800 Average Inventory Lateral Length 1,450 4, , Wells Completed (1) <6,000' 6,000' - 8,000' 8,000' - 10,000' Feet 10,000' - 12,000' 12,000' 1) Wells completed reflects midpoint of targeted completions per year. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW SIZE & SCALE IN THE APPALACHIAN BASIN 11

13 Why Are We Growing? Outstanding Well Economics Single Well Economics Well Economics Support Investment 100% Full Cycle ROR: 28% Half Cycle ROR: 82% Full Cycle ROR at $60/Bbl Flat: 33% Half Cycle ROR at $60/Bbl Flat: 90% ROR Well in Excess of Cost of Capital 90% 80% Cash Cost Economics $60 Oil 70% 60% Strip Pricing 28% Corporate Level ROR 2018 & 2019 Full Cycle Returns 50% 40% 30% 20% AR Corporate Level Returns 10% WACC 8% 0% 2018 Completion Program 2019 Completion Program 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. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW ATTRACTIVE WELL ECONOMICS DRIVES GROWTH 12

14 $ Billions Almost $3B Capital Reduction to 5-Year Plan Bcfe/d Consolidated Drilling & Completion Capital Expenditures Production Targets As of December 2016 As of December 2017 As of December 2016 $2.5 $2.0 $1.5 $1.0 $0.5 $2.4 $2.2 $2.0 $1.7 $1.7 $1.6 $1.4 $1.3 $1.3 $1.3 $2.9B Capex Reduction Cumulative Reduction in Drilling & Completion Capital Same Production Targets 20% Production CAGR % Production CAGR As of December $ Same Production Growth With Much Less Capital Spending VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW ATTRACTIVE WELL ECONOMICS DRIVES GROWTH 13

15 New Development Plan $2.9B D&C Capex Savings D&C Capex Savings Capital Allocation Lateral Lengths Cycle Times & Enhanced Well Cost Savings Recoveries $0.4B Well Cost Savings $2.9B Capital Efficiencies Captured Within D&C Capex From New Development Program $0.5B Improved Cycle Times $1.1B Optimizing Capital Allocation Continued shift to highgraded Marcellus Related to reduced AFEs including lower flowback water handling cost due to Clearwater Facility $0.9B Lateral Lengths Reduced drilling days, increase in stages per day and concurrent operations $0.09MM/1,000 savings from 9,000 to 12,000 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW COST EFFICIENCY DRIVERS 14

16 Lower Capital & Higher Liquids Free Cash Flow Over $1.6B of Targeted Free Cash Flow from 2018 to 2022 at Strip Pricing Including Maintenance Land Capital Expenditures $1,500 $1,000 $500 Stand-Alone E&P Free Cash Flow Outspend We Are Here Stand-Alone Free Cash Flow: $60 Oil / $2.85 Gas Case Strip Pricing at 12/31/17 (Base Case) $50 Oil / $2.85 Gas Case 5-Year Cumulative Free Cash Flow $2.8B $1.6B $0 $1.0B ($500) ($1,000) ($1,500) 2014A 2015A 2016A 2017E 2018 Guidance 2019 Target 2020 Target 2021 Target 2022 Target 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. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW SUSTAINABLE CASH FLOW GROWTH 15

17 Significant Exposure to Higher Liquids Prices $2.8B in Free Cash Flow at $60/Bbl from $4.8B in Free Cash Flow at $70/Bbl from Annual Free Cash Flow Upside Aggregate 5-Year Free Cash Flow Upside $1,000 $900 $800 $700 $600 $500 $400 Strip Pricing at 12/31/17 $60 Oil / $2.85 Gas $3,000 $2,500 $2,000 $1,500 Strip Pricing at 12/31/17 $1.2B Strip Pricing $60 Oil / $2.85 Gas $60 Oil $300 $1,000 $200 $100 $500 $ Guidance 2019 Target 2020 Target 2021 Target 2022 Target $0 Crude Price Scenarios Not Just a Natural Gas Producer 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 (after ME2 in-service). ME2 fees included in transportation costs once in-service. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW 5-YEAR OUTLOOK 16

18 FCF Yield Attractive Free Cash Flow Yield 9% 8% 7% 6% AR 8% FCF Yield (1) Surpasses Industry Leading Peers, While Maintaining Strong Production Growth 5% 4% 3% 2% 1% 0% Free Cash Flow Yields Exceed Both Best-In-Class Peers & Integrated Oil & Gas Companies 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. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW 5-YEAR OUTLOOK 17

19 Shareholder Interests in Focus: 5-Year Cash Priorities Priorities for Cash Sustain Asset Base Disciplined Growth Investments Optionality Return of Capital Debt Reduction Land Acquisitions $10.4B Cumulative Stand-Alone E&P Adjusted Operating Cash Flow $5.9B D&C Growth Capital $1.6B Free Cash Flow for Deployment $0.2B Land Maintenance $2.7B D&C Maintenance Capital Significant Financial Flexibility with Cash Flow in Excess of Maintenance Capital 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. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW SUSTAINABLE CASH FLOW GROWTH 18

20 Cash Flow Growth Dramatic Delevering Stand-Alone Financial Leverage 12/31/17 Strip Pricing (Base Case) $60 Oil / $2.85 Gas $50 Oil / $2.85 Gas 5.0x 4.5x 4.0x 3.5x 3.9x 3.6x Leverage targets inclusive of $500 MM of maintenance and discretionary land capex from % Debt-Adjusted Production Growth Per Share 3.0x 2.5x 2.8x 2.8x Generates Free Cash Flow 2.0x 1.5x 1.0x 0.5x <2.0x by 2019 Net Debt / LTM Stand-Alone E&P Adjusted EBITDAX Balance Sheet Delevering & Optionality 0.0x 2014A 2015A 2016A 2017E Guidance Target 2020 Target 2021 Target 2022 Target 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. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW CASH FLOW DRIVES LOW LEVERAGE 19

21 Antero Profile To Drive Multiple Expansion # of Companies Median Debt/ Adjusted EBITDAX Median EV/ 2018 Adj. EBITDAX U.S. Publicly Traded E&Ps AR 2018E EBITDAX Multiple: 5.1x x 7.1x Leverage < 3.0x Premium for: Enterprise Value Scale > $10B x 7.8x x 8.9x Growth Production Growth >15% x 9.7x Low Leverage Leverage < 2.0x in x 11.1x FCF Generation Free Cash Flow in 2018 EOG CXO PXD FANG COG XEC Permian & Appalachia 6 1.3x 11.1x 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. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW ATTRACTIVE VALUATION 20

22 Scale & Growth: Liquids-Rich Resource Meets Capital Efficiency PAUL RADY Chairman & CEO & GLEN WARREN President & CFO 21

23 A Deep Understanding of the Appalachian Basin 10 NE Marcellus Rigs 22 Utica Rigs 68 Total Rigs 36 SW Marcellus Rigs K 7% C 13% Core Liquids-Rich Appalachia Undrilled Locations (1) D 7% I 7% B 5% H 3% A 13% J 2% F 3% AR 40% 40% of Core Undrilled Liquids-Rich Locations are Held by Antero 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. SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY UNDERSTANDING THE RESOURCE 22

24 Defining the Resource: Appalachia Basin Core Analysis 9,600 Wells Horizontal Wells Analyzed Since Basin Inception A deep database of peer information and analysis is maintained in house Acreage positions: developed and undeveloped Well locations, lateral lengths, completions & production results 7.8 MM Acres Acreage Analyzed by Antero Teams 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 27,000 Locations Future Locations Plotted on Antero Maps Geologists map structure, rock quality and pressure Core area maps reflect the collective work of our technical teams 30 Professionals Involved Team of Geologists, Reservoir Engineers, Land and GIS Geologists map core areas based on the well data provided by engineers Both productivity and well economics are factored into core outlines Cross-Functional Team Works Together to Define Core Boundaries and Competitor Positions In Basin SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY UNDERSTANDING THE RESOURCE 23

25 Undrilled Locations Who Has the Running Room? Undrilled Core Marcellus & Utica Locations (1) 4,000 Marcellus & Utica Liquids Rich Locations SW Marcellus & Utica Dry Locations NE Pennsylvania Dry Locations 3,500 3,000 2,500 2,000 3,295 2,333 1,930 Who Can Drill Long Laterals? Who Has the Running Room? We Have 40% of Liquids-Rich Locations Largest Inventory in Appalachia 1,500 1,259 1, Lateral Length: - AR A B C D E F G H I J 10,848 9,563 6,775 7,731 7,723 8,639 6,040 9,583 8,905 8,396 9,398 (1) Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG, RRC and SWN. SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY UNDERSTANDING THE RESOURCE 24

26 Core of the Core Antero Acreage Antero Marcellus Wells Industry Marcellus Wells Antero Marcellus Rig Industry Marcellus Rig > 1,300 lb/ft Completions 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 Dry Gas High-Graded Core ~1,051,000 acres 2.30 Bcf/1,000 Avg. Wellhead EUR 78% Undeveloped AR Holds 13% of Undeveloped High- Graded Core Areas Most Active Operators Percent Undeveloped Advanced Completions (>1,300 lbs/ft) Bcfe / 1,000 Wells Southwest Marcellus Core ~2.9 Million Acres ~78% Undeveloped Northern Rich RRC, CNX, HG 67% Southern Rich AR, EQT, SWN 70% Dry Gas EQT, CVX, RRC, CNX 78% Recently Expanded Core & High-Graded Core Reflecting Well Performance Note: Excludes 600,000 urban acres. EURs on ethane rejection basis. SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY UNDERSTANDING THE RESOURCE 25

27 Core of the Core Development Programs EUR Regime Marcellus BTU Range 2018 Well Completions 2019 Well Completions Half Cycle Well Economics (Strip Price) Total Undrilled Locations Average Lateral Length Highly-Rich Gas Condensate % ,500 Highly-Rich Gas % ,500 Rich Gas % ,150 Ohio Utica Condensate % 206 9,950 Rich Gas % ,550 Dry Gas % ,450 Total (1) Program Stats: 78% 86% Strip $60 Oil ROR Program Stats: 86% 93% Strip $60 Oil ROR High-Grade Inventory Totals: High-Grade Inventory Averages: 1,253 BTU Average 1,248 BTU Average 2,372 11,400 1) Wells completed reflects midpoint of targeted completions per year. SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY UNDERSTANDING THE RESOURCE 26

28 5-Year Core of the Core Program Highly-Rich Gas Condensate 1275 BTU+ Well Inventory: 447 Avg. Lateral Length: 12,522 Highly-Rich Gas BTU Well Inventory: 935 Avg. Lateral Length: 11,502 Rich Gas BTU Well Inventory: 495 Avg. Lateral Length: 11, Producing Wells 2.7 Bcfe/1,000 Average 14 Producing Wells 2.8 Bcfe/1,000 Average 15 Producing Wells 2.7 Bcfe/1,000 Average 5-Year Program Producing Wells Antero Marcellus Rig Antero Acreage 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. SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY UNDERSTANDING THE RESOURCE 27

29 A Pioneer in Drilling Longer Laterals in Appalachia Well Count Antero Historical & Future Lateral Length Program 300 Antero # of Wells Avg. Lateral Length Total Drilling Program to Date 945 8, Program (2) ,425 Wells to Date 10, , (1) All laterals rounded to the nearest thousand. (2) Represents wells placed to sales ,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 > 15,000 Lateral Length (1) SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY COST EFFICIENCY DRIVERS: LONGER LATERALS 28

30 Lateral Lengths Up 29% in 5-Year Plan Average Lateral Length (in feet) Average Lateral Length per Completed Well 14,000 12,000 10,000 8,000 9, Plan 2018 Plan 11,600 10,500 9,700 9,100 9,000 8,600 9,200 12,400 8,500 12,700 6,000 4,000 2, Lateral Lengths per Year Increasing by 2,500 in New Plan (1) Represents 2017 YTD average as of SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY COST EFFICIENCY DRIVERS: LONGER LATERALS 29

31 Longer Laterals Scale the Resource EUR (Bcfe) EURs by Marcellus Lateral Lengths 45 EUR in Bcfe/1,000' 2.3 Bcfe/1,000' R 2 = 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 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 Lateral Length (ft) Note: Assumes 25% ethane recovery. SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY COST EFFICIENCY DRIVERS: LONGER LATERALS 30

32 The Longer, the Better Single Well Economics by Lateral Lengths PV-10 ($MM) ROR (%) $25.0 $20.0 $ % 67% 74% $ % $ % 80% 60% $10.0 $ % $5.0 $6.8 20% $- 6,000' Lateral 9,000' Lateral 12,000' Lateral 15,000' Lateral 0% Note: Represents half cycle economics at strip pricing. See Appendix for further assumptions on single well economics. SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY COST EFFICIENCY DRIVERS: LONGER LATERALS 31

33 Well Costs Longer Laterals is the Next Step $MM/1,000 ft of lateral 41% Reduction $MM/1,000 ft of lateral 43% Reduction 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 $2.20 $2.00 $1.80 Marcellus $2.60 $2.40 $2.20 $2.00 Utica $1.60 $1.80 9% 10% Cost Benefit Marcellus Utica reduction in well cost per 1,000 lateral going from 9,000 to 12,000 laterals $1.40 $1.20 $1.00 $0.80 9% Reduction $0.60 3,000 6,000 9,000 12,00015,000 Lateral Length (ft) $1.60 $1.40 $1.20 $1.00 $ % Reduction $0.60 3,000 6,000 9,000 12,000 15,000 Lateral Length (ft) Note: Well costs reflect 2,000 pound per foot completions. See appendix for further assumptions. SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY COST EFFICIENCY DRIVERS: LONGER LATERALS 32

34 Drilling Days Reduced Cycle Times Lead to Lower Well Costs Stages per Day Drilling Days Completion Stages per Day Marcellus Utica 59% 34% Decline in Drilling Days in the Marcellus Utica 7.0 Marcellus Utica % 25% Improvement in Marcellus Utica Stages Per Day Record Record Drilling Longer Laterals with Dramatically Fewer Drilling Days and More Stages per Day SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY COST EFFICIENCY DRIVERS: CYCLE TIMES 33

35 Operating Evolution Continues % of Total Well Cost Savings Total Well Cost Savings in the Marcellus (1) Next Steps in D&C Evolution 42% Decline in well costs since % Vendor-related cost reductions 100% 90% 80% 70% 60% 50% 40% Drilling Vendor Reduction (3%) Completion Vendor Reduction (43%) Drilling Efficiency (25%) 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 30% Self-sourcing initiative reduce supply risk and cost 54% Permanent cost efficiencies 20% 10% 0% Completion Efficiency (29%) Fit-for-purpose rigs improves cycle times Enhanced walking and dual operation capabilities (1) Based on Marcellus 9,000 foot lateral and 2,000 pounds per foot AFE. Concurrent operations ( ConOps ) Plan to implement in 2019 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY OPERATING TECHNOLOGIES EVOLVE 34

36 Wells per Pad Feet Continuous Design Improvement in Operations Average Wells per Pad by Year Current Well Pads % increase in wells per pad Generation 1.0 Average Lateral Lengths by Year Map View 12 Well Pad Pad Size: 3-4 Acres 10,000 Pad Construction 9,000 8,000 Drilling 7,000 6,000 70% increase in lateral lengths Completion 5, Production Rig Wellheads SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY OPERATING TECHNOLOGIES EVOLVE 35

37 Concurrent Operations Boost Returns Rate of Return ConOps Concurrent vs. Batch (1) 110% Theoretical Best 100% 90% Concurrent Operations 80% 70% Batch Drill Then Complete 60% Wells per Pad ConOps: Improved Cycle Times Lift Returns (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. SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY OPERATING TECHNOLOGIES EVOLVE 36

38 Pad Designs Support Concurrent Operations New Pads Designed for ConOps Generation 2.0 Completions Fleet Operations Map View Pad Construction 200 Feet 12 Well Pad Pad Size: Approximately 7 Acres Drilling 1 st Six Wells Drilling 2 nd Six Wells Completion Production Completion Production Rig Wellheads Frac Fleet 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 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY OPERATING TECHNOLOGIES EVOLVE 37

39 Pounds of Proppant Per Foot Advanced Completions Drive EURs Higher Processed EUR per 1,000' of Lateral (Bcfe) 3,000 2,500 2,000 1,500 1,000 Proppant Per Foot Increasing EUR per 1,000 (1)(2) Marcellus 1,298 1,267 1,163 1,165 Utica 1,702 1,648 2,375 2,094 2,757 2,530 Higher Proppant per Foot has contributed to higher recoveries Marcellus EURs +33% Marcellus Utica Record Record Dramatically Improved Well Recoveries From Advanced Completions (1) Based on statistics for wells completed within each respective period. (2) Ethane rejection assumed for Ohio Utica and 25% ethane recovery assumed in for Marcellus. SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY COST EFFICIENCY DRIVERS: ENHANCED RECOVERIES 38

40 Result in Dramatically Lower F&D Cost F&D Cost per Mcfe (1)(2) $1.40 $1.20 $1.28 Marcellus Utica 52% 42% Lower F&D in Marcellus Utica $1.00 $0.88 $0.94 $0.80 $0.73 $0.73 $0.74 $0.60 $0.40 $0.51 $0.42 $0.20 $ Dramatic Improvement in Operating Efficiencies, Lower Service Costs and Higher Well Recoveries Have Driven F&D Costs Materially Lower (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. SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY COST EFFICIENCY DRIVERS: WELL COST REDUCTION 39

41 Natural Gas Liquids: Leading Position & Strong Fundamentals DAVID CANNELONGO Oil & NGL Marketing Manager 40

42 MBbl/d Largest NGL Producer in the U.S. NGL % of Product Revenues NGL Price Exposure Among Top NGL Producers Q17 Daily NGL Production Including Recovered Ethane NGL % of Product Revenues Pre-hedged Realized Price ($/Bbl) 45% % % 30% 34% of AR Q Revenue from NGLs 35% 30% 25% % % 12% 12% 12% 13% 11% 8% 7% $23.11 $16.93 $15.15 $31.07 $22.38 $20.72 $21.83 $18.96 $22.91 $22.99 AR RRC DVN APC EOG COP CHK PXD NBL OXY 15% 10% 5% 0% Antero Has The Highest NGL Price Exposure Among Top NGL Producers Pre-hedged Realized Price ($/Bbl) Source: SEC filings and company press releases. Note: Realized prices are weighted average including ethane (C2) where applicable. NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS LEADING THE WAY AS THE LARGEST U.S. NGL PRODUCER 41

43 Total (Bbl/d) Rapidly Growing NGL Production Antero NGL Production Growth by Purity Product 250,000 Natural Gasoline (C5+) Normal Butane (nc4) Ethane (C2) IsoButane (ic4) Propane (C3) C3+ Production 245, ,000 C2 150, ,000 C2 Ethane 26,500 C2 Ethane 44,000 C3 50,000 C2 Ethane 17,476 nc4 ic E Guidance 2019E Target 2020E Target 2021E Target C E Target Note: Excludes condensate. See Appendix for further assumptions around long-term targets. NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS LEADING THE WAY AS THE LARGEST U.S. NGL PRODUCER 42

44 MBbl/d Current Propane Market Fundamentals MBbl U.S. propane exports exceeded excess domestic supply in 2016 and 2017 Resulting in a material reduction in U.S. propane inventories U.S. Propane: Excess Supply vs. Net Exports U.S. Propane Inventories Excess Supply Net (Imports) / Exports 120, year Range In 2016 U.S. exports exceed excess supply by ~120MBbl/d 100,000 80, , ,000 20, inventory is 36% below 2016 inventory levels (100) Jan FebMar Apr May Jun Jul Aug Sep Oct Nov Dec NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS LPG FUNDAMENTALS 43

45 $/Gallon C3+ NGLs: Absolute & Relative Price Improvement % of WTI Mt. Belvieu C3+ Price Mont Belvieu C3+ to WTI Price Ratio $2.00 $1.80 $ % 90% 80% 72% of WTI $1.40 $1.20 $1.05/gal 70% 60% $ % $ % $ % $ % $ % $0.00 0% 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 Source: Intercontinental Exchange (ICE) pricing data. Assumes C3+ barrel weightings of: propane 56%, normal butane 16%, Isobutane 9%, pentanes 19%. NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS MARKET DYNAMICS 44

46 MBbl/d Significant Investment in LPG Infrastructure Vessels U.S. LPG Export Capacity Global VLGC Ship Fleet 1, , , In response to subdued domestic NGL prices and attractive arbitrage opportunities from , a significant investment was made in LPG export and shipping capacity Source: Poten Partners. S&P Global Platts. NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS LPG FUNDAMENTALS 45

47 $/Gallon The New Norm: Tighter U.S. Differentials to Global Prices $/Metric Ton Mont Belvieu vs. Far East Index Differential Baltic LPG Shipping Rates $ ($0.20) ($0.40) ($0.60) ($0.80) ($1.00) ($1.20) ($1.40) 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 Source: Intercontinental Exchange (ICE) pricing data. S&P Global Platts. NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS LPG FUNDAMENTALS 46

48 Propane and Butane: U.S. Supply Growth by Region C3+ supply growth from low cost basins: Appalachia (+59%) and Permian (+22%) Supply increases ~475 MBbl/d over the next 3 years to ~2,475 MBbl/d Bakken Supply +29% 36 MBbl/d BAKKEN/ WILLISTON Mid Continent Rockies Supply % 9 MBbl/d ROCKIES PERMIAN +22% 226 MBbl/d +13% 39 MBbl/d MID-CONTINENT 2, GULF COAST Permian and Gulf Coast Supply NORTHEAST % 165 MBbl/d Appalachia Supply Note: Bubbles reflect growth over the next five years ( ). Supply includes field production and refinery production. Excludes imports. Source: EIA and S&P Global Platts NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS MARKET DYNAMICS 47

49 Propane and Butane: U.S. Demand Growth by Sector MBbl/d U.S. Propane & Butane Demand 1,600 ~145 MBbl/d of U.S. demand growth over the next 3 years 1,400 1,200 1,000 Refinery/Blending/Other ~60% of total demand growth driven by petrochemical demand Residential/Commercial Petrochemical E 2018E 2019E 2020E Source: S&P Global Platts & U.S. Energy Information Administration NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS MARKET DYNAMICS 48

50 The Result? The Need for More LPG Exports MBbl/d 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) 3,000 2,500 2,000 Growth in LPG waterborne exports needed to clear the U.S. NGL Market 1,500 1, Exports Total U.S. Demand E 2018E 2019E 2020E Source: S&P Global Platts & U.S. Energy Information Administration NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS MARKET DYNAMICS 49

51 LPG Exports & Export Capacity Then vs. Now Then: U.S. has excess NGL supply But is export constrained Now: U.S. has excess NGL supply Sufficient export capacity U.S. LPG Exports vs. Capacity (MBbl/d) 1,800 1,600 Historically Export Constrained Sufficient Near-Term Capacity Potential for Export Capacity Expansions 1,400 1,200 1, Export 85% Utilization 2012A 2013A 2014A 2015A 2016A 2017E 2018E 2019E 2020E Source: S&P Global Platts & U.S. Energy Information Administration NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS LPG FUNDAMENTALS 50

52 VLGC s LPG Shipping Fleet Continues to Support Global Trade Baltic Rate ($/ton) VLCG s VLGC fleet continues to expand with ~50 new build VLGC orders through 2020 Ship capacity sufficient to support global LPG trade through 2020 Global VLGC Shipping Fleet vs. Baltic Rates Global LPG Shipping Supply/Demand Baltic Rates Ship Supply Ship Demand Current VLGC Fleet Confirmed New Builds Source: Poten Partners NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS LPG FUNDAMENTALS 51

53 U.S. Exports Displacing Middle East Exports MBbl/d 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 U.S. Middle East Middle East LPG cargos have remained flat due to strategy of keeping LPG purity products at home and OPEC oil production cuts October 2017 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS MARKET DYNAMICS 52

54 LPG: Significant Long Term Demand Growth LPG Import Demand Growth by Region Global LPG import demand increases by ~415 MBbl/d from (MBbl/d) 1, China LPG Import Demand (MBbl/d) 1, Japan/S. Korea/Taiwan LPG Import Demand Asia accounts for ~70% of forecasted worldwide LPG import demand growth through LPG Import Growth (MBbl/d) Total Asia/Pacific ~300 (MBbl/d) 1,000 India LPG Import Demand (MBbl/d) 1,000 Indonesia LPG Import Demand Europe/Mediterranean ~85 Latin America ~30 Total ~ Source: S&P Global Platts. Note: Import demand is shown net of domestic production (i.e. country supply/demand imbalance) NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS LPG FUNDAMENTALS 53

55 India and China: A Detailed Look at Demand HOME India Aggressive government initiatives to replace wood and animal waste with propane in households relying on open fires China Demand growing with government initiatives to displace solid biofuels in rural areas Industrial Last planned refinery startup (Paradip) marks last major domestic supply addition, in-turn supporting further future imports Build-out of PDH plants from 1 in 2013 to 15 by 2020 accounts for roughly half of total Chinese LPG growth Travel Increased gasoline taxes have resulted in an uptick in LPG auto-gas demand Upgrade of emissions standards similar to Europe and the U.S. Misc./ Other Non-subsidized market continues to grow and is price receptive Processing plants using butanerich LPG as feedstock Source: Poten Partners and Dorian LPG NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS LPG FUNDAMENTALS 54

56 Global LPG Demand Growth Absorbs Supply Growth LPG Import/Export Growth by Region (MBbl/d) N. America/Carib - (1,000) Europe/Med ,000 1,000 Russia 2,000 1,000 (2,000) To Asia via Panama Canal ,000 1,000 - Middle East (500) (1,500) (2,500) Asia Pacific Latin America ,000 1,000 Africa (1,000) (2,000) Source: Poten Partners. Long LPG +415 Short LPG (-415) NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS LPG FUNDAMENTALS 55

57 C3+ NGLs: Northeast Market Dynamics and Supply ~165 MBbl/d of Northeast C3+ demand vs. ~350 MBbl/d of Northeast supply in Resulted in 47% of production consumed locally - Remainder moved primarily by rail Mariner East II provides additional baseload demand and access to international LPG markets Northeast C3+ NGL Supply Midwest/ Conway Northeast C3+ NGL Takeaway Cornerstone Mariner East 1 70 MBbl/d Mariner East MBbl/d 2Q 2018 Mariner East 2X: 250 MBbl/d 1Q 2019 Export Markets Pentanes IsoButane Butane Propane U.S. Gulf Coast 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 Source: S&P Global Platts NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS MARKET DYNAMICS 56

58 C3+ NGLs: Northeast Supply & Demand Northeast C3+ NGL Supply vs. Demand & Takeaway Capacity Excluding Rail (MBbl/d) Long Local Demand and Pipeline Capacity = Tight Differentials ~$(2.00)/Bbl vs. Mont Belvieu Short Local Demand & Pipeline Capacity = Wide Differentials ~$(6.00)/Bbl vs. Mont Belvieu Sufficient Pipeline Capacity = Tight Differentials Mariner East 2 Expansions Rail fills short term gaps Mariner East 2 Cornerstone 200 Mariner East Local Demand & TEPPCO 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 Source: S&P Global Platts NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS MARKET DYNAMICS 57

59 LPG: Marcus Hook vs. U.S. Gulf Coast Shipping Appalachia is geographically advantaged for Northwest Europe cargos and at parity with Gulf Coast for Asia destination cargos LPG Shipping Routes and 2018 Propane Netbacks ($/Gallon) U.S. Gulf Coast Marcus Hook NWE Antero Netback 2018 NWE Price ($/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 FEI FEI To Asia via Panama Canal 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. NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS LPG FUNDAMENTALS 58

60 2018 Guidance: Transition to Free Cash Flow & Low Leverage MICHAEL KENNEDY SVP of Finance & CFO, Antero Midstream 59

61 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 Free Cash Flow Before Change in Working Capital & Land (at Midpoint) ($1,525) N/A $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 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE GUIDANCE 60

62 2018 Product Revenue Buildup 38% Liquids as a Percent of Total Volume $1.5B Liquids Revenue Natural Gas NGLs Crude Product GAS C2 C3+ Oil Volumes (Guidance) 1,925 MMcf/d Realized Price Revenues % of Total Volume $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% 43% 38% Pre- Post- Hedge Liquids as Percent of Revenue Hedges N/A $0.45/Mcfe $0.4B 10% 2,700 MMcfe/d $4.00/Mcfe $3.9B 100% Note: See Appendix for key assumptions 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE PROFITABILITY DRIVERS 61

63 2018 Natural Gas Market Mix Antero Firm Transportation Portfolio in 2018 Antero Producing Areas Local Markets 10% of FT Portfolio $(0.53)/Mcf Differential 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: BTU Uplift $0.24 All-in vs. NYMEX +$0.03 $(0.21) 100% +$ $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 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE PROFITABILITY DRIVERS 62

64 Well Hedged at High Prices Relative to Strip Commodity Hedge Position Hedged Volume Average Index Hedge Price (1) Current NYMEX Strip (2) Mark-to-Market Value (2) 2,400 1,900 1, ,141 $3.66 2,330 $3.50 $3.5B of gains on hedges since 2008 $3.25 1,418 $3.00 $ Tcfe hedged through 2023 at $3.39/MMBtu ~19 MBbl/d of propane hedged in 2018 at $0.75/Gal 850 $2.91 $2.84 $2.81 $2.82 $2.85 $2.89 $2.93 $450 MM $584 MM $225 MM $38 MM $35 MM $0 MM 90 $5.00 $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $ ~ 100% of 2018 and 2019 Target Gas Production Hedged ~$1.3B Mark-To-Market Unrealized Gains Based On 12/31/2017 Prices (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. $ GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE PRODUCTIVITY DRIVERS 63

65 2018 C3+ NGL Pricing & Market Mix Antero 2018 C3+ NGL Production Netbacks 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Propane (C3) 56% Butane (C4) 16% IsoButane (IC4) 9% Pentane (C5) 19% Antero C3+ NGL Barrel Composition 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% % of WTI 2018 Weighted Average ~$39/Barrel 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 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE PROFITABILITY DRIVERS 64

66 Significant Value Derived from Midstream Ownership $ in MMs Antero Midstream Targeted Distributions to Antero Resources $450 $400 $350 $300 $250 $200 $150 $100 $89 $112 $132 $50 $- 2015A 2016A 2017A 2018E 2019E 2020E 2021E 2022E Note: Represents distribution growth targets for AR owned units through As of 9/30/17, AR owns 98.9 million AM units GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE FIRM TRANSPORTATION & HEDGE BOOK 65

67 2018 Stand-Alone E&P EBITDAX Margin Stand-Alone E&P EBITDAX Margin Waterfall ($/Mcfe) $4.50 $4.00 $3.50 $3.00 $2.50 AM Distributions $4.18 $0.17 $0.10 $0.11 $0.45 Hedges Revenues $0.65 Fully Burdened Stand-alone gathering fees $0.60 $0.10 $0.55 Liquids FT Gas FT $1.75B Stand- Alone E&P EBITDAX = $1.80/Mcfe X 2.7 Bcfe/d of production $2.00 $1.50 $3.56 $0.13 $0.15 $1.80 $0.45 Hedges $1.00 $0.50 $1.34 $0.00 Revenues, Hedges, AM Distributions LOE and Production Taxes Gathering & Compression Fees Processing & Fractionation Expenses Firm Net Marketing Transportation Expense Expenses Cash G&A Stand-alone E&P EBITDAX Margin 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE ATTRACTIVE MARGINS 66

68 Midstream Driving Value for AR Since Inception Cash Proceeds (SMM) Antero Midstream Return on Investment for AR (Pre-tax) (1) $7,000 $6,000 $5,000 $3,112 $6, x ROI $4,000 $3,000 $2,000 $1,000 $1,150 $795 $179 $311 $321 $2,756 $250 $0 AM IPO (2014) Sale of Water Business (2015) Sale of AM Units (2016) Sale of AM Units (9/6/17) AM Total Proceeds Distributions to Date Received as of 12/31/17 Expected Earnout Payments (2019E-2020E) Pre-tax Value of AM Units Held by $31.75 (01/12/18) Pre-tax Cumulative Value of Antero Midstream Takeaway Assurance Downstream Visibility Return on Investment (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 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE ATTRACTIVE MARGINS 67

69 Understanding Liquids Uplift and Processing Costs Antero Processing Benefit vs. Cost ($/Mcfe) $1.60 $1.40 $ BTU 2.75 GPM (Partial Ethane Recovery) $1.26 C3+ Benefits $1.45 $0.19 $0.60 Costs $0.75 / Mcfe Uplift from liquids production, net of processing and liquids transport fees $1.00 $0.80 $0.60 $0.10 $1.11 $0.75 $0.40 $0.20 $0.00 Ethane $0.15 NGL Uplift Oil Uplift Processing Cost Transportation Cost Net Gas Equivalent Price (Net of Liquids Transport) Note: Based on 2018 strip pricing as of 12/31/ GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE LIQUIDS UPLIFT 68

70 Price Certainty Gained from Firm Transportation Natural Gas Price Differentials Relative to NYMEX $0.50 Appalachia (1) Antero Realized Differential (2) 3-Year Appalchian Average 3-Year Antero Realized Basis Price Certainty $0.00 Antero Low Volatility ($0.03) ($0.50) Limited Northeast Pricing Exposure ($1.00) ($1.50) ($1.03) ($2.00) Floating High Volatility Limited Volatility ($2.50) (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 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE FIRM TRANSPORTATION & HEDGE BOOK 69

71 $/Mcf Significant Value Derived from Firm Transportation Natural Gas Price Realization Relative to Appalachia In-Basin Pricing $4.50 $4.00 $3.50 $3.00 $4.10 $3.82 $3.82 AR Price Realization (Excluding Hedges) $3.27 Realized price, net of all FT costs exceeds inbasin prices In-Basin Price(1) $491 MM Total Value Created from FT Portfolio Since 2014 AR Prices Net of FT & Net Marketing Expense $3.18 $2.50 $2.00 $1.50 $2.37 $1.80 $1.80 $2.50 $1.70 $1.47 $1.49 $2.39 $2.24 $1.00 $0.50 $0.00 $173MM $148MM $109MM $62MM YTD 2017(2) (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 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE FIRM TRANSPORTATION & HEDGE BOOK 70

72 $/Mcf 2018 Guidance: Understanding FT, Marketing & Hedge Benefits Firm Transportation Hedge Book $0.34/Mcfe Uplift in Realized Gas Prices vs. Local Dominion South index (1) $3.50 Benefits $3.30 Costs $3.00 $2.50 $2.85 $0.45 $0.55 $2.75 $2.63 $0.13 $2.29 $0.56 $0.34 $2.00 $1.50 $1.00 $0.50 $0.00 Dominion South Strip Pricing Firm Transportation Pricing Uplift Hedge Gains Firm Transportation Cost Net Marketing Expense Net Uplift to Dominion South Strip Pricing Note: Based on strip pricing as of 12/31/ GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE FIRM TRANSPORTATION & HEDGE BOOK 71

73 $ Millions Attractive Gas Marketing Plan $600 $585 $0.48/Mcfe Net Marketing Expense (High End) Net Marketing Expense (Low End) Hedge Gains Hedge Portfolio Supports Firm Commitments $500 $400 $469 $0.45/Mcfe 5-Year Cumulative: Hedge Gains: $1,350 Marketing Expense: ($472) Net Uplift: $878 Firm Transportation Portfolio Allows Antero to achieve: $300 $200 $100 $0 $0.15/Mcfe $0.10/ Mcfe 2018 Guidance $0.20/Mcfe $0.15/ Mcfe < $0.10/ Mcfe $224 $0.15/Mcfe $37 $35 $0 $ Target 2020 Target 2021 Target 2022 Target Premium Price Certainty Less volatility and greater surety in realized prices Effectively Hedge NYMEX Index A key advantage as our product is delivered to NYMEXrelated markets Hedge Gains More than Offset Marketing Expense Hedges Support FT Commitments 2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE FIRM TRANSPORTATION & HEDGE BOOK 72

74 Understanding G&A: Most Productive Employees Production Per Employee (MMcfe/d) (1) 2.3x More Productive Employees Based on Daily Production Production per Employee Peer Average AR A B C D E F G H I J K L ,469 1,080 1, ,085 3, AR A B C D E F G H I J K L x More Productive Employees on an EBITDAX Basis $3.5 $3.0 $2.5 $2.0 $1.5 $1.0 $0.5 $0.0 $2.9 EBITDAX Per Employee ($MM) Peer Average $1.7 $1.7 $1.5 $1.2 Peer Average $1.0 $1.0 $0.9 $0.9 $1.0 $0.8 $0.7 $0.5 $0.5 AR A B C D E F G H I J K L Note: Peer group includes: Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG Energy, RICE, RRC and SWN. (1) Based on 2016 actuals GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE PRODUCTIVITY 73

75 ($/Mcfe) ($/Mcfe) Peer Leading Margins: Before NGL Price Uptick $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $- 3Q 2017 Stand-Alone E&P Adj. EBITDAX Margins (Pre-Hedge / Pre-Marketing Expense) (1) Margin Rank: # $3.47 $1.38 $2.09 $1.75 $2.79 $2.78 $1.56 $2.24 $1.04 $1.22 $1.25 $2.05 $0.99 $1.23 AR A B C D Adjusted EBITDAX GPT LOE Ad Valorem G&A Revenue Cash Costs $0.82 3Q 2017 Stand-Alone E&P Adj. EBITDAX Margins (Post-Hedge / Post Marketing Expense) (1) Margin Rank: # $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $- $(0.50) $3.76 $1.54 $2.86 $2.87 $2.22 $1.75 $1.11 $1.33 $1.27 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. $1.54 $2.27 $1.00 AR A B C D Adjusted EBITDAX GPT LOE Ad Valorem G&A Net Marketing Revenue Cash Costs $2.13 $0.88 $ GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE ATTRACTIVE MARGINS 74

76 Attractive 2018 E&P Margins and Recycle Ratio Antero Fully Burdened Stand-Alone E&P Cash Margins ($/Mcfe) 3.4x Recycle Ratio (1) ($/Mcfe) $2.50 $2.00 $1.50 $1.00 $1.80 $1.80 $0.45 $0.21 Hedges $1.59 $0.45 Hedges 2.7x Unhedged Recycle Ratio (1) $0.50 $1.34 $1.13 $0.47 $0.00 Stand-Alone E&P EBITDAX Margin Interest expense Stand-Alone E&P Cash Margin 2018 F&D Cost 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 $ GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE ATTRACTIVE MARGINS 75

77 Antero Consolidated and Stand-Alone Enterprise Value ($MM) $12,000 $10,801 $10,000 $1,077 $8,000 Net Debt $4,529 $2,796 $6,928 $6,000 $4,000 $2,000 Market Value $6,272 21% tax on value of AM units (net of NOLs) 99MM units owned and AM market price of $31.75/unit ~$1,300 Hedge MTM E&P Assets $5,628 $0 Consolidated Enterprise Value Antero Midstream Net Debt After Tax Value of AM Owned Units AR Stand-alone E&P Value Note: Data as of 9/30/17, except AM unit price as of 1/12/18 and hedge mark-to-market as of 12/31/18. See Appendix for further details on Antero trading multiples GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE VALUE CREATION 76

78 5-Year Outlook: Disciplined Growth Drives Equity Upside GLEN WARREN President & CFO 77

79 Financial Policy Overview Free Cash Flow 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) Leverage Maintain conservative leverage profile below 3.0x near-term (on a stand-alone basis) with a medium-term target of below 2x Hedge Program 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 Liquidity Maintain stand-alone AR liquidity of at least ~$1B on a $2.5B credit facility Investment Grade Debt Accelerate trend towards investment grade quality current corporate ratings Ba2/BB/BBB- 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE 78

80 Commodity Outlook Outlook Factors Natural Gas Oil NGLs Constructive Mid-Term, Positive Long-term Positive Positive + Strip weighed upon by wind power hedging and upstream acquisition hedging + Operators drilling up their best gas inventory in U.S. over next several years + Strong demand growth LNG, Mexico, coal displacement, petchem, etc. - Associated gas growth from Permian + Solid global demand growth with aligned global economic growth + E&P capital discipline + OPEC / Russia production compliance - Permian activity level + 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. 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE 2018 OUTLOOK 79

81 Looking to the Future: Disciplined Growth 2,500 Average Increase in Lateral Length Per Well 365 Fewer Completions than Previous Plan $2.9B Cumulative Savings, Same Production Targets January 2017 Plan 45 Planned Antero Well Completions by Year ( ) Cumulative Well Count Reduction January 2018 Plan (Low-End) January 2018 Plan (High-End) Lateral Length Lateral Length ,100 9,700 9,000 10,500 8,600 11,600 9,200 12,400 8,500 12,700 Drilling & Completion Capital Budget and Targets Targets Targets Consolidated Drilling & Completion ($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 (1) Includes full water fees paid to Antero Midstream for water handling and treatment services (fees are eliminated in consolidated financials). 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE CAPITAL DISCIPLINE 80

82 Capital Budget Discipline Capital Spend ($MM) Historical Consolidated D&C Capital Spend vs. Initial Guidance $2,000 Initial Guidance Actual $1,800 $1,600 +3% + 4% Within Initial D&C Targets Set at Outset of the Year $1,400 +2% (4%) $1,200 $1,000 $800 $600 $400 $200 $ A Proven Track Record of Meeting D&C Capital Guidance 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE CAPITAL DISCIPLINE 81

83 Same Production Growth With Much Less Capital Spending $ Billions Bcfe/d Consolidated Drilling & Completion Capital Expenditures Production Targets As of December 2016 As of December 2017 As of December 2016 As of December 2017 $2.5 $2.0 $1.5 $1.6 $2.2 $2.0 $1.7 $1.3 $1.3 $1.3 $1.4 $2.4 $ $ $ $ YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE CAPITAL DISCIPLINE 82

84 Attractive Debt-Adjusted Production Driving Cash Flow Net Production per Debt-Adjusted Share (Mcfe/share) Discretionary Cash Flow Per Share % CAGR in Debt-Adjusted Production Per Share Through % CAGR in Discretionary Cash Flow Per Share Through 2022 $ $ $ $ $ E 2018 Guidance 2019 Target Production Per Share 2020 Target 2021 Target Cash Flow Per Share 2022 Target Accelerating Debt-Adjusted Production Per Share Drives Cash Flow Per Share Growth $0.00 Note: Debt-adjusted production per share assumes Antero (AR) share price of $19.87, per 1/12/18 closing price. 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE SUSTAINABLE CASH FLOW GROWTH 83

85 Low Maintenance Capital: Key to FCF Generation $MM $10.4B projected cash flow ~800 wells completed $3,000 $2,500 Maintenance Capex Growth Capex $5.9B growth capex ~560 wells completed $2,000 $1,500 $2.9B maintenance (including land) $590 MM per year $1,000 Growth Capex $1.6B projected free cash flow at YE 2017 Strip Pricing (~$55 Oil / $2.84 Gas) $500 $0 Maintenance Capex Delivers $1.6B Projected Free Cash Flow Net of Maintenance and Growth Capital Note: See Appendix for key assumptions and definitions. 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE SUSTAINABLE CASH FLOW GROWTH 84

86 Liquidity & Debt Term Structure 9/30/2017 Debt Maturity Profile AR Credit Facility AM Credit Facility AR Senior Notes AM Senior Notes $1,800 $1,600 AR 2025 Notes (1) Yielding 4.4% $1,400 $1,200 $1,000 New credit facilities for AR and AM have allowed Antero to extend its average debt maturity out to 2022 $1,000 $427 $25 AM 2024 Notes (1) Yielding 4.4% $800 $600 $1,100 $750 $650 $600 $400 $200 $ (1) As of 1/12/18 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE FINANCIAL PERFORMANCE & PRINCIPLES 85

87 Positive Ratings Momentum Historical Corporate Credit Ratings Corporate Credit Rating (Moody s / S&P / Fitch) Baa3 / BBB- Ba1 / BB+ Ba2 / BB Ba3 / BB- B1 / B+ B2 / B B3 / B- Ba2/BB Moody s/s&p Investment Grade Rating: BBB- Fitch January 2018 Stable through commodity price crash Caa1 / CCC+ 9/1/2010 2/24/2011 5/31/ /21/2013 9/4/2014 3/31/ /31/ /1/2017 Moody's S&P Fitch Antero Has Enjoyed Positive Debt Ratings Momentum Since YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE ACCELERATED FOCUS TOWARDS INVESTMENT GRADE 86

88 Key Takeaways Announcing New Long Lateral Development Plan Averaging 11,500 Step Change in Capital Efficiency Reducing 5-Year D&C Capex by $2.9B Largest NGL Producer in U.S. With Highest Leverage to Rising NGL Prices Size & Scale to Capitalize on Resource Sustainable Cash Flow Growth Generating 5-Year Free Cash Flow of $1.6B at Strip & $2.8B at $60 Oil Disciplined Returns Focus 28% Full Cycle Returns 23% 5-Year Debt-Adjusted Production CAGR per share 22% 5-Year Cash Flow CAGR per share Joining an Elite Group With: Scale Double Digit Growth Low Leverage Free Cash Flow 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. 5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE VALUE PROPOSITION 87

89 Appendix I Supplemental Materials 88

90 What Drives NGL Product Pricing? Gas Linked Crude Linked 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 APPENDIX I SUPPLEMENTAL MATERIALS 89

91 Ethane: Northeast Market Dynamics & Supply Ethane Rejection and Transportation Rates by Region Bakken Rejection West of Appalachia BAKKEN/WILLISTON 4 Appalachia Rockies Rejection Texas & Gulf Coast Rejection ROCKIES 2 TEXAS & GULF COAST 1 U.S Gulf Coast 3 NORTHEAST Appalachia Rejection Source: S&P Global Platts and EnVantage APPENDIX I ETHANE FUNDAMENTALS 90

92 Ethane: Significant Demand Growth On Horizon Over 1.0 MM barrels per day of incremental ethane demand, including ~167 MBbl/d in the Northeast 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 with potential to add additional 173 MBbl/d of ethane demand MBbl/d of Ethane 1,200 1, Incremental U.S. Ethylene Plant Demand 1, APPENDIX I ETHANE FUNDAMENTALS 91

93 Ethane: Northeast Market Dynamics & Supply ~190 MBbl/d of ethane current rejected in Northeast (~48% of potentially recoverable ethane) Northeast Ethane Takeaway and Capacities Antero is an anchor supplier to Shell s cracker expected in 2021 PTT evaluating a world scale cracker with expected FID 2018 Utopia East 75 MBbl/d 1Q18 Mariner West 50 Mbbl/d Shell Cracker 105 MBbl/d Mariner East 70 MBbl/d Northeast Ethane Supply (MBbl/d) Mariner East 2X: TBD MBbl/d 1Q Actual Ethane Recovery Full Ethane Recovery ME2X Shell Cracker Mariner East Utopia Mariner West ATEX Announced De-ethanization Capacity (MBbl/d) 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 APPENDIX I ETHANE FUNDAMENTALS 92

94 Credit Facility Update: October 2017 Old Facility New Facility Borrowing Base $4,750 MM $4,500 MM Commitments $4,000 MM $2,500 MM Maturity 5/5/ Years (2022) Security First-priority, perfected liens and security interests on 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 Covenants Borrowing Base Utilization Libor margin (bps) Commitment fee (bps) Borrowing Base Utilization Libor margin (bps) Commitment fee (bps) < 25% < 25% > 25%, < 50% > 25%, < 50% > 50%, < 75% > 50%, < 75% > 75%, < 90% > 75%, < 90% > 90% > 90% 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. APPENDIX I CREDIT FACILITY UPDATE 93

95 3Q 2017 Segment EBITDAX & Capital Expenditures 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 operating 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 ($MMs) Revenues: Stand-Alone Adjusted EBITDAX : $284 Million (1) : $128 Million Exploration & Production Gathering & Processing Water Handling & Treatment Marketing Elimination of Intersegment Transactions Consolidated Total Third-Party $660 $7 $0 $51 - $718 Intersegment (191) - Gains on settled derivatives Total Revenue $722 $105 $93 $51 (191) $780 Cash operating expenses: Lease operating $24 - $52 - ($52) $23 Gathering, Processing & Transp. (3rd party) Gathering, Processing & Transp. (AM fees) (98) 10 Production Taxes G&A (before equity-based comp) (0) 36 Marketing Total Cash Operating Expenses $445 $15 $55 $79 ($150) $443 Segment Adjust EBITDAX $278 $90 $38 ($28) ($41) $336 Capital Expenditures: On consolidated basis, water fees are eliminated from D&C D&C (excluding water) $265 capital, - but water operating - expenses -are capitalized - $265 D&C (including water) (41) 52 Land / Acquisitions G&C / Water Infrastructure Total CapEx $415 $99 $48 $0 ($41) $522 (1) AR stand-alone EBITDAX represents E&P EBITDAX plus ~$35 million in distributions from AM ownership less net marketing expense. APPENDIX I SUPPLEMENTAL MATERIALS 94

96 Appendix II Guidance Material & Cautionary Language 95

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