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Am website presentation april 2016

Am website presentation april 2016

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Am website presentation april 2016

  1. 1. Partnership Overview April 2016
  2. 2. FORWARD-LOOKING STATEMENTS This presentation contains forward-looking statements. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Midstream Partners LP, and its subsidiaries (collectively, the “Partnership”) expect, believe or anticipate 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 expectations of plans, strategies, objectives, and anticipated financial and operating results of the Partnership and Antero Resources Corporation (“Antero Resources”). These statements are based on certain assumptions made by the Partnership and Antero Resources 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 Partnership, 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 Partnership’s subsequent filings with the SEC. The Partnership cautions you that these forward-looking statements are subject to risks and uncertainties that may cause these statements to be inaccurate, and readers are cautioned not to place undue reliance on such statements. These risks include, but are not limited to, Antero Resources’ expected future growth, Antero Resources’ ability to meet its drilling and development plan, commodity price volatility, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks discussed or referenced under the heading “Item 1A. Risk Factors” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 and in the Partnership’s subsequent filings with the SEC. Our ability to make future distributions is substantially dependent upon the development and drilling plan of Antero Resources, which itself is substantially dependent upon the review and approval by the board of directors of Antero Resources of its capital budget on an annual basis. In connection with the review and approval of the annual capital budget by the board of directors of Antero Resources, the board of directors will take into consideration many factors, including expected commodity prices and the existing contractual obligations and capital resources and liquidity of Antero Resources at the time. Any forward-looking statement speaks only as of the date on which such statement is made, and the Partnership 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. 1 Antero Midstream Partners LP is denoted as “AM” and Antero Resources Corporation is denoted as “AR” in the presentation, which are their respective New York Stock Exchange ticker symbols.
  3. 3. 2 CHANGES SINCE MARCH 2016 PRESENTATION Updated AR and AM standalone leverage and liquidity slides as of 12/31/2015 pro forma for AM unit sale Slide 16
  4. 4. Sustainable Business Model High Growth Sponsor Drives AM Throughput and Distribution Growth Largest Dedicated Core Liquids-Rich Acreage Position in Appalachia $900 Million of AM Liquidity 3 Premier E&P Operator in Appalachia 100% Fixed Fee and Largest Firm Transport and Hedge Portfolio Opportunity to Build Out Northeast Value Chain Growth Liquids- Rich Value Chain Opportunity High Visibility Sponsor Strength LEADING UNCONVENTIONAL MIDSTREAM BUSINESS MODEL “Just-in Time” Non-Speculative Capital Program Strong Financial Position Mitigated Commodity Risk 1 2 3 4 5 67 8 Premier Appalachian Midstream Partnership Run by Co-Founders Consolidated Acreage Position in Lowest Unit Cost Basin
  5. 5. 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 EQT CHK COG AR SWN RRC CNX - 100 200 300 400 500 600 AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Core Net Acres - Dry Core Net Acres - Liquids Rich Top Producers in Appalachia (Net MMcfe/d) – 4Q 2015(1)(2) Top 12 U.S. Natural Gas Producers (Net MMcf/d) – 4Q 2015(1) Appalachian Producers by Proved Reserves (Bcfe) – YE 2015(1)(2) Appalachian Producers by Core Net Acres (000’s) – December 2015(4) 1. Based on company filings and presentations. 2. Appalachian only production and reserves where available. Excludes companies that do not break out Appalachian production including CVX, HES and XOM. 3. Includes proved reserves categorized in “Northern Division” consisting of Utica Shale, Marcellus Shale and Powder River Basin. 4. Based on Antero geologic interpretation supported by state well data, company presentations and public land data. Peer group includes CNX, COG, EQT, RRC, SWN, CHK. (3) 4 4th Largest Appalachian Producer  Antero has the largest proved reserve base, largest core liquids-rich acreage position and is one of the largest producers in the Appalachian Basin Appalachian Peers 11th Largest U.S. Gas Producer Largest Proved Reserve Base In Appalachia Largest Liquids- Rich Core Position in Appalachia 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 AR EQT RRC COG CNX CHK SWN 0 500 1,000 1,500 2,000 2,500 3,000 3,500 SPONSOR STRENGTH – LEADERSHIP IN APPALACHIAN BASIN
  6. 6. Note: 2015 SEC prices were $2.56/MMBtu for natural gas and $50.13/Bbl for oil on a weighted average Appalachian index basis. 1. 3P reserve pre-tax PV-10 based on annual strip pricing for first 10-years and flat thereafter as of December 31, 2015. NGL pricing assumes 39%, 46% and 48% of WTI strip prices for 2016, 2017 and 2018 and thereafter, respectively. 2. All net acres allocated to the WV/PA Utica Shale Dry Gas and Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as they are stacked pay formations attributable to the same leasehold. 3. Antero and industry rig locations as of 3/11/2016, per RigData. 5 COMBINED TOTAL – 12/31/15 RESERVES Assumes Ethane Rejection Net Proved Reserves 13.2 Tcfe Net 3P Reserves 37.1 Tcfe Strip Pre-Tax 3P PV-10(1) $11.2 Bn Net 3P Reserves & Resource 50 to 53 Tcfe Net 3P Liquids 1,237 MMBbls % Liquids – Net 3P 20% 4Q 2015 Net Production 1,497 MMcfe/d - 4Q 2015 Net Liquids 54,750 Bbl/d Net Acres(2) 569,000 Undrilled 3P Locations 3,719 OHIO UTICA SHALE CORE Net Proved Reserves 1.8 Tcfe Net 3P Reserves 7.5 Tcfe Strip Pre-Tax 3P PV-10(1) $2.5 Bn Net Acres 147,000 Undrilled 3P Locations 814 MARCELLUS SHALE CORE Net Proved Reserves 11.4 Tcfe Net 3P Reserves 29.6 Tcfe Strip Pre-Tax 3P PV-10(1) $8.7 Bn Net Acres 422,000 Undrilled 3P Locations 2,905 WV/PA UTICA SHALE DRY GAS Net Resource 12.5 to 16 Tcf Net Acres 188,000 Undrilled Locations 1,889 0 1 2 3 4 5 6 7 8 9 RigCount Operators Current SW Marcellus & Utica(3) SPONSOR STRENGTH – MOST ACTIVE OPERATOR IN APPALACHIA
  7. 7. $1 $5 $7 $8 $11 $19 $28 $36 $41 $55 $83 $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 26 31 40 36 41 116 222 358 454 435 478 0 100 200 300 400 500 600 700 800 Utica Marcellus 10 38 80 126 266 531 908 1,134 1,197 1,216 1,195 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 Utica Marcellus 108 216 281 331 386 531 738 935 965 1,038 1,124 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 Utica Marcellus Low Pressure Gathering (MMcf/d) Compression (MMcf/d) High Pressure Gathering (MMcf/d) EBITDA ($MM) 6 $313 Note: Y-O-Y growth based on 4Q’14 to 4Q’15. 1. Represents midpoint of 2016 guidance . GROWTH – HIGH GROWTH MIDSTREAM THROUGHPUT
  8. 8. $0.170 $0.180 $0.190 $0.205 1.1x 1.2x 1.3x 1.4x 1.8x 0.0x 0.2x 0.4x 0.6x 0.8x 1.0x 1.2x 1.4x 1.6x 1.8x 2.0x $0.000 $0.050 $0.100 $0.150 $0.200 $0.250 $0.300 $0.350 $0.400 $0.450 $0.500 4Q14A 1Q15A 2Q15A 3Q15A 4Q15A 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E Distribution Per Unit (Left Axis) DCF Coverage (Right Axis) $0.220 7 • Antero Midstream is targeting 28% to 30% annual distribution growth through 2017 • AM has delivered on those targets with DCF coverage of 1.4x in the third quarter 2015 Note: Future distributions subject to AM Board approval. 1. Assumes midpoint of target distribution growth range. 2. 4Q 2015 distribution per Partnership press release dated 1/13/2016. (2) GROWTH – TOP TIER DISTRIBUTION GROWTH
  9. 9. 8 LIQUIDS-RICH – LARGEST CORE POSITION Source: Core outlines and peer net acreage positions based on investor presentations, news releases and 10-K/10-Qs. Rig information per RigData as of 1/1/2016. 1. Based on company filings and presentations. Peer group includes Ascent, CHK, CNX, CVX, ECR, EQT, GPOR, NBL, RRC, STO, SWN. • Antero controls an estimated 37% of the NGLs in the liquids-rich core of the two plays • Antero has the largest core liquids- rich position in Appalachia with ≈371,000 net acres (> 1100 Btu) • Represents over 21% of core liquids- rich acreage in Marcellus and Utica plays combined  Antero has over 2,700 undeveloped rich gas locations with an average lateral length of 7,580’ in its 3P reserves as of 12/31/2015 0 100 200 300 400 (000s) Core Liquids-Rich Net Acres(1)
  10. 10. 626 971 553 755 70% 52% 27% 32%37% 25% 10% 13% 0 400 800 1,200 0% 20% 40% 60% 80% Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total3PLocations ROR Total 3P Locations ROR @ 12/31/2015 Strip Pricing - After Hedges ROR @ 12/31/2015 Strip Pricing - Before Hedges 184 98 108 161 263 17% 62% 85% 73% 82% 11% 28% 29% 24% 27% 0 100 200 300 0% 20% 40% 60% 80% 100% Condensate Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total3PLocations ROR MARCELLUS WELL ECONOMICS(1)(2) Marcellus Well Cost Improvement(3) 1. 12/31/2015 pre-tax well economics based on a 9,000’ lateral, 12/31/2015 natural gas and WTI strip pricing for 2016-2025, 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, which include $1.2 million for road, pad and production facilities. 2. ROR @ 12/31/2015 Strip-With Hedges reflects 12/31/2015 well cost ROR methodology, with the 12/31/2015 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip and hedge prices. 3. Current spot well costs based on $8.5 million for a 9,000’ lateral Marcellus well and $10.25 million for a 9,000’ lateral Utica well. 9 UTICA WELL ECONOMICS(1)(2)  74% of Marcellus locations are processable (1100-plus Btu)  68% of Utica locations are processable (1100-plus Btu) 2016 Drilling Plan  Antero has reduced average well costs for a 9,000’ lateral by 16% in the Marcellus and 18% in the Utica as compared to 2014 well costs  At 12/31/2015 strip pricing, Antero has 2,227 locations that exceed a 20% rate of return (excluding hedges) – Including hedges, these locations generate rates of return of approximately 50% to 80% Utica Well Cost Improvement(3) $1.36 $1.14 $0.95 $0.000 $0.500 $1.000 $1.500 $2.000 2014 2015 Current Spot $MM/1,000’Lateral Well Cost ($MM/1,000' of Lateral) 16% Decrease vs. 2014 $1.57 $1.29 $1.14 $0.000 $0.500 $1.000 $1.500 $2.000 2014 2015 Current Spot $MM/1,000’Lateral Well Cost ($MM/1,000' of Lateral) 18% Decrease vs. 2014 12% Decrease vs. 2015 17% Decrease vs. 2015 SUSTAINABLE BUSINESS MODEL – AR MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW RISK, HIGH RETURN GROWTH PROFILE
  11. 11. 10 In-service 2016 Budget HIGH VISIBILITY – PROJECTED MARCELLUS MIDSTREAM BUILDOUT
  12. 12. 11 In-service 2016 Budget HIGH VISIBILITY – PROJECTED UTICA MIDSTREAM BUILDOUT
  13. 13. 10 0 5 0 0 7 0 5 10 15 AM CNNX EQM CMLP SMLP RMP Fixed Fee 100% Fixed Fee 100% 12 MITIGATED COMMODITY RISK – 100% FIXED FEE – RICH TO DRY Contract Mix Fixed Fee 97% Fixed Fee 100% Fixed Fee 100% Fixed Fee 90% (1) . Source: Core net acreage positions based on investor presentations, news releases and 10-K/10-Qs. 1. Represents assets held at MLP. 2. Rig count as of 1/1/2016, per RigData. 3. Includes Antero Resources rigs located in Doddridge County, WV operating on SMLP assets. Commodity Based Commodity Based Appalachian Exposure Marcellus – Dry       Marcellus – Rich     Utica – Dry   Utica – Rich  Water Services   Rigs Running on Midstream Footprint (2) (3)
  14. 14. - 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000 4,500,000 5,000,000 5,500,000 13 BBtu/d Antero Resources Transportation Portfolio • Antero Resources has built the largest firm transportation portfolio in Appalachian Basin with 4.85 BBtu/d by year end 2018 2015 2016E 2017E 2018E Favorable: Chicago MichCon Gulf Coast NYMEX TCO AR Increasing Access to Favorable Markets Less favorable: TETCO M2 Dominion South 74% 26% 99% 1% 97% 3% 97% 3% (Stonewall/WB) Mid-Atlantic/NYMEX (Stonewall/TGP) Gulf Coast (TCO) Appalachia or Gulf Coast Appalachia Appalachia (REX/ANR/NGPL/MGT) Midwest (ANR/Rover) Gulf Coast MITIGATED COMMODITY RISK – FIRM TRANSPORTATION & SALES PORTFOLIO
  15. 15. $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $0 $50 $100 $150 $200 $250 $300 $MM 14 HEDGING – INTEGRAL TO BUSINESS MODEL  Hedging is a key component of Antero’s business model which includes development of a large, repeatable drilling inventory – Locks in higher returns in a low commodity price environment and reduces well payout thereby enhancing liquidity  Antero has realized $1.7 billion of gains on commodity hedges since 2009 – Gains realized in 28 of last 29 quarters, or 97% of the quarters since 2009 ● Based on Antero’s hedge position and strip pricing as of 12/31/2015, the unrealized commodity derivative value is $3.1 billion ● Significant additional hedge capacity remains under the credit facility hedging covenant for 2018 – 2022 period Quarterly Realized Hedge Gains / (Losses) Realized Hedge Gains Projected Hedge Gains NYMEX Natural Gas Historical Spot Prices ($/MMBtu) NYMEX Natural Gas Futures Prices 3.5 Tcfe Hedged at average price of $3.79/Mcfe through 2022 Average Hedge Prices ($/Mcfe) $3.50 $3.94 $3.57 $3.88 $3.89 $3.73 $3.30 $3.1 Billion on Balance Sheet in Hedge Gains Through 2022Realized $1.7 Billion in Hedge Gains Since 2009
  16. 16. Regional Gas Pipelines Miles Capacity In-Service Stonewall Gathering Pipeline(2) 50 1.4 Bcf/d Yes 1. Acquired by AM from AR for a $1.05 billion upfront payment and a $125 million earn out in each of 2019 and 2020. 2. AM holds option to purchase 15% of Stonewall pipeline at cost plus cost of carry. End Users End Users Gas Processing Y-Grade Pipeline Long-Haul Interstate Pipeline Inter Connect NGL Product Pipelines Fractionation Compression Low Pressure Gathering Well Pad Terminals and Storage (Miles) YE 2015 YE 2016E Marcellus 106 114 Utica 55 56 Total 161 170 AM has option to participate in processing, fractionation, terminaling and storage projects offered to AR (Miles) YE 2015 YE 2016E Marcellus 76 98 Utica 36 36 Total 112 134 (MMcf/d) YE 2015 YE 2016E Marcellus 700 940 Utica 120 120 Total 820 1,060 AM Owned Assets Condensate Gathering Stabilization (Miles) YE 2015 YE 2016E Utica 19 19 End Users AM Option Assets (Ethane, Propane, Butane, etc.) 15 VALUE CHAIN OPPORTUNITY – FULL MIDSTREAM VALUE CHAIN
  17. 17. Liquid “non-E&P assets” of $5.5 Bn significantly exceeds total debt of $3.9 Bn Liquidity Antero Resources (NYSE:AR) Antero Midstream (NYSE:AM) 12/31/2015 Debt Liquid Non-E&P Assets 12/31/2015 Debt Liquid Assets Debt Type $MM Credit facility $529 6.00% senior notes due 2020 525 5.375% senior notes due 2021 1,000 5.125% senior notes due 2022 1,100 5.625% senior notes due 2023 750 Total $3,904 Asset Type $MM Commodity derivatives(1) $3,117 AM equity ownership(2) 2,407 Cash 16 Total $5,540 Asset Type $MM Cash $16 Credit facility – commitments(3) 4,000 Credit facility – drawn (529) Credit facility – letters of credit (702) Total $2,785 Debt Type $MM Credit facility $620 Total $620 Asset Type $MM Cash $7 Total $7 Liquidity Asset Type $MM Cash $7 Credit facility – capacity 1,500 Credit facility – drawn (620) Credit facility – letters of credit - Total $887 Approximately $2.8 billion of liquidity at AR plus an additional $2.4 billion of AM units Approximately $900 million of liquidity at AM 16 Only 41% of AM credit facility capacity drawn Note: All balance sheet data as of 12/31/2015. Pro forma for AR secondary offering of 8.0 million AM units on 3/24/2016 for net proceeds of $178 million. 1. Mark-to-market as of 12/31/2015. 2. Based on AR ownership of AM units (108.9 million common and subordinated units) and AM’s closing price as of 3/31/2016. 3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion. STRONG FINANCIAL POSITION – STRONG BALANCE SHEET AND FLEXIBILITY
  18. 18. 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x 4.0x 4.5x Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 TotalDebt/LTMEBITDA • $1.5 billion revolver in place to fund future growth capital (5x Debt/EBITDA Cap) • Liquidity of $887 million at 12/31/2015 • Sponsor (NYSE: AR) has Ba2/BB corporate ratings AM Liquidity (12/31/2015) AM Peer Leverage Comparison(1) ($ in millions) Revolver Capacity $1,500 Less: Borrowings 620 Plus: Cash 7 Liquidity $887 1. As of 12/31/2015. Peers include TEP, EQM, WES, RMP, SHLX, DM, and CNNX. 2. AM includes full year EBITDA contribution from water business. Financial Flexibility 17 (2) STRONG FINANCIAL POSITION – SIGNIFICANT FINANCIAL FLEXIBILITY
  19. 19. TOP TIER DISTRIBUTION GROWTH & HEALTHY COVERAGE 18 3–Year Street Consenus Distribution Growth Rate and DCF Coverage(1) 28% 28% 27% 26% 24% 23% 20% 17% 13% 11% 1.7x 1.5x 1.3x 1.7x 1.1x 1.4x 1.3x 1.3x 1.4x 1.3x 0.00x 0.20x 0.40x 0.60x 0.80x 1.00x 1.20x 1.40x 1.60x 1.80x 2.00x 0% 5% 10% 15% 20% 25% 30% SHLX AM PSXP VLP MPLX DM EQM TEP CNNX WES 1. Based on Bloomberg 2015-2018 Bloomberg consensus estimates as of 12/31/2015.
  20. 20. WES CNNX TEP EQM MPLX DM VLP PSXP SHLX 0.0% 1.0% 2.0% 3.0% 4.0% 5.0% 6.0% 7.0% 8.0% 9.0% 10.0% 3.0% 8.0% 13.0% 18.0% 23.0% 28.0% 33.0% Yield(%) 2015-2018 Distribution Growth CAGR(1) Bubble Size Reflects Relative Market Capitalization R-squared = .76 ATTRACTIVE VALUE PROPOSITION 19 AM – 12/31/15 Yield: 3.59% Price: $22.82 AM - Implied Yield: 2.39% Price: $34.34 • Attractive appreciation potential on a relative basis 1. Based on Bloomberg 2015-2018 Bloomberg consensus distribution estimates and market data as of 12/31/2015.
  21. 21. Antero Midstream (NYSE: AM) Asset Overview 20
  22. 22. 1. Represents inception to date actuals as of 12/31/2015 and 2016 guidance. 2. Includes both expansion capital and maintenance capital. 21 Utica Shale Marcellus Shale Projected Gathering and Compression Infrastructure(1) Marcellus Shale Utica Shale Total YE 2015 Cumulative Gathering/ Compression Capex ($MM) $981 $462 $1,443 Gathering Pipelines (Miles) 182 91 273 Compression Capacity (MMcf/d) 700 120 820 Condensate Gathering Pipelines (Miles) - 19 19 2016E Gathering/Compression Capex Budget ($MM)(2) $235 $20 $255 Gathering Pipelines (Miles) 30 1 31 Compression Capacity (MMcf/d) 240 - 240 Condensate Gathering Pipelines (Miles) - - - Gathering and Compression Assets ANTERO MIDSTREAM GATHERING AND COMPRESSION ASSET OVERVIEW • Gathering and compression assets in core of rapidly growing Marcellus and Utica Shale plays – Acreage dedication of ~438,000 net leasehold acres for gathering and compression services – Additional stacked pay potential with dedication on ~147,000 acres of Utica deep rights underlying the Marcellus in WV and PA – 100% fixed fee long term contracts • AR owns 62% of AM units (NYSE: AM)
  23. 23. ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS 22 • Provides Marcellus gathering and compression services − Liquids-rich gas is delivered to MWE’s 1.2 Bcf/d Sherwood processing complex • Significant growth projected over the next twelve months as set out below: • Antero plans to operate an average of five drilling rigs in the Marcellus Shale during 2016, including intermediate rigs − 100% of rigs targeting the highly-rich gas/condensate and highly-rich gas regimes • All 80 gross wells targeted to be completed in 2016 are in the AM dedicated area − AM dedicated acreage contains 2,126 gross undeveloped Marcellus locations • Antero will defer an additional 62 completions, with 20 being wells dedicated to a third-party midstream provider that were originally scheduled for completion in 2016 but will now be carried into 2017, in order to limit natural gas volumes sold into unfavorable pricing markets Marcellus Gathering & Compression Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned. YE 2015 YE 2016E Low Pressure Gathering Pipelines (Miles) 106 114 High Pressure Gathering Pipelines (Miles) 76 98 Compression Capacity (MMcf/d) 700 940
  24. 24. 23 • Provides Utica gathering and compression services − Liquids-rich gas delivered into MWE’s 800 MMcf/d Seneca processing complex − Condensate delivered to centralized stabilization and truck loading facilities • Significant growth projected over the next twelve months as set out below: • Antero plans to operate an average of two drilling rigs in the Utica Shale during 2016, including intermediate rigs − 100% of rigs targeting the highly-rich gas/condensate and highly-rich gas regimes • All 35 gross wells targeted to be completed in 2016 are on Antero Midstream’s footprint • Antero will defer an additional 8 completions in order to limit natural gas volumes sold into unfavorable pricing markets Utica Gathering & Compression Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned. ANTERO MIDSTREAM ASSETS – RICH & DRY GAS UTICA YE 2015 YE 2016E Low Pressure Gathering Pipelines (Miles) 55 56 High Pressure Gathering Pipelines (Miles) 36 36 Condensate Pipelines (Miles) 19 19 Compression Capacity (MMcf/d) 120 120
  25. 25. ANTERO MIDSTREAM WATER BUSINESS OVERVIEW 24 Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned. 1. Represents inception to date actuals as of 12/31/2015 and 2016 guidance. 2. All Antero water withdrawal sites are fully permitted under long-term state regulatory permits both in WV and OH. 3. Includes both expansion capital and maintenance capital. 4. Marcellus assumes fee of $3.685 per barrel subject to annual inflation and 250,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes G&A. Utica assumes fee of $3.635 per barrel subject to annual inflation and 275,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes G&A.  AM acquired AR’s integrated water business for $1.05 billion plus earn out payments of $125 million at year-end in each of 2019 and 2020 − The acquired business includes Antero’s Marcellus and Utica freshwater delivery business, the fully-contracted future advanced wastewater treatment complex and all fluid handling and disposal services for Antero Antero advanced wastewater treatment facility to be constructed – connects to Antero freshwater delivery system Projected Water Business Infrastructure(1) Marcellus Shale Utica Shale Total YE 2015 Cumulative Fresh Water Delivery Capex ($MM) $469 $62 $531 Water Pipelines (Miles) 184 75 259 Fresh Water Storage Impoundments 22 13 35 2016E Fresh Water Delivery Capex Budget ($MM)(3) $40 $10 $50 Water Pipelines (Miles) 20 9 29 Fresh Water Storage Impoundments 1 - 1 Cash Operating Margin per Well(4) $700k - $750k $775k - $825k 2016E Advanced Waste Water Treatment Budget ($MM) $130 2016E Total Water Business Budget ($MM) $180 Water Business Assets • Fresh water delivery assets provide fresh water to support Marcellus and Utica well completions – Year-round water supply sources: Clearwater Facility, Ohio River, local rivers & reservoirs(2) – 100% fixed fee long term contracts
  26. 26. 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 Antero Clearwater Advanced Wastewater Treatment Capacity (Bbl/d) Produced/Flowback Volumes (Bbl/d) Illustrative Produced & Flowback Water VolumesAdvanced Wastewater Treatment Antero Produced Water Services and Freshwater Delivery Business Antero Advanced Wastewater Treatment 3rd Party Recycling and Well Disposal (Bbl/d) Advanced Wastewater Treatment Complex Estimated capital expenditures ($ 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 •Antero has contracted with Veolia to integrate an advanced wastewater treatment complex into its water business • Veolia will build and operate, and Antero will own largest advanced wastewater treatment complex in Appalachia − Will treat and recycle AR produced and flowback water − Creates additional year-round water source for completions − Will have capacity for third party business over first two years 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. 20 Years, Extendable 25Integrated Water Business Antero Advanced Wastewater Treatment Freshwater delivery system Flowback and produced Water Well Pad Well Pad Completion Operations Producing Freshwater Salt Calcium Chloride Marketable byproduct Marketable byproduct used in oil and gas operations Freshwater delivery system ANTERO MIDSTREAM ADVANCED WASTEWATER TREATMENT ASSET OVERVIEW
  27. 27. ORGANIC GROWTH STRATEGY: “BUILD VS. BUY” 26 • Organic growth strategy provides attractive returns and project economics, while avoiding the competitive acquisition market • Industry leading organic growth story – ~$1.06 billion in capital spent through 9/30/2014 – $425 million in additional growth capital forecast for the twelve-month period ending 12/31/15 (excludes $12.5 million of maintenance capital) Note: Precedent data per IHS Herold’s research and public filings. 1. Antero organic multiple calculated as estimated gathering and compression capital expended through Q3 2014 divided by 2015 projected gathering and compression EBITDA, assuming 12-15 month lag between capital incurred and full system utilization. 2. Selected gathering and compression drop down acquisitions since 1/1/2011. Drop down multiples are based on NTM EBITDA. Source: Barclays. 6.8x 11.9x 10.7x 10.0x 9.3x 9.0x 9.0x 9.0x 8.9x 8.9x 8.8x 8.6x 8.0x 7.9x 7.0x 6.9x 5.5x 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x 7.0x 8.0x 9.0x 10.0x 11.0x 12.0x Drop Down Multiple(2) Organic EBITDA Multiple vs. Precedent Drop Down Multiples Median: 8.9x Value creation for the AM unit holder = Build at 4x to 7x EBITDA vs. Drop Down / Buy at 8x to 12x EBITDA
  28. 28. LP Gathering HP Gathering Compression Condensate Gathering Fresh Water Delivery Advanced Wastewater Treatment Regional Pipeline Processing/ Fractionation Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 25% - 35% 30% - 40% 15% - 25% 15% - 25% 15% - 20% Payout (Years): 2.5 - 4.0 3.5 - 4.5 4.0 - 6.5 2.0 - 3.5 2.0 – 3.0 6.0 - 8.0 3.5 - 7.0 5.0 - 6.0 Minimum Volume Commitments: N/A 75% 70% N/A Yes N/A 80% 80% 2016 Expansion Capex(2) Total Marcellus $388 $33 $49 $143 - $33 $130 Utica 22 7 1 7 - 7 - Growth Capex $410 $40 $50 $150 $0 $40 $130 % of Capex 100% 10% 12% 37% 0% 10% 32% Included in 2016 Budget: Marcellus & Utica Marcellus & Utica Marcellus & Utica Utica Marcellus & Utica Marcellus & Utica Not Included Not Included Additional In-hand Opportunities: Dry Utica Dry Utica Dry Utica Utica Stabilization Dry Utica Dry Utica Regional Gathering Pipeline Marcellus Processing/ Fractionation 25% 15% 10% 25% 30% 15% 15% 15% 35% 25% 20% 35% 25% 25% 40% 20% 0% 10% 20% 30% 40% InternalRateofReturn 27 Project Economics by Segment(1) ESTIMATED PROJECT ECONOMICS BY SEGMENT 1. Based on management capex, operating cost and throughput assumptions by project. Capex guidance updated per 2016 Partnership guidance press release. 2. Excludes $25.0 million of maintenance capex. Wtd. Avg. 21% IRR AM Option Opportunities
  29. 29. AM UPSIDE OPPORTUNITY SET 28 ACTIVITY CURRENTLY DEDICATED TO AM Third Party Business Processing, Fractionation, Transportation and Marketing Regional Pipeline Project • Option to participate for up to 15% in regional gathering pipeline project in West Virginia that went in-service 12/1/2015 • Additive to full value chain model • Opportunity to expand fresh water, waste water and gathering/compression services to third parties in Marcellus and Utica to enhance asset utilization • AR must request a bid from AM and can only reject if third party service fees are lower. AM has right to match lower fee offer. WV/PA Utica Dry Gas • 188,000 net acres of AR Utica dry gas acreage underlying the Marcellus in West Virginia and Pennsylvania dedicated to AM • AR has drilled and completed its first WV Utica well Active AR Leasing • Future acreage acquisitions by AR are dedicated to AM • Added 92,000 net acres in 2014 and added 26,000 net acres in 2015
  30. 30. REGIONAL PIPELINE PROJECT •Option to Acquire Up To 15% Non-Op Equity Interest ●Enables Antero Resources to move up to 1.1 Bcf/d of gas on a firm basis (900 MMcf/d minimum volume commitment) to more favorably priced markets including TCO, NYMEX and Gulf Coast markets - Currently moving ~950 MMcf/d Regional Gathering Pipeline Throughput Capacity: 1.4 Bcf/d Pipeline Specifications: 50 miles of 36 inch pipeline Project Capital: ≈ $400 Million In-Service Date: 12/1/2015 AR Firm Commitment: 900 MMcf/d 29
  31. 31. AR Gross Processable Acres Gross 3P NGL Reserves (MMBbls)(1) AR 3P Gross Wellhead Gas (Tcf) Potential Processing AOD for AM Tyler 78,000 406.8 7.4 Ritchie 49,000 295.1 6.3 Gilmer 14,000 42.7 1.1 Total 141,000 744.6 14.8 PROCESSING – VALUE CHAIN POTENTIAL FOR UNDEDICATED ACREAGE Sherwood Processing Complex AR acreage position on map reflects tax districts in which greater than 3,000 net acres are held. 1. Antero gross 3P C3+ NGL volumes and 3P Gross Wellhead Gas reserves as of 12/31/2015. Processing Area Of Dedication for AM MarkWest Processing AOD – 194,500 Gross Acres Tyler County 78,000 Gross Acres Ritchie County 49,000 Gross Acres  Antero Resources has 14.8 Tcf of processable gross 3P gas reserves and 745 Million Bbls of gross 3P NGL reserves across 141,000 gross processable Marcellus acres that are dedicated to Antero Midstream for processing 30 Gilmer County 14,000 Gross Acres
  32. 32. LARGE UTICA SHALE DRY GAS POSITION 31  Antero has completed its first dry gas Utica well – a 6,620’ lateral in Tyler County, WV  Antero has 229,000 net acres of exposure to Utica dry gas play in OH, WV and PA  Other operators have reported strong Utica Shale dry gas results including the following wells: Chesapeake Hubbard BRK #3H 3,550’ Lateral IP 11.1 MMcf/d Hess Porterfield 1H-17 5,000’ Lateral IP 17.2 MMcf/d Gulfport Irons #1-4H 5,714’ Lateral IP 30.3 MMcf/d Eclipse Tippens #6H 5,858’ Lateral IP 23.2 MMcf/d Magnum Hunter Stalder #3UH 5,050’ Lateral IP 32.5 MMcf/d Well Operator 24-hr IP (MMcf/d) Lateral Length (Ft) 24-hr IP/1,000’ Lateral (MMcf/d) Scotts Run EQT 72.9 3,221 22.633 Gaut 4IH CNX 61.0 5,840 11.131 CSC #11H RRC 59.0 5,420 10.886 Stewart-Win 1300U MHR 46.5 5,289 8.792 Bigfoot 9H RICE 41.7 6,957 5.994 Blank U-7H GST 36.8 6,617 5.561 Stalder #3UH MHR 32.5 5,050 6.436 Irons #1-4H GPOR 30.3 5,714 5.303 Pribble 6HU SGY 30.0 3,605 8.322 Simms U-5H GST 29.4 4,447 6.611 Conner 6H CVX 25.0 6,451 3.875 Messenger 3H SWN 25.0 5,889 4.245 Tippens #6H ECR 23.2 5,858 3.960 Porterfield 1H-17 HESS 17.2 5,000 3.440 1. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA. 2. The Rymer 4HD has been flowing into the sales line for 90 days with an average choke-restricted flow rate of 20 MMcf/d. Magnum Hunter Stewart Winland 1300U 5,289’ Lateral IP 46.5 MMcf/d Range Claysville SC #11H 5,420’ Lateral IP 59.0 MMcf/d Chevron Conner 6H 6,451’ Lateral IP 25.0 MMcf/d Gastar Simms U-5H 4,447’ Lateral IP 29.4 MMcf/d Utica Shale Dry Gas Acreage in OH/WV/PA(1) Rice Bigfoot 9H 6,957’ Lateral IP 41.7 MMcf/d AR Utica Shale Dry Gas WV/PA Net Resource 12.5 to 16 Tcf 1,889 Gross Locations 188,000 Net Acres AR Utica Shale Dry Gas Ohio 3P Reserves 2.3 Tcf 263 Gross Locations 41,000 Net Acres AR Utica Shale Dry Gas Total OH/WV/PA Net Resource 14.8 to 18.3 Tcf 2,152 Gross Locations 229,000 Net Acres Stone Energy Pribble 6HU 3,605’ Lateral IP 30.0 MMcf/d Southwestern Messenger 3H 5,889’ Lateral IP 25.0 MMcf/d Rice Blue Thunder 10H, 12H ≈9,000’ Lateral Gastar Blake U-7H 6,617’ Lateral IP 36.8 MMcf/d EQT Scotts Run 3,221’ Lateral IP 72.9 MMcf/d CNX Gaut 4IH 5,840’ Lateral IP 61.0 MMcf/d Antero Rymer 4HD 6,620’ Lateral IP 20.0 MMcf/d (2)
  33. 33. Low Cost Marcellus/Utica Focus “Best-in-Class” Distribution Growth 32 CATALYSTS 28% to 30% per year for 2016 and 2017 targeted based on Sponsor planned development; additional third party business expansion opportunities AM Sponsor is the most active operator in Appalachia; 15% production growth guidance for 2016 supported by $1.4 billion capital budget, firm processing and takeaway, long-term natural gas hedges and $2.6 billion of liquidity; targeting 20% production growth in 2017 Sponsor operations target two of the lowest cost shale plays in North America; attractive well economics support continued drilling at current prices Multiple opportunities exist for additional gathering and compression, processing and pipeline assets for Sponsor and third party use Appalachian Basin Midstream Growth High Growth Sponsor Production Profile 1 2 3 4 5 6 Acquisition of integrated water business from Antero expected to result in distributable cash flow per unit accretion in 2016 Stacked Pay Basin Upside Development of Utica Shale Dry Gas and Upper Devonian resources provide further midstream infrastructure expansion opportunities Integrated Water Business Drop Down
  34. 34. APPENDIX 33
  35. 35. ANTERO MIDSTREAM – 2016 GUIDANCE Key Variable 2016 Guidance Financial: Adjusted EBITDA ($MM) $300 - $325 Distributable Cash Flow ($MM) $250 - $275 Year-over-Year Distribution Growth(1) 28% - 30% Operating: Low Pressure Pipeline Added (Miles) 9 High Pressure Pipeline Added (Miles) 22 Compression Capacity Added (MMcf/d) 240 Fresh Water Pipeline Added (Miles) 30 Capital Expenditures ($MM): Gathering and Compression Infrastructure $240 Fresh Water Infrastructure $40 Advanced Wastewater Treatment $130 Maintenance Capital $25 Total Capital Expenditures ($MM) $435 1. Reflects the expected distribution growth percentage associated with the fourth quarter 2016 over the fourth quarter 2015. Key Operating & Financial Assumptions 34
  36. 36. 2016 CAPITAL BUDGET By Area 35 $423 Million – 2015(1) By Segment ($MM) $349 $6 $55 $13 Gathering & Compression Fresh Water Infrastructure Advanced Wastewater Treatment Maintenance Capital 74% 26% Marcellus Utica By Area $435 Million – 2016 By Segment ($MM)  Antero Midstream’s 2016 initial capital budget is $435 million, a 3% increase from 2015 capital expenditures of $423 million 3% 130 Completions 1. Excludes $1.05 billion water drop down in September 2015. Water capex values only from 4Q 2015. $240 $40 $130 $25 Gathering & Compression Fresh Water Infrastructure Advanced Wastewater Treatment Maintenance Capital 92% 8% Marcellus Utica
  37. 37. ANTERO RESOURCES – 2016 GUIDANCE Key Variable 2016 Guidance Net Daily Production (MMcfe/d) 1,715 Net Residue Natural Gas Production (MMcf/d) 1,355 Net C3+ NGL Production (Bbl/d) 46,500 Net Ethane Production (Bbl/d) 10,000 Net Oil Production (Bbl/d) 3,500 Net Liquids Production (Bbl/d) 60,000 Natural Gas Realized Price Premium to NYMEX Henry Hub Before Hedging ($/Mcf)(1)(2) +$0.00 to $0.10 Oil Realized Price Differential to NYMEX WTI Oil Before Hedging ($/Bbl) $(10.00) - $(11.00) C3+ NGL Realized Price (% of NYMEX WTI)(1) 35% - 40% Ethane Realized Price (Differential to Mont Belvieu) ($/Gal) $0.00 Operating: Cash Production Expense ($/Mcfe)(3) $1.50 - $1.60 Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.15 - $0.20 G&A Expense ($/Mcfe) $0.20 - $0.25 Operated Wells Completed 110 Drilled Uncompleted Wells 70 Average Operated Drilling Rigs ≈ 7 Capital Expenditures ($MM): Drilling & Completion $1,300 Land $100 Total Capital Expenditures ($MM) $1,400 1. Based on current strip pricing as of December 31, 2015. 2. Includes Btu upgrade as Antero’s processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average. 3. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes. Key Operating & Financial Assumptions 36
  38. 38. Antero Long Term Firm Processing & Takeaway Position (YE 2018) – Accessing Favorable Markets Mariner East 2 62 MBbl/d Commitment Marcus Hook Export Shell 20 MBbl/d Commitment Beaver County Cracker (2) Sabine Pass (Trains 1-4) 50 MMcf/d per Train Lake Charles LNG(3) 150 MMcf/d Freeport LNG 70 MMcf/d 1. February 2016 and full year 2016 futures basis, respectively, provided by Intercontinental Exchange dated 12/31/2015. Favorable markets shaded in green. 2. Subject to Shell FID expected mid-year 2016. 3. Lake Charles LNG 150 MMcf/d commitment subject to BG FID expected in 2016. Chicago(1) $0.25 / $0.02 CGTLA(1) $(0.07) / $(0.06) TCO(1) $(0.16) / $(0.18) 37 Cove Point LNG4.85 Bcf/d Firm Gas Takeaway By YE 2018  Antero’s natural gas firm transportation (FT) portfolio builds to 4.85 Bcf/d by YE 2018 with 87% serving favorable markets, with an average demand fee of $0.46/MMBtu and positive weighted average basis differential to NYMEX after assumed Btu uplift for gas YE 2018 Gas Market Mix Antero 4.85 Bcf/d FT 44% Gulf Coast 17% Midwest 13% Atlantic Seaboard 13% Dom S/TETCO (PA) 13% TCO Positive weighted average basis differential Antero Commitments (3) (2) LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA
  39. 39. NORTHEAST NGLS ARE TRANSPORTATION CHALLENGED 1. As an anchor shipper on Mariner East 2, Antero has the right to expand its NGL commitment with notice to operator. 2. 2015 NGL production assumes ethane rejection. Mariner East 2 61,500 Bbl/d AR Commitment(1) 4Q 2016 In-Service  Not so much a supply problem but more of a logistics problem for NGLs in the northeast today − The majority of northeast NGL production is being transported by expensive rail and trucking − NGLs that are transported “to the water” are also faced with high shipping rates Export 15% Gulf Coast 13% Mid- Atlantic 6% Sarnia 3% Northeast 43% Midwest 10% Edmonton 10% 2015 NGL Marketing by Region 38
  40. 40. NORTHEAST NGL GROWTH IS SUPPORTED BY INCREASING TAKEAWAY OPTIONS 1. Chart 10 per BAML research dated 6/5/2015. Pipeline volumes are capacity estimates. Industry NGL Pipelines – Actual (2015) and Projected(1) 39 Shell Beaver County Cracker (Pending FID 1H 2016) Mariner East 2 62 MBbl/d Commitment Marcus Hook Export Gulf Coast Critical to NGL Pricing Appalachia  NGL transportation rates are expected to decline $0.12 to $0.15 per gallon by 2017 as pipeline options to domestic markets and export terminals go in-service (Mariner East 1 and 2, for example) (MMBbl/d)
  41. 41. 2015 GLOBAL LPG DEMAND  Global LPG demand is 8.5 MMBbl/d and growing 40
  42. 42. POSITIVE OUTLOOK FOR LONG-TERM NGL MARKETS Steady Global LPG Demand Growth Through 2035(1) 1. Source: PIRA NGL Study, September 2015. 2. Source: IHS, Waterborne, SK Gas Analysis; Wood Mackenzie; Wood Mackenzie; PDH C3 capacity based on 25 MBbl/d = 650 Mt/y. Multiple Factors Driving Global LPG Demand Growth Through 2020(2) MMBbl/d 0.0 0.33 0.67  Forecast global LPG demand growth of 800 MBbl/d to 1 MMBbl/d by 2020 to be driven by petrochem projects in Asia and Middle East as well as residential/commercial, alkylate and power generation demand − Naphtha cracker conversion to LPG another potential demand driver that has not yet been factored into analyst estimates ≈1 MMBbl/d China Korea Haiwei (2016) - 21 MBbl/d C3 SK Advanced (2016) - 27 MBbl/d C3 Ningbo Fuji (2016) - 29 MBbl/d C3 Fujian Meide (2016) - 29 MBbl/d C3 Tianjin Bohua 2 (2018) - 29 MBbl/d C3 United States Fujian Meide 2 (2018) - 29 MBbl/d C3 Enterprise (3Q 2016) - 29 MBbl/d C3 Oriental Tangshan (2019) - 25 MBbl/d C3 Formosa (2017) - 25 MBbl/d C3 Firm and Likely PDH Underway (By 2020) Total - 243 MBbl/d C3 Million Tons, Global PDH Capacity 1990 2000 2010 2020 20 10 0 41 14.7 13.0 11.4 9.8 8.2 6.5 4.9 3.3 1.7 U.S. Driven Global LPG Supply Through 2035(1) MMBbl/d MMBbl/d 1.3 1.0 0.7 0.3 -0.3
  43. 43. GLOBAL LPG DEMAND DRIVEN BY PETCHEM AND RES/COMM  Largest end-use sectors for LPG are residential/commercial, which tends to grow with population and improvement in living standards in the emerging markets − PIRA forecasting >1.0 MMBbl/d over next 5 years and >4.5 MMBbl/d of global LPG demand growth over next 20 years 42 1. PIRA NGL Study, September 2015. MMBbl/d 14.7 13.0 11.4 9.8 8.2 6.5 4.9 3.3 1.6
  44. 44. GLOBAL LPG TRADE DRIVEN BY U.S. SHALE  The U.S. is the largest single driver of the rapid expansion in LPG trade accounting for over 90% in trade growth 43 1. PIRA NGL Study, September 2015. MMBbl/d 5.2 4.6 3.9 3.3 2.6 2.0 1.3 0.7 United States
  45. 45. U.S. SHALE NGL EURS SUPPORT LPG TRADE GROWTH 44 1. PIRA NGL Study, September 2015. • U.S. shale play NGL reserves are 50.8 billion barrels • Eagle Ford, Marcellus, Utica, Bakken and Permian are the work horses of U.S. shale production growth • Marcellus/Utica NGL resource estimate by PIRA is 9.7 billion barrels, in line with Antero estimate of ≈ 11.1 billion barrels • The growth curve of each basin will ultimately be a function of downstream solutions and investment (1) (1) (1)
  46. 46. POSITIVE OUTLOOK FOR LONG-TERM ETHANE MARKETS AS WELL U.S. Ethane Supply/Demand Balance Through 2020(1) 1. Source: Bentek, August 2015. 2. Source: Citi research dated 7/15/2015. U.S. Ethane Exports Through 2020(2)  U.S. ethane demand is projected to increase at an annual 3.5% CAGR through 2020, primarily based on an ≈8% CAGR for U.S. petrochem demand and a 30% growth in exports primarily to Europe − The growth in shipping exports in 2016 and 2017 is driven by Enterprise Products’ 200 MBbl/d export facility on the Gulf Coast - 0.5 1.0 1.5 2.0 2.5 2012 2013 2014 2015 2016 2017 2018 2019 2020 MMBb/d Petchem Exports Rejection Total Supply (Net Stock Change) U.S. Seaborne Ethane Exports Through 2020(2) - 50 100 150 200 250 300 350 2013 2014 2015 2016 2017 2018 2019 2020 MBbl/d Ship Pipeline 250 200 150 100 50 MBbl/d U.S. exports increase significantly into 2016 and 2017 as EPD’s Morgan Point Facility comes in-service U.S. Ethane Rejection by Region Through 2020(1) Access to both Marcus Hook and the Gulf Coast is critical to optimizing ethane netbacks Rejection declines significantly into 2018 Unlike LPG, 80% of ethane will be consumed in the U.S. Petrochem demand increases at ≈8% CAGR through 2020 - 100 200 300 400 500 600 2012 2013 2014 2015 2016 2017 2018 2019 2020 MBbl/d Williston PADD 4 PADD 1 (East Coast) PADD 2 PADD 3 No Northeast rejection after 2017 45 Northeast Ethane Rejection Exports U.S. PetChem
  47. 47. LTM Production NTM Production Forecast Average LTM Production MAINTENANCE CAPITAL METHODOLOGY • Maintenance Capital Calculation Methodology – Low Pressure Gathering – Estimate the number of new well connections needed during the forecast period in order to offset the natural production decline and maintain the average throughput volume on our system over the LTM period – (1) Compare this number of well connections to the total number of well connections estimated to be made during such period, and – (2) Designate an equal percentage of our estimated low pressure gathering capital expenditures as maintenance capital expenditures Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity or revenue • Illustrative Example LTM Forecast Period Decline of LTM average throughput to be replaced with production volume from new well connections 46 • Maintenance Capital Calculation Methodology – Fresh Water Distribution − Estimate the number of wells to which we would need to distribute fresh water during the forecast period in order to maintain the average fresh water throughput volume on our system over the LTM period − (1) Compare this number of wells to the total number of new wells to which we expect to distribute fresh water during such period, and − (2) Designate an equal percentage of our estimated water line capital expenditures as maintenance capital expenditures
  48. 48. ANTERO RESOURCES EBITDAX RECONCILIATION 47 EBITDAX Reconciliation ($ in millions) Quarter Ended LTM Ended 12/31/2015 12/31/2015 EBITDAX: Net income including noncontrolling interest $175.6 $980.0 Commodity derivative fair value (gains) (545.1) (2,381.5) Net cash receipts on settled derivatives instruments 269.9 856.6 Interest expense 60.5 234.4 Income tax expense (benefit) 77.2 575.9 Depreciation, depletion, amortization and accretion 162.2 711.4 Impairment of unproved properties 60.7 104.3 Exploration expense 0.8 3.8 Equity-based compensation expense 18.6 97.9 State franchise taxes (0.1) 0.1 Contract termination and rig stacking 27.6 38.5 Consolidated Adjusted EBITDAX $307.8 $1,221.4
  49. 49. ANTERO MIDSTREAM EBITDA RECONCILIATION 48 EBITDA and DCF Reconciliation $ in thousands Three months ended December 31, 2014 2015 Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow: Net income $55,898 $49,008 Add: Interest expense 2.062 2,892 Depreciation expense 17,290 23,152 Contingent acquisition consideration accretion - 3,333 Equity-based compensation 4,226 4,810 Adjusted EBITDA $79,476 $83,195 Less: Pre-water acquisition net income attributed to parent (22,234) - Pre-water acquisition depreciation expense attributed to parent (3,086) - Pre-water acquisition equity-based compensation expense attributed to parent (654) - Pre-water acquisition interest expense attributed to parent (359) - Pre-IPO EBITDA (36,464) - Adjusted EBITDA $16,679 83,195 Less: Cash interest paid - attributable to Partnership (331) (2,934) Income tax witholding upon vesting of Antero Midstream LP equity-based compensation awards - (4,806) Maintenance capital expenditures attributable to Partnership (1,157) (3,096) Distributable Cash Flow $15,191 $72,359
  50. 50. CAUTIONARY NOTE 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, which have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates as of December 31, 2015 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, 2015. 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. Regarding Hydrocarbon Quantities 49

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