Company Overview November 2017
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- Willa Butler
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1 Company Overview November 2017
2 1 Forward-Looking Statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Resources Corporation and its subsidiaries (collectively, the Company or Antero ) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words believe, expect, anticipate, plan, intend, estimate, project, foresee, should, would, could, or other similar expressions are intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include estimates of the Company s reserves, expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced under the heading Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2016 and in the Company s subsequent filings with the SEC. The Company 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 our control, incident to the exploration for and development, production, gathering and sale of natural gas 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 Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2016 and in the Company s subsequent filings with the SEC. 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. 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.
3 Antero Profile Market Cap (1).... Enterprise Value (2) Corporate Debt Ratings Stand-alone Leverage (3) Net Production (3Q 2017) Liquids (4)... 3P Reserves (5)..... Net Acres (6).... Midstream Ownership (7) $6.3 billion $9.7 billion Ba2 / BB 2.6x 2,317 MMcfe/d 112,000 Bbl/d 53.0 Tcfe 636,000 $3.1 billion 1. Based on market capitalization as of 9/30/ Market capitalization plus net debt on a stand-alone basis as of 9/30/ Stand-alone Net debt to latest twelve months EBITDAX as of 9/30/ Oil plus NGLs 5. 3P reserves as of 6/30/2017, assuming 28% ethane recovery, of which 96% represent 2P reserves. 6. Net acres as of 9/30/ Market value of AR s 53% ownership of Antero Midstream Partners (NYSE: AM) as of 9/30/
4 Antero s Core Business Strategy 1 Develop World Class Resource Over the Long Term Run by co-founders and management with significant ownership Forward thinking with industry leading hedge and firm transportation portfolio designed to reduce price volatility and facilitate consistent, repeatable asset development Expand core inventory opportunistically through grass roots leasing and acquisitions 2 Generate High Margin Cash Flow Disciplined capital investment driven by single well but also corporate-wide returns Focus on liquids-rich inventory in the lowest cost U.S. shale basins Continuous focus on efficiency gains through reduced cycle times and long laterals 3 Maintain a Strong and Flexible Stand-alone Balance Sheet Fund drilling and completion capital with discretionary cash flow Target leverage in the low to mid 2x range Create optionality to return capital to shareholders 4 Capture the Energy Value Chain Continue to build the most integrated natural gas and NGL story in the U.S. Significant value, visibility and opportunity in integrated operations and 53% midstream ownership (NYSE: AM) 3
5 Undrilled Locations Largest Core Drilling Inventory in Appalachia- Liquids Focused Based on thorough technical analysis of competitor acreage configurations, well results and geology, Antero has the largest core drilling inventory (see core outlines) in Appalachia and holds 44% of the total liquids rich undrilled inventory 12 NE Marcellus Rigs Undrilled Core Marcellus and Core Utica 3P Locations (1) 31 Utica Rigs 33 SW Marcellus Rigs 76 Total Rigs 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, ,890 Core - NE Pennsylvania Dry Locations Core - SW Marcellus & Utica Dry Locations Core - Marcellus & Utica Liquids Rich Locations 2,096 1,757 1,024 1, Core Liquids-Rich Appalachia Undrilled Locations AR 44% Avg. AR A B C D E F G H I J K Lateral Length 7,812 6,414 6,416 7,157 8,394 8,033 5,868 8,547 9,339 7,301 7,486 8,868 Core outlines based upon Antero geologic interpretation, well control, drilling activity, well economics and peer acreage positions based on investor presentations, news releases, 10-K/10-Qs and various other sources. Rig information per RigData as of 10/27/ Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG, RICE, RRC and SWN. * Undrilled location count net of acreage allocated to publicly disclosed joint ventures. E 6% H 8% C 10% I 5% A 4% B 13% D 3% J 3% G 2% K 2% 4
6 Antero Investment Highlights 1 Market Leading Exposure to NGL Prices and Production Growth 2 Maximizing Financial Returns with Enhanced Completions and Long Laterals 3 Capital Efficiencies and Cash Flow Growth Result in Free Cash Flow and Declining Leverage Through 2020 (1) 4 Midstream Ownership and Integration Delivers Tremendous Value to Antero Shareholders 1. Assuming flat $3.00 NYMEX gas and $54 WTI oil through
7 MBbl/d NGL % of Product Revenues 1 Largest NGL Producer in the U.S. Antero is the largest NGL producer in the U.S and has the most NGL exposure at 34% of total upstream company revenues Top U.S. NGL Producers (MBbl/d) 3Q % 30% Largest NGL producer in the U.S. in 3Q 17 with the Highest exposure to NGLs among the top 10 peer group 45% 40% 35% 30% % 20% % 12% 12% 13% 11% 8% 9% 7% $23.11 $16.93 $15.15 $31.07 $18.65 $20.72 $18.96 $22.91 $18.36 $22.99 (1) (1) AR RRC DVN APC EOG COP PXD NBL CHK OXY 15% 10% 5% 0% 3Q17 Daily NGL Production NGL % of Product Revenues Pre-hedged Realized Price ($/Bbl) Source: SEC filings and company press releases. Realized prices are weighted average including ethane (C2) where applicable. 1. CHK and EOG C2+ production, realized prices and NGL percentage of product revenues based on 2Q 2017 actual results. 6
8 MBbls Propane Price ($/gallon) Propane % of WTI 000s Bbl/day 1 Strong Propane Fundamentals Antero is well positioned to capitalize on an improving propane market with low inventories, increasing demand and tightening of Mont Belvieu pricing relative to WTI Historically Isolated U.S. Markets Unlocked with LPG Export Capacity Buildout 1,600 1,400 1,200 1, Propane Butane Export Terminal Capacity Historically the U.S. has been constrained by export capacity Excess capacity for exports to global markets Driving Propane Inventories Short Strong Absolute & Relative Price Improvement 120, ,000 80,000 60,000 40,000 20, % and 37% reduction from 2015 and 2016 trough inventory levels, respectively 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec $1.60 $1.40 $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 Mont Belvieu Propane Price % of WTI 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Source: EIA and Bentek. Data as of 10/18/17. 7
9 $/gallon 1 And Healthy Global Demand Propane and butane increasingly becoming a globally priced product as U.S. domestic supply has the ability to reach primary demand growth centers in Asia Global Propane and Butane Outlook Growing Propane and Butane Demand Global propane and butane LPG demand growing at or above global GDP, equating to 1.6 MMBbls/d of incremental demand forecast from Demand driven primarily by industrialization and urbanization in Asia Asia becoming the price setter as the world s largest demand center Appalachia geographically advantaged for Europe destination cargoes and at parity for Asia destination cargoes vs. the Gulf Coast $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 Global Propane Prices Converge Mont Belvieu Far East Index Northwest Europe MMBbl/d Asia Europe Latin America North America Middle East Africa Other Asia Europe Latin America North America 11.0 Source: PIRA report dated March 17,
10 1 Rapidly Growing NGL Production Antero has market-leading exposure to NGL volume growth Antero NGL Production Growth by Purity Product (Bbl/d) Total (Bbl/d) 175, ,000 Ethane (C2) C3+ Production Propane (C3) Normal Butane (nc4) IsoButane (ic4) Natural Gasoline (C5+) 125,000 C2 100,000 75,000 50,000 C2 Ethane 17,476 C2 Ethane 26,500 C3 nc4 25,000 ic E Guidance 1. Excludes condensate. 2. Based on Antero NGL production targets from 2018 to (1) 2018E Target 2019E Target C E Target (2) (2) (2) 9
11 1 Improving Propane Prices Drive Increase in C3+ NGL Netbacks Despite a flat oil price environment, Antero s pre-hedged realized C3+ NGL price has increased 70% since 2015 and is expected to improve further Antero C3+ NGL Realized Pricing ($/Bbl) (1) WTI Price Antero Realized C3+ Price Mont Belvieu C3+ NGL Price $55.00 $50.00 $48.63 $48.16 $54.00 Antero Forecast Netback Price (3) $45.00 $43.14 $40.00 $35.00 $30.00 $25.00 $20.00 $ % of WTI $17.01 $ % of WTI $18.74 $ % of WTI $ % of WTI $ % of WTI $ % of WTI $15.00 $ % of WTI 43% of WTI $5.00 $ Q WTI price and Mont Belvieu C3+ NGL price forecasts and represent strip pricing as of 9/25/2017. Antero year to date 2017 realized C3+ NGL pricing represents actuals through 6/30/ realized C3+ NGL pricing reflects current company targets. 2. Based on unhedged contracted differentials for C4+ NGL products, guidance from midstream providers and strip pricing as of 10/27/ Net of ME2 fees. Antero will account for ME2 fees as an expense once ME2 is placed in-service. (2) 10
12 C3+ NGL Cash Flow ($MM) 1 Powerful C3+ NGL Pricing Upside Exposure Antero expects significant cash flow growth in 2018 from the improvement in NGL pricing with attractive upside to further increases in liquids pricing Significant Improvement in Cash Flow from C3+ NGLs (2018 vs. 2017) $700 C3+ Cash Flow Incremental C3+ Cash Flow $651 $600 $500 $537 $114 $400 $300 $200 $147 $100 $0 $27.56/Bbl C E $49 Oil 56% of WTI (1) $35.00/Bbl C E $54 Oil 65% of WTI Note: C3+ NGL cash flow represents revenue from C3+ NGL production, less processing, transportation and all other operating costs associated with C3+ NGL production and sales. (1) Represents annualized actual results for nine months ended September 30, 2017, annualized. $39.00/Bbl C E $60 Oil 65% of WTI 11
13 Wellhead Production (Cumulative MMcf) 2 Higher Intensity Completions Increasing EURs AR s production from advanced completions is outperforming the 2.0 Bcf/1,000 wellhead type curve 2,500 lb/ft completions are 17% above type curve (First 243 days) AR Type Curve Outperformance (1)(2) 3,500 3,000 1,875 lb/ft $0.89 MM/1,000 Well Cost 90 wells 1,500 lb/ft $0.85 MM/1,000 Well Cost 38 wells 2,500 2,500 lb/ft $0.97 MM/1,000 Well Cost 21 wells 2,000 1, Bcf/1,000' Type Curve Cumulative Production 1, Days From Peak Gas 1. Cumulative average production per well normalized to a 9,000 lateral. Cumulative production lines excludes wellhead condensate. 2. 1,875 pounds per foot type curve represents 1,750 pounds per foot wells and 2,000 pounds per foot wells. 12
14 Pre-Tax PV-10 ($MM) Unhedged Pre-Tax ROR Pre-Tax PV-10 ($MM) Unhedged Pre-Tax ROR 2 Strong Marcellus Half-Cycle Returns Integrated platform yields attractive well economics and sustainable growth Highly-Rich Gas: $3.00 Gas / $54 Oil (1) Highly-Rich Gas/Condensate: $3.00 Gas / $54 Oil (1) $20.0 $16.0 $12.0 $8.0 $4.0 $0.0 Wellhead Bcf/1,000 : Processed Bcfe/1,000 : Pre-Tax PV-10 45% $ Btu 55% $ Pre-Tax ROR 67% $ % 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% $20.0 $16.0 $12.0 $8.0 $4.0 $0.0 Wellhead Bcf/1,000 : Processed Bcfe/1,000 : Pre-Tax PV % $ Btu 132% $ Pre-Tax ROR 162% $ % 160% 140% 120% 100% 80% 60% 40% 20% 0% 1,211 Undrilled Locations 632 Undrilled Locations 1. Assumes Nymex Henry Hub prices of $3.00 and WTI of $54; ethane rejection; and 9,000 lateral length. Half cycle returns burdened by full fixed and variable transportation costs. See appendix for further assumptions. Locations as of 6/30/
15 Well Count 2 Longer Laterals Materially Improve Economics Antero has been a leader in drilling long laterals in Appalachia Antero Lateral Lengths To Date Future completion programs focused on longer lateral length locations Antero Total Drilling Program to Date # of Wells Avg. Lateral Length 894 8, Program (2) 135 9, Program (2) 470 9,500 Wells to Date 10, , ,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14, Lateral Length (1) 6,000 Foot Lateral 9,000 Foot Lateral 12,000 Foot Lateral 15,000 Foot Lateral Pre-Tax Economics Pre-Tax Economics Pre-Tax Economics Pre-Tax Economics ROR (%) 39% ROR (%) 55% ROR (%) 61% ROR (%) 68% PV-10 ($MM) $5.1 PV-10 ($MM) $9.5 PV-10 ($MM) $12.5 PV-10 ($MM) $16.3 NOTE: Assumes 2.0 Bcf/1,000 type curve for the Antero Marcellus Highly-Rich Gas (1250 Btu) and Nymex Henry Hub prices of $3.00 and WTI of $ All laterals rounded to the nearest thousand. 788 of the 894 wells have been completed 2. Represents wells placed to sales. 14
16 Number of Wells 2 Antero Holds the Largest Long Lateral Inventory Antero holds over 30% of the core drilling inventory (2) in Appalachia for lateral lengths greater than 10,000 feet and has been a consistent leader in drilling long laterals in Appalachia Peer Core Undrilled Inventory by Lateral Length 600 ANTERO Peer 1 Peer 2 Peer 3 Peer 4 Peer ,000 7,000 8,000 9,000 10,000 11,000 12,000 >12,000 Lateral Length (in feet) 1. Direct Appalachian Basin peers include EQT, RRC, RICE, COG, CNX. Acreage must support 50% WI in laterals to be counted. 2. Represents estimated total location inventory of undrilled wells for the top 12 peers operating in the core Marcellus & Utica plays. Core based upon Antero geologic interpretation, well control and peer acreage positions based on investor presentations, news releases, 10-K/10-Qs and various other sources; see page 4 for core outlines and additional information. 15
17 3 $1 Billion Delevering Program Completed BBtu/d 2,400 2,000 1,600 1, Antero monetized over $1 billion of non-e&p assets through the sale of $311 million of AM common units and $750 million through hedge restructuring - Reduced stand-alone net debt/ltm EBITDAX to 2.6x Restructuring of hedge swap prices resulted in no change to hedge volumes 80% of targeted natural gas production hedged through 2020 at $3.43/MMBtu $1.2 billion of remaining hedge value Utilizing a portion of net operating losses carried forward to eliminate cash taxes on realized gains 0 $3.64 No Change to Price $3.91 $3.50 $3.70 $3.63 $3.50 $ x 3.0x 2.0x 1.0x 0.0x AR Leverage Reduction (1) 3.4x Natural Gas Hedge Position Previous Hedge Price Restructured Hedge Price $3.31 $3.00 Remaining Value as of 9/30/17: $1.2 Billion (2) Consolidated 3.2x Hedged Volume ~$750 Million of Proceeds $3.16 $3.00 Standalone 3.0x Current NYMEX Strip (2) $ x 6/30/2017 9/30/2017 $/Mcf $4.00 $3.00 $ AR stand-alone LTM EBITDAX includes $127 million in distributions from AR s ownership of AM common units. 2. Nymex strip pricing as of 9/30/
18 3 Improving Capital Efficiencies Improving EURs, longer laterals and reduced cycle times results in 200 fewer well completions saving approximately $1.5 billion through 2020 while still delivering essentially the same production targets Planned Antero Well Completions by Year ( ) January 2017 Plan Current Plan Cumulative Well Count Reduction Lateral Length Lateral Length ,300 9,250 9,100 9,600 9,000 9,200 8,600 10, Drilling and Completion Capital Budget and Targets (1) 2017 Budget 2018 Target 2019 Target 2020 Target Drilling & Completion ($MM) $1,300 ~$1,300 $1,500 $1,500 % Production Growth Target 20% CAGR Through 2020 (4-Year CAGR) 1. Represents a combination of 2,000 lb/ft and 2,500 lb/ft completions. 17
19 3 Capital Efficiency Drives Elimination of Outspend Capital efficiencies have significantly reduced E&P outspend and are expected to result in drilling and completion (D&C) capex within E&P free cash flow by 2019 D&C Capex vs. Stand-alone E&P Cash Flow ($MM) - $3.00 Gas / $54 Oil $2,500 Stand-alone E&P Free Cash Flow Outspend (1) Stand-alone E&P Positive Free Cash Flow (1) Consolidated Drilling and Completion Capex (2) $2,000 $1,500 D&C $2,477 D&C $1,684 D&C $1,472 D&C $1,300 D&C $1,300 D&C $1,500 D&C $1,500 $1,000 D&C Capital to be funded with E&P Cash Flow (1) $500 $0 ($500) ($757) ($358) ($150) ($1,484) ($1,000) ($1,500) 2014A 2015A 2016A 2017 Consensus 2018 Target 2019 Target 2020 Target Note: E&P cash flow represents E&P cash flow from operations plus AM distributions from condensed consolidating statement of cash flows in Antero Resources 10-K. (1) E&P free cash flow represents AR stand alone cash flow from operations, plus distributions from LP ownership in AM, plus earn out payments associated with water drop-down ($125 MM in each of 2019 and 2020) less stand-alone D&C capex which includes water fees paid to AM for completions which are capitalized on stand-alone basis. (2) Consolidated D&C capex excludes water fees paid to AM for completions. 18
20 Net Production (Bcfe/d) 3 Attractive Long Term Outlook Antero is now well positioned to generate free cash flow and peer leading growth Antero Resources Stand-alone E&P Long-Term Targets (1) 6.0 Stand-alone E&P Leverage Net Production (Actual) Net Production (Guidance) Net Production (Target) 4.5x 4.0x Reduce Capex & Leverage x x x Target Leverage in Low 2x x 3.0x 2.5x 2.0x 1.5x 1.0x 0.5x Stand-alone E&P Leverage Generate Free Cash Flow Optionality to Return Capital to Shareholders A 2015A 2016A 2017 Guidance 2018 Target 2019 Target 2020 Target 0.0x (1) Assumes WTI price of $54 and Nymex Henry Hub price of $
21 20 3 More Conservative Financial Policy New $4.5 Billion Credit Facility with $2.5 Billion in Lender Commitments - Downsized lender commitments by $1.5 billion due to reduced need for bank capital - Supported by $4.5 billion borrowing base - Credit facility includes fall away covenants (interest coverage ratio and proved PV-9 to total debt ratio) triggered if and when Antero is assigned an investment grade rating - No leverage test Financial Policy Overview Accelerate trend towards investment grade quality current corporate ratings Ba2/BB Maintain conservative leverage profile below 3.0x near-term (on stand-alone basis) with medium-term target of low 2x leverage Fund drilling and completion capital with stand-alone upstream cash flow from operations (including AM distributions and earn-out payments from water business sale in 2015) Continue to hedge over a rolling five to six year period to support consistent production development into long-term processing and firm transportation commitments, smoothing volatile oil and gas prices Maintain stand-alone AR liquidity of at least ~$1 billion on $2.5 billion credit facility
22 Cash Proceeds (SMM) 4 Midstream Driving Value for AR Since Inception Midstream integration has provided tremendous value to AR shareholders and the go-forward upside is very attractive Antero Midstream Return on Investment for AR (Pre-tax) (2) $7,000 $6,000 $5,000 $4,000 $3,000 $2,000 $1,000 $0 $1,150 AM IPO (2014) $795 $179 Sale of Water Business (2015) Sale of AM Units (2016) AM Distributions to AR (1) $311 $320 Sale of AM Units (9/6/17) AM Distributions Received as of 9/30/17 $2,755 Total Proceeds to Date $250 Expected Earnout Payments (2019E-2020E) $3,118 Pre-tax Value of AM Units Held by $31.53 (9/30/17) AM Share Price Value $6, x ROI Pre-tax Cumulative Value of Antero Midstream (2) $300 $250 $200 $150 $100 $50 $- $89 $ A 2016A 2017E 2018E 2019E 2020E AM price per unit After-tax value of AM units held by AR ($Billion) (3) Note: Represents distributions declared during fiscal year ended December 31 based on Antero Midstream guidance and long-term distribution growth targets. 1. Represents distribution growth targets for AR owned units through As of 9/30/2017, AR owns 98.9 million AM units. 2. Midstream proceeds received by AR to date plus market value of AR s 53% ownership of AM divided by the approximate $1.3 billion of AR capital invested at time of AM IPO. 3. After-tax using 38% federal and state tax rate and $1.5 billion of AR NOLs. Value per AR share $29 $2.3 $7 $32 $2.5 $8 $35 $2.7 $9 $38 $2.9 $9 $41 $3.1 $10 Consensus AM Price Target: $41 21
23 Antero Midstream Asset Overview Midstream Infrastructure (In Service) Gathering Pipelines (Miles) 341 Compression Capacity (MMcf/d) 1,600 Condensate Pipelines (Miles) 19 Processing Plant (MMcf/d) 400 Fractionation Plant (Bbl/d) 20,000 Fresh Water Pipelines (Miles) 323 Fresh Water Impoundments 38 Regional Pipeline Capacity (Bcf/d) 1.4 Antero Clearwater Facility (Bbl/d) (1) 60,000 Antero Clearwater Facility Sherwood Processing Complex Compressor Station Antero Clearwater Facility Sherwood Processing Facility Stonewall Pipeline Gathering Pipelines Freshwater Delivery Pipelines` Antero Rig. 1. The Antero Clearwater Facility is scheduled to be placed into service in the fourth quarter of
24 4 Capturing the Midstream Value Chain Participating in the full value chain diversifies and sustains Antero s integrated business model $5.0 billion organic project backlog and ~$1.0 billion potential downstream investment opportunity set Upstream Downstream AM Assets AM/MPLX JV Assets Potential AM Opportunities ~$800 Million JV Project Backlog FRACTIONATION NGL PRODUCT PIPELINES TERMINALS & STORAGE (ETHANE, PROPANE, BUTANE) WELL PAD LOW PRESSURE GATHERING COMPRESSION HIGH PRESSURE GATHERING ~$4.2 Billion Organic Project Backlog GAS PROCESSING (50% INTEREST) REGIONAL GATHERING PIPELINE (15% INTEREST) Y-GRADE PIPELINE ~$1.0 Billion Downstream Investment Opportunity Set PDH PLANT LONG HAUL PIPELINE END USERS Note: Third party logos denote company operator of respective asset. INTERCONNECT 23
25 Key Drivers Behind Long Term Outlook NGL Exposure Drilling Inventory Capital Efficiency Attractive Returns Market Leading Exposure to NGLs Largest Core Liquids-Rich Drilling Inventory Improving Capital Efficiencies with Long Laterals and Higher Intensity Completions Attractive Half Cycle and Company-Wide Returns Cash Flow Growth Balance Sheet Disciplined Spending Within Upstream Cash Flow Solid Balance Sheet with Abundant Liquidity and Optionality 24
26 APPENDIX 25 25
27 Simplified Organizational Structure The combined enterprise value of the Antero complex is over $20 billion Affiliates Public Affiliates Public 32% 68% 80% 20% (NYSE: AR) Enterprise Value: $9.7 Bn 53% 100% Incentive Distribution Rights (IDRs) (NYSE: AMGP) Enterprise Value : $3.8 Bn Public 47% (NYSE: AM) Enterprise Value : $6.9 Bn Note: Enterprise Value as of 9/30/
28 Antero Resources Q4 17 and 2017 Guidance Key Operating & Financial Assumptions Key Variable Updated Previous Q Guidance (1) 2017 Guidance (1) 2017 Guidance Net Daily Production (MMcfe/d) 2,250 2,300 Net Residue Natural Gas Production (MMcf/d) 1,650 1,675 Net C3+ NGL Production (Bbl/d) 68,000 71,000 Net Ethane Production (Bbl/d) 26,000 27,000 Net Oil Production (Bbl/d) 6,000 7,000 Net Liquids Production (Bbl/d) 100, ,000 Natural Gas Realized Price Differential to NYMEX Before Hedging ($/Mcf) (2)(3) ($0.15) ($0.10) +$0.00 $0.10 ($0.20) ($0.15) Oil Realized Price Differential to NYMEX WTI Oil Before Hedging ($/Bbl) ($7.00) ($6.50) ($9.00) ($7.00) ($5.00) ($6.00) C3+ NGL Realized Price (% of NYMEX WTI) (2) 57.5% 62.5% 50% 55% 70% 75% Ethane Realized Price (Differential to Mont Belvieu) ($/Gal) $0.00 $0.00 $0.00 Consolidated EBITDAX ($MM): $410 - $440 Operating: Cash Production Expense ($/Mcfe) (4) $1.55 $1.65 Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.075 $0.125 G&A Expense ($/Mcfe) $0.15 $0.20 Capital Expenditures ($MM): Drilling & Completion $1,300 Land $200 Total Capital Expenditures ($MM) $1, Updated guidance per press release dated 11/02/ Includes Btu upgrade as Antero s processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average. 2. Based on strip pricing as of 10/27/ Includes lease operating expenses, gathering, compression and transportation expenses and production taxes. 27
29 Antero NGL Barrel (September Pricing) Antero realized $33.23/Bbl for its C3+ NGL barrels in September % of WTI oil price Including 21% ethane recovery, Antero realized $26.54 per barrel for its NGL barrels Antero is currently leaving approximately 123,000 Bbl/d of ethane in the gas stream NGL Barrel Composition & Pricing Ethane Rejection vs. Partial Recovery 100% 80% 60% 40% 20% 0% 1.5 GPM (1) Mont Belvieu 2.2 GPM C3: 57% C4: 9% IC4: 16% C5: 18% Ethane Rejection September 2017 Pricing Ethane (C2): Propane (C3): Butane (C4): IsoButane (IC4): $1.02 /Gallon Pentane (C5): $0.27/Gallon $0.89/Gallon $0.99/Gallon $1.17/Gallon 31% 39% 11% 7% 12% 21% Recovery $40.75/Bbl Mont Belvieu Pricing $31.63/Bbl $(7.52)/Bbl Northeast Differential $(5.09)/Bbl $33.23/Bbl Antero Realized Price ($/Bbl) $26.54/Bbl 67% % of WTI 53% 1. GPM represents gallons of NGLs per wellhead unproccessed Mcf. 28
30 MBbl/d) Ethane Fundamentals and Improving Pricing Ethane Outlook Significant domestic demand growth for ethane driven by construction and expansion of world-class steam crackers Antero is an anchor supplier (30 MBbl/d) to Shell s planned ethane cracker in Beaver Co, PA Ethane rejection rates will continue to decrease; however, ethane supply will be partially restricted by takeaway capacity U.S. is currently rejecting ~575 MBbl/d of ethane 240 MBbl/d of seaborne export capacity completed in 2016 provides additional outlet to global markets Additional 100 MBbl/d of demand via pipeline exports to Canada Historical Ethane Prices ($/Gallon) U.S. Domestic Steam Cracker Capacity (MBbl/d) Does not include ~350 MBbl/d of additional cracking capacity that has been proposed but has not reached FID $0.90 $0.80 $0.70 $0.60 $0.50 $0.40 $0.30 $0.20 $0.10 $- Ethane price collapse driven by U.S. shale development and inability to absorb supply until cracker demand increases in Shell - PA Source: Bentek and PIRA. 29
31 Most Attractive Firm Transport Portfolio in Appalachia Antero s natural gas takeaway position results in price certainty at attractive all-in netbacks to Nymex: Nymex less $0.42/Mcf expected , after deducting FT costs Antero Firm Transportation Portfolio ( ) $0.06 ($0.18) Antero Producing Areas Local Markets ($1.19) ($0.57) 13% of FT Portfolio $0.15/Mcf Average Cost (0.6 Bcf/d) Weighted Avg. FT Cost $0.46/Mcf Weighted Average Differential to Nymex (1) +$0.04/Mcf Premium with BTU Upgrade ($0.10) ($0.08) ($0.32) ($0.31) ($0.22) ($0.22) Note: Strip basis differentials to Nymex Henry Hub represents October 2017 and strip pricing, respectively as of October 27 th, 2017 for each index. 1. Weighted average differential to Nymex calculated using strip pricing as of October 27 th,
32 1. Pro forma for hedge monetization per press release dated 9/21/ Weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio; excludes impact of TCO basis hedges. 27,500 Bbl/d of propane hedged in 2017 and 2,000 Bbl/d hedged in ,000 Bbl/d of ethane hedged in 2017 and 3,000 Bbl/d of oil hedged in As of 9/30/2017. Includes impact from $750 million hedge monetization in September Largest E&P Gas Hedge Position in U.S. BBtu/d 2,400 2,000 1,600 1,200 Pro forma ~$1.2 billion mark-to-market unrealized gain based on 9/30/2017 prices with 2.9 Tcfe hedged from October 1, 2017 through year-end 2023 at $3.36 per MMBtu $3.58 $3.52 $3.50 $3.25 $3.00 $3.00 $2.91 $3.10 $3.05 $2.89 $2.84 $2.83 $2.85 $2.87 $62 MM 2,163 2,027 2,330 1, ~ 95% of 2017 Guidance Hedged Pro Forma Commodity Hedge Position (1) Hedged Volume Average Index Hedge Price (2) Current NYMEX Strip (3) Mark-to-Market Value (3) $323 MM $504 MM $202 MM $39 MM $42 MM $1 MM ~ 84% of 2018 Target Hedged Hedging is a key component of Antero s business model due to the large, repeatable drilling inventory $/Mcfe $5.00 Antero has realized $3.6 billion of gains on commodity hedges since 2008 with gains realized in 37 of last 39 quarters (3) $4.00 $3.00 $2.00 $1.00 $0.00 $MM $350.0 $280.0 $210.0 $140.0 $70.0 $0.0 Quarterly Realized Gains/(Losses) 1Q 08-3Q 17 $80 $83 $4 $5 $25 $34 $29 $28 $26 $12 $16 $17 $28 $29 $19 $25 $43 $59 $49 $48 $47 $54 $14 $1 $58 $78 $185 $196 $206 $324 $293 $270 $197 $190 $/Mcfe $811 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 $45 $31 ($1.00) ($2.00)
33 Source: SEC filings and company press releases. Peers include COG, EQT, RRC and SWN. 1. AR and EQT EBITDAX include distributions from midstream ownership. AR s EBITDAX excludes net marketing expense and the hedges put in place to support firm transportation. Cash costs for AR and EQT represent stand-alone GPT, production taxes, LOE and cash G&A. 2. Stand-alone EBITDAX divided by unprocessed units (Mcf) of production to normalize to dry gas production. 32 Peer Leading Stand-alone EBITDAX Margin On a Normalized Basis $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $- 3Q 2017 Stand-alone EBITDAX Margins (Pre-Hedge / Pre-Marketing)($/Mcfe) (1) Margin Rank: $3.26 Peer Rank: 3 $ $2.79 $2.78 $1.75 $1.56 $2.24 $1.13 $1.04 $1.22 $1.25 $2.05 $0.99 $1.23 AR Peer 1 Peer 2 Peer 3 Peer 4 EBITDAX GPT LOE Ad Valorem G&A Revenue Cash Costs Normalized Antero Stand-alone EBITDAX Margins 3Q 2017 ($/Unit) $ $1.80 $1.60 $1.40 $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $- $1.13 Raw EBITDAX Margin ($/Mcfe) Compare to Rich Gas Peers $0.21 Add Back Contract Underpayments (WGL & SJR) $1.34 Normalized EBITDAX Margin ($/Mcfe) Compare to Dry Gas Peers $0.32 Pre-Processing Unit Conversion $1.66 (2) (2) Normalized EBITDAX Margin ($/Mcf) Transitory Event
34 Single Well Economics: Half Cycle Cost Assumptions (1) SWE Cost Type Description of Cost Marcellus Utica Well Costs Drilling and completion costs Reflects average well costs across most Btu regimes for a 9,000 lateral Includes 50% AM water fees Includes $1.0 million for road, pad and production facilities. $8.4 mm (Assumes 1,750 lbs of proppant per lateral foot) $9.6 mm (Assumes ~2,000 lbs of proppant per lateral foot) Net Royalty Interest Reflects Antero s average NRI in the respective plays 84% 81% Midstream Gathering Fees Midstream compression fees (50% of AM fees, unless otherwise noted) Compression fuel ($0.10-$0.11 per Mcfe) $0.39 per Mcfe (Crestwood: $0.79 per Mcfe) $0.50 per Mcfe Processing Fees Operating Expenses Processing fees Plant fuel & electricity Transportation & fractionation Does not apply to wells under 1100 Btu Fixed costs (monthly expenses) Variable costs (gas and liquids) Numbers reflect averages across most Btu regimes $0.62 per Mcfe $0.67 per Mcfe $0.07 per Mcfe $0.08 per Mcfe FT (1) Fully utilized FT costs (including both demand and variable fees associated $0.52 per Mcfe $0.51 per Mcfe with expected production) Taxes Ad valorem and severance taxes vary depending on revenue and production $0.15 per Mcfe $0.07 per Mcfe (1) SWE cost assumptions reflect average costs per Mcfe on the first five years of the life of a well (2) SWEs exclude marketing expenses and related commodity hedge contracts that support Antero s firm transportation portfolio 33
35 ROR Total 3P Locations Single Well Economics: Marcellus In Ethane Rejection Assumptions Natural Gas $3 Oil $54 NGLs ~65% of Oil Price Drilling Plan 180% 160% 140% 120% 100% 80% 60% 40% 20% 0% Marcellus Well Economics and Total Gross Locations (1) 161% 132% 632 Highly-Rich Gas/ Condensate (4) 1,211 1,400 1, ,000 72% % 16% 18% % 11% 0 Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR at $3 Gas / $54 Oil - After Hedges ROR at $3 Gas / $54 Oil - Before Hedges Highly-Rich Gas/ Highly-Rich Classification Condensate (4) Gas (4) Rich Gas (4) Dry Gas (4) Modeled BTU EUR (Bcfe): EUR (MMBoe) : % Liquids: 32% 24% 10% 0% Lateral Length (ft): 9,000 9,000 9,000 9,000 Proppant (lbs/ft sand): 1,750 1,750 1,750 1,750 Well Cost ($MM): $8.4 $8.4 $8.4 $8.4 Bcfe/1,000 : HIGHLY Net F&D ($/Mcfe): $0.41 $0.45 RICH GAS $0.52 $0.55 Net Direct Operating DRY Expense GAS LOCATIONS ($/Mcfe): RICH GAS LOCATIONS $1.20 $1.27 LOCATIONS $1.57 $1.08 Transportation Expense ($/Mcfe): $0.41 $0.48 $0.57 $0.63 Pre-Tax NPV10 ($MM): $16.4 $9.5 $0.0 $0.3 Pre-Tax ROR: 132% 55% 10% 11% Payout (Years): Gross 3P Locations in BTU Regime (3) : 632 1, Pre-tax well economics reflect $3.00 Nymex Henry Hub natural gas prices, $54 WTI oil prices, and NGLs at ~65% of WTI. NGL prices are forecast to increase in 2018 relative to WTI due to projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship. 2. Pricing for a 1225 BTU y-grade ethane rejection barrel. 3. Undeveloped well locations as of 6/30/ SWE cost assumptions reflect average costs per Mcfe on the first five years of the life of a well 34
36 ROR Total 3P Locations Single Well Economics: Utica In Ethane Rejection Assumptions Natural Gas $3 Oil $54 NGLs ~65% of Oil Price % 60% 40% 20% % Drilling Plan % 23% Condensate Utica Well Economics and Gross Locations (1) 55% 44% 43% 30% Highly-Rich Gas/ Condensate Classification Condensate (4) Condensate (4) Highly-Rich Gas/ % % 20% 23% Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR at $3 Gas / $54 Oil - After Hedges ROR at $3 Gas / $54 Oil - Before Hedges EUR (Bcfe): EUR (MMBoe) : % Liquids 39% 30% 21% 16% 0% Lateral Length (ft): 9,000 9,000 9,000 9,000 9,000 Proppant (lbs/ft sand): 1,500 2,000 2,000 2,000 2,000 Well Cost ($MM): $8.7 $9.3 $9.9 $9.9 $9.9 Bcfe/1,000 : HIGHLY Net F&D ($/Mcfe): $1.09 $0.62 RICH $0.57 GAS $0.59 $0.62 Net Direct Operating DRY GAS Expense LOCATIONS ($/Mcfe): RICH GAS LOCATIONS $1.17 $1.27 LOCATIONS $1.36 $1.39 $0.74 Transportation Expense ($/Mcfe): $0.38 $0.45 $0.52 $0.55 $ Highly-Rich Gas (4) Rich Gas (4) Dry Gas (4) Modeled BTU Pre-Tax NPV10 ($MM): $3.3 $8.1 $5.5 $3.1 $4.0 Pre-Tax ROR: 23% 44% 30% 20% 23% Payout (Years): Gross 3P Locations in BTU Regime (3) : Pre-tax well economics reflect $3.00 Nymex Henry Hub natural gas prices, $54 WTI oil prices, and NGLs at ~65% of WTI. NGL prices are forecast to increase in 2018 relative to WTI due to projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship. 2. Pricing for a 1225 BTU y-grade ethane rejection barrel. 3. Undeveloped well locations as of 6/30/2017, pro forma for recent acreage acquisition. 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content. 4. SWE cost assumptions reflect average costs per Mcfe on the first five years of the life of a well 0 35
37 Strong Balance Sheet and High Flexibility Antero Resources (NYSE:AR) Antero Midstream (NYSE:AM) 9/30/2017 Debt Liquid Non-E&P Assets 9/30/2017 Debt (1) Liquid Assets Debt Type $MM Asset Type $MM Debt Type $MM Asset Type $MM Credit facility $25 Commodity derivatives $1,200 Credit facility $427 Cash $ % senior notes due ,000 AM equity ownership 3, % senior notes due % senior notes due ,100 Cash 21 Total $1,077 Total $ % senior notes due % senior notes due Total $3,475 Total $4,339 Asset Type Liquid non-e&p assets of $4.7 Bn significantly exceeds total debt of $3.5 billion Liquidity $MM Cash $21 Credit facility commitments (1) 2,500 Credit facility drawn - Credit facility letters of credit (700) Total $1,821 Only 28% of AM credit facility capacity drawn Pro Forma Liquidity Asset Type $MM Cash $2 Credit facility capacity 1,500 Credit facility drawn (427) Credit facility letters of credit - Total $1,075 Approximately $1.8 billion of liquidity at AR plus an additional $3.1 billion of AM units Approximately $1.1 billion of liquidity at AM 1. AR credit facility commitments of $2.5 billion, borrowing base of $4.0 billion. 2. AM equity value as of 9/30/
38 Liquidity & Debt Term Structure - Approximately $2.9 billion of combined AR and AM financial liquidity as of 9/30/ No leverage covenant in AR bank facility, only interest coverage and working capital covenants AR Liquidity Position ($MM) (1) AM Liquidity Position ($MM) (1) $4,000 $1,500 $3,000 $2,000 $1,000 $2,500 $25 $700 $21 $1,796 $1,200 $900 $600 $300 $1,500 $427 $0 $2 $1,075 $0 Credit Facility 9/30/2017 Bank Debt 9/30/2017 L/Cs Outstanding 9/30/2017 Cash 9/30/2017 Liquidity 9/30/2017 $0 Credit Facility 9/30/2017 Bank Debt 9/30/2017 L/Cs Outstanding 9/30/2017 Cash 9/30/2017 Liquidity 9/30/2017 New credit facilities for AR and AM have allowed Antero to extend its average debt maturity of to 2022 Debt Maturity Profile (1) AR Credit Facility AM Credit Facility AR Senior Notes AM Senior Notes $1,000 $427 $25 $750 $1,100 $650 $ As of 9/30/
39 Antero Resources Stand-alone EBITDAX Reconciliation AR Stand-alone EBITDAX Reconciliation ($ in millions) Three Months Ended LTM Ended 09/30/ /30/2017 EBITDAX: Operating loss $(114.1) $(235.8) Commodity derivative fair value losses Net cash receipts on settled derivatives instruments Depreciation, depletion, amortization and accretion Impairment of unproved properties and accretion Exploration expense Change in fair value of contingent acquisitions consideration (2.6) (15.8) Equity-based compensation expense Gain on sale of assets - (93.8) AM distributions net to AR ownership Segment Adjusted EBITDAX $284.3 $1,
40 Antero Resources EBITDAX Reconciliation EBITDAX Reconciliation ($ in millions) Quarter Ended LTM Ended 9/30/2017 9/30/2017 EBITDAX: Net income including noncontrolling interest $(90.0) $(197.3) Commodity derivative fair value gains Net cash receipts on settled derivatives instruments Gain of sale on assets - (97.6) Interest expense Loss on early extinguishment of debt Income tax expense (45.1) (160.5) Depreciation, depletion, amortization and accretion Impairment of unproved properties Exploration expense Equity-based compensation expense Equity in earnings of unconsolidated affiliate (7.0) (11.3) Distributions from unconsolidated affiliates Consolidated Adjusted EBITDAX $336.4 $1,
41 40 Antero Midstream EBITDA Reconciliation EBITDA and DCF Reconciliation Three months ended ($ in thousands) September 30, Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow: Net income $70,524 $80,893 Interest expense 5,303 9,311 Depreciation expense 26,136 30,556 Accretion of contingent acquisition consideration 3,527 2,556 Equity-based compensation 6,599 7,199 Equity in earnings from unconsolidated affiliate (1,544) (7,033) Distributions received from unconsolidated affiliates - 4,300 Adjusted EBITDA $110,545 $127,782 Interest paid (4,043) (20,572) Cash reserved for payment of income tax withholding upon vesting of Antero Midstream Partners LP equitybased compensation awards (1,000) (1,500) Cash to be received from unconsolidated affiliates 2,221 - Cash reserved for bond interest - 8,831 Maintenance capital expenditures (4,638) (16,000) Distributable Cash Flow $103,085 $98,541
42 3Q 2017 Segment EBITDAX and Capital Expenditures 1 2 Gathering and compression fees paid to Antero Midstream are included in Gathering, Processing & Transportation expense on stand-alone basis (eliminated on consolidated basis); Gathering and compression operating expenses borne by AM on stand-alone basis (included in GPT on consolidated basis) Water fees paid to Antero Midstream included in Drilling & Completion capital expenditures on stand-alone basis; water operating expenses borne by AM on stand-alone basis and AR on consolidated basis 3Q 2017 Segment EBITDAX and Capital Expenditures ($MMs) Revenues: Stand-alone EBITDAX : $284 Million (1) : $128 Million Exploration & Production Gathering & Processing Water Handling & Treatment Marketing Elimination of Intersegment Transactions Consolidated Total Third-Party $660 $7 $0 $51 - $718 Intersegment (191) - Gains on settled derivatives Total Revenue $722 $105 $93 $51 (191) $780 Cash operating expenses: Lease operating $24 - $52 - ($52) $23 Gathering, Processing & Transp. (3rd party) Gathering, Processing & Transp. (AM fees) (98) 10 Production Taxes G&A (before equity-based comp) (0) 36 Marketing Total Cash Operating Expenses $445 $15 $55 $79 ($150) $443 Segment Adjust EBITDAX $278 $90 $38 ($28) ($41) $336 Capital Expenditures: On consolidated basis, water fees are eliminated from D&C D&C (excluding water) $265 capital, - but water operating - expenses -are capitalized - $265 D&C (including water) (41) 52 Land / Acquisitions G&C / Water Infrastructure Total CapEx $415 $99 $48 $0 ($41) $ AR stand-alone EBITDAX represents E&P EBITDAX plus ~$35 million in distributions from AM ownership less net marketing expense. 41
43 42 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, The SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. EUR, or Estimated Ultimate Recovery, refers to Antero s internal estimates of per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer s Petroleum Resource Management System or the SEC s oil and natural gas disclosure rules. Condensate refers to gas having a heat content between 1250 BTU and 1300 BTU in the Utica Shale. Highly-Rich Gas/Condensate refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1225 BTU and 1250 BTU in the Utica Shale. Highly-Rich Gas refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and 1225 BTU in the Utica Shale. Rich Gas refers to gas having a heat content of between 1100 BTU and 1200 BTU. Dry Gas refers to gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.
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