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Am website presentation (a) september 2016

Am website presentation (a) september 2016

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Am website presentation (a) september 2016

  1. 1. Partnership Overview September 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 SEPTEMBER 2016 PRESENTATION Updated balance sheet and liquidity data pro forma for AM senior notes offering Slides 27, 28
  4. 4. 491 638 597 744 0 100 200 300 400 500 600 700 800 900 1,000 Dedicated Acreage: Gathering & Compression Dedicated Acreage: Water Services ANTERO RESOURCES ACQUISITION BENEFITS AM 3 Antero Midstream Buildout Compressor Station – In service Districts with 3,000+ Antero Net Acres Acquisition Acreage Compressor Station – Planned on Existing Acreage Existing Gathering Line New Platform for Antero Midstream Infrastructure Buildout Fresh Water Delivery Take Point Planned Gathering Line 1. Includes projects currently under construction. AM Gross Dedicated Acreage (000’s) A unique opportunity as most Appalachian core acreage is already dedicated to third party midstream providers 12/31/2015 Pro Forma Fresh Water ImpoundmentExisting Fresh Water Line Planed Fresh Water Line Planned Gathering Line – Acquisition Acreage Compressor Station – Planned on Acquisition Acreage On June 9, 2016 Antero Resources announced the acquisition of 66,500 net acres in the southwestern Marcellus Shale, over 95% of which will be dedicated to AM for gathering, compression, processing, and water services  Acquisition and associated equity financing allows Antero Resources to increase 2017 production target to 20% to 25%, providing further support to Antero Midstream’s 2017 distribution growth target of 28% to 30%  Expands Antero Midstream footprint and identified 5-year investment opportunity set by over 15% to ~$3.2 billion(1) – Attractive organic investment opportunities at 4x to 7x build-out EBITDA – Additional adjacent third-party midstream opportunities
  5. 5. Classification(1) Highly-Rich Gas/Condensate Highly-Rich Gas BTU Regime 1275-1350 1275-1350 1275-1350 1200-1275 1200-1275 1200-1275 EUR (Bcfe): 20.8 24.4 27.9 18.8 22.1 25.2 EUR (MMBoe): 3.5 4.1 4.7 3.1 3.7 4.2 % Liquids: 33% 33% 33% 24% 24% 24% Well Cost ($MM): $8.1 $8.1 $8.1 $8.1 $8.1 $8.1 Bcf/1,000’ 1.7 2.0 2.3 1.7 2.0 2.3 Bcfe/1,000’: 2.3 2.7 3.1 2.1 2.5 2.8 Net F&D ($/Mcfe): $0.46 $0.39 $0.34 $0.51 $0.43 $0.38 Pre-Tax NPV10 ($MM): $12.3 $15.9 $19.5 $8.2 $11.1 $13.9 Pre-Tax ROR: 58% 77% 99% 38% 51% 66% Payout (Years): 1.5 1.1 0.9 2.1 1.6 1.3 Breakeven NYMEX Gas Price ($/MMBtu)(5) $1.22 $0.95 $0.76 $2.02 $1.77 $1.57 Gross 3P Locations(3): 557 1,052 Pro Forma Gross 3P Locations(3): 664 (19% Increase) 1,235 (17% Increase) $12.3 $15.9 $19.5 $8.2 $11.1 $13.9 58% 77% 99% 38% 51% 66% 0% 20% 40% 60% 80% 100% -$1.0 $2.0 $5.0 $8.0 $11.0 $14.0 $17.0 $20.0 1.7 2.3 2.0 2.7 2.3 3.1 1.7 2.1 2.0 2.5 2.3 2.8 Pre-TaxROR Pre-TaxPV-10 Pre-Tax PV-10 Pre-Tax ROR NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL(2) ($/Bbl) 2016 $3.04 $50 $22 2017 $3.18 $52 $26 2018 $3.02 $54 $27 2019 $3.00 $55 $28 2020 $3.06 $55 $28 2021-25 $3.53 $58 $30 Assumptions  Natural Gas – 6/30/2016 strip  Oil – 6/30/2016 strip  NGLs – 37.5% of Oil Price 2016; ~50% of Oil Price 2017+ 45/8435/24 2016/2017 Development Plan: Completions 1. 6/30/2016 pre-tax well economics based on a 9,000’ lateral, 6/30/2016 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 include $1.2 million for road, pad and production facilities. Assumes ethane rejection. 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 Marcellus well locations as of 12/31/2015 adjusted for 6/30/2016 net acreage and pending acreage acquisition. 4. Represents actual results for 1Q 2016. 5. Breakeven price for 15% pre-tax rate of return. Highly-Rich Gas/Condensate Highly-Rich Gas (4) (4)Bcf/1,000’ Bcfe/1,000’ MARCELLUS UPSIDE POTENTIAL 4  33% lower well cost per 1,000’ lateral and 33% higher EUR per 1,000’ since 2014 are driving rates of return significantly higher despite lower strip pricing
  6. 6. Marcellus ShaleUtica Shale OhioOperating Highlights  Top 20 best drilling footage days in Marcellus since 2009 have all occurred in 2016, including 7,274’ drilled in 24 hours in West Virginia on the Hunter 1H  Recently drilled and cased longest lateral in company history at 14,024 feet  Stayed within targeted zone for 95% of lateral length of all wells drilled in Q2 2016  Increased sand placement during completions to 99% in Q2 2016  Utilizing new floating casing procedure, reducing casing run time by over 12 hours  Increased proppant and water loading by 25% in 2016 with encouraging results to date 1. 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 81% NRI in Utica and 85% NRI in Marcellus. Acquired Acreage CONTINUOUS OPERATING IMPROVEMENTS BY AR Utica Marcellus 2014 2015 Q2 2016 Q2 2016 vs. 2014 2014 2015 Q2 2016 Q2 2016 vs. 2014 Activity Levels Average Rigs Running 4 5 1 (75%) 14 9 6 (57%) Average Completion Crews 2.0 3.0 1.0 (50%) 5.5 2.0 3.5 (36%) Operational Improvements Drilling Days 29 31 16 (45%) 29 24 15 (48%) Average Lateral Length (Ft) 8,543 8,575 9,000 5% 8,052 8,910 9,000 12% Stages per Well 47 49 51 9% 40 45 45 12% Stage Length 183 175 175 4% 200 200 200 0% Stages per Day 3.2 3.7 4.4 38% 3.2 3.5 3.9 22% Well Cost & Performance Improvements D&C per 1,000' of lateral ($MMs) $1.55 $1.36 $1.04 (33%) $1.34 $1.18 $0.90 (33%) Wellhead EUR per 1,000' of lateral (Bcf) (1) 1.4 1.6 1.6 14% 1.5 1.7 2.0 33% Processed EUR per 1,000' of lateral (Bcfe) (1)(2) 1.5 1.8 1.8 20% 1.8 1.9 2.3 28% Net development cost (F&D) per Mcfe (2)(3) $1.28 $0.94 $0.72 (44%) $0.88 $0.73 $0.46 (47%) 5
  7. 7. 32 31 32 32 32 32 32 31 31 32 34 34 35 36 37 39 41 43 45 41 20 25 30 35 40 45 50 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 2016 Plan BarrelsPerFootofLateral 1,194 1,128 1,117 990 1,031 1,016 958 956 1,084 1,126 1,274 1,304 1,337 1,418 1,480 1,530 1,578 1,701 1,724 1,700 - 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 2016 Plan SandPlacedPerFootofLateral ADVANCED COMPLETIONS DRIVE INCREASED WATER VOLUMES 6 AR Has Increased Proppant Load by over 25% in the Marcellus and Utica Pilot Testing Demonstrated Improved Recoveries While Maintaining Well Density New AR Marcellus Completion Designs Utilizing 38 to 45 Barrels of Water Per Lateral Foot, a 19% to 41% Increase  New AR completion designs result in more water utilization driving higher AM fees, while increased proppant generating encouraging results with potential long-term benefits to AM
  8. 8. 0 500 1,000 1,500 2,000 2,500 2Q16 Actual 2016 Guidance 2017 Target GrossWellheadGasProduction(MMcf/d)AM VOLUME THROUGHPUT VS. AR PRODUCTION 7 1,755 MMcf/d Third Party Gathering: 402 MMcf/d AM Compression Capacity @ YE 2016: 1,060 MMcf/d AM Compression Capacity @ YE 2017: 1,420 MMcf/d AM Compression: 658 MMcf/d (80% Utilization) AM LP: 1,353 MMcf/d (78% of AR Gross Wellhead Volume) AR does not expect material growth in third party gathered volumes through 2017 Third Party Gathering Third Party Gathering AM HP: 1,253 MMcf/d (93% of LP Volume) 1,783 MMcf/d 2,184 MMcf/d AR Gross Wellhead Gas Production (Including 3rd Party Gathering) Antero Midstream Volumes • AM continues to gather and compress an increasing percentage of the total gross gas production 1. Assumes 3% fuel. AM Compression Capacity: 820 MMcf/d Production/Throughput Reconciliation (MMcf/d) 2Q16 AR Net Gas Production 1,311 Net Revenue Interest Gross-Up 80% Average Processing Shrink Gross-Up 94% AR Gross Gas Production (MMcf/d) 1,755 - Third Party LP Gathering Volumes 402 = AM LP Gathering Volumes 1,353 - Fuel/Third Party HP Gathering Volumes (1) 7% = AM HP Gathering Volumes 1,253
  9. 9. 132 96 MVC 90 MVC 100 MVC 120 MVC 120 0 20 40 60 80 100 120 140 160 180 200 2014 2015 2016 2017 2018 2019 2020 MBbl/d 2017 MVC 2017-2019 Earnout Fresh Water Volumes (MBbl/d) 100 161 Fresh Water Volumes (MBbls) 36,500 58,765 Volumes per Well Completion (MBbls)(2) 345 345 Implied Well Completions (Annual) 105 170 SUSTAINABLE WATER BUSINESS GROWTH 81. Includes 70 deferred completions. 2. Assumes 9,000 foot lateral and 39 Bbl/ft and 34 Bbl/ft of water for Marcellus and Utica, respectively. Deferred completions drive substantial growth in 2017 and beyond, underpinned by minimum volume commitments 177Completions ~110Completions (Guidance) 2020 Earn Out – 200 MBbl/d Avg 131Completions 170-180Completions Targeted(1) Fresh Water Delivery Volumes (MBbl/d) “Traditional” Completions “Advanced” Completions utilizing 25% more water 2017 targeted activity implies 155- 165 MBbl/d of delivered water 2019 Earn Out – 161 MBbl/d Avg
  10. 10. ANTERO MIDSTREAM EXERCISES STONEWALL OPTION • Antero Midstream has exercised its option to acquire a 15% non-operated equity interest in the Stonewall gathering pipeline - Capital investment: $45 million - Expected unlevered IRR: 25% - 35% - Effective date: May 26, 2016 ● Another step towards becoming “full value chain” midstream provider - Fixed fee revenues with minimum volume commitments ● Antero Resources is an anchor shipper with the ability to transport 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 transporting ~950 MMcf/d Stonewall Gathering Pipeline Option Throughput Capacity: 1.4 Bcf/d Pipeline Specifications: 67 miles of 36-inch pipeline Project Capital: ≈ $400 Million In-Service Date: 12/1/2015 AR Firm Commitment: 900 MMcf/d 9 Stonewall Gathering Pipeline Asset Details Acquisition Acreage
  11. 11. WHY OWN ANTERO MIDSTREAM? 10  Best-in-class distribution growth guidance of 30% in 2016 and 28% to 30% target for 2017  Strong DCF coverage of 1.60x in 1Q16 and 1.45x in 2015, above 1.1x–1.2x target Strong Distribution Growth & Coverage Sponsor Strength Organic Investment Opportunity Set Full Value Chain Midstream Opportunity Financial Flexibility Aligned High Growth Sponsor  $4.6 billion of consolidated pro forma liquidity; stable leverage through the down cycle  Ba2/BB corporate ratings affirmed; $4.5 billion AR borrowing base affirmed  94% of forecasted production hedged through 2018 at $3.81/MMBtu  Peer leading realized prices and EBITDAX margins  Identified organic investment opportunity set of $3.2 billion over the next five years  “Just-in-time capital” results in more capital efficient project economics, while avoiding the competitive acquisition market and reliance on capital markets  Organic growth strategy results in investment build-out EBITDA multiples of 4x–7x vs. drop-downs of 8x–12x  Opportunity to expand gathering, compression, and water services to third parties  Right of first offer for processing, fractionation, transportation and marketing activities  Midstream provider for the largest and most active operator in Appalachia inherently brings additional downstream opportunities to AM  $1,390 million of liquidity and 2.4x debt to EBITDA ratio at June 30, 2016 pro forma  20% production growth guidance in 2016 and 20% to 25% growth targeted for 2017 drives AM volume growth  Continuous operating improvements, including more water and sand in completions resulting in improved recoveries and well economics for AR and higher volumes for AM  AR has a 61% LP ownership in AM, resulting in direct alignment with midstream value creation
  12. 12. Sustainable Business Model High Growth Sponsor Drives AM Throughput and Distribution Growth Largest Dedicated Core Liquids-Rich Acreage Position in Appalachia $1.4 billion of AM Liquidity 11 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 Hedges Bolster Solid Well Economics
  13. 13. 0 500 1,000 1,500 2,000 2,500 3,000 3,500 - 100 200 300 400 500 600 AR Peer 1 Peer 2 Peer 3 Peer 5 Peer 4 Peer 6 Pro Forma Core Net Acres - Dry Core Net Acres - Dry Pro Forma Core Net Acres - Liquids-Rich Core Net Acres - Liquids-Rich 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 AR EQT RRC COG CNX CHK SWN 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 EQT AR CHK COG RRC SWN CNX SPONSOR STRENGTH – LEADERSHIP IN APPALACHIAN BASIN Top Producers in Appalachia (Net MMcfe/d) – 2Q 2016(1)(2) Top 12 U.S. Natural Gas Producers (Net MMcf/d) – 2Q 2016(1) Appalachian Producers by Proved Reserves (Bcfe) – YE 2015(1)(2) Appalachian Producers by Core Net Acres (000’s) – June 2016(4) 1. Based on company filings and presentations. Excludes pro forma additions via acquisitions. 2. Appalachian only production and reserves where available. 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. EQT adjusted for STO acreage acquisition. Pro forma for AR announced acreage acquisition. (3) 12 2nd Largest Appalachian Producer in 2Q ‘16 Appalachian Peers 8th Largest U.S. Gas Producer in 2Q ‘16 Largest Proved Reserve Base In Appalachia Antero Has the Largest Liquids-Rich Core Position in Appalachia ) ) ) )  Antero has the largest proved reserve base, largest core liquids-rich acreage position and is one of the largest producers in the Appalachian Basin and the U.S.
  14. 14. $198 $341 $434 $649 $1,164 $1,221 $1,386 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 2010 2011 2012 2013 2014 2015 2016E 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 2010 2011 2012 2013 2014 2015 2016E NGLs (C3+) Oil Ethane 5 246 6,436 23,051 48,298 73,000 51% Growth Guidance 1. Represents midpoint of updated 2017 production guidance of 20% to 25% per press release dated 6/9/2016. 2. Represents Bloomberg street consensus estimates as of 6/30/2016. 1,800 2,205 0 600 1,200 1,800 2,400 2010 2011 2012 2013 2014 2015 2016E 2017E Marcellus Utica Guidance 30 124 239 522 1,007 1,493 13 AVERAGE NET DAILY PRODUCTION (MMcfe/d) 0 50 100 150 200 2010 2011 2012 2013 2014 2015 2016E Marcellus Utica Deferred Completions 19 38 60 114 177 181 131 110 180 OPERATED GROSS WELLS COMPLETED AVERAGE NET DAILY LIQUIDS PRODUCTION (Bbl/d) 20% Growth Guidance 23% Growth Target(1)  Antero is in the unique position of being able to sustain growth and value creation through the price down cycle CONSOLIDATED EBITDAX ($MM) Street Consensus(2) SPONSOR STRENGTH – MOMENTUM THROUGH THE DOWN CYCLE
  15. 15. 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. Pro forma for recently announced third-party acreage acquisition. 3P reserve additions are unaudited. 14 to 18 Tcf Utica dry resource in WV/PA. 2. 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. $1.5 billion 3P PV-10 estimate for acreage acquisition, using 12/31/2015 strip pricing and same year end 2015 assumptions, is unaudited. 3. Virtually all WV/PA Utica Shale net acres are included among the net acres of Marcellus Shale rights as they are stacked pay formations attributable to the same leasehold. 4. Antero and industry rig locations as of 7/22/2016, per RigData. 14 AR COMBINED TOTAL – 12/31/15 RESERVES Assumes Ethane Rejection Net Proved Reserves 13.2 Tcfe Net 3P Reserves(1) 42.1 Tcfe Strip Pre-Tax 3P PV-10(2) $12.7 Bn Net 3P Reserves & Resource(1) 57 to 60 Tcfe Net 3P Liquids(1) 1,377 MMBbls % Liquids – Net 3P(1) 20% 2Q 2016 Net Production 1,762 MMcfe/d - 2Q 2016 Net Liquids 75,041 Bbl/d Net Acres(1)(3) 641,000 Undrilled 3P Locations(1) 4,344 OHIO UTICA SHALE CORE Net Proved Reserves 1.8 Tcfe Net 3P Reserves 7.5 Tcfe Strip Pre-Tax 3P PV-10(2) $2.5 Bn Net Acres 147,000 Undrilled 3P Locations 814 MARCELLUS SHALE CORE Net Proved Reserves 11.4 Tcfe Net 3P Reserves(1) 34.6 Tcfe Strip Pre-Tax 3P PV-10(2) $10.2 Bn Net Acres(1) 494,000 Undrilled 3P Locations(1) 3,530 WV/PA UTICA SHALE DRY GAS Net Resource 14.3 to 17.8 Tcf Net Acres 231,000 Undrilled Locations 2,269 SPONSOR STRENGTH – MOST ACTIVE OPERATOR  AR is operating 16% of all rigs running and 67% of rigs running in liquids rich core areas in Appalachia 0 1 2 3 4 5 6 7 RigCount Operators SW Marcellus + Utica Rigs(4) Most Active Operator Pending Acquisition Acreage Antero Acreage Marcellus Core Marcellus Fairway Utica Core Utica Fairway Antero Rig Marcellus Industry Rig Utica Industry Rig
  16. 16. 110 0 50 100 150 200 250 300 350 400 2016E 2017E 2018E 2019E 2020E AnnualCompletions Marcellus 3P Completions Ohio Utica Completions Antero plans to develop over 1,000 horizontal locations in the Marcellus and Ohio Utica by the end of the decade while reducing its current 3P drilling inventory by less than 25% PLANNED ANTERO WELL COMPLETIONS BY YEAR CURRENT UNDRILLED 3P LOCATIONS (1) ESTIMATED YE 2020 UNDRILLED 3P LOCATIONS 4,344 Locations 3,309 Locations Expect to place >1,000 Marcellus and Utica wells to sales by YE 2020 Condensate 4% Highly-Rich Gas 29%Rich Gas 20% Dry Gas 28% Highly-Rich Gas/Condensate 19% Condensate, 5% Highly-Rich Gas/Condens ate (8%) Highly-Rich Gas 33% Rich Gas, 20% Dry Gas, 34% Highly-Rich Gas/Condensate 8% 1. Marcellus and Utica 3P locations pro forma for recent acreage acquisition. Excludes WV/PA Utica Dry locations. Average Lateral Length ~8,800 feet 15 38% to 62% IRRs 17% to 49% IRRs 58% to 66% IRRs19% to 44% IRRs 21% IRR SPONSOR STRENGTH – SIGNIFICANT SPONSOR DRILLING INVENTORY TO DRIVE VALUE FOR ANTERO MIDSTREAM
  17. 17. $1 $5 $7 $8 $11 $19 $28 $36 $41 $55 $83 $80 $88 $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 26 31 40 36 41 116 222 358 454 435 478 606 657 0 100 200 300 400 500 600 700 800 Utica Marcellus 10 38 80 126 266 531 908 1,134 1,197 1,216 1,1951,222 1,253 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 Utica Marcellus 108 216 281 331 386 531 738 935 965 1,038 1,124 1,303 1,353 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 Utica Marcellus Low Pressure Gathering (MMcf/d) Compression (MMcf/d) High Pressure Gathering (MMcf/d) EBITDA ($MM) 16 $375 Note: Y-O-Y growth based on 2Q’15 to 2Q’16. 1. Represents midpoint of updated 2016 guidance. GROWTH – HIGH GROWTH MIDSTREAM THROUGHPUT $215
  18. 18. $0.170 $0.180 $0.190 $0.205 $0.235 $0.250 1.1x 1.2x 1.3x 1.4x 1.8x 1.6x 1.7x 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 1Q16A 2Q16A 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E Distribution Per Unit (Left Axis) DCF Coverage (Right Axis) $0.220 17 • Antero Midstream is targeting 28% to 30% annual distribution growth through 2017 • AM has delivered on those targets with DCF coverage of 1.7x in the second quarter 2016 Note: Future distributions subject to AM Board approval. 1. Assumes midpoint of target distribution growth range. GROWTH – TOP TIER DISTRIBUTION GROWTH AND COVERAGE
  19. 19. GROWTH – ORGANIC GROWTH STRATEGY DRIVES VALUE CREATION 18 • Organic growth strategy provides attractive returns and project economics, while avoiding the competitive acquisition market and reliance on capital markets • Industry leading organic growth story – ~$1.9 billion in capital spent through 09/30/2015 on gathering and compression and water assets – $410 million in additional growth capital forecast for the twelve-month period ending 12/31/16 (excludes $25 million of maintenance capital and $45 million acquisition of Stonewall pipeline interest) – 5-year identified investment opportunity set of $3.2 billion through 2020 Note: Precedent data per IHS Herold’s research and public filings. 1. Antero organic multiple calculated as estimated gathering and compression and water capital expended through Q3 2015 divided by midpoint of 2016 EBITDA guidance of $325 to $350 million, assuming 12-15 month lag between capital incurred and full system utilization. 2. Selected gathering and compression drop down acquisitions since 6/1/2014. Drop down multiples are based on NTM EBITDA. Source: Barclays. 5.0x 10.0x 9.6x 9.5x 9.5x 9.4x 9.3x 9.0x 8.8x 8.7x 8.6x 8.6x 8.6x 8.5x 8.3x 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
  20. 20. LP Gathering HP Gathering Compression Condensate Gathering Fresh Water Delivery Advanced Wastewater Treatment Stonewall Gathering Pipeline Processing/ Fractionation Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 25% - 35% 30% - 40% 15% - 25% 25% - 35% 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 2.0 - 3.5 5.0 - 6.0 Minimum Volume Commitments: N/A 75% 70% N/A Yes N/A 80% 80% 2016 Expansion Capex(2) Total Marcellus $433 $33 $49 $143 - $33 $130 $45 Utica 22 7 1 7 - 7 - - Growth Capex $455 $40 $50 $150 $0 $40 $130 $45 % of Capex 100% 9% 11% 33% 0% 9% 28% 10% Included in 2016 Budget: Marcellus & Utica Marcellus & Utica Marcellus & Utica Utica Marcellus & Utica Marcellus & Utica Marcellus Not Included 5-year identified investment opportunity set $3.2 B 30% - 35% 15% - 20% 30% - 35% 0% 8% - 12% 6% - 8% 1% Additional In-hand Opportunities: Dry Utica Dry Utica Dry Utica Utica Stabilization Dry Utica Dry Utica Marcellus Processing/ Fractionation 25% 15% 10% 25% 30% 15% 15% 35% 25% 20% 35% 25% 25% 40% 20% 0% 10% 20% 30% 40% InternalRateofReturn 19 Project Economics by Segment(1) GROWTH – ESTIMATED PROJECT ECONOMICS BY SEGMENT 1. Based on management capex, operating cost and throughput assumptions by project. 2. Excludes $25.0 million of maintenance capex. Includes Stonewall option exercise. Wtd. Avg. 21% IRR AM Option Opportunities 35%
  21. 21. 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 7/22/2016. 1. Based on company filings and presentations. Peers include: Ascent, CHK, CNX, CVX, ECR, EQT, GPOR, NBL, REX, RRC and SWN. • Pro forma for the recent acreage acquisition, Antero controls an estimated 39% of the NGLs in the liquids-rich core of the two plays • Antero has the largest core liquids-rich position in Appalachia with ≈420,000 net acres (> 1100 Btu) • Represents over 24% of core liquids- rich acreage in Marcellus and Utica plays combined  Antero has over 3,080 undeveloped rich gas locations in its 3P reserves as of 12/31/2015, pro forma for the pending acreage acquisition 0 100 200 300 400 500 (000s) Core Liquids-Rich Net Acres(1) 20 Incremental core liquids-rich acreage included in pending acquisition LIQUIDS-RICH – LARGEST CORE DRILLING INVENTORY
  22. 22. $1.55 $1.36 $1.04 $0.000 $0.500 $1.000 $1.500 $2.000 2014 2015 Current $MM/1,000’Lateral Well Cost ($MM/1,000' of Lateral) 12% Decrease vs. 2014 24% Decrease vs. 2015 664 1,235 691 940 69% 48% 24% 28% 58% 38% 17% 19% 0 400 800 1,200 1,600 0% 20% 40% 60% 80% Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total3PLocations ROR Total 3P Locations ROR @ 6/30/2016 Strip Pricing - After Hedges ROR @ 6/30/2016 Strip Pricing - Before Hedges 184 98 108 161 263 24% 79% 84% 70% 71% 21% 66% 62% 49% 44% 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)(3) Marcellus Well Cost Improvement(4) 1. 6/30/2016 pre-tax well economics based on 1.7 Bcf/1,000’ type curve for Marcellus 9,000’ lateral, 6/30/2016 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 include $1.2 million for road, pad and production facilities. 2. ROR @ 6/30/2016 Strip-With Hedges reflects 6/30/2016 well cost ROR methodology, with the 6/30/2016 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip and hedge prices. 3. Marcellus undeveloped well locations as of 12/31/2015 adjusted for 6/30/2016 net acreage and pro forma for third-party acreage acquisition per press release dated 6/9/2016. 4. Current spot well costs based on $8.1 million for a 9,000’ lateral Marcellus well and $9.4 million for a 9,000’ lateral Utica well. 21 UTICA WELL ECONOMICS(1)(2)  73% 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 33% in the Marcellus and 33% in the Utica as compared to 2014 well costs  At 6/30/2016 strip pricing, Antero has 2,713 locations that exceed a 20% rate of return (excluding hedges) – Including hedges, these locations generate rates of return of approximately 48% to 84% Utica Well Cost Improvement(4) $1.34 $1.18 $0.90 $0.000 $0.500 $1.000 $1.500 $2.000 2014 2015 Current $MM/1,000’Lateral Well Cost ($MM/1,000' of Lateral) 12% Decrease vs. 2014 24% Decrease vs. 2015 SUSTAINABLE BUSINESS MODEL – HEDGES BOLSTER SOLID WELL ECONOMICS
  23. 23. 22 In-service 2016 Budget HIGH VISIBILITY – PROJECTED MIDSTREAM BUILDOUT Pending Acquisition Acreage Utica Marcellus
  24. 24. 7 0 3 0 2 6 0 2 4 6 8 AM CNNX EQM CMLP SMLP RMP Fixed Fee 100% Fixed Fee 100% 23 MITIGATED COMMODITY RISK – 100% FIXED FEE – RICH TO DRY Contract Mix Fixed Fee 98% 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 6/24/2016, 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) AM has no direct commodity price exposure
  25. 25. - 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 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 May-18 Jul-18 Sep-18 Nov-18 Jan-19 Mar-19 May-19 Jul-19 Sep-19 Nov-19 Jan-20 Mar-20 May-20 Jul-20 Sep-20 Nov-20 24 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 • Realized pricing in line with Nymex gas prices year-to-date in 2016, before hedges 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 Gross Gas Production (BBtu/d) 2017 Production Target: 20 – 25%(1) 1. Per press release dated 09/06/16.
  26. 26. $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $0 $50 $100 $150 $200 $250 $300 $350 $MM 25  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 the amount of time for well payouts, thereby enhancing liquidity  Antero has realized $2.4 billion of gains on commodity hedges since 2009 – Gains realized in 29 of last 30 quarters, or 97% of the quarters since 2009 ● Based on Antero’s hedge position and strip pricing as of 6/30/2016, the unrealized commodity derivative value is $2.1 billion ● Significant additional hedge capacity remains under the credit facility hedging covenant for 2020 – 2022 period Quarterly Realized Hedge Gains / (Losses) Realized Hedge Gains Projected Hedge Gains NYMEX Natural Gas Historical Spot Prices ($/MMBtu) NYMEX Natural Gas Futures Prices 06/30/16 3.4 Tcfe Hedged at average price of $3.71/Mcfe through 2022 Average Hedge Prices ($/MMBtu) $3.36 $3.96 $3.57 $3.91 $3.70 $3.66 $3.24 $2.1 Billion in Projected Hedge Gains Through 2022Realized $2.4 Billion in Hedge Gains Since 2009 HEDGING – INTEGRAL TO BUSINESS MODEL (1) 1. Represents average hedge price for six months ending 12/31/2016.
  27. 27. Regional Gas Pipelines – 15% Ownership Miles Capacity In-Service Stonewall Gathering Pipeline(3) 67 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. Antero Midstream has a right of first offer on 220,000 dedicated net acres for processing and fractionation pro forma for pending third-party acreage acquisition. 3. Antero Midstream owns 15% ownership in Stonewall pipeline. 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 (Ethane, Propane, Butane, etc.) 26 VALUE CHAIN OPPORTUNITY – FULL MIDSTREAM VALUE CHAIN AM Option Opportunities(2) AM recently exercised its option on 15% interest in Stonewall, adding a regional gas gathering pipeline to its portfolio
  28. 28. Liquid “non-E&P assets” of $5.1 Bn significantly exceeds total debt of $3.9 Bn pro forma for equity offering shoe exercise Pro Forma Liquidity Antero Resources (NYSE:AR) Antero Midstream (NYSE:AM) Pro Forma 6/30/2016 Debt Liquid Non-E&P Assets Pro Forma 6/30/2016 Debt (4) Liquid Assets Debt Type $MM Credit facility $556 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 $3,931 Asset Type $MM Commodity derivatives(1) $2,096 AM equity ownership(2) 3,018 Cash 19 Total $5,133 Asset Type $MM Cash $19 Credit facility – commitments(3) 4,000 Credit facility – drawn (556) Credit facility – letters of credit (708) Total $2,755 Debt Type $MM Credit facility $120 5.375% senior notes due 2024 650 Total $770 Asset Type $MM Cash $9 Total $9 Pro Forma Liquidity Asset Type $MM Cash $9 Credit facility – capacity 1,500 Credit facility – drawn (120) Credit facility – letters of credit - Total $1,389 Approximately $2.8 billion of liquidity at AR pro forma for equity offering shoe exercise plus an additional $3.0 billion of AM units Approximately $1.4 billion of liquidity at AM pro forma for senior notes offering 27 Only 8% of AM credit facility capacity drawn pro forma for recent $650 million senior notes offering Note: All balance sheet data as of 6/30/2016. Antero Resources pro forma for $85 million net proceeds from shoe exercise and $546 million cost of pending acreage acquisition including tag along right less $45 million deposit. 1. Mark-to-market as of 6/30/2016. 2. Based on AR ownership of AM units (108.3 million common and subordinated units as of 9/2/2016) and AM’s closing price as of 6/30/2016. 3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion. 4. Pro forma for $650 million senior notes offering on 9/8/2016 with net proceeds used to repay the credit facility. LIQUIDITY – STRONG BALANCE SHEET AND FLEXIBILITY
  29. 29. 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x 4.0x 4.5x Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 TotalDebt/LTMAdjusted EBITDA • $1.5 billion revolver in place to fund future growth capital (5x Debt/EBITDA Cap) • Liquidity of $1,389 million at 6/30/2016 pro forma for $650 million senior notes offering as of 9/8/2016 • Sponsor (NYSE: AR) has Ba2/BB corporate debt ratings • AM corporate debt ratings also Ba2/BB Pro Forma AM Liquidity (6/30/2016) AM Peer Leverage Comparison(2) ($ in millions) Revolver Capacity $1,500 Less: Borrowings(1) 120 Plus: Cash 9 Liquidity $1,389 1. Pro forma for $650 million senior notes offering as of 9/8/2016 with net proceeds used to repay credit facility. 2. As of 3/31/2016. Peers include TEP, EQM, WES, RMP, SHLX, DM, and CNNX. 3. AM includes full year EBITDA contribution from water business. Financial Flexibility 28 (3) 2.3x STRONG FINANCIAL POSITION – SIGNIFICANT FINANCIAL FLEXIBILITY
  30. 30. TOP TIER DISTRIBUTION GROWTH & HEALTHY COVERAGE 29 3 –Year Street Consensus Distribution Growth Rate and DCF Coverage(1) 1. Based on Bloomberg 2015-2018 Bloomberg consensus estimates as of 6/30/2016. 31% 26% 26% 24% 23% 22% 19% 12% 12% 8% 1.7x 1.3x 1.4x 2.0x 1.3x 1.3x 1.4x 1.4x 1.2x 1.2x 0.0x 0.2x 0.4x 0.6x 0.8x 1.0x 1.2x 1.4x 1.6x 1.8x 2.0x 0% 5% 10% 15% 20% 25% 30% 35% SHLX PSXP AM VLP DM TEP EQM CNNX MPLX WES
  31. 31. EQM DM SHLX CNNX WES TEP MPLX PSXPVLP RMP AM – 6/30/2016 Yield: 3.37% Price: $27.87/unit 0.0% 1.0% 2.0% 3.0% 4.0% 5.0% 6.0% 7.0% 8.0% 9.0% 10.0% 3% 8% 13% 18% 23% 28% 33% Yield(%) 2016-2018 Distribution Growth CAGR Bubble Size Reflects Market Capitalization ATTRACTIVE VALUE PROPOSITION 30 • Attractive appreciation potential on a relative basis 1. Based on Bloomberg 2015-2018 Bloomberg consensus distribution estimates and market data as of 6/30/2016. R-squared = 66%
  32. 32. Antero Midstream (NYSE: AM) Asset Overview 31
  33. 33. 1. Represents inception to date actuals as of 12/31/2015 and 2016 guidance. 2. Includes both expansion capital and maintenance capital. 32 Utica Shale Marcellus Shale Projected Gathering and Compression Infrastructure(1) Marcellus Shale Utica Shale Total YE 2015 Cumulative Gathering/ Compression Capex ($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 ~597,000 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 • AR owns 61% of AM units (NYSE: AM) Pending Acquisition Acreage
  34. 34. ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS 33 • Provides Marcellus gathering and compression services − Liquids-rich gas is delivered to MPLX’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 Pending Acquisition Acreage
  35. 35. 34 • Provides Utica gathering and compression services − Liquids-rich gas delivered into MPLX’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 30 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
  36. 36. ANTERO MIDSTREAM WATER BUSINESS OVERVIEW 35 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 $3.69 per barrel subject to annual inflation and 38 barrels of water per lateral foot that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes G&A. Utica assumes fee of $3.64 per barrel subject to annual inflation and 34 barrels of water per lateral foot that utilize the fresh water delivery system based on 9,000 foot lateral. Water volumes assume 5% recycling. Operating margin excludes G&A.  AM acquired AR’s integrated water business for $1.05 billion plus earn out payments of $125 million at year-end in each of 2019 and 2020 − The acquired business includes Antero’s Marcellus and Utica freshwater delivery business, the fully-contracted future advanced wastewater treatment complex and all fluid handling and disposal services for Antero Projected Water Business Infrastructure(1) Marcellus Shale Utica Shale Total YE 2015 Cumulative Fresh Water Delivery Capex ($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) $950k - $1,050k $825k - $925k 2016E Advanced Waste Water Treatment Budget ($MM) $130 2016E Total Water Business Budget ($MM) $180 Water Business Assets • Fresh water delivery assets provide fresh water to support Marcellus and Utica well completions – Year-round water supply sources: Clearwater Facility, Ohio River, local rivers & reservoirs(2) – 100% fixed fee long term contracts Antero Clearwater advanced wastewater treatment facility currently under construction – connects to Antero freshwater delivery system Pending Acquisition Acreage
  37. 37. 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 Antero Clearwater Advanced Wastewater Treatment Capacity (Bbl/d) Produced/Flowback Volumes (Bbl/d) Illustrative Produced & Flowback Water VolumesAdvanced Wastewater Treatment Antero Produced Water Services and Freshwater Delivery Business Antero Advanced Wastewater Treatment 3rd Party Recycling and Well Disposal (Bbl/d) Advanced Wastewater Treatment Complex Estimated capital expenditures ($ 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 significant third party business 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 36Integrated 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 Capacity for third party business
  38. 38. AM UPSIDE OPPORTUNITY SET 37 ACTIVITY CURRENTLY DEDICATED TO AM Third Party Business Processing, Fractionation, Transportation and Marketing • 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 • 278,000 gross 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 AR Acreage Consolidation • 66,500 net acre acquisition announced by AR substantially undedicated for gathering, compression, processing and water services • Future acreage acquisitions by AR are dedicated to AM
  39. 39. PROCESSING – VALUE CHAIN POTENTIAL FOR UNDEDICATED ACREAGE Sherwood Processing Complex Processing Area Of Dedication for AM MarkWest Processing AOD – 192,000 Gross Acres Tyler County 94,000 Gross Acres Ritchie County 53,000 Gross Acres Gilmer County 14,000 Gross Acres Wetzel County 57,000 Gross Acres Pleasants County 7,000 Gross Acres AR Gross Processble Acres (1) AR C3+ 3P Reserves (MMBbls)(2) AR 3P Gross Wellhead Gas (Tcf) Total 225,000 1,022 21.4 38  Antero Resources has over 21 Tcf of processable gross 3P gas reserves and 1.0 billion Bbls of gross 3P NGL reserves across 225,000 gross processable Marcellus acres that are dedicated to Antero Midstream for processing 1. Gross Processable Acres defined as acres with expected Btu greater than 1,100 2. Antero gross 3P C3+ NGL volumes and 3P Gross Wellhead Gas reserves as of 12/31/2015, pro forma for AR announced acreage acquisition. Gross acres as of 6/30/2016. Undedicated Acreage
  40. 40. LARGE UTICA SHALE DRY GAS POSITION 39  Antero has completed its first dry gas Utica well – a 6,620’ lateral in Tyler County, WV  Antero has 285,000 net acres of exposure to Utica dry gas play in OH, WV and PA pro forma  Other operators have reported strong Utica Shale dry gas results including the following wells: 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 GH9 CNX 61.9 6,141 11.131 Claysville Sportsman RRC 59.0 5,420 10.886 Stewart-Winland MHR 46.5 5,289 8.792 Bigfoot 9H RICE 41.7 6,957 5.994 Blake U-7H GST 36.8 6,617 5.561 Stalder #3UH MHR 32.5 5,050 6.436 Big 190 EQT 31.3 6,335 4.941 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. RRC – Claysville Sportsman 5,420’ Lateral 24-hr IP: 59.0 MMcf/d EQT – Scotts Run 3,221’ Lateral 24-hr IP: 72.9 MMcf/d CNX – GH9 6,141’ Lateral 24-hr IP: 61.9 MMcf/d EQT – Big 190 6,335’ Lateral 24-hr IP: 31.3 MMcf/d MHR – Stewart Winland 5,289’ Lateral 24-hr IP: 46.5 MMcf/d SGY – Pribble 3,605’ Lateral 24-hr IP: 30.0 MMcf/d Tughill – Blake 6,617’ Lateral 24-hr IP: 36.8 MMcf/d Tughill – Simms 4,447’ Lateral 24-hr IP: 29.4 MMcf/d Antero – Rymer 4HD 6,620’ Lateral 90-day IP: 20 MMcf/d SWN – Messenger 5,889’ Lateral 24-hr IP: 25.0 MMcf/d ECR – Tippens 5,858’ Lateral 24-hr IP: 23.2 MMcf/d MHR – Stalder 5,050’ Lateral 24-hr IP: 32.5 MMcf/d CVX – Conner 6,451’ Lateral 24-hr IP: 25.0 MMcf/d
  41. 41. Low Cost Marcellus/Utica Focus “Best-in-Class” Distribution Growth 40 CATALYSTS • 30% for 2016 and 28% to 30% for 2017 targeted based on Sponsor planned development; additional third party business expansion opportunities • AM Sponsor is the most active operator in Appalachia; • 20% production growth guidance for 2016 supported by $1.4 billion capital budget, firm processing and takeaway, long-term natural gas hedges and $3.2 billion of liquidity • Targeting 20% to 25% 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 • $3.2 billion of capital investment opportunities over the next five years, pro forma for the AR acreage acquisition Appalachian Basin Midstream Growth High Growth Sponsor Production Profile 1 2 3 4 5 6 • Acquisition of integrated water business from AR expected to result in distributable cash flow per unit accretion in 2016 Consolidation and Stacked Pay Upside • AR plans to continue to consolidate Marcellus/Utica acreage • Development of Utica Shale Dry Gas resource will provide further midstream infrastructure expansion opportunities Integrated Water Business Drop Down
  42. 42. APPENDIX 41
  43. 43. Key Variable Updated 2016 Guidance(1) Previous 2016 Guidance Financial: Net Income ($MM) $205 - $225 $165 - $190 Adjusted EBITDA ($MM) $365 - $385 $325 - $350 Distributable Cash Flow ($MM) $315 - $335 $275 - $300 Year-over-Year Distribution Growth 30% 30% Operating: Low Pressure Pipeline Added (Miles) 9 9 High Pressure Pipeline Added (Miles) 22 22 Compression Capacity Added (MMcf/d) 240 240 Fresh Water Pipeline Added (Miles) 30 30 Capital Expenditures ($MM): Gathering and Compression Infrastructure $240 $240 Fresh Water Infrastructure $40 $40 Advanced Wastewater Treatment $130 $130 Stonewall Gathering Pipeline Option $45 $45 Maintenance Capital $25 $25 Total Capital Expenditures ($MM) $480 $480 ANTERO MIDSTREAM – UPDATED 2016 GUIDANCE Key Operating & Financial Assumptions 1. Updated guidance per press release dated 09/06/2016. 42
  44. 44. 2016 UPDATED CAPITAL BUDGET By Area 43 $423 Million – 2015(1) By Segment ($MM) $349 $6 $55 $13 Gathering & Compression Fresh Water Infrastructure Advanced Wastewater Treatment Maintenance Capital 74% 26% Marcellus Utica By Area $480 Million – 2016 By Segment ($MM)  Antero Midstream’s 2016 updated capital budget is $480 million, a 13% increase from 2015 capital expenditures of $423 million 13% 130 Completions 1. Excludes $1.05 billion water drop down in September 2015. Water capex values only from 4Q 2015. $240 $40 $130 $45 $25 Gathering & Compression Fresh Water Infrastructure Advanced Wastewater Treatment Stonewall Pipeline Maintenance Capital 95% 5% Marcellus Utica
  45. 45. ANTERO RESOURCES – UPDATED 2016 GUIDANCE Key Variable Updated 2016 Guidance(1) Previous 2016 Guidance Net Daily Production (MMcfe/d) 1,800 1,750 Net Residue Natural Gas Production (MMcf/d) 1,365 1,355 Net C3+ NGL Production (Bbl/d) 53,500 52,500 Net Ethane Production (Bbl/d) 15,000 10,000 Net Oil Production (Bbl/d) 4,500 3,500 Net Liquids Production (Bbl/d) 73,000 66,000 Natural Gas Realized Price Premium to NYMEX Henry Hub Before Hedging ($/Mcf)(2)(3) +$0.00 to $0.05 +$0.00 to $0.10 Oil Realized Price Differential to NYMEX WTI Oil Before Hedging ($/Bbl) $(10.00) - $(11.00) $(10.00) - $(11.00) C3+ NGL Realized Price (% of NYMEX WTI)(2) 35% - 40% 35% - 40% Ethane Realized Price (Differential to Mont Belvieu) ($/Gal) $0.00 $0.00 Operating: Cash Production Expense ($/Mcfe)(4) $1.40 - $1.50 $1.50 - $1.60 Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.15 - $0.20 $0.15 - $0.20 G&A Expense ($/Mcfe) $0.20 - $0.22 $0.20 - $0.25 Operated Wells Completed 110 110 Drilled Uncompleted Wells 70 70 Average Operated Drilling Rigs ≈ 7 ≈ 7 Capital Expenditures ($MM): Drilling & Completion $1,300 $1,300 Land $100 $100 Total Capital Expenditures ($MM) $1,400 $1,400 1. Updated guidance per press release dated 09/06/2016. 2. Based on current strip pricing as of August 30, 2016. Key Operating & Financial Assumptions 3. 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. 44
  46. 46. Antero Long Term Firm Processing & Takeaway Position (YE 2018) – Accessing Favorable Markets Mariner East 2 62 MBbl/d Commitment Marcus Hook Export Shell 30 MBbl/d Commitment Beaver County Cracker (2) 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 1. October 2016 and full year 2017 futures basis, respectively, provided by Intercontinental Exchange dated 8/31/2016. Favorable markets shaded in green. 2. Shell announced final investment decision (FID) on 6/7/2016. 3. Lake Charles LNG 150 MMcf/d commitment subject to Shell FID. Chicago(1) $0.03 / $0.02 CGTLA(1) $(0.09) / $(0.08) TCO(1) $(0.21) / $(0.23) 45 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, for 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 Expect NYMEX-plus pricing per Mcf Antero Commitments (3) (2) Dom South(1) $(1.63) / $(1.14) LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA
  47. 47. 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 and Projected(1) 46 Shell Beaver County Cracker (Received FID June 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 in 2017 as pipeline options to domestic markets and export terminals go in-service (Mariner East) (MMBbl/d) Mariner West 50 MBbl/d C2
  48. 48. 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 47 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
  49. 49. 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 48 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
  50. 50. 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 49 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
  51. 51. U.S. SHALE NGL EURS SUPPORT LPG TRADE GROWTH 50 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)
  52. 52. 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 51 Northeast Ethane Rejection Exports U.S. PetChem
  53. 53. 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 52 • 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
  54. 54. ANTERO RESOURCES EBITDAX RECONCILIATION 53 EBITDAX Reconciliation ($ in millions) Quarter Ended LTM Ended 6/30/2016 6/30/2016 EBITDAX: Net income including noncontrolling interest $(575.5) $155.5 Commodity derivative fair value (gains) 684.6 (1,219.5) Net cash receipts on settled derivatives instruments 292.5 1,092.7 Interest expense 62.6 247.2 Income tax expense (benefit) (376.5) 41.0 Depreciation, depletion, amortization and accretion 198.0 741.4 Impairment of unproved properties 19.9 104.9 Exploration expense 1.1 4.0 Equity-based compensation expense 25.8 91.8 Equity in earnings of unconsolidated affiliate (0.5) (0.5) Contract termination and rig stacking 0.0 27.6 Consolidated Adjusted EBITDAX $332.1 $1,286.1
  55. 55. ANTERO MIDSTREAM EBITDA RECONCILIATION 54 EBITDA and DCF Reconciliation $ in thousands Six months ended June 30, 2015 2016 Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow: Net income $67,451 $92,829 Interest expense 3,222 7,582 Depreciation expense 41,955 47,963 Accretion of contingent acquisition consideration - 6,857 Equity-based compensation 12,376 12,766 Equity in earnings from unconsolidated affiliate - (484) Adjusted EBITDA $125,004 $167,513 Pre-Water Acquisition net income attributed to parent (32,353) - Pre-Water Acquisition depreciation expense attributed to parent (12,282) - Pre-Water Acquisition equity-based compensation expense attributed to parent (2,365) - Pre-Water Acquisition interest expense attributed to parent (1,556) - Adjusted EBITDA attributable to the Partnership 76,448 167,513 Cash interest paid - attributable to Partnership (1,177) (7,708) Cash reserved for payment of income tax witholding upon vesting of Antero Midstream LP equity-based compensation awards - (2,000) Cash to be received from unconsolidated affiliate - 778 Maintenance capital expenditures attributable to Partnership (5,787) (11,518) Distributable Cash Flow $69,484 $147,065
  56. 56. 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 55

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