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 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, 2016. 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 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 Antero Resources at a Glance
Market Cap……….……...... $6.3B Stand-Alone Enterprise Value $9.7B Corporate Debt Ratings…… Ba2 / BB / BBB- Stand-Alone Leverage……. 2.6x Net Production (4Q 2017)… 2,347 MMcfe/d Liquids...... 107,000 Bbl/d 3P Reserves………..…...... 53.0 Tcfe Net Acres………….…...…… 630,000 AR Midstream Ownership…. $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 Simplified Organizational Structure
An $18B Family Valuation
Sponsors(1) Public Sponsors(1) Public
27% 73% 68% 32%
NYSE: AR 100% Incentive NYSE: AMGP Enterprise Value: $9.7B Distribution Rights Enterprise Value: $3.9B (IDRs) Corp Ratings: Ba2 / BB / BBB- No Ratings
53%
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 Co-Founders & Significant Owners
Current Management Ownership
CLR 78% RSPP 13.4% PE 13.1% AR 9.0% HES 8.8% XEC 1.7% COG 1.4% NBL 1.2% CXO 1.1% U.S. E&Ps PXD 1.0% ≥ $6B Market Cap NFX 0.8% Management Owns ~$550 MM of EQT 0.7% DVN 0.4% Antero (AR) Stock FANG 0.4% EOG 0.4% 9% of Company Shares OXY 0.3% APA 0.2% MRO 0.2% $400 MM More Than Peer Median APC 0.2% COP 0.1% ECA 0.1% 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 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 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
Announcing New Long Lateral Development Plan Joining an Averaging 11,500’ Elite Group With: Sustainable Cash Flow Growth
Step Change in Capital Generating 5-Year Free Cash Scale Efficiency Reduces 5-Year Flow of $1.6B at YE Strip & D&C Capex by $2.9B $2.8B at $60 Oil Double Digit Growth Largest NGL Producer in U.S. With Highest Leverage Disciplined Returns Focus to Rising NGL Prices Low → 28% Full Cycle Returns Leverage → 23% 5-Year Debt-Adjusted Production CAGR per share → 22% 5-Year Cash Flow Size & Scale to CAGR per share Free Cash Capitalize on Resource 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 A Transformational History: From Ambition to Results
2001-2010 2011-2014 2015-2017 2018- Antero 1.0 Antero 2.0 Antero 3.0 Antero 4.0 A Shale Pioneer Scaling Up for Optimizing Disciplined Returns Strong Growth Development Program Focus
Early success in Intensified acreage Dramatic drilling Capitalizing on the Barnett expansion & infill efficiencies critical mass and cash flow engine Identified a large Implemented Advanced resource base in marketing plan with completions Maintaining the Marcellus hedge portfolio & discipline in capital firm transportation Sustained investment Key acreage to key gas markets development acquisitions momentum through Sustaining cost Built competitive downturn efficiencies and Confirmed advantage with reliable execution resource with initial midstream assets Improved balance well tests sheet Delivering free Brought liquids into cash flow Built out initial focus with infrastructure processing Reducing leverage commitments
VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | OVERVIEW 9 Core of the Core Acreage Position
Antero Acreage Antero Marcellus Wells(1) Northern Rich Industry Marcellus Wells(1) High-Graded Core 2.24 Bcfe / 1,000’ EURs Antero Marcellus Rig 67% Undeveloped Industry Marcellus Rig
Dry Gas High-Graded Core 2.30 Bcf / 1,000’ EURs 78% Undeveloped Southern Rich AR Holds 13% of Undeveloped High-Graded Core 2.24 Bcfe / 1,000’ EURs 70% Undeveloped AR Holds 61% 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 New Long Lateral Plan
59% of Inventory Now 5-Year Plan Averages 11,500’ ≥ 10,000’ Lateral Length
Average Lateral Length Core Inventory by Lateral Length per Completed Well
14,000 1,600 12,700 1,450 1,400 12,000 10,800’ 1,200 Average Inventory 10,000 Lateral Length
1,000 8,000 Feet 800 6,000
600 (Number of locations)of(Number 4,000 400
2,000 200
0 0 2018 2019 2020 2021 2022 <6,000' 6,000' - 8,000' - 10,000' - ≥12,000' Wells 8,000' 10,000' 12,000' 145 155 160 165 165 Completed(1) Feet 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 Why Are We Growing? Outstanding Well Economics
Single Well Economics
Full Cycle ROR: 28% Half Cycle ROR: 82% Well Economics Full Cycle ROR at $60/Bbl Flat: 33% Half Cycle ROR at $60/Bbl Flat: 90% Support Investment 100%
ROR Well in Excess of 90% Cash Cost Economics $60 Oil Cost of Capital 80%
70% Strip Pricing 60%
50% 28% Corporate 40% Level ROR AR Corporate Level 30% 2018 & 2019 Full Cycle Returns
20% Returns
10% 10% WACC ≈ 8%
0% 2018 Completion 2019 Completion Program 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 Almost $3B Capital Reduction to 5-Year Plan
Consolidated Drilling & Completion Capital Production Targets Expenditures
As of December 2016 As of December 2017 As of December 2016 As of December 2017 $2.5 $2.4 $2.9B Capex 6.0 $2.2 Reduction 5.2 5.2 $2.0 Cumulative Reduction in Drilling & 5.0 $2.0 4.6 Completion Capital 4.5 $1.7 $1.7 $1.6 4.0 3.9 4.0 $1.5 $1.4 $1.3 3.3 3.3 $1.3 $1.3 3.0 2.7 2.7
$Billions Bcfe/d $1.0 Same Production 2.0 Targets $0.5 20% Production CAGR 2018-2020 1.0 15% Production CAGR 2021-2022
$0.0 0.0 2018 2019 2020 2021 2022 2018 2019 2020 2021 2022
Same Production Growth With Much Less Capital Spending
VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | ATTRACTIVE WELL ECONOMICS DRIVES GROWTH 13 New Development Plan $2.9B D&C Capex Savings
D&C Capex Capital Allocation Lateral Lengths Cycle Times & Enhanced Well Cost Savings Savings Recoveries $0.4B Well Cost Savings
Related to reduced AFEs including lower $1.1B flowback water Optimizing Capital handling cost due to $2.9B Allocation Clearwater Facility Capital Efficiencies Captured Within Continued shift to high- D&C Capex From $0.5B graded Marcellus New Development Improved Cycle Program Times
Reduced drilling days, increase in stages per day and $0.9B concurrent operations Lateral Lengths
$0.09MM/1,000’ savings from 9,000’ to 12,000’
VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | COST EFFICIENCY DRIVERS 14 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
5-Year Stand-Alone Free Cash Flow: Cumulative Stand-Alone E&P Free Cash Flow Outspend $1,500 $60 Oil / $2.85 Gas Case Free Cash Strip Pricing at 12/31/17 (Base Case) Flow $50 Oil / $2.85 Gas Case $1,000 $2.8B We Are $500 Here $1.6B
$1.0B $0
($500)
($1,000)
($1,500) 2014A 2015A 2016A 2017E 2018 2019 2020 2021 2022 Guidance Target Target Target 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 Significant Exposure to Higher Liquids Prices
$2.8B in Free Cash Flow at $60/Bbl from 2018 - 2022
$4.8B in Free Cash Flow at $70/Bbl from 2018-2022
Aggregate 5-Year Annual Free Cash Flow Upside Free Cash Flow Upside
Strip Pricing at 12/31/17 $60 Oil / $2.85 Gas Strip Pricing at 12/31/17 $60 Oil / $2.85 Gas $3,000 $1,000 $60 Oil $900 $2,500 $800 $1.2B $700 $2,000 $600 Strip Pricing $500 $1,500 $400 $300 $1,000 $200 $100 $500 $0 2018 2019 2020 2021 2022 $0 Guidance Target Target Target Target 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 2019+ (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 Attractive Free Cash Flow Yield
9% AR 8% 8% FCF Yield(1) 7% Surpasses Industry Leading Peers, While Maintaining Strong Production 6% Growth
5%
4% FCF Yield FCF
3%
2%
1%
0% 2018 2019 2020
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 Shareholder Interests in Focus: 5-Year Cash Priorities
Priorities Sustain Asset Disciplined Growth Optionality for Cash Base Investments
Return of Capital
Debt Reduction
Land Acquisitions
$1.6B Free Cash Flow $10.4B for Deployment $5.9B Cumulative Stand-Alone E&P Adjusted Operating D&C Growth Capital Cash Flow
$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 Cash Flow Growth → Dramatic Delevering
12/31/17 Strip Pricing (Base Case) $60 Oil / $2.85 Gas $50 Oil / $2.85 Gas 5.0x 23% Debt-Adjusted 4.5x Production Growth Per Share 3.9x Leverage targets inclusive of $500 MM 4.0x 3.6x of maintenance and discretionary land 3.5x capex from 2018 - 2022
3.0x 2.8x 2.8x Generates Free 2.5x Cash Flow
2.0x
Alone Financial Leverage Financial Alone - 1.5x <2.0x by 2019 Net Debt / LTM Stand-Alone Stand E&P Adjusted EBITDAX 1.0x Balance Sheet Delevering & 0.5x Optionality 0.0x 2014A 2015A 2016A 2017E 2018 2019 2020 2021 2022 Guidance Target Target Target 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 Antero Profile To Drive Multiple Expansion
Median Debt/ Median EV/ # of Adjusted 2018 Adj. Companies EBITDAX EBITDAX
AR 2018E U.S. Publicly Traded E&Ps EBITDAX 51 3.1x 7.1x Multiple: 5.1x
Leverage < 3.0x 23 1.5x 7.8x Premium for: Enterprise Value Scale 18 1.9x 8.9x > $10B
Production Growth 10 1.5x 9.7x Growth >15%
Leverage 6 1.3x 11.1x Low Leverage <2.0x in 2019 Free EOG FANG CXO COG 6 1.3x 11.1x FCF Generation Cash in 2018 Flow PXD XEC Permian & Appalachia 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 Scale & Growth: Liquids-Rich Resource Meets Capital Efficiency
PAUL RADY & GLEN WARREN Chairman & CEO President & CFO
21 A Deep Understanding of the Appalachian Basin
10 NE Marcellus Rigs
Core Liquids-Rich Appalachia (1) 22 Utica Undrilled Locations Rigs B H J I F 5% 3% 2% 3% D 7% 7% K 36 SW Marcellus Rigs 7% AR 40% C 13% A 68 Total Rigs 13%
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 Defining the Resource: Appalachia Basin Core Analysis
• A deep database of peer information and analysis is maintained in house 9,600 Wells Horizontal Wells Analyzed – Acreage positions: developed and undeveloped Since Basin Inception – Well locations, lateral lengths, completions & production results
– Optimal undrilled location inventory based on operator well density 7.8 MM Acres Acreage Analyzed by Antero Teams • 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 27,000 Locations pressure Future Locations Plotted on Antero Maps
• Core area maps reflect the collective work of our technical teams
– Geologists map core areas based on the well data provided by 30 Professionals engineers Involved Team of Geologists, Reservoir Engineers, Land and GIS – 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 Who Has the Running Room?
Undrilled Core Marcellus & Utica Locations(1)
Marcellus & Utica Liquids Rich Locations SW Marcellus & Utica Dry Locations NE Pennsylvania Dry Locations 4,000
3,500 3,295 Who Can Drill Long Laterals? 3,000
Who Has the
2,500 2,333 Running Room? We Have 40% of
2,000 1,930 Liquids-Rich Locations Largest Inventory in Appalachia
1,500
Undrilled LocationsUndrilled 1,259
1,000 720 714 663 588 583 556 544 500
- AR A B C D E F G H I J Lateral Length: 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 Core of the Core
Antero Acreage Antero Marcellus Wells Northern Rich Industry Marcellus Wells High-Graded Core Antero Marcellus Rig ~283,000 acres Industry Marcellus Rig 2.24 Bcfe/1,000’ Avg. EUR > 1,300 lb/ft Completions 67% Undeveloped
Dry Gas Southern Rich High-Graded Core High-Graded Core ~1,051,000 acres ~487,000 acres 2.30 Bcfe/1,000’ Avg. EUR 2.24 Bcfe/1,000’ Avg. EUR 78% Undeveloped 70% Undeveloped AR Holds 13% of Undeveloped AR Holds 61% of Undeveloped
Advanced Completions High- Graded Most Active Percent (>1,300 lbs/ft) Core Areas Operators Undeveloped Bcfe / Wells 1,000’
Southwest Marcellus Core Northern Rich RRC, CNX, HG 67% 2.24 474 ~2.9 Million Acres Southern Rich AR, EQT, SWN 70% 2.24 517 ~78% Undeveloped EQT, CVX, Dry Gas 78% 2.30 747 RRC, CNX Recently Expanded Core & High-Graded Core Reflecting Well Performance
Note: Excludes 600,000 urban acres. EURs assume full ethane rejection. Based on Antero reserve engineering of most recent state and internal production data.
SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE 25 Core of the Core Development Programs
Half Cycle Total Average BTU 2018 Well 2019 Well Well EUR Regime Undrilled Lateral Range Completions Completions Economics Locations Length (Strip Price) Marcellus Highly-Rich Gas 1275-1350 14 30 168% 447 12,500’ Condensate Highly-Rich Gas 1200-1275 106 101 74% 935 11,500’
Rich Gas 1100-1200 0 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: Program Stats: High-Grade High-Grade
Inventory Inventory 78% | 86% 86% | 93% Totals: Averages: Strip | $60 Oil ROR Strip | $60 Oil ROR
2,372 11,400’ 1,253 BTU Average 1,248 BTU Average
1) Wells completed reflects midpoint of targeted completions per year.
SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE 26 5-Year Core of the Core Program
Highly-Rich Gas Condensate Highly-Rich Gas Rich Gas 1275 BTU+ 1200 – 1275 BTU 1100 – 1200 BTU Well Inventory: 447 Well Inventory: 935 Well Inventory: 495 Avg. Lateral Length: 12,522 Avg. Lateral Length: 11,502 Avg. Lateral Length: 11,158
25 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 A Pioneer in Drilling Longer Laterals in Appalachia
Antero Historical & Future Lateral Length Program
300 # of Avg. Lateral Antero Wells Length
Total Drilling Program 250 945 8,275 to Date 103 2018-2022 Program(2) 790 11,425
57
200 Wells to Date 245 10,700 13 ≥10,000’
12 93 Well Count Well 150 107
100
113 76 50 81 78 93 85 77
22 12 10 0 4 ≤ 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 > 15,000 Lateral Length(1) (1) All laterals rounded to the nearest thousand. (2) Represents wells placed to sales.
SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: LONGER LATERALS 28 Lateral Lengths Up 29% in 5-Year Plan
Average Lateral Length per Completed Well
2017 Plan 2018 Plan 14,000
12,400 12,700
12,000 11,600 10,500 9,700 10,000 9,300 9,200 9,100 9,000 8,600 8,500 8,000
6,000
4,000 Average Lateral feet) (in Length Average
2,000
0 2017 2018 2019 2020 2021 2022
Lateral Lengths per Year Increasing by 2,500’ in New Plan
(1) Represents 2017 YTD average as of 12.10.2017.
SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: LONGER LATERALS 29 Longer Laterals Scale the Resource
EURs by Marcellus Lateral Lengths
EUR in Bcfe/1,000' 2.3 Bcfe/1,000' R2 = .73 45
A 1:1 Proportional 40 Increase in EURs with
35 Longer Laterals Antero well results show no evidence of degradation in recovery per foot of 30 completed lateral out to over 14,000’
25
20 EUR (Bcfe) EUR
15
10
5
0 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 Lateral Length (ft) Note: Assumes ethane rejection.
SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: LONGER LATERALS 30 The Longer, the Better…
Single Well Economics by Lateral Lengths
PV-10 ($MM) ROR (%) $25.0 100% 79% 74% $20.0 67% $20.4 80% 50% $15.0 $15.9 60% $10.0 $11.4 40% $5.0 $6.8 20%
$- 0% 6,000' Lateral 9,000' Lateral 12,000' Lateral 15,000' Lateral
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 Well Costs → Longer Laterals is the Next Step
Historical Well Costs
Marcellus Utica
41% | 43% 2014 2017 2014 2017 Lower Costs $2.20 $2.60 Marcellus | Utica reduction in well costs $2.40 from 2014 to 2017 for a 9,000’ lateral $2.00 - 54% from efficiencies $2.20 - 45% from service costs $1.80
$2.00
$1.60 $1.80
$1.40 $1.60 9% | 10% $1.40
$1.20 43% 43%
Cost Benefit 41%
$MM/1,000 $MM/1,000 ftof lateral $MM/1,000 $MM/1,000 ftof lateral
$1.20 Reduction
Marcellus | Utica reduction in well cost Reduction per 1,000’ lateral going from $1.00 9,000’ to 12,000’ laterals $1.00 $0.80 $0.80 9% 10% $0.60 Reduction $0.60 Reduction 3,000 6,000 9,000 12,00015,000 3,000 6,000 9,000 12,000 15,000 Lateral Length (ft) 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 Reduced Cycle Times Lead to Lower Well Costs
Drilling Days Completion Stages per Day
Marcellus Utica Marcellus Utica 45 59% | 34% 10.0 Decline in Drilling Days in 7.0 40 the Marcellus | Utica
6.0 35 31
30 29 29 5.0 4.8
4.2 25 24 4.0 4.0 4.0 3.7 3.5 3.2 3.2 20 18
Drilling Drilling Days 17 3.0 15 Stages Day per 15 12 31% | 25% Improvement in 2.0 10 8 Marcellus | Utica Stages Per Day 1.0 5
0 0.0 2014 2015 2016 2017 Record 2014 2015 2016 2017 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 Operating Evolution Continues
Total Well Cost Savings Next Steps in D&C Evolution in the Marcellus(1)
• Automated completion equipment 100% 42% Drilling Vendor Reduction (3%) → increase stages per day
Decline in well costs 90% since 2014 • Program wide implementation of 80% higher proppant loading, zipper
Completion Vendor stimulations and longer laterals
70% Reduction (43%) • Reduced cluster spacing → higher 60% potential recoveries
46% 50% • Sand Vendor-related cost Drilling • 100 mesh efficiency → easier reductions 40% Efficiency (25%) pumping with fewer screenouts
• Self-sourcing initiative → reduce of Total Well Cost Savings Cost Well Total of 30%
supply risk and cost % %
20% Completion • Fit-for-purpose rigs improves cycle 54% 10% Efficiency (29%) times Permanent cost • Enhanced walking and dual operation efficiencies 0% capabilities
• Concurrent operations (“ConOps”) • Plan to implement in 2019 (1) Based on Marcellus 9,000 foot lateral and 2,000 pounds per foot AFE.
SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | OPERATING TECHNOLOGIES EVOLVE 34 Continuous Design Improvement in Operations
Average Wells per Pad by Year Current Well Pads
10 Generation 1.0 9 150% increase in wells 8 per pad 7 6 5
Wells per Pad per Wells 4 3 2 2010 2011 2012 2013 2014 2015 2016 2017 2018
Map View Pad Size: 3-4 Acres Average Lateral Lengths by Year 12 Well Pad
10,000 Pad Construction
9,000 Drilling 8,000
Feet 7,000 70% increase in lateral Completion 6,000 lengths 5,000 2010 2011 2012 2013 2014 2015 2016 2017 2018 Production Rig Wellheads
SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | OPERATING TECHNOLOGIES EVOLVE 35 Concurrent Operations Boost Returns
ConOps Concurrent vs. Batch(1)
110% Theoretical Best
100%
90% Concurrent Operations
80% Rate of ReturnofRate
70% Batch Drill Then Complete
60% 2 4 6 8 10 12 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 Pad Designs Support Concurrent Operations
New Pads Designed for ConOps
Generation 2.0
Completions Fleet Operations
200 Feet Map View Pad Size: Approximately 7 Acres
Pad Construction 12 Well Pad
Drilling 1st Six Wells Drilling 2nd Six Wells
Completion Completion Rig
Production Wellheads Production 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 Advanced Completions Drive EURs Higher
Proppant Per Foot Increasing EUR per 1,000’(1)(2) Higher Proppant Marcellus Utica per Foot Marcellus Utica 3,000 3.0 2,757 has contributed to higher 3.0 recoveries 2,530
2,500 2,375 2.5 2.4 2.3 2.3 2,094 2,000 1,702 2.0 1.9 1,648 1.8 1.8 1.7 1.6 1.5 1,500 1,298 1,267 1.5 1,163 1,165 Marcellus
1,000 EURs +33% 1.0
Pounds Pounds Proppant of Per Foot
500 0.5 Processed EUR 1,000' per ofLateral (Bcfe)
- 0.0 2014 2015 2016 2017 Record 2014 2015 2016 2017 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 2016-2017 for Marcellus.
SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: ENHANCED RECOVERIES 38 Result in Dramatically Lower F&D Cost
F&D Cost per Mcfe(1)(2)
Marcellus Utica $1.40 52% | 42% $1.28
$1.20 Lower F&D in Marcellus | Utica
$1.00 $0.94 $0.88
$0.80 $0.73 $0.73 $0.74
$0.60 $0.51 $0.42 $0.40
$0.20
$0.00 2014 2015 2016 2017 Dramatic Improvement in Operating Efficiencies, Lower Service Costs and Higher
(1) Ethane rejection assumed. Well Recoveries Have Driven F&D Costs Materially Lower (2) F&D cost is defined as current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 85% NRI in Marcellus and 81% NRI in Utica. Please see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix.
SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | COST EFFICIENCY DRIVERS: WELL COST REDUCTION 39 Natural Gas Liquids: Leading Position & Strong Fundamentals
DAVID CANNELONGO Oil & NGL Marketing Manager
40 Largest NGL Producer in the U.S.
NGL Price Exposure Among Top NGL Producers
3Q17 Daily NGL Production Including Recovered Ethane 115.0 45% NGL % of Product Revenues Pre-hedged Realized Price ($/Bbl) 105.6 40% 105.0
35% 34% 95.0 34% of AR Q3 2017 30% 30% Revenue from NGLs
85.0 25%
/d MBbl
75.0 20% Revenues Product of 15% 65.0 13% 12% 12% 12% 13% 11% 10% % NGL 8% 55.0 7% 5% $23.11 $16.93 $15.15 $31.07 $22.38 $20.72 $21.83 $18.96 $22.91 $22.99 45.0 0% AR RRC DVN APC EOG COP CHK PXD NBL OXY
Antero Has The Highest NGL Price Exposure Among TopPre- NGLhedged Producers Realized Price ($/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 Rapidly Growing NGL Production
Antero NGL Production Growth by Purity Product
Natural Gasoline (C5+) IsoButane (iC4) 250,000 245,000 Normal Butane (nC4) Propane (C3) Ethane (C2) C3+ Production
200,000 C2
/d)
150,000 Bbl
Total ( Total C2 Ethane 44,000 C3 100,000 C2 Ethane 26,500
C2 Ethane 17,476 nC4 50,000 iC4
C5+ 0 2014 2015 2016 2017 2018E 2019E 2020E 2021E 2022E Guidance Target Target Target 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 Current Propane Market Fundamentals
U.S. propane exports exceeded excess Resulting in a material reduction in domestic supply in 2016 and 2017 U.S. propane inventories
U.S. Propane: Excess Supply vs. Net Exports U.S. Propane Inventories
120,000 Excess Supply Net (Imports) / Exports 5-year Range 2016 2017 800
700 In 2016 U.S. exports 100,000 exceed excess supply by 600 ~120MBbl/d 80,000
500
400
/d 60,000 MBbl
MBbl 300
40,000 200 2017 inventory is 36% below 2016 100 inventory levels 20,000 -
(100) 0 2010 2011 2012 2013 2014 2015 2016 2017 Jan FebMar Apr May Jun Jul Aug Sep Oct Nov Dec
NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS 43 C3+ NGLs: Absolute & Relative Price Improvement
Mt. Belvieu C3+ Price Mont Belvieu C3+ to WTI Price Ratio
$2.00 100%
$1.80 90% 72% of WTI $1.60 80%
$1.40 70%
$1.05/gal
$1.20 60%
$1.00 50% $/Gallon $0.80 WTI % of 40%
$0.60 30%
$0.40 20%
$0.20 10%
$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 Significant Investment in LPG Infrastructure
U.S. LPG Export Capacity Global VLGC Ship Fleet
1,400 300
1,200 250
1,000
200
800
150 Vessels MBbl/d 600
100 400
50 200
0 0 2012 2013 2014 2015 2016 2017 2012 2013 2014 2015 2016 2017
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
Source: Poten Partners. S&P Global Platts.
NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS 45 The New Norm: Tighter U.S. Differentials to Global Prices
Mont Belvieu vs. Far East Index Baltic LPG Shipping Rates Differential
$0.00 100
90 ($0.20) 80
($0.40) 70
60 ($0.60) 50
$/Gallon ($0.80) $/Metric Ton $/Metric 40
($1.00) 30
20 ($1.20) 10
($1.40) 0 2012 2013 2014 2015 2016 2017 2012 2013 2014 2015 2016 2017 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 Propane and Butane: U.S. Supply Growth by Region
C3+ supply growth from low cost basins: Supply increases ~475 MBbl/d Appalachia (+59%) and Permian (+22%) over the next 3 years to ~2,475 MBbl/d
Bakken Supply Mid Continent 400 200 BAKKEN/ 31 +29% WILLISTON 36 MBbl/d 100 200
0 0 2014 2017 2020 2014 2017 2020 +59% 165 MBbl/d +4% NORTHEAST 9 MBbl/d +13% 39 MBbl/d Rockies Supply ROCKIES Appalachia Supply 300 600 MID-CONTINENT 200 400 100 200 PERMIAN 0 0 2014 2017 2020 GULF COAST 2014 2017 2020 +22% Permian and Gulf 226 MBbl/d Coast Supply
2,000
Note: Bubbles reflect growth over the next five years (2017-2022). 0 Supply includes field production and refinery production. Excludes imports. 2014 2017 2020 Source: U.S. Energy Information Administration and S&P Global Platts.
NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS 47 Propane and Butane: U.S. Demand Growth by Sector
U.S. Propane & Butane Demand
1,600
1,400 ~145 MBbl/d of U.S. demand growth over 1,200 the next 3 years Refinery/Blending/Other
1,000
800 Residential/Commercial ~60% of total MBbl/d demand growth 600 driven by petrochemical 400 demand Petrochemical 200
0 2017E 2018E 2019E 2020E
Source: S&P Global Platts & U.S. Energy Information Administration
NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS 48 The Result? The Need for More LPG Exports
U.S. Butane & Propane Supply vs. Demand
3,000 U.S. supply growth over 3 years exceeds domestic demand growth 2,500 by ~365 Mbbl/d (including 35 MBbl/d of
imports) 2,000
/d 2017 Exports 1,500
Growth in LPG MBbl waterborne exports needed to clear the U.S. 1,000 NGL Market
500 Total U.S. Demand
0 2017E 2018E 2019E 2020E
Source: S&P Global Platts & U.S. Energy Information Administration
NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS 49 LPG Exports & Export Capacity – Then vs. Now
U.S. has U.S. has Sufficient But is export Then: excess NGL Now: excess NGL export constrained supply supply capacity
U.S. LPG Exports vs. Capacity (MBbl/d)
1,800 Historically Sufficient Export Near-Term 1,600 Constrained Capacity 1,400
1,200
1,000
800
600
400
200 Export Capacity @ 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
2,000
1,800
1,600
1,400
1,200
1,000
800
600
400
200
- 2012A 2013A 2014A 2015A 2016A 2017E 2018E 2019E 2020E 2021E 2022E LPG Shipping Fleet Continues to Support Global Trade
VLGC fleet continues to expand with Ship capacity sufficient to ~50 new build VLGC orders support global LPG trade through 2020 through 2020
Global VLGC Shipping Fleet vs. Baltic Rates Global LPG Shipping Supply/Demand
350 100 Baltic Rates 250 Ship Supply Ship Demand 90 300 80 200
250 70
60 150 200
50 VLCG’s VLGC’s 150 100
40 Baltic Rate($/ton) Baltic 100 30 50 Current VLGC Confirmed 20 50 Fleet New Builds 10 0 0 0 201220132014201520162017201820192020
Source: Poten Partners
NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS 51 U.S. Exports Displacing Middle East Exports
Northeast Asia LPG Imports by Exporting Region
700 Northeast Asia U.S. Middle East U.S. Share: imported more U.S. 51% 600 LPG cargos than 513 Middle East cargos 497 for the first time ever 500 in 2017
400 MBbl/d Middle East LPG 300 cargos have remained flat due to 200 strategy of keeping LPG purity products 100 at home and OPEC
oil production cuts 0 2013 2014 2015 2016 2017 October 2017
NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS 52 LPG: Significant Long Term Demand Growth
LPG Import Demand Growth by Region
Global LPG import (MBbl/d) China LPG Import (MBbl/d) Japan/S. Korea/Taiwan demand increases by Demand 1,000 LPG Import Demand ~415 MBbl/d 1,000 from 2017 - 2020 500 500
- - 2017 2020 Asia accounts for ~70% 2017 2020 of forecasted worldwide LPG import demand growth through 2020
LPG Import Growth (MBbl/d) (MBbl/d) India LPG Import Demand 2017 - 2020 Indonesia LPG Import 1,000 (MBbl/d) Total Asia/Pacific ~300 1,000 Demand
Europe/Mediterranean ~85 500 500 Latin America ~30 - Total ~415 2017 2020 - 2017 2020
Note: Import demand is shown net of domestic production (i.e. country supply/demand imbalance) Source: S&P Global Platts.
NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS 53 India and China: A Detailed Look at Demand
India China
Aggressive government Demand growing with initiatives to replace wood and government initiatives to HOME animal waste with propane in displace solid biofuels in rural households relying on open fires areas
Last planned refinery startup Build-out of PDH plants from 1 Industrial (Paradip) marks last major in 2013 to 15 by 2020 accounts domestic supply addition, in-turn for roughly half of total Chinese supporting further future imports LPG growth
Increased gasoline taxes have Upgrade of emissions standards similar to Europe and the U.S. Travel resulted in an uptick in LPG auto-gas demand
Misc./ Non-subsidized market Processing plants using butane- Other continues to grow and is price rich LPG as feedstock receptive
Source: Poten Partners and Dorian LPG
NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS 54 Global LPG Demand Growth Absorbs Supply Growth
LPG Import/Export Growth by Region (MBbl/d)
Europe/Med 2017 2020 Russia - 2,000 N. America/Carib (1,000) 1,000 2,000 (2,000) - 2017 2020 1,000
- Middle East 2017 2020 2,000 Asia Pacific To Asia via 2017 2020 Panama 1,000 (500) Canal (1,500) - 2017 2020 (2,500) Africa Latin America 2,000 2017 2020 - 1,000
(1,000) - (2,000) 2017 2020
Long LPG Short LPG
Source: Poten Partners. +415 (-415)
NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS 55 C3+ NGLs: Northeast Market Dynamics and Supply
~165 MBbl/d of Northeast C3+ demand vs. ~350 MBbl/d of Northeast supply in 2017 Northeast C3+ NGL Takeaway - Resulted in 47% of production consumed locally - Remainder moved primarily by rail Midwest/ Conway Mariner East II provides Cornerstone Mariner East 1 additional “baseload demand” 70 MBbl/d
and access to international LPG Mariner East 2 Export markets 275 MBbl/d – 2Q 2018 Markets Mariner East 2X: 250 MBbl/d 1Q 2019 Northeast C3+ NGL Supply
700 600 Pentanes U.S. Gulf 500 Coast IsoButane 400 Butane 300 200 Propane 100 0
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 C3+ NGLs: Northeast Supply & Demand
Northeast C3+ NGL Supply vs. Demand & Takeaway Capacity Excluding Rail (MBbl/d)
Long Local Demand and Short Local Demand & 800 Pipeline Capacity Pipeline Capacity Sufficient Pipeline Mariner East 2 = Tight Differentials = Wide Differentials Capacity = Tight 700 ~$(2.00)/Bbl vs. Mont ~$(6.00)/Bbl vs. Mont Differentials Expansions Belvieu Belvieu 600
500
400 Mariner East 2 Rail fills short 300 term gaps Cornerstone 200 Mariner East 1
100 Local Demand & TEPPCO 0
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 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 ($/Gallon)
Antero Netback 2018 Antero Netback 2018 NWE Price ($/Gal) $0.97 FEI Price ($/Gal) $1.04 Pipeline & Terminal (1) $(0.19) Pipeline & Terminal (1) $(0.19) Shipping $(0.05) NWE Shipping $(0.14) Netback $0.73 Marcus Netback $0.71 Uplift vs. $0.25/Gal Hook $0.13 Uplift vs. $0.25/Gal Rail to Mt. Belvieu $0.11 Rail to Mt. Belvieu U.S. Gulf Coast 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 2018 Guidance: Transition to Free Cash Flow & Low Leverage
MICHAEL KENNEDY SVP of Finance & CFO, Antero Midstream
59 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 ($1,525) N/A Maintenance Expenditures
Free Cash Flow Before Change in $15 N/A Working Capital & Land (at Midpoint)
Note: See Appendix for definitions of non-GAAP terms. Cash flow and EBITDAX guidance based on 12/31/2017 strip pricing . 2018 average NYMEX and WTI pricing was $2.83/MMBtu and $59.57/Bbl, respectively. (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.
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | GUIDANCE 60 2018 Product Revenue Buildup
Volumes Realized % of Total Product Revenues (Guidance) Price Revenue 38%
Liquids as a Percent Natural Gas NGLs Crude of Total Volume 1,925 $2.85/Mcf $2.0B 52% GAS MMcf/d
C2 44 MBbl/d $10/Bbl $0.2B 5% $1.5B Liquids Revenue C3+ 77.5 MBbl/d $39/Bbl $1.1B 28%
Oil 9.5 MBbl/d $54/Bbl $0.2B 5%
Hedges 43% | 38% N/A $0.45/Mcfe $0.4B 10%
Pre- | Post- Hedge Liquids as Percent of Revenue 2,700 $4.00/Mcfe $3.9B 100% MMcfe/d
Note: See Appendix for key assumptions
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS 61 2018 Natural Gas Market Mix
Antero Firm Transportation Portfolio in 2018
% of Gas Index Differential Sold TETCO M2 $(0.53) 10% Local Mid-Atlantic $(0.34) 6% Markets TCO $(0.27) 16% 10% of FT Portfolio Gulf Coast $(0.14) 41% $(0.53)/Mcf Midwest $(0.13) 27% Differential Weighted Average $(0.21) 100% vs. NYMEX: Antero Producing BTU Uplift $0.24 Areas All-in vs. NYMEX +$0.03
+$0.00 - $0.05 forecasted premium to NYMEX after BTU uplift
90% of Antero Gas Is Sold In Favorably Priced Markets Note: Based on 2018 strip pricing as of 12/31/2017. See Appendix for further assumptions.
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS 62 Well Hedged at High Prices Relative to Strip
Commodity Hedge Position
Hedged Volume Average Index Hedge Price(1) Current NYMEX Strip(2) Mark-to-Market Value(2) ($/MMBtu) 2,400 2,330 2.8 Tcfe hedged through $5.00 2,141 2023 at $3.39/MMBtu $3.5B of realized gains $4.50 on hedges since 2008 ~19 MBbl/d of propane 1,900 $3.66 hedged in 2018 at $0.75/Gal $4.00 $3.50 $3.25 $3.50 $3.00 $3.00 $2.91
1,400 $3.00 /d $2.93 $2.84 $2.81 $2.82 $2.85 $2.89 $2.50 1,418 MMcfe 900 850 $2.00 710 $1.50
400 $1.00 $450 MM $584 MM $225 MM $38 MM $35 MM $0 MM 90 $0.50
-100 2018 2019 2020 2021 2022 2023 $- ~ 100% of 2018 and 2019 Target Gas Production Hedged at $3.50 ~$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 for 2018 only. (2) As of 12/31/17.
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PRODUCTIVITY DRIVERS 63 2018 C3+ NGL Pricing & Market Mix
Antero 2018 C3+ NGL Production Netbacks
100%
90% Weighted Average C3+ $/Bbl Pre-ME2 Post-ME2 80% Marcus Realized Pricing Location Houston, PA Hook Dock 70% Propane (C3) – 56% 60% Mont Belvieu Price(1) $41.00 $41.00 50% Differential/Uplift Net of Cost(2) $(5.50) +$2.00 40% Butane (C4) – 16% Antero Realized C3+ Price $35.50 $43.00 30% % of WTI 60% 72% 20% IsoButane (IC4) – 9%
10% Pentane (C5) – 19% 2018 Weighted Average 62.5% - 67.5% of WTI 0% Antero C3+ NGL 2018 Weighted Average ~$39/Barrel Barrel Composition 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.
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS 64 Significant Value Derived from Midstream Ownership
Antero Midstream Targeted Distributions to Antero Resources
$450
$400
$350
$300
$250
$200 $ in in MMs $
$150 $132 $112 $100 $89
$50
$- 2015A 2016A 2017A 2018E 2019E 2020E 2021E 2022E
Note: Represents distribution growth targets for AR owned units through 2022. As of 9/30/17, AR owns 98.9 million AM units.
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK 65 2018 Stand-Alone E&P EBITDAX Margin
Stand-Alone E&P EBITDAX Margin Waterfall ($/Mcfe)
$4.50 AM Distributions $4.18 Fully Burdened Stand-alone gathering fees $0.17 $0.10 $4.00 $0.11 $1.75B Stand- $0.45 Hedges $0.65 Alone E&P $3.50 EBITDAX Revenues = $1.80/Mcfe X 2.7 $3.00 $0.60 Bcfe/d of production $0.10 Liquids FT $2.50 $0.55 Gas FT $2.00 $0.13 $1.80 $3.56 $0.15 $1.50 $0.45 Hedges
$1.00 $1.34 $0.50
$0.00 Revenues, LOE and Gathering & Processing & Firm Net Marketing Cash G&A Stand-alone Hedges, Production Compression Fractionation Transportation Expense E&P EBITDAX AM Taxes Fees Expenses Expenses Margin Distributions
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | ATTRACTIVE MARGINS 66 Midstream Driving Value for AR Since Inception
Antero Midstream Return on Investment for AR (Pre-tax)(1)
$7,000 $6,117 $3,112 $6,000
4.7x
$5,000 ROI
$4,000 $321 $2,756 $250 $3,000 $311 $795 $179 $2,000 Cash ProceedsCash(SMM) $1,150 $1,000
$0 AM IPO (2014) Sale of Water Sale of AM Sale of AM AM Total Proceeds Expected Pre-tax Value Pre-tax Business Units (2016) Units (9/6/17) Distributions to Date Earnout of AM Units Cumulative (2015) Received as of Payments Held by AR @ Value of Antero 12/31/17 (2019E-2020E) $31.75 Midstream (01/12/18)
Takeaway Downstream Return on Assurance Visibility 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 $1.3B of AR capital invested at time of AM IPO.
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | ATTRACTIVE MARGINS 67 Understanding Liquids Uplift and Processing Costs
Antero Processing Benefit vs. Cost
Benefits Costs ($/Mcfe) 1250 BTU 2.75 GPM $0.75 / Mcfe $1.60 (Partial Ethane $1.45 Uplift from liquids Recovery) production, net of $1.40 processing and liquids $0.19 $1.26 transport fees $1.20 C3+ $0.60 $1.00
$0.80 $0.10 $0.75 $1.11 $0.60
$0.40
$0.20 Ethane $0.15 $0.00 NGL Uplift Oil Uplift Processing Cost Transportation Cost Net Gas Equivalent Price (Net of Liquids Transport)
Note: Based on 2018 strip pricing as of 12/31/17.
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | LIQUIDS UPLIFT 68 Price Certainty Gained from Firm Transportation
Natural Gas Price Differentials Relative to NYMEX
Appalachia (1) Antero Realized Differential (2) $0.50 3-Year Appalchian Average 3-Year Antero Realized Basis
Antero – Low Volatility Price Certainty ($0.03) $0.00
($0.50)
($1.03) Limited ($1.00) Northeast Pricing Exposure ($1.50)
Floating – High Volatility ($2.00)
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.
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK 69 Significant Value Derived from Firm Transportation
Natural Gas Price Realization Relative to Appalachia In-Basin Pricing
AR Price Realization In-Basin Price(1) AR Prices Net of FT & Net Marketing Expense (Excluding Hedges) $4.50 $4.10 $4.00 Realized price, net of $491 MM $3.82 all FT costs $3.50 $3.82 Total Value Created from FT exceeds in- Portfolio Since 2014 $3.18 $3.27 basin prices
$3.00
$2.50
Mcf $2.50 $2.37 $/ $2.39$2.39 $2.00 $2.24 $1.80 $1.80 $1.70 $1.50 $1.70 $1.47 $1.49 $1.00
$0.50 $173MM $148MM $109MM $62MM $0.00 2014 2015 2016 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.
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK 70 2018 Guidance: Understanding FT, Marketing & Hedge Benefits
Firm $0.34/Mcfe Uplift Hedge Book in Realized Gas Prices vs. Local Transportation Dominion South index(1)
$3.50 Benefits $3.30 Costs
$2.85 $0.45 $3.00 $0.55 $2.75 $2.63 $0.13 $0.56 $2.50 $2.29 $0.34
$2.00
$/Mcf $1.50
$1.00
$0.50
$0.00 Dominion South Firm Hedge Gains Firm Net Marketing Net Uplift to Strip Pricing Transportation Transportation Expense Dominion South Pricing Uplift Cost Strip Pricing
Note: Based on strip pricing as of 12/31/17.
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK 71 Attractive Gas Marketing Plan
Hedge Portfolio Supports Net Marketing Expense (High End) Net Marketing Expense (Low End) Firm Commitments Hedge Gains $585 $0.48/Mcfe $600
$469 5-Year Cumulative: $0.45/Mcfe $500 Firm Transportation Portfolio Hedge Gains: $1,350 Allows Antero to achieve: Marketing Expense: ($472)
$400 Net Uplift: $878
$300 $224
$ Millions $ $0.20/Mcfe $0.15/Mcfe Effectively $200 Premium Price $0.15/Mcfe Hedge NYMEX Certainty Index $100 $0.15/ Less volatility and Mcfe < $0.10/ $37 $35 A key advantage as $0.10/ Mcfe greater surety in Mcfe realized prices our product is $0 $0 $0 delivered to NYMEX- 2018 2019 Target 2020 Target 2021 Target 2022 Target related markets Guidance
Hedge Gains More than Offset Marketing Expense – Hedges Support FT Commitments
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK 72 Understanding G&A: Most Productive Employees
Production Per Employee (MMcfe/d)(1)
Production per Employee Peer Average
5.00 AR A B C D E F G H I J K L 528 241 576 762 467 1,469 1,080 1,809 856 994 850 1,085 3,604 4.00 3.5 3.0 3.0 3.00 2.3x 2.0 1.8 More Productive Employees 2.00 1.5 1.5 Based on Daily Production 1.2 1.1 1.1 0.9 0.9 1.00 0.8 0.4 0.00 AR A B C D E F G H I J K L
EBITDAX Per Employee ($MM)
2.9x Peer Average Peer Average $3.5 More Productive Employees $2.9 on an EBITDAX Basis $3.0 $2.5 $2.0 $1.7 $1.7 $1.5 $1.5 $1.2 $1.0 $1.0 $1.0 $0.9 $0.9 $1.0 $0.8 $0.7 $0.5 $0.5 $0.5 $0.0 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.
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PRODUCTIVITY 73 Peer Leading Margins: Before NGL Price Uptick
3Q 2017 Stand-Alone E&P Adj. EBITDAX Margins (Pre-Hedge / Pre-Marketing Expense)(1) Margin Rank: #1 4 3 2 5
$4.00 $3.47 $3.50 $2.79 $2.78 $3.00
$2.24 $2.50 $2.05 $2.00 $2.09 $1.75 $1.56 ($/Mcfe) $1.50 $0.99 $1.23 $1.00 $1.38 $1.22 $1.25 $0.50 $1.04 $0.82 $- AR A B C D Adjusted EBITDAX GPT LOE Ad Valorem G&A Revenue Cash Costs
3Q 2017 Stand-Alone E&P Adj. EBITDAX Margins (Post-Hedge / Post Marketing Expense)(1) Margin Rank: #1 2 4 3 5 $3.76 $4.00 $3.50 $2.86 $2.87 $3.00 $2.27
$2.50 $2.13 ) $2.22 $1.75 $2.00 $1.54 Mcfe $1.50 $1.25
($/ $1.00 $1.00 $1.54 $1.33 $1.27 $0.50 $1.11 $0.88 $- $(0.50) AR A B C D Adjusted EBITDAX GPT LOE Ad Valorem G&A Net Marketing Revenue Cash Costs Source: SEC filings and company press releases. AR margins exclude $0.21/Mcfe negative impact from WGL and SJR natural gas contract disputes. Peers include COG, EQT, RRC & SWN. (1) AR and EQT EBITDAX include distributions from midstream ownership. Cash costs for AR and EQT represent stand-alone GPT, production taxes, LOE and cash G&A. (2) AR’s EBITDAX excludes net marketing expense and the hedges put in place to support firm transportation.
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | ATTRACTIVE MARGINS 74 Attractive 2018 E&P Margins and Recycle Ratio
Antero Fully Burdened Stand-Alone E&P Cash Margins ($/Mcfe)
($/Mcfe)
$2.50
3.4x $2.00 $1.80 $1.80 Recycle Ratio(1) $1.59 $0.45 $0.21 $1.50 $0.45 Hedges
$1.00 Hedges
2.7x Unhedged $1.34 $1.13 $0.47 Recycle Ratio(1) $0.50
$0.00 Stand-Alone E&P Interest Stand-Alone E&P 2018 F&D Cost EBITDAX expense Cash Margin Margin
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 $0.125.
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | ATTRACTIVE MARGINS 75 Antero Consolidated and Stand-Alone Enterprise Value
($MM)
$12,000 $10,801
$10,000 $1,077
Net Debt $2,796 $8,000 $4,529 $6,928 ~$1,300 $6,000 21% tax on value of Hedge MTM AM units (net of NOLs) $4,000 Market E&P Value Assets $6,272 99MM units owned and AM $5,628 $2,000 market price of $31.75/unit
$0 Consolidated Antero Midstream After Tax Value of AM AR Stand-alone Enterprise Value Net Debt Owned Units 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 12/31/17. See Appendix for further details on Antero trading multiples.
2018 GUIDANCE: TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | VALUE CREATION 76 5-Year Outlook: Disciplined Growth Drives Equity Upside
GLEN WARREN President & CFO
77 Financial Policy Overview
Fund drilling & completion capital with stand-alone upstream cash Free Cash Flow 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 Leverage stand-alone basis) with a medium-term target of below 2x
Continue to hedge over a rolling five to six year period to support Hedge Program 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 Accelerate trend towards investment grade quality – current Grade Debt corporate ratings Ba2/BB/BBB-
5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE 78 Commodity Outlook
Outlook Factors
+ Strip weighed upon by wind power hedging and upstream acquisition hedging + Operators drilling up their best gas inventory in U.S. Constructive Mid-Term, Natural Gas over next several years Positive Long-term + Strong demand growth – LNG, Mexico, coal displacement, petchem, etc. - Associated gas growth from Permian
+ Solid global demand growth with aligned global economic growth Oil Positive + 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 NGLs Positive + 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 Looking to the Future: Disciplined Growth
2,500’ Average Increase 365 Fewer Completions $2.9B Cumulative Savings, in Lateral Length Per Well than Previous Plan Same Production Targets
Planned Antero Well Completions by Year (2018-2022) 400 January 2017 Plan January 2018 Plan (Low-End) Lateral Length Lateral Length 365 350 Cumulative Well Count Reduction January 2018 Plan (High-End) 290 300 255 240 250 230 190 190 175 200 170 170 150 160 165 150 155 160 160 140 80 150 100 45 50 9,100 9,700 9,000 10,500 8,600 11,600 9,200 12,400 8,500 12,700 0 2018 2019 2020 2021 2022
Drilling & Completion Capital Budget and Targets 2018 – 2020 Targets 2021 – 2022 Targets Consolidated Drilling & Completion ($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
(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 Capital Budget Discipline
Historical Consolidated D&C Capital Spend vs. Initial Guidance
$2,000 Initial Guidance Actual
$1,800 +3% + 4% Within Initial D&C Targets Set at $1,600 Outset of the Year +2%
$1,400 (4%) $1,200
$1,000
$800
Capital Spend ($MM) SpendCapital $600
$400
$200
$0 2015 2016 2017 2018 2019 2020 2021 2022 A Proven Track Record of Meeting D&C Capital Guidance
5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | CAPITAL DISCIPLINE 81 Same Production Growth With Much Less Capital Spending
Consolidated Drilling & Completion Production Targets Capital Expenditures
As of December 2016 As of December 2017 As of December 2016
As of December 2017
$2.5 $2.4 6.0 $2.2 5.2 5.2 $2.0 $2.0 5.0 4.6 4.5 $1.7 $1.7 $1.6 4.0 3.9 4.0 $1.5 $1.4 $1.3 3.3 3.3 $1.3 $1.3 3.0
$Billions 2.7 2.7 Bcfe/d $1.0
2.0
$0.5 1.0
$0.0 0.0 2018 2019 2020 2021 2022 2018 2019 2020 2021 2022
5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | CAPITAL DISCIPLINE 82 Attractive Debt-Adjusted Production Driving Cash Flow
23% CAGR in 22% CAGR in $10.00 Debt-Adjusted Production Discretionary Cash Flow
6.0 Per Share Through 2022 Per Share Through 2022
/share)
Mcfe $8.00
5.0 Share(
4.0 $6.00 Adjusted
- 3.0 $4.00
2.0
$2.00 1.0 Per Cash Share Flow Discretionary
0.0 $0.00 Net Production perProductionDebt Net 2017E 2018 2019 2020 2021 2022 Guidance Target Target Target Target Production Per Share Cash Flow Per Share 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.
5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | SUSTAINABLE CASH FLOW GROWTH 83 Low Maintenance Capital: Key to FCF Generation
Maintenance Capex Growth Capex $10.4B projected cash flow $3,000 ~800 wells completed
$2,500
$5.9B growth capex $2,000
~560 wells completed
$1,500 $MM $2.9B maintenance (including land) $590 MM per year $1,000 Growth Capex
$500 $1.6B projected free cash flow Maintenance Capex at YE 2017 Strip Pricing (~$55 Oil / $2.84 Gas) $0 2018 2019 2020 2021 2022
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 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 New credit facilities for AR $427 AM 2024 Notes(1) Yielding 4.4% and AM have allowed $1,200 Antero to extend its average $25 $1,000 $1,000 debt maturity out to 2022 $1,100 $800 $750 $650 $600 $600
$400
$200
$0 2017 2018 2019 2020 2021 2022 2023 2024 2025
(1) As of 1/12/18.
5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | FINANCIAL PERFORMANCE & PRINCIPLES 85 Positive Ratings Momentum
Historical Corporate Credit Ratings
Corporate Credit Rating (Moody’s / S&P / Fitch) Investment Grade Baa3 / BBB- Rating: BBB- Ba1 / BB+ Fitch January 2018 Ba2/BB Ba2 / BB Moody’s/S&P Ba3 / BB-
B1 / B+ B2 / B Stable through commodity price crash B3 / B-
Caa1 / CCC+ 9/1/2010 2/24/2011 5/31/2013 10/21/2013 9/4/2014 3/31/2015 12/31/2016 12/1/2017
Moody's S&P Fitch
Antero Has Enjoyed Positive Debt Ratings Momentum Since 2010
5-YEAR OUTLOOK: DISCIPLINED GROWTH DRIVES EQUITY UPSIDE | ACCELERATED FOCUS TOWARDS INVESTMENT GRADE 86 Key Takeaways
Announcing New Long Lateral Development Plan Joining an Averaging 11,500’ Elite Group With: Sustainable Cash Flow Growth
Step Change in Capital Generating 5-Year Free Cash Scale Efficiency Reducing 5-Year Flow of $1.6B at Strip & D&C Capex by $2.9B $2.8B at $60 Oil Double Digit Growth Largest NGL Producer in U.S. With Highest Leverage Disciplined Returns Focus to Rising NGL Prices Low → 28% Full Cycle Returns Leverage → 23% 5-Year Debt-Adjusted Production CAGR per share → 22% 5-Year Cash Flow Size & Scale to CAGR per share Free Cash Capitalize on Resource 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 Appendix I
Supplemental Materials
88 What Drives NGL Product Pricing?
Gas Linked Crude Linked
Ethane Propane Butane IsoButane Pentane (C2) (C3) (C4) (IC4) (C5)
Heating, Alkylate feed to Ethylene Winter gasoline Gasoline blend Crop drying, produce Primary Use Production Blending and diluent Commercial gasoline Pet Chem Refineries/ Flexible Pet Limited by facilities that Blenders, Pet Chem and Alkylate Refineries Price Makers can consume Chem and exports production crude exports
Ethane Only Heating fuel Commercial DilBit Refineries Price Takers Pet Chem consumers users producers
Crude Crude Crude Crude (via winter Limited ceiling (Naptha derived Crude (via winter gasoline, Global due to requiring Price Ceiling ethylene & Naptha heating) LPG prices, Alkylate in production) propane) RBOB
Gasoline & Natural Gas Ethane Price Propane Price Refined Refined Price (Ethylene (Ethylene Price Floor Products Price products (Rejection) switching) switching) price
APPENDIX I | SUPPLEMENTAL MATERIALS 89 Ethane: Northeast Market Dynamics & Supply
Ethane Rejection and Transportation Rates by Region
Bakken Rejection West of Appalachia Appalachia 100 78 31 46 BAKKEN/WILLISTON 50 0 4 0 2012 2017 2022
Rockies Rejection NORTHEAST 142 150 123 ROCKIES 3 100 2 Appalachia Rejection 50 19 294 300 0 158 2012 2017 2022 TEXAS & 200 GULF COAST 100 1 0 Texas & Gulf Coast 1 2012 2017 2022 Rejection 200 103 100 45 5 U.S Gulf 0 Coast 2012 2017 2022
Source: S&P Global Platts and EnVantage
APPENDIX I | ETHANE FUNDAMENTALS 90 Ethane: Significant Demand Growth On Horizon
Incremental U.S. Ethylene Plant Demand
Over 1.0 MM MBbl/d of barrels per day of Ethane incremental ethane 1,200 demand, including ~167 MBbl/d in the 1,028 Northeast 1,000 173 855
“First Wave” 800 750 105 Ethylene crackers under 657 construction will add 92 ~855MBbl/d of ethane 600 165 demand by the end of 492 2021 400 309 “Second Wave” 183 Ethylene crackers under 200 consideration in 2022+ with potential to add 183 additional 173 MBbl/d - of ethane demand 2017 2018 2019 2020 2021 2022+
APPENDIX I | ETHANE FUNDAMENTALS 91 Ethane: Northeast Market Dynamics & Supply
~190 MBbl/d of ethane current rejected in Northeast Ethane Takeaway and Capacities Northeast (~48% of potentially recoverable ethane)
Antero is an anchor supplier to Shell’s Shell Cracker cracker expected in 2021 Mariner West 105 MBbl/d 50 Mbbl/d Utopia East Mariner East PTT evaluating a world scale cracker with 75 MBbl/d 70 MBbl/d expected FID 2018 1Q18
Northeast Ethane Supply (MBbl/d) Mariner East 2X: TBD MBbl/d 1Q19
800 Actual Ethane Recovery Announced De-ethanization 700 Full Ethane Recovery Capacity (MBbl/d) 600 500 390 390 400 357 500 ME2X 300 270 400 Shell Cracker 177 200 128 300 Mariner East 103 100 40 200 Utopia 0 0 Mariner West 0 100 ATEX 0
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 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 5/5/2019 5 Years (2022)
Same as existing, until at least one of Moody’s or First-priority, perfected liens and security interests S&P assigns the Borrower a Senior Unsecured on substantially all assets including oil and gas Security Rating > Baa3 or BBB-, at which time the Borrower properties comprising no less than 80% of the may elect to enter into a “Release Period”, effectively total value of the Borrowing Base properties. going unsecured Borrowing Libor margin Commitment Borrowing Base Libor margin Commitment fee Base Utilization (bps) fee (bps) Utilization (bps) (bps) < 25% 150.0 37.5 < 25% 125.0 30.0 Pricing > 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 Below Investment Grade Period: Below Investment Grade Period: • Current Ratio of > 1.0x • Current Ratio of > 1.0x • Interest Coverage Ratio of > 2.50x • Interest Coverage Ratio of > 2.50x Covenants 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 $2.5B and Added Investment Grade Fall-Away Covenants (1) Only applicable upon going unsecured with only one investment grade rating and until the second investment grade rating is achieved.
APPENDIX I | CREDIT FACILITY UPDATE 93 3Q 2017 Segment EBITDAX & Capital Expenditures
1 Gathering and compression fees paid to Antero Midstream are included in Gathering, Processing & Transportation expense on stand-alone basis (eliminated on consolidated basis); Gathering and compression operating expenses borne by AM on stand-alone basis (included in GPT on consolidated basis) 2 Water fees paid to Antero Midstream included in Drilling & Completion capital expenditures on stand-alone basis; water operating expenses borne by AM on stand-alone basis and AR on consolidated basis
($MMs) Stand-Alone Water Elimination of Adjusted EBITDAX Exploration & Gathering & Handling & Intersegment Consolidated : $284 Million(1) Production Processing Treatment Marketing Transactions Total Revenues: : $128 Million 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 0 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: 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) 93 - - - (41) 52 Land / Acquisitions 57 - - - - 57 G&C / Water Infrastructure - 99 48 147 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 Appendix II
Guidance Material & Cautionary Language
95 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 $0.00 to $0.05 Premium Nymex C3+ NGL Realized Price 62.5% – 67.5% (% of Nymex WTI)
Cash Production Expense ($/Mcfe) $2.10 – $2.20 $1.65 – $1.75
Marketing Expense ($/Mcfe) $0.10 – $0.15 (10% Mitigation Assumed) G&A Expense ($/Mcfe) $0.125 – $0.175 $0.15 - $0.20 (before equity-based compensation)
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
$150 $150 Land Capital Expenditures ($MM) ($25MM Maintenance) ($25MM Maintenance) Note: See Appendix for key definitions. Cash flow and EBITDAX guidance based on 12/31/2017 strip pricing . 2018 average NYMEX and WTI pricing was $2.83/MMBtu and $59.57/Bbl, respectively. (1) Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes.
APPENDIX II | 2018 96 Highly Visible 2018 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
Transparent Operating Plan and Expenditures Remove Uncertainty in D&C Budget
APPENDIX II | GUIDANCE MATERIALS 97 Maintenance Capital Drops with Longer Laterals
2018 Maintenance Capex at 9,000’ and 12,000’ Laterals
Marcellus Utica $700 $613 $600
$552
$500
$400
$300 Maintenance Capital($MM) Maintenance $200
$100
$0 9,000 ft lateral 12,000 ft lateral
Note: See Appendix for maintenance capital definition as well as further assumptions.
APPENDIX II | GUIDANCE MATERIALS 98 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 & $2.85 Nymex Henry Hub gas prices for 2019 - 2022
Oil and Gas Strip Commodity Prices (12/31/17)
($/Bbl) ($/MMBtu) $65.00 $2.82 $2.82 $2.85 $2.89 $3.00 $2.81 $60.00 $59.62 $2.50 $56.19
$55.00 $53.76 $2.00 $52.29 $51.67 $50.00 $1.50
$45.00 $1.00
$40.00 $0.50
$35.00 $0.00 2018 2019 2020 2021 2022 WTI Nymex
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)
APPENDIX II | PRICING ASSUMPTIONS 99 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.
APPENDIX II | PROJECT ASSUMPTIONS 100 Antero Guidance and Long-Term Target Assumptions
Stand-Alone E&P Consolidated
20% CAGR through 2020 and 15% Growth in each of Net Daily Production (MMcfe/d) 2021 and 2022
Natural Gas Realized Price Differential to $0.00 to $0.05 Premium (2018) Nymex $0.00 to $0.10 Premium (2019 – 2022)
C3+ NGL Realized Price 62.5% – 67.5% (2018) (% of Nymex WTI) 72% (2019+) – ME2 Fees Booked to Transport Costs
Realized Oil Price Differential to WTI ($5.00) – ($6.00)
$2.10 - $2.20 (2018) $1.65 - $1.75 (2018) Cash Production Expense ($/Mcfe)(1) $2.10 – $2.25 (2019 – 2022) $1.65 – $1.75 (2019 – 2022)
$0.10 - $0.15 (2018) $0.15 – $0.20 (2019) Marketing Expense ($/Mcfe) <$0.10 (2020) $0.00 (2021 – 2022)
G&A Expense ($/Mcfe) $0.125 – $0.175 (2018 – 2019) $0.15 - $0.20 (2018 – 2019) (before equity-based compensation) $0.10 – $0.15 (2020 – 2022) $0.10 – $0.15 (2020 – 2022)
$0.175 – $0.225 (2018 – 2019) $0.25 – $0.30 (2018 – 2019) Cash Interest Expense ($/Mcfe) $0.10 – $0.15 (2020 – 2021) $0.20 – $0.25 (2020 – 2022) <$0.10 (2022) Well Costs ($MM / 1,000’) Marcellus: $0.95 MM Marcellus: $0.80 MM (Assumes 12,000’ completions at Utica: $1.07 MM Utica: $0.95 MM 2,000 lbs. per foot of proppant)
(1) Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes.
APPENDIX II | 5-YEAR ASSUMPTIONS 101 Antero Guidance and Long-Term Target Assumptions (Cont.)
Stand-Alone E&P Consolidated
$10.4B Adjusted Operating Cash Flow(1) N/A (Cumulative 2018 – 2022)
$1,500 – $1,600 (2018 – 2020) $1,300 – $1,400 (2018 – 2021) Annual D&C Capital Expenditures ($MM) $1,700 – $2,000 (2021 – 2022) $1,600 – $1,700 (2022)
Land Maintenance Expenditures ($MM)(2) ~$200 (Cumulative 2018 – 2022)
$1.6B Free Cash Flow(1) N/A (Cumulative 2018 – 2022)
Leasehold Growth Capital Expenditures ($MM) ~$300 (Cumulative 2018 – 2022)
Number of Well Completions 790 well completions
Marcellus EUR per 1,000’ of Lateral 2.0 Bcf/1,000’; 2.5 Bcfe/1,000’ (25% ethane recovery)
Utica EUR per 1,000’ of Lateral 2.0 Bcfe/1,000’ (ethane rejection)
Note: See Appendix for key definitions. Cash flow guidance is based on 12/31/2017 strip pricing. Average NYMEX pricing was $2.83/MMBtu, $2.81/MMBtu, $2.82/MMBtu, $2.85/MMBtu and $2.89/MMBtu in 2018, 2019, 2020, 2021 and 2022. Average WTI pricing was $59.57/Bbl, $56.19/Bbl, $53.76/Bbl, $52.29/Bbl and $51.67/Bbl for 2018, 2019, 2020, 2021 and 2022. (1) Adjusted Operating Cash Flow and Free Cash Flow are non-GAAP financial measures. For additional information regarding these measures, please see the following pages (“Antero Definitions” and “Antero Non-GAAP Measures”). (2) Includes leasehold capital expenditures required to achieve targeted working interest percentage.
APPENDIX II | 5-YEAR ASSUMPTIONS 102 Single Well Economics: Marcellus – In Ethane Rejection
Highly-Rich Classification Highly-Rich Gas Rich Gas Dry Gas Gas/Condensate
Modeled BTU 1313 1250 1150 1050 EUR (Bcfe): 32 29 26 24 EUR (MMBoe): 5.3 4.9 4.3 3.9 % Liquids: 33% 24% 11% 0% Well Cost ($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
Highly-Rich Highly-Rich Gas Rich Gas Dry Gas Cumulative Gas/Condensate Volumes 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 0 4,300 0 Year 2 6,500 143 6,500 31 6,500 0 6,500 0 Year 3 7,900 152 7,900 36 7,900 0 7,900 0 Year 4 9,100 157 9,100 40 9,100 0 9,100 0 Year 5 10,200 161 10,200 44 10,200 0 10,200 0 Year 10 13,900 176 13,900 57 13,900 0 13,900 0 Year 20 18,500 194 18,500 73 18,500 0 18,500 0 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.
APPENDIX II | SINGLE WELL ECONOMICS 103 Antero Assumptions: Single Well Economics
SWE Cost Type Description of Cost Half Cycle Full Cycle
• Drilling and completion costs Marcellus: $10.6MM Marcellus: $11.4MM • Assumes well costs for a 12,000’ lateral, Utica South/Dry: $12.2MM Utica South/Dry: $12.8MM Well Costs 2,000 lbs of proppant per lateral foot and Utica Beaver: $11.5MM Utica Beaver: $12.2MM both fresh and flowback water (60% AM water fees) (100% AM water fees)
Working Interest / • Reflects Antero’s average WI/NRI in the Marcellus: 100% / 85% Net Royalty Interest respective plays Utica: 100% / 81%
Midstream Gathering • Midstream low pressure, high pressure 60% of AM gathering fees 100% of AM gathering fees Fees and compression fees
Variable FT costs only of • FT costs may include both demand and Fully utilized FT costs of $0.06/Mcf (variable fees Firm Transportation(1) variable fees associated with expected $0.54/Mcf (including both associated with expected production demand and variable fees) production)
General & Administrative • General and administrative costs None $750,000 per well Costs associated with Antero
• Assumes 12,000’ well with 660’ spacing Land None $655,000 per well and $3,600 per acre
• Provides a timeframe for initial spud to Spud to FP Timing 184 days spud to FP first production
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
APPENDIX II | SINGLE WELL ECONOMICS 104 EUR Recoveries (25% Ethane Recovery)
1200 – 1275 1100 – 1200 1275 BTU+ < 1100 BTU BTU 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 -
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.
APPENDIX II | EUR RECOVERIES 105 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 out payments expected from Antero Midstream associated with the water drop down transaction that occurred in 2015. See “Non-GAAP Measures” on slide 18 for additional detail. Stand-Alone Drilling & Completion Capital: Represents drilling and completion capital as reported in the Parent column of AR’s guarantor footnote to its financial statements and includes 100% of fees paid to AM for water handling and treatment and excludes operating costs associated with AM’s Water Handling and Treatment segment).
APPENDIX II | DISCLOSURES & RECONCILIATIONS 106 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 of 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 other factors; • helps investors to more meaningfully evaluate and compare the results of Antero’s operations (both on a consolidated and Stand-alone basis) from period to period by removing the effect of its capital structure from its operating structure; and • is used by management for various purposes, including as a measure of Antero’s operating performance (both on a consolidated and Stand-alone basis), in presentations to the company’s board of directors, and as a basis for strategic planning and forecasting. Consolidated Adjusted EBITDAX is also used by the board of directors as a performance measure in determining executive compensation. Consolidated Adjusted EBITDAX, as defined by our credit facility, is used by our lenders pursuant to covenants under our revolving credit facility and the indentures governing the company’s senior notes. There are significant limitations to using Consolidated Adjusted EBITDAX and Stand-alone 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.
APPENDIX II | DISCLOSURES & RECONCILIATIONS 107 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:
(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
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%.
APPENDIX II | DISCLOSURES & RECONCILIATIONS 108 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 operations. 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 of 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 obligations. 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 $8.6 billion.
APPENDIX II | DISCLOSURES & RECONCILIATIONS 109 Antero Resources Stand-Alone E&P Adjusted EBITDAX Reconciliation
AR Stand-Alone E&P Adjusted EBITDAX Reconciliation
($ in millions) Three Months LTM Ended 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 $1,296.2
APPENDIX II | DISCLOSURES & RECONCILIATIONS 110 Antero Resources Consolidated Adjusted EBITDAX Reconciliation
Consolidated Adjusted EBITDAX Reconciliation
($ 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 $1,498.3
APPENDIX II | DISCLOSURES & RECONCILIATIONS 111 Antero Resources Adjusted EBITDAX Reconciliation (4Q 2017)
AR Consolidated and Stand-Alone E&P Adjusted EBITDAX Reconciliation ($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 — — — (3,000) — (4,000) consideration 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 — — — 33,000 — 34,000 Midstream . Adjusted EBITDAX $ 430,000 $ 445,000 $ 370,000 $ 385,000
APPENDIX II | DISCLOSURES & RECONCILIATIONS 112 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.
APPENDIX II | DISCLOSURES & RECONCILIATIONS 113