Credit Suisse 22 nd Annual Energy Summit February 14, 2017

Transcription

1 Credit Suisse 22 nd Annual Energy Summit February 14, 2017

2 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, forwardlooking 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, 2015 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, 2015 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 and Antero Midstream Partners LP is denoted as AM in the presentation, which are their respective New York Stock Exchange ticker symbols. 1

3 ANTERO PROFILE Market Cap... $8.0 billion Enterprise Value (1)(2)... $13.8 billion LTM EBITDAX.... $1.4 billion Net Debt/LTM EBITDAX (2) 3.2x Net Production (3Q 2016) 1,875 MMcfe/d % Liquids... 26% 3P Reserves (3)..... % Natural Gas Tcfe 71% Net Acres (4) , Based on market cap as of 2/6/2017 plus net debt plus minority interest ($1.4 billion) on a consolidated basis. 2. Pro forma for $175 million AR PIPE transaction on 10/3/2016, $170 million AR acreage divestiture that closed on 12/16/2016 and $195 million AM unit offering on 2/6/2017 with gross proceeds of $198 million used to fund $155 million MPLX JV payment. AM credit facility as of 2/3/2017 per AM S-3 filing dated 2/6/2017 was $210 million prior to unit offering. 3. 3P reserves as of 12/31/2016, assuming ethane rejection. 4. Net acres as of 12/31/2016 pro forma for additional leasing and acquisitions. 2

4 DELIVERING ON OCTOBER 2013 IPO PROMISE At IPO (October 2013) Current Change Acreage: 431,000 Net Acres 624,000 Net Acres (5) +45% Leading consolidator since IPO adding ~200,000 net acres Net Production (1) : 458 MMcfe/d 1,875 MMcfe/d +309% LTM EBITDAX (2) : $457 Million $1,368 Million +199% 3P Reserves (3) : 27.7 Tcfe 46.4 Tcfe +68% Public Float (4) : 14% 68% +386% 1. Represents 2Q 2013 and 3Q 2016 net production, respectively. 2. Represents LTM EBITDAX as of 6/30/13 and 9/30/16, respectively. 3. 3P reserves are as of 12/31/2016, assuming ethane rejection. 4. Public float defined as portion of shares outstanding that are freely tradable excluding 57 million shares held by Warburg Pincus Funds, 16 million shares held by Yorktown Energy Funds and 26 million shares held by Antero NEOs. 5. Net acres as of 12/31/2016 pro forma for additional leasing and acquisitions. 3

5 A LEADING CONSOLIDATOR IN APPALACHIA 2016 Acquisitions and Recent Well Completions Southern Rich Average 2.0 Bcf / 1,000 Wellhead EUR Antero - 7 Well Average (Weigle East Pad) Advanced 1,500# Completion Wellhead: 2.0 Bcf/1,000 Processed: 2.5 Bcfe/1,000 C2 Recovery: 3.2 Bcfe/1,000 YE 2016 Reserves 81 PUD Locations 2.0 Bcf / 1,000 Wellhead EUR Type Curve Dry Gas Average 2.2 Bcf / 1,000 Wellhead EUR Antero - 4 Well Average (Hamilton Pad) Advanced 1,500# Completion Wellhead: 2.0 Bcf/1,000 Processed: 2.4 Bcfe/1,000 C2 Recovery: 3.0 Bcfe/1,000 Antero - 2 Well Average (Pierpoint Pad) Advanced 1,750# Completion Wellhead: 2.3 Bcf/1,000 Processed: 2.9 Bcfe/1,000 C2 Recovery: 3.7 Bcfe/1,000 Antero - 5 Well Average (Rock Run Pad) Advanced 1,750# Completion Wellhead: 2.0 Bcf/1,000 Processed: 2.5 Bcfe/1,000 C2 Recovery: 3.1 Bcfe/1,000 Antero - 6 Well Average (Cofor Pad #2) Advanced 1,500# Completion Wellhead: 2.1 Bcf/1,000 Processed: 2.5 Bcfe/1,000 C2 Recovery: 3.2 Bcfe/1,000 Acquired Acreage Districts with 3,000+ Antero Net Acres Antero Horizontal Marcellus Wells Industry Horizontal Marcellus Wells 4

6 OUTSTANDING 2016 RESERVE GROWTH (Tcfe) NET PROVED RESERVES (Tcfe) (1) Marcellus Utica RESERVE ADDITIONS Proved reserves increased 16% to 15.4 Tcfe Proved pre-tax PV-10 at SEC pricing of $6.7 billion, including $3.0 billion of hedge value Proved pre-tax PV-10 at strip pricing of $9.8 billion, including $1.3 billion of hedge value Booked 81 Marcellus PUD locations at new 2.0 Bcf/1,000 type curve 3P reserves increased 25% to 46.4 Tcfe 3P PV-10 at strip pricing of $16.7 billion, including $1.3 billion of hedge value All-in F&D cost of $0.52/Mcfe for 2016 Drill bit only F&D cost of $0.39/Mcfe for 2016 (Tcfe) NET PDP RESERVES (Tcfe) (1) Utica Marcellus Borrowing Base 5.6 $4.75 Bn $550 MM $Bn Proved Probable Possible 3P RESERVES BY VOLUME 2016 (1) 29.1 Tcfe Probable 1.9 Tcfe Possible 46.4 Tcfe 3P 15.4 Tcfe Proved 96% 2P Reserves , 2013, 2014 and 2015 reserves assuming ethane rejection. In 2016, it is assumed that 554 MMBbls of ethane recovered to meet ethane contract SEC prices were $2.56/MMBtu for natural gas and $50.13/Bbl for oil on a weighted average Appalachian index basis year average strip prices are NYMEX $3.13/Mcf, WTI $56.84/Bbl, propane $0.68/gal and ethane $0.30/gal. 5

7 PROCESSING AND FRACTIONATION JOINT VENTURE On 2/6/17, Antero Midstream (NYSE: AM) and MPLX (NYSE: MPLX) announced the formation of a 50/50 joint venture for processing and fractionation infrastructure in the core of the liquids-rich Marcellus and Utica Shales Strategic Rationale Further aligns the largest core liquids-rich resource base with the largest processing and fractionation footprint in Appalachia Up to 11 additional processing plants 20,000 Bbl/d of capacity at Hopedale 3 fractionation facility with an option to invest in future fractionation capacity Over $800 million project inventory through 2020 (net to AM), including ~$155 million contribution upfront for processing and fractionation infrastructure Fits with AM s full value chain organic growth strategy Long-term 100% fixed-fee revenues Ohio Condensate Stabilization Cadiz Complex Seneca Complex Seneca In Service (1) Hopedale Fractionation Complex Hopedale 1 2 In Service Hopedale 3 In Service 60,000 Bbl/d Potential Future Capacity Houston Complex Majorsville Complex Keystone Complex Harmon Creek Complex Significant MVCs on processing Full build out EBITDA multiple of 4x 6x 15% 18% IRR Improved visibility throughout vertical value chain and ability to deploy just-in-time capital supporting Antero Resources rich gas development Pro forma for the JV, AM has $2.7 billion of organic growth opportunities from at attractive 4x 6x investment to EBITDA multiples 1. RigData as of 01/06/17. Rigs drilling in rich gas areas only. 2. New West Virginia site location still to be determined. New Complex (2) Future Processing TBA 1 6 Potential 1,200 MMcf/d Mobley Complex Sherwood Complex Sherwood In Service 1,200 MMcf/d Sherwood 7 1Q MMcf/d Sherwood 8 3Q MMcf/d Sherwood 9 1Q MMcf/d Sherwood Potential 400 MMcf/d 6

8 2017 GUIDANCE AND LONG TERM OUTLOOK Production Growth: (Bcfe/d) $ Guidance Long Term Targets Hedged Volume Hedged Price ($/Mcfe) Net Daily Production $3.47 $3.91 $3.70 $ E 2017E 2018E 2019E 2020E 2017 Guidance Long Term Targets D&C Capital: Consolidated Cash Flow from Operations (1) : $1.3 Billion Modest annual increases within Cash Flow from Operations In line with D&C capital Doubling by 2020 Leverage (1) : 3.0x to 3.5x Declining to mid-2s by 2018 Hedging: 96% Hedged at $3.47/Mcfe 58% Hedged at $3.76/Mcfe 1. Assuming 12/31/ year strip pricing averaging $3.12/MMBtu for natural gas and $56.23/Bbl for oil. Consolidated cash flow from operations includes realized hedge gains. 7

9 KEY DRIVERS BEHIND LONG TERM OUTLOOK Drilling Inventory Deep Drilling Inventory Capital Efficiency Improving Capital Efficiencies Well Performance Price Realizations Strong Well Performance Visible, Attractive Price Realizations Cash Flow Growth Significant Cash Flow Growth and Declining Leverage Profile Balance Sheet Solid Balance Sheet with Abundant Liquidity 8

10 DRILLING INVENTORY LARGEST CORE ACREAGE POSITION IN APPALACHIA Antero has the largest core acreage position in Appalachia, particularly as it relates to undeveloped acreage and is running 38% of the total rigs in liquids-rich core areas Leading Appalachia Core Acreage Position Core Net Acres Dry 575 AR has dominant liquids-rich position Core Net Acres Liquids-Rich Developed Acreage Marker P9 P11 P AR P1 P2 P3 P4 P5 P6 P8 P7 P10 Source: Core outlines based upon Antero geologic interpretation, well control and peer acreage positions based on investor presentations, news releases and 10-K/10-Qs. Rig information per RigData as of 2/3/2017. Competitor leasehold positions analyzed include Ascent (private), CHK, CNX, COG, CVX, ECR, EQT, GPOR, NBL, RICE, RRC, SWN. 9

11 DRILLING INVENTORY LARGEST CORE DRILLING INVENTORY IN SOUTHWEST APPALACHIA Antero has ~2x as many core drilling locations of its nearest competitor and ~3x as many core liquids-rich locations as nearest competitor Undrilled Core Southwest Marcellus and Utica Locations (1)(2) 4,000 3,500 3,443 Core - Dry Locations Core - Liquids Rich Locations 3,000 Undrilled Locations 2,500 2,000 1,500 1,000 1,826 1,104 1, Avg. Lateral Length AR P2 P7 P8 P4 P9 P12 P11 P3 P1 8,092 6,381 7,584 8,750 5,923 6,698 9,262 8,690 8,398 8, Peers include Ascent, CHK, CNX, EQT, GPOR, NBL, RICE, RRC, SWN. 2. Based on Antero technical review of geology and well control to delineate core areas and peer acreage positions both drilled and undrilled. Excludes Northeast Pennsylvania core locations. 10

12 DRILLING INVENTORY LOW BREAKEVEN PRICES Antero has a 15 year drilling inventory at $3.00 natural gas or less at the 2017 development pace (170 completions), excluding 2,000 incremental locations representing additional 15 Tcf risked resource Cumulative 3P Drilling Inventory Breakeven Prices at 20% ROR (1)(2) 4,000 3,500 3,000 Marcellus Rich Gas Marcellus Dry Gas Ohio Utica Rich Gas Ohio Utica Dry Gas ~70% of total locations generate a 20% rate of return at $3.00/Mcf Nymex or less 3,419 3,611 Average Lateral Length 3,645 Ohio Utica Dry Gas Ohio Utica Rich Gas 2,500 2,536 Marcellus Dry Gas Locations 2,000 29% of total locations generate a 20% rate of return at $2.00/Mcf Nymex or less 1,756 1,500 1,000 1,060 Marcellus Rich Gas ,229 9,109 8,630 < $1.50 < $2.00 < $2.50 < $3.00 < $3.50 < $4.00 $4.00 NYMEX Natural Gas Price ($/MMBtu) 1. Marcellus and Utica 3P locations as of 1/31/2017. Categorized by breakeven price solving for a 20% BTAX ROR and assuming 50% of AM fees due to AR ownership of AM. Assumes strip pricing for oil which averages $56.00/Bbl over the next five years and 50% of WTI for NGLs ($27/Bbl). 2. Includes 3,443 total core locations plus 202 non-core 3P locations, including 211 3P locations with laterals less than 4,000 feet. 8,607 8,177 8,062 < 8,253 11

13 DRILLING INVENTORY MULTI-YEAR GROWTH ENGINE Antero plans to develop over 800 horizontal locations in the Marcellus and Ohio Utica by the end of the decade while utilizing less than 25% of its current 3P drilling inventory Average Lateral Length ~8,998 feet Planned Antero Well Completions by Year Marcellus Rich Gas Marcellus Dry Gas Utica Rich Gas Ohio Utica Dry Gas Ohio Utica Dry Gas Ohio Utica Rich Gas Marcellus Dry Gas Marcellus Rich Gas 50 9, E 2018E 2019E 2020E CURRENT UNDRILLED 3P LOCATIONS BY BTU REGIME (1) ESTIMATED YE 2020 UNDRILLED 3P LOCATIONS 13% Utica Rich Gas 469 Locations 16% Marcellus Dry Gas 572 Locations 64% Marcellus Rich Gas 2,351 Locations 7% Ohio Utica Dry Gas 253 Locations Expect to place >800 new Marcellus and Ohio Utica wells to sales by YE % Utica Rich Gas 303 Locations 20% Marcellus Dry Gas 562 Locations 63% Marcellus Rich Gas 1,803 Locations 6% Ohio Utica Dry Gas 172 Locations 3,645 Locations 2,840 Locations 1. Marcellus and Utica 3P locations as of 12/31/2016 pro forma for recent acreage acquisitions. Excludes WV/PA Utica Dry locations. 12

14 CAPITAL EFFICIENCY CONTINUOUS OPERATING IMPROVEMENT Driving drilling and completion efficiencies which continues to lower well costs Drilling Days Dramatic Decrease in Drilling Days Drilling longer laterals while reducing drilling days by 60% Q Record Record Drilling Longer Laterals 9 Stages per Day Increasing Completion Stages per Day More efficient completions ( zipper fracs ) are increasing stages per day Q Record Declining Well Costs per 1, Lateral Length (feet) 11,000 9,000 7,000 5,000 3,000 1,000 (1,000) 8,052 Continuing to be an industry leader in drilling longer laterals 8,910 8,903 8,543 8,575 9,221 14, Q Record Well Cost per 1,000 of Lateral ($MM) $2.00 $1.50 $1.00 $0.50 $0.00 Reducing well costs by ~35% since 2014 $1.55 $1.34 $1.36 $1.18 $0.99 $ Q

15 CAPITAL EFFICIENCY DRAMATICALLY LOWER F&D COST Enhanced completion designs have contributed to improved recoveries and capital efficiency Increasing Proppant Per Foot Increasing Water Per Foot Pounds of Proppant Per Foot 2,400 2,000 1,600 1, Higher proppant concentration has contributed to higher recoveries 1,267 1,298 1,165 1,163 2,035 1, Q ,555 Record Barrels of Water Per Foot Higher proppant concentration requires increased water usage Q Record Processed EUR per 1,000' of Lateral (Bcfe) Increasing EUR per 1,000 (Bcfe) (1)(2) Since 2014, Antero has increased EURs by 33% in the Marcellus and 20% in the Utica Q Record F&D per Mcfe $1.50 $1.00 $0.50 $0.00 Much Lower F&D Cost per Mcfe (2)(3) $0.88 $1.28 Bottom line: F&D costs per Mcfe have declined by 52% in the Marcellus and 46% in the Utica since 2014 $0.73 $0.94 $0.41 $ Q Based on statistics for wells completed within each respective period. 2. Ethane rejection assumed. 3. 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. 14

16 CAPITAL EFFICIENCY LONGER LATERALS IMPROVE ROR Antero s typical Marcellus well in 2017 will have a 9,200 lateral length, an EUR of 22.3 Bcfe, including 857 MBbls of NGLS and 66 MBbls of oil and cost $7.7 MM (1) 6,500 Foot Lateral (2) Antero 2016 average lateral: 9,000 feet Pre-Tax Economics ROR (%) 63% PV-10 ($MM) $10.0 Breakeven Nymex ($/MMBtu) $1.09 Dev. Cost ($/Mcfe) $0.42 Pre-Tax Economics ROR (%) 78% PV-10 ($MM) $15.0 Breakeven Nymex ($/MMBtu) $0.89 Dev. Cost ($/Mcfe) $0.38 AR Variance to Peer Average ROR (%) +15% PV-10 ($MM) +$5.0 Breakeven Nymex ($/MMBtu) ($0.20) Dev. Cost ($/Mcfe) ($0.04) 6,500 9,000 NOTE: Assumes 2.0 Bcf/1,000 type curve for the Antero Marcellus Highly-Rich Gas/Condensate ( Btu). 1. Assumes ethane rejection. 2. Represents 2016 Marcellus average for peers including: CNX, COG, EQT, RICE, RRC based on public guidance. 15

17 CAPITAL EFFICIENCY DRIVING CASH FLOW GROWTH Antero s capital efficiency has reduced outspend while maintaining its growth profile and is expected to deliver cash flow from operations higher than drilling and completion capex through 2020 $MM $800 $700 $600 $500 $400 $300 $200 $100 $753 1,265 D&C Capital Consolidated Cash Flow From Operations Production (MMcfe/d) $199 1,485 1,484 1,506 1,497 $569 $351 $440 $341 $239 $246 $301 $170 1,758 1,762 $395 $340 $315 $239 1,875 D&C within cash flow from operations $327 $300 2,000 1,800 1,600 1,400 1,200 1, Production (MMcfe/d) $0 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 Rigs

18 CAPITAL EFFICIENCY MITIGATING SERVICE COST EXPOSURE Antero has limited its exposure to service cost increases over the next few years through long-term agreements with drilling contractors and completion services Drilling Rigs Contracted Rigs Rigs Needed E 2018E 2019E (1) Completion Crews Since 2014, approximately 50% of the reduction in well costs was driven by efficiency gains and 50% through service cost reductions Contracted Completion Crews E 2018E 2019E 1. Excludes intermediate rigs used to drill to kick-off point. Completion Crews Needed 2 By maintaining drilling and completion momentum during the commodity downturn, Antero had the opportunity to lock in many of the best crews at attractive long-term contracted rates 17

19 WELL PERFORMANCE OPTIMIZING WELL RECOVERIES WITH HIGHER INTENSITY COMPLETIONS Marcellus Cumulative Natural Gas Production Curves (Normalized to 9,000 Lateral) Cumulative Wellhead Gas Production (MMcf) 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 Vintage E Change Stage Length (Feet) (33)% Proppant (lb/ft) 913 1,146 1,500 64% Water (Bbl/ft) % Wellhead EUR/1,000' % 2016 Advanced Completions Cumulative Natural Gas Production (1) Year Bcf/1,000 at the wellhead equates to 2.5 Bcfe/1,000 after processing assuming 1275 Btu gas, and 3.2 Bcfe/1,000 processed assuming full ethane recovery Wellhead EUR/1,000 Year Includes condensate at 6:1 gas/condensate ratio. Days 18

20 WELL PERFORMANCE MARCELLUS COMPLETION EVOLUTION Antero plans to continue to increase proppant intensity in 2017 primarily utilizing 1,750 and 2,000 lb/ft completions in the Marcellus 3,000 2,750 Per Well Frac Size Design (lb/ft) 1,250 Testing higher proppant loads in 2017 EUR impact to come 2,500 1,500 Antero Completion Size (lbs/ft) 2,250 2,000 1,750 1,500 1,250 1,000 1,750 2,000 2,500 Supports 2.0 Bcf/1,000 type curve and 81 PUD bookings at YE Supports 1.7 Bcf/1,000 type curve and historical reserve bookings Completion Start Date 19

21 WELL PERFORMANCE IMPROVING MARCELLUS RETURNS Antero expects to complete 114 wells in 2017 in the highly-rich gas regimes where 2016 advanced completions are tracking 2.0 Bcf/1,000 of lateral Highly-Rich Gas/Condensate (1) Highly-Rich Gas (1) Pre-Tax PV-10 Pre-Tax ROR Pre-Tax PV-10 Pre-Tax ROR Pre-Tax PV-10 $20.0 $15.0 $10.0 $5.0 $0.0 Wellhead Bcf/1,000 : Processed Bcfe/1,000 : 67% $ % $ % $ Planned 2017 Completions 1. See Appendix for SWE assumptions and 12/31/2016 pricing. 2. Assumes ethane rejection. 140% 120% 100% 80% 60% 40% 20% 0% Pre-Tax PV-10 $20.0 $15.0 $10.0 $5.0 $0.0 Wellhead Bcf/1,000 : Processed Bcfe/1,000 : 2016 Advanced Completion Results 41% $ % 75% $9.7 $ Planned 2017 Completions 120% 100% 80% 60% 40% 20% 0% Pre-Tax ROR 20

22 PRICE REALIZATIONS ANTERO FIRM TRANSPORT MITIGATES NORTHEAST BASIS RISK Antero Expected Pricing: ($/MMBtu) Forecasted Realized Natural Gas Price (1) Nymex + ~$ Average FT Expense (operating expense) $(0.46) - Average Net Marketing Expense $(0.10) = Net Natural Gas Price vs. Nymex $(0.46) Dom South and Tetco M2 Realized Natural Gas Strip (2) Nymex - $(0.84) Antero Pricing Relative to Northeast Differential +$0.38 Even with the relative tightening of local basis indicated in the futures market, Antero s expected netback through the end of the decade (after deducting FT and marketing costs) is $0.38 per MMBtu higher than the local Dominion South and TETCO M2 indices 1. Based on management forecast of net production, BTU of future production and the 2017 through 2020 futures strip as of 12/31/16 for various indices that Antero can access with its firm transport portfolio. 2. Assumes 50/50 DOM S and TETCO M2 split, from ICE futures as of 12/31/

23 PRICE REALIZATIONS FAVORABLE PRICE INDICES Antero expects to realize a premium to NYMEX gas prices before hedges through 2020 ($/Mcf) (1) 2016E 2017E Target $2.46 $3.63 $2.96 Basis Differential to NYMEX (1) $(0.20) $(0.29) $(0.17) - $(0.22) BTU Upgrade (2) $0.23 $0.34 $0.32 Realized Gas Price $2.49 $3.68 $ $3.11 Premium to Nymex without Hedges +$0.03 +$0.05 $ $0.15 Estimated Realized Hedge Gains $1.91 $0.01 $0.60 Realized Gas Price with Hedges $4.40 $3.69 $ $3.71 Premium to NYMEX with Hedges +$1.94 +$0.06 +$ $ Based on 12/31/2016 strip pricing. 2. Based on BTU content of residue sales gas. 22

24 PRICE REALIZATIONS NGL GROWTH AND EXPOSURE ANTERO IS THE LARGEST C3+ LIQUIDS PRODUCER IN THE NORTHEAST NGL Production Growth by Purity Product (Bbl/d) (Bbl/d) 160, , ,000 Propane Revenue ($MM) $600 $500 $400 $300 $200 Propane Revenue Sensitivity ($0.75/Gal) ($0.65/Gal) ($0.55/Gal) Propane Production (MBbl/d) Natural Gasoline (C5+) Normal Butane (nc4) Ethane (C2) IsoButane (ic4) Propane (C3) C3+ Production 100,000 80,000 MB Spot C3 = $0.80/Gal MB 2017 Strip C3 = $0.69/Gal 68,500 86,500 C2 Ethane 19, % Y-O-Y Long-Term Growth Target 60,000 40,000 20,000 19,500 42,500 C2 Ethane 15,000 C3 nc4 ic Guidance 2017 Target 2018E Target 2019E Target 1. Assumes 15,000 Bbl/d of ethane and 53,500 Bbl/d of C3+, respectively, per guidance release on 9/6/2016. C3+ barrel composition based on 3Q16 actual barrel composition. 2. C3+ production growth midpoint guidance of 26%. Excludes condensate. 3. Assumes midpoint of 20 22% year-over-year equivalent production growth in For illustrative purposes C3+ production growth assumed at same rate. (1) (2) C5+ (3) (3) (3) 2020E Target 23

25 PRICE REALIZATIONS HIGH LEVERAGE TO LIQUIDS PRICES AND LIMITED DOWNSIDE EXPOSURE TO NATURAL GAS PRICES Antero has hedged only 8% of its 3P reserve base leaving significant cash flow upside to commodity price improvements Cumulative EBITDAX Liquids Pricing Exposure % 120% 100% 80% 60% 40% 20% 100% $56 Oil 12/30/16 Strip 119% 126% 113% 106% $60 Oil $65 Oil $70 Oil $75 Oil Cumulative EBITDAX Natural Gas Pricing Exposure % 100% 100% 102% 104% 106% 108% 75% 50% 25% $3.09 Gas 12/30/16 Strip $3.25 Natural Gas $3.50 Natural Gas $3.75 Natural Gas Note: For natural gas pricing sensitivity, oil prices assume strip pricing as of 12/31/16. For oil pricing sensitivity, natural gas prices based on strip pricing as of 12/31/16. $4.00 Natural Gas 24

26 PRICE REALIZATIONS HIGHEST EBITDAX & MARGINS AMONG APPALACHIAN PEERS Antero has extended its lead among Appalachian Basin peers in both EBITDAX and EBITDAX margin Quarterly Appalachian Peer Group Consolidated EBITDAX ($MM) (1) $500 $400 $300 $291 $308 Among Appalachian peers, AR has ranked in the top 2 for the highest EBITDAX and EBITDAX margin for the sixth straight quarter $355 $332 $373 Y-O-Y AR: $82MM Peer Avg: $23MM NYMEX Gas: 1% NYMEX Oil: 3% $200 $100 $0 $3.00 $2.50 $2.00 P5 AR P2 P3 P4 P6 P1 3Q 2015 $1.97 P2 AR P5 P3 P4 P6 P1 AR P2 P5 P6 P3 P1 P4 4Q Q 2016 $2.03 $2.03 AR P2 P6 P3 P4 P5 P1 2Q 2016 Quarterly Appalachian Peer Group EBITDAX Margin ($/Mcfe) (1) $1.86 AR P2 P5 P3 P6 P4 P1 P7 3Q 2016 AR Peer Group Ranking Improving Over Time #2 #2 #1 #1 #1 $1.91 Y-O-Y AR: 3% Peer Avg: 3% NYMEX Gas: 1% NYMEX Oil: 3% $1.50 $1.00 $0.50 $0.00 P6 AR P3 P5 P4 P2 P1 3Q 2015 P6 AR P3 P2 P1 P5 P4 AR P6 P2 P1 P3 P4 P5 AR P6 P1 P3 P4 P2 P5 AR P6 P2 P7 P3 P1 P4 P5 4Q Q Q Q 2016 AR Peer Group Ranking Top Tier #2 #2 #1 #1 #1 Note: AR, RICE and EQT EBITDAX margin excludes EBITDA from midstream MLP associated with noncontrolling interest. AR consolidated EBITDAX margin for 3Q 2016 was $2.16/Mcfe. CNX excludes EBITDAX contribution from coal operations. 1. Source: Public data from form 10-Qs and 10-Ks and Wall Street research. Peers include COG, CNX, EQT, GPOR, RICE, RRC and SWN where applicable 25

27 SIGNIFICANT CASH FLOW GROWTH SIGNIFICANT CASH FLOW GROWTH DRIVES DECLINING LEVERAGE PROFILE Visible cash flow growth given hedges, firm transportation portfolio, and capital efficient longterm development plan targeting 20% to 22% production CAGR $3,000 Consensus EBITDAX (1) Production Guidance (Bcfe) 4.5 Consensus EBITDAX Estimates ($MM) $2,500 $2,000 $1,500 $1,000 $500 Production Targets (Bcfe) Leverage Targets $1,495 $1, $2,220 Declining Leverage Production Guidance / Targets (Bcfe/d) Net Debt/LTM EBITDAX Targets $0 1. Bloomberg Consensus EBITDAX estimates as of 1/31/ E 2017E 2018E 2019E 2020E

28 Antero Midstream (NYSE: AM) Overview 27

29 2017 GUIDANCE AND LONG TERM TARGETS Distribution Growth (1) : $3.50 $3.00 $2.50 Guidance Long Term Targets $2.00 $1.50 $1.00 $0.50 $1.03 $1.33 $ A 2016E 2017E 2018E 2019E 2020E Updated 2017 Guidance (2) Long-Term Targets DCF Coverage: 1.30x 1.45x > 1.25x EBITDA ($MM): $520 $560 Peer Leading Growth Capital Expenditures ($MM): $800 $2.7 Billion organic opportunity set from Leverage: 1. Assumes midpoint of 2017 distribution growth guidance and long-term target. Future distributions subject to Board approval. 2. Per press release dated 2/6/ x 2.5x Low 2-times range 28

30 ANTERO MIDSTREAM GATHERING AND COMPRESSION ASSET OVERVIEW Gathering and Compression Assets Gathering and compression assets in core of rapidly growing Marcellus and Utica Shale plays Acreage dedication of ~528,000 gross leasehold acres for gathering and compression services Additional stacked pay potential with dedication on ~278,000 gross acres of Utica deep rights underlying the Marcellus in WV and PA 100% fixed fee long term contracts Projected Gathering and Compression Infrastructure Marcellus Shale Utica Shale Total YE 2016E Cumulative Gathering/ Compression Capex ($MM) (1) $1,216 $482 $1,698 Gathering Pipelines (Miles) Compression Capacity (MMcf/d) 1, ,135 Condensate Gathering Pipelines (Miles) E Gathering/Compression Capex Budget ($MM) (2) $255 $95 $350 Gathering Pipelines (Miles) Compression Capacity (MMcf/d) Based on 2016 capital budget. 2. Includes both expansion capital and maintenance capital. 29

31 ANTERO MIDSTREAM ADVANCED WASTEWATER TREATMENT ASSET OVERVIEW Antero has contracted with Veolia to build the largest advanced wastewater treatment complex in the world for oil and gas produced water Advanced Wastewater Treatment Veolia will build and operate, and Antero will fund and own the Clearwater facility Will treat and recycle AR produced and flowback water Creates additional year-round water source for completions Will have capacity for significant third party business Advanced Wastewater Treatment Complex Estimated capital expenditures ($ million) (1) ~$275 Standalone EBITDA at 100% utilization (2) ~$55 $65 Implied investment to standalone EBITDA build-out multiple ~4x 5x Estimated per well savings to Antero Resources ~$150,000 Estimated in-service date Late 2017 Operating capacity (Bbl/d) 60,000 Operating agreement 20 Years, Extendable (Bbl/d) 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 Illustrative Produced & Flowback Water Volumes Antero Clearwater Advanced Wastewater Treatment Capacity (Bbl/d) Produced/Flowback Volumes (Bbl/d) 3 rd Party Recycling and Well Disposal Capacity for third party business Antero Advanced Wastewater Treatment Antero Produced Water Services and Freshwater Delivery Business Well Pad Antero Advanced Wastewater Treatment Freshwater delivery system Well Pad Flowback and produced Freshwater Water Salt Marketable byproduct Producing Calcium Chloride Integrated Water Business Marketable byproduct used in oil and gas operations 1. Includes capital to construct pipeline to connect facility to freshwater delivery system. Includes $10 million that AR agreed to fund in the drop down transaction. 2. Standalone EBITDA projection assumes inter-company fixed fee for recycling of $4.00 per barrel and 60,000 barrels per day of capacity. Does not include potential sales of marketable byproducts. Completion Operations 30

32 KEY ATTRIBUTES PROCESSING & FRACTIONATION JV Aligns largest core liquids-rich resource base (AR) with the largest processing & fractionation footprint (MPLX) in Appalachia JV secures over $800 million in organic project inventory for AM for 2017 to 2020 period JV processing volumes driven by AR production volumes JV fractionation volumes driven by both AR and third party producers Attractive expected mid to high-teens rates of return Diversifies AM s investment portfolio and cash flow contribution mix Initial JV facilities in-service and cash flow producing in 1Q Sherwood 7 processing and Hopedale 3 fractionation Accretive transaction for Antero Midstream Further strengthens long-term Antero relationship with MarkWest and now MPC/MPLX (Baa3/BBB-) to facilitate Northeast NGL infrastructure buildout 31

33 FULL MIDSTREAM VALUE CHAIN BUILDOUT Processing and fractionation infrastructure adds to AM s full value chain model Well Pad Condensate Gathering Stabilization Compression End Users Low Pressure Gathering End Users Terminals and Storage NGL Product Pipelines (Ethane, Propane, Butane, etc.) Fractionation Y-Grade Pipeline Gas Processing AM has option to participate in terminaling and storage projects offered to AR End Users AM Owned Assets Long-Haul Interstate Pipeline AM/MPLX JV Assets Inter Connect AM Option Assets 1. Acquired by AM from AR for a $1.05 billion upfront payment and a $125 million earn out in each of 2019 and Antero Midstream owns 15% ownership in Stonewall pipeline. Regional Gas Pipeline 15% Ownership Miles Capacity In-Service Stonewall Gathering Bcf/d Yes Pipeline (2) 32

34 OUTLOOK Macro Significant natural gas demand growth through 2020 Continued oil and NGL price recovery 20% to 25% production growth guidance for % to 22% production growth CAGR targets for Forecast a $0.05 to $0.15/Mcf premium to NYMEX natural gas prices through % of production targets hedged through 2020 at $3.76/MMBtu 24% to 26% liquids contribution to production Maintaining D&C spending within consolidated cash flow from operations through 2020 Declining leverage profile to mid 2s Investing $2.7 billion in midstream project inventory with AM through 2020, with upside exposure to full value chain opportunities Strong commitment to health, safety and environment 33

35 APPENDIX 34 34

36 ANTERO RESOURCES 2017 GUIDANCE Key Operating & Financial Assumptions Key Variable 2017 Guidance (1) Net Daily Production (MMcfe/d) 2,160 2,250 Net Residue Natural Gas Production (MMcf/d) 1,625 1,675 Net C3+ NGL Production (Bbl/d) 65,000 70,000 Net Ethane Production (Bbl/d) 18,000 20,000 Net Oil Production (Bbl/d) 5,500 6,500 Net Liquids Production (Bbl/d) 88,500 96,500 Natural Gas Realized Price Premium to NYMEX Henry Hub Before Hedging ($/Mcf) (2)(3) +$0.00 $0.10 Oil Realized Price Differential to NYMEX WTI Oil Before Hedging ($/Bbl) $(7.00) $(9.00) C3+ NGL Realized Price (% of NYMEX WTI) (2) 45% 50% Ethane Realized Price (Differential to Mont Belvieu) ($/Gal) $0.00 Operating: Cash Production Expense ($/Mcfe) (4) $1.55 $1.65 Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.075 $0.125 G&A Expense ($/Mcfe) $0.15 $0.20 Operated Wells Completed 170 Drilled Uncompleted Wells 30 Capital Expenditures ($MM): Drilling & Completion $1,300 Land $200 Total Capital Expenditures ($MM) $1, Guidance per press release dated 01/04/ Based on current strip pricing as of December 30, Includes Btu upgrade as Antero s processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average. 4. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes. 35

37 ANTERO MIDSTREAM 2017 GUIDANCE Key Operating & Financial Assumptions Key Variable Financial: 2017 Previous Guidance 2017 Updated Guidance (1) Net Income ($MM) $295 $335 $305 $345 Adjusted EBITDA ($MM) $510 $550 $520 $560 Distributable Cash Flow ($MM) $395 $435 $405 $445 Year-over-Year Distribution Growth 28% 30% 28% 30% DCF Coverage Ratio 1.30x 1.45x 1.30x 1.45x Operating: Gathering Pipelines (Miles) Compression Capacity Added (MMcf/d) Fresh Water Pipeline Added (Miles) Fresh Water Impoundments 4 4 Capital Expenditures ($MM): Gathering and Compression Infrastructure $350 $350 Fresh Water Infrastructure $75 $75 Advanced Wastewater Treatment $100 $100 Processing and Fractionation Joint Venture $275 Total Capital Expenditures ($MM) $525 $ Per press release dated 2/6/

38 3P RESERVES & RESOURCE AR COMBINED TOTAL 12/31/16 RESERVES Assumes Ethane Rejection Net Proved Reserves Net 3P Reserves (1) Strip Pre-Tax 3P PV-10 (2) 15.4 Tcfe 46.4 Tcfe $15.4 Bn Additional Unbooked Resource (3) 15 Tcfe Net Acres (4) 624,000 Undrilled 3P Locations (4) 3,645 OHIO UTICA SHALE Net Proved Reserves Net 3P Reserves Strip Pre-Tax 3P PV-10 (2) 2.0 Tcfe 6.8 Tcfe $2.4 Bn Net Acres 157,000 Undrilled 3P Locations (4) 722 MARCELLUS SHALE Net Proved Reserves 13.4 Tcfe Net 3P Reserves (1) 39.6 Tcfe Strip Pre-Tax 3P PV-10 (2) $13.0 Bn Net Acres (4) 467,000 Undrilled 3P Locations (4) 2,923 AR Marcellus Acreage AR Ohio Utica Acreage Rigs Running Avg. Appalachian Rig Count Note: 2016 SEC prices were $2.31/MMBtu for natural gas and $42.68/Bbl for oil on a weighted average Appalachian index basis. 1. SEC reserves as of 12/31/ P reserve pre-tax PV-10 based on annual strip pricing for first 10-years and flat thereafter as of December 31, Excludes hedge value of $1.3 billion. 3. Incremental net unrisked resource of 15 Tcfe supported by over 2,000 locations, including 600 Marcellus, 1,000 Upper Devonian and 400 deep Utica. 4. Net acres and locations pro forma for additional leasing and acquisitions year-to-date. 37

39 MARCELLUS SINGLE WELL ECONOMICS IN ETHANE REJECTION Assumptions Natural Gas 12/31/2016 strip Oil 12/31/2016 strip NGLs ~50% of Oil Price NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL (2) ($/Bbl) 2017 $3.61 $56 $ $3.14 $57 $ $2.87 $56 $ $2.88 $56 $ $2.90 $56 $ $2.93-$3.46 $57-$58 $30-$31 Marcellus Well Economics and Total Gross Locations (1) ROR 2017 Drilling Plan 120% 100% 80% 60% 40% 20% 0% 98% 93% 632 Highly-Rich Gas/ Condensate (5) 1. 12/31/2016 pre-tax well economics based on 1.7 Bcf/1,000 type curve for a 9,000 lateral, 12/31/2016 natural gas and WTI strip pricing for , flat thereafter, NGLs at ~50% of WTI thereafter, and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates include $1.2 million for road, pad and production facilities. 2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at ~50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship. 3. Undeveloped well locations as of 12/31/ Assumes standard completions (1,200 lbs/ft of proppant). 5. Assumes enhanced completions (1,500 lbs/ft of proppant). 1,030 65% 57% % 20% 13% 14% 0 Highly-Rich Gas (5) Rich Gas (4) Dry Gas (4) Total 3P Locations 12/31/2016 Strip Pricing - After Hedges 12/31/2016 Strip Pricing - Before Hedges Highly-Rich Gas/ Highly-Rich Classification Condensate (5) Gas (5) Rich Gas (4) Dry Gas (4) Modeled BTU EUR (Bcfe): EUR (MMBoe) : % Liquids: 33% 24% 12% 0% Lateral Length (ft): 9,000 9,000 9,000 9,000 Proppant (lbs/ft sand): 1,500 1,500 1,200 1,200 Well Cost ($MM): $7.8 $7.8 $7.8 $7.8 Bcfe/1,000 : Net F&D ($/Mcfe): $0.38 $0.42 $0.55 $0.60 Direct Operating Expense ($/well/month): $1,353 $1,353 $1,353 HIGHLY $1,353 RICH GAS Direct Operating DRY Expense GAS LOCATIONS ($/Mcf): RICH $0.96 GAS LOCATIONS $0.96 $1.20 $0.74 LOCATIONS Transportation Expense ($/Mcf): $0.44 $0.44 $0.44 $0.44 Pre-Tax NPV10 ($MM): $15.0 $9.7 $0.7 $0.8 Pre-Tax ROR: 93% 57% 13% 14% Payout (Years): Gross 3P Locations in BTU Regime (3) : 683 1, ,200 1, Total 3P Locations 38

40 UTICA SINGLE WELL ECONOMICS IN ETHANE REJECTION Assumptions Utica Well Economics and Gross Locations (1) Natural Gas 12/31/2016 strip 80% 60% Oil 12/31/2016 strip 58% 60% 47% 48% NGLs ~50% of Oil Price % 25% 50% NYMEX WTI C3+ NGL (2) 43% ($/MMBtu) ($/Bbl) ($/Bbl) 20% 33% 2017 $3.61 $56 $28 23% 32% 2018 $3.14 $57 $30 0% $2.87 $56 $30 Condensate (4) Highly-Rich Gas/ Highly-Rich Gas Rich Gas (5) Dry Gas (4) Condensate (5) (5) 2020 $2.88 $56 $ Total 3P Locations Drilling 12/31/2016 Strip Pricing - After Hedges 2021 $2.90 $56 $30 12/31/2016 Strip Pricing - Before Hedges Plan $2.93-$3.46 $57-$58 $30-$31 Highly-Rich Gas/ Highly-Rich Classification Condensate (4) Condensate (5) Gas (5) Rich Gas (5) Dry Gas (4) Modeled BTU ROR EUR (Bcfe): EUR (MMBoe) : % Liquids 39% 30% 21% 17% 0% Lateral Length (ft): 9,000 9,000 9,000 9,000 9,000 Proppant (lbs/ft sand): 1,200 1,500 1,500 1,500 1,200 Well Cost ($MM): $8.9 $8.9 $9.4 $9.4 $9.4 Bcfe/1,000 : Net F&D ($/Mcfe): $1.10 $0.58 $0.54 $0.56 $0.54 Fixed Operating Expense ($/well/month): $3,011 $3,011 $3,011 $3,011 $1,353 Direct Operating Expense ($/Mcf): $1.04 $1.04 $1.04 HIGHLY $1.04 $0.54 Direct Operating Expense ($/Bbl): $0.30 $0.30 $0.30 RICH GAS - - Transportation Expense DRY GAS ($/Mcf): LOCATIONS RICH $0.53 GAS LOCATIONS $0.53 $0.53 LOCATIONS $0.53 $0.65 Pre-Tax NPV10 ($MM): $3.2 $9.0 $7.9 $5.7 $5.7 Pre-Tax ROR: 23% 50% 43% 33% 32% Payout (Years): Gross 3P Locations in BTU Regime (3) : /31/2016 pre-tax well economics based on a 9,000 lateral, 12/31/2016 natural gas and WTI strip pricing for , flat thereafter, NGLs at 37.5% of WTI for 2016 and ~50% of WTI thereafter, and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates include $1.2 million for road, pad and production facilities. 2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 2016 and ~50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 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. 3. Undeveloped well locations as of 12/31/2016 pro forma for 15 added through recent acreage acquisition. 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content. 4. Assumes standard completions (1,200 lbs/ft of proppant). 5. Assumes enhanced completions (1,500 lbs/ft of proppant) Total 3P Locations 39

41 WELL COST REDUCTIONS Marcellus Well Cost Reductions for a 9,000 Lateral ($MM) (1) ($MM) $14.0 $12.0 $10.0 $8.0 $6.0 $4.0 $12.3 $8.3 $11.1 $10.8 $7.3 $7.4 $10.2 $10.2 $7.0 $7.0 $8.5 $8.1 $5.4 COMPLETION COST $7.8 $5.3 $5.2 $5.0 $0.84 / 1,000 $7.6 DRILLING COST 38% Reduction in Marcellus well costs since Q % Reduction vs. well costs assumed in YE 2015 reserves $2.0 $4.0 $3.8 $3.4 $3.2 $3.2 $3.1 $2.8 $2.6 $2.6 ($MM) $- $16.0 $14.0 $12.0 $10.0 $8.0 $6.0 $4.0 $2.0 Q Q Q Q Q Q Q Q Q Utica Well Cost Reductions for a 9,000 Lateral ($MM) (2) $14.0 $8.7 $12.4 $12.9 $7.8 $7.6 $11.8 $11.8 $7.1 $7.1 $10.3 $5.3 $4.6 $5.3 $4.7 $4.7 $4.7 $4.0 $3.9 $3.6 $5.6 COMPLETION COST $9.4 $9.1 $8.9 $5.4 $5.2 $5.3 DRILLING COST $0.99 / 1,000 36% Reduction in Utica well costs since Q % Reduction vs. well costs assumed in YE 2015 reserves $- Q Q Q Q Q Q Q Q Q NOTE: Based on statistics for drilled wells within each respective period. 1. Based on 200 ft. stage spacing. 2. Based on 175 ft. stage spacing. 40

42 LARGEST GAS HEDGE POSITION IN U.S. E&P $MM $350.0 $280.0 $210.0 $140.0 $70.0 $0.0 BBtu/d 2,400 2,000 1,600 1, ~$1.6 billion mark-to-market unrealized gain based on 12/31/2016 prices with 3.4 Tcfe hedged from January 1, 2017 through year-end 2022 at $3.63 per MMBtu $4 $5 $3.51 $3.61 $3.91 $3.70 $3.66 2,163 2,015 2,330 1, $25 $34 $29 $28 $26 $12 $16 $17 $28 $29 $19 $25 $43 $80 $83 Commodity Hedge Position Hedged Volume Average Index Hedge Price (1) Current NYMEX Strip (2) $59 $49 $48 $14 $47 $54 $3.35 $3.21 $3.14 $2.87 $2.88 $2.90 $2.93 $(130) MM $546 MM $666 MM $363 MM $92 MM ~ 100% of 2016 Guidance Hedged ~ 100% of 2017 Target Hedged $1 $58 $78 Mark-to-Market Value (2) $63 MM Hedging is a key component of Antero s business model due to the large, repeatable drilling inventory $185 $196 $206 $270 $/MMBtu $6.00 Antero has realized $2.8 billion of gains on commodity hedges since 2008 with gains realized in 34 of last 36 quarters Quarterly Realized Gains/(Losses) 1Q 08-4Q 16 $324 $293 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 $197 $190 $/Mcfe $4.00 $3.00 $2.00 $1.00 $0.00 ($1.00) ($2.00) 1. 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 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 12/31/

43 PRICE REALIZATIONS LARGEST FT PORTFOLIO IN NORTHEAST Antero Long Term Firm Processing & Takeaway Position (YE 2018) Accessing Favorable Markets YE 2018 Gas Market Mix Antero 4.85 Bcf/d FT Chicago (1) $0.17 / $(0.04) Shell 30 MBbl/d Commitment Beaver County Cracker (2) Dom South (1) $(0.57) / $(1.19) Mariner East 2 62 MBbl/d Commitment Marcus Hook Export 13% Dom S/TETCO (PA) 13% TCO 13% Atlantic Seaboard 17% Midwest Expect NYMEX-plus pricing per Mcf 44% Gulf Coast 4.85 Bcf/d Firm Gas Takeaway By YE 2018 TCO (1) $(0.23) / $(0.24) Cove Point LNG CGTLA (1) $(0.10) / $(0.09) Sabine Pass (Trains 1-4) 50 MMcf/d per Train (T1 and T2 in-service) Lake Charles LNG (3) 150 MMcf/d Freeport LNG 70 MMcf/d Antero Commitments (3) (2) 1. February 2017 and full year 2017 futures basis, respectively, provided by Intercontinental Exchange dated 12/30/2016. Favorable markets shaded in green. 2. Shell announced final investment decision (FID) on 6/7/ Lake Charles LNG 150 MMcf/d commitment subject to Shell FID. 42

44 INCREMENTAL ANTERO TAKEAWAY CAPACITY Approximately 65% of Antero s expected firm transportation capacity is in service today 6.0 Antero Capacity on Northeast Takeaway Projects MMcf/d 4.8 Bcf/d Bcf/d 800 MMcf/d Chicago / Gulf Coast 200 MMcf/d Gulf Coast TCO / Gulf Coast Current Gross Firm Transportation / Firm Sales Capacity ET Rover (3Q (2Q 2017) (1) TGP Tennessee Expansion Gas (2Q Expansion 2018) (2Q 2018) TCO Mountaineer / CGT Gulf Xpress (2) (4Q 2018) 1. Antero has contracted for downstream capacity of 800 MMcf/d that connects to Rover ince placed in service. 2. Represents 700 MMcf/d of capacity on TCO Mountaineer that can be sold into TCO pool and 183 MMcf/d of capacity available on CGT Gulf Xpress to the Gulf Coast markets. YE 2018E Gross Firm Transportation / Firm Sales Capacity 43

45 UPSIDE IN C3+ PRICE RECOVERY Propane Revenue EVERY $0.10/GAL INCREASE IN PROPANE DRIVES AN INCREMENTAL $45 MILLION INCREASE IN ANNUAL REVENUE (1) $600 $500 $400 $300 $200 Revenue Sensitivity to Propane Recovery Mont Propane Belvieu Production MTB Pricing ($/gal) (MBbl/d) ($MM) (1) Q Annualized $ $238 $0.75/gal Propane $0.65/gal Propane $0.55/gal Propane $ Propane Production (MBbl/d) C3+ NGL Pricing Guidance (2) C3+ Liquids Price per Bbl $60.00 $50.00 $40.00 $30.00 $20.00 $10.00 $0.00 $49.00/Bbl Realized C3+ NGL Price $17.15 $ % of WTI 1. Based on Mont Belvieu (MB) pricing as of 12/31/2016, before Northeast differentials. 2. Based on strip pricing as of 12/31/2016 and associated NGL differentials to Mont Belvieu. $41.15/Bbl 40% of WTI $ YTD 2017 Guidance WTI $56.00/Bbl 45% - 50% of WTI 44

46 ANTERO HAS SIGNIFICANT EXPOSURE TO UPSIDE IN ETHANE (C2) PRICES BENTEK FORECASTS ETHANE PRICES TO INCREASE TO MORE THAN $0.50 / GALLON BY 2018 AND BEYOND Incremental EBITDAX Attributable to Ethane Recovery (1) Ethane EBITDAX $450 $400 $350 $300 $250 $200 $150 $100 $50 $0 $0.70 $147 $103 $60 $281 $214 $175 $139 $414 $347 $248 $212 ATEX FT $65 $70 $76 $ Ethane Recovered (MBbl/d) Ethane Price Forecasts ($/Gallon) (1) Bentek Ethane Forecast (2) (2) Ethane Futures (ICE) $0.60/gal Ethane $0.50/gal Ethane $0.40/gal Ethane $0.60 $0.50 $0.40 $0.30 $0.20 $0.21 $0.24 $0.39 $0.26 $0.50 $0.52 $0.31 $0.32 $0.54 $0.56 $0.35 $0.35 $0.10 $ Represents incremental EBITDA associated with ethane recovery (vs. rejection) at prices ranging from $0.40 to $0.60 per gallon. Assumes (1) ATEX costs are sunk up to 20,000 Bbl/d, (2) $3.00 NYMEX natural gas prices and (3) Borealis firm sale at NYMEX plus pricing. 2. Ethane futures data from ICE as of 9/30/2016. Bentek forecast as of 4/26/ Represents ethane price required to match TCO strip sales price on a realized basis, assuming 20,000 Bbl/d of ATEX costs are sunk. 45

47 BALANCE SHEET STRONG BALANCE SHEET AND HIGH FLEXIBILITY Antero Resources (NYSE:AR) Antero Midstream (NYSE:AM) Pro Forma 9/30/2016 Debt (1) Liquid Non-E&P Assets 9/30/2016 Debt (1) Liquid Assets Debt Type $MM Credit facility $ % senior notes due % senior notes due , % senior notes due , % senior notes due % senior notes due Total $3,658 Asset Type Asset Type Liquid non-e&p assets of $5.3 Bn significantly exceeds total debt of $3.7 billion pro forma for recent transactions Pro Forma Liquidity $MM Commodity derivatives (2) $1,600 AM equity ownership (3) 3,691 Cash 10 Total $5,301 $MM Cash $10 Credit facility commitments (4) 4,000 Credit facility drawn (208) Credit facility letters of credit (709) Total $3,093 Approximately $3.1 billion of liquidity at AR pro forma for recent transactions plus an additional $3.1 billion of AM units Debt Type $MM Credit facility $ % senior notes due Total $817 Asset Type Liquidity Asset Type $MM Cash $9 Total $9 Only 14% of AM credit facility capacity drawn following recent $650 million senior notes offering $MM Cash $9 Credit facility capacity 1,157 Credit facility drawn (167) Credit facility letters of credit - Total $999 Approximately $1.0 billion of liquidity at AM following recent senior notes offering 1. AR balance sheet data as of 9/30/2016. Antero Resources pro forma for $175 million private placement on 10/3/2016, $170 million AR acreage divestiture closed on 12/16/2016 and $600 million 5.00% AR senior note offering closed on 12/21/2016 to refinance $525 million 6% senior notes due 2020 callable at 103% and including transaction expenses. Antero Midstream credit facility as of 2/3/2017 pro forma for 6.0 million unit offering on 2/6/2017 with gross proceeds of $198 million used to fund $155 million MPLX JV payment. 2. Mark-to-market as of 12/31/ Based on AR ownership of AM units and closing price as of 2/6/ AR credit facility commitments of $4.0 billion, borrowing base of $4.75 billion. 46

48 POSITIVE RATINGS MOMENTUM Given Antero s stable credit metrics through the commodity price crisis and improved leverage profile, Antero requests a ratings upgrade from Moody s Moody s / S&P Historical Corporate Credit Ratings Moody s Rating Rationale Outlook Upgraded to Stable. The outlook change reflects Moody s expectation of lower financial leverage and less negative free cash flow through 2018 relative to our prior estimates. Facing weak industry conditions, Antero has taken a number of measures over the past year to keep its leverage in check, including issuing over $1 billion of equity, raising $170 million from asset sales and reducing debt with those proceeds, while also cutting operating and capital costs. - Moody s Credit Research, February 2017 S&P Rating Rationale Outlook Stable. The affirmation reflects our view that Antero will maintain funds from operations (FFO)/Debt above 20% in 2016, as it continues to invest and grow production in the Marcellus Shale. The company has very good hedges in place, which will limit exposure to commodity prices. - S&P Credit Research, February 2016 Corporate Credit Rating (Moody s / S&P) Baa3 / BBB- Ba1 / BB+ Ba2 / BB Ratings Affirmed February 2016 Ba2/BB Ba3 / BB- B1 / B+ B2 / B B3 / B- Reduced D&C capex by 20% in 2016 Deleveraged to 3.2x at 9/30/16 (1) $3.0bn+ of liquidity at AR alone $2.4bn mark to market at 9/30/16 strip 2,700+ locations with 20% unhedged ROR Caa1 / CCC+ 9/1/2010 2/24/2011 5/31/ /21/2013 9/4/2014 3/31/2015 9/30/2016 Moody's 1. Pro forma for $175 million AR PIPE on 10/3/2016 with net proceeds used to repay bank facility and $170 million AR acreage divestiture announced on 10/26/ Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC. S&P (2) 47