JP Morgan Global High Yield and Leveraged Finance Conference March 1, 2016
FORWARD-LOOKING STATEMENTS This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Resources Corporation and its subsidiaries (collectively, the Company or Antero ) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words believe, expect, anticipate, plan, intend, estimate, project, foresee, should, would, could, or other similar expressions are intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forwardlooking statements contained in this presentation specifically include estimates of the Company s reserves, expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced under the heading Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015 and in the Company s subsequent filings with the SEC. The Company cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015 and in the Company s subsequent filings with the SEC. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Antero Resources Corporation is denoted as AR and Antero Midstream Partners LP is denoted as AM in the presentation, which are their respective New York Stock Exchange ticker symbols. 1
ANTERO THE BRIDGE TO BETTER OIL & GAS PRICES Highly Sustainable Business Model - Antero holds a leading position within the lowest cost U.S. basin, a large and growing production base, a substantial long-term hedge position, over $5.0 billion of direct and indirect liquidity, and virtually all of its production volumes sold to favorable markets 2015A 2016E 2017E Large and Growing Production Base 48% growth to 1.493 Bcfe/d 15% growth guidance to 1.715 Bcfe/d 20% growth target on 2016E guidance Declining Development Costs ~$0.88/Mcfe in 2015 down 10% from 2014 2,227 high grade horizontal locations with similar economics Target 12% cost reduction Continue to target peer-leading development costs Production Sold Forward 1,316 BBtu/d hedged at $4.43/MMBtu (94% of guidance) 1,793 BBtu/d hedged at $3.94/MMBtu ( 100% of guidance) 2,073 BBtu/d hedged at $3.57/MMBtu ( 100% of target) Strong Liquidity $2.6 billion at 12/31/2015 Additional $2.3 billion of AM units Continue to target growth in PDP reserves, midstream assets and hedge portfolio Continue to target growth in PDP reserves, midstream assets and hedge portfolio Firm Transport to Favorable Markets 2.3 Bcf/d of FT 74% of sales volumes priced at favorable markets 3.5 Bcf/d of FT Expect 99% of sales volumes priced at favorable markets 3.6 Bcf/d of FT Expect 97% of sales volumes priced at favorable markets 61,500 Bbl/d of FT on Mariner East 2 for NGL export 2
2016 CAPITAL BUDGET DRIVES MOMENTUM Antero s 2016 initial capital budget is $1.4 billion, a 23% decrease from 2015 capital expenditures of $1.8 billion and a 58% decline from 2014 capital expenditures $1.8 Billion 2015 (1) By Segment ($MM) $1.4 Billion 2016 By Segment ($MM) $160 23% $100 $1,650 131 Completions 50 DUCs at YE $1,300 110 Completions 70 DUCs at YE Drilling & Completion Land Drilling & Completion Land By Area By Area 25% 44% 56% 75% Marcellus Utica Marcellus Utica 3 1. Excludes $39 million for leasehold acquisitions in 2015. DUCs are drilled but uncompleted wells at year-end.
ANTERO CREDIT QUALITY AFFIRMED AT Ba2/BB Amidst the energy sector wide re-rating, Antero recently received affirmed ratings of Ba2 / BB from Moody s and S&P Of the 21 public US Baa/Ba E&P issuers reviewed by Moody s and highlighted below, 15 received downgrades of two or more notches, including five companies that received downgrades of 4 or more notches, and one received a one notch downgrade S&P reviewed 45 High Yield issuers with 25 downgrades ranging from 1-3 notches Moody s Baa / Ba Ratings Review Baa3 Baa1 Baa2 Baa3 Baa2 Baa2 Baa2 Gray Previous Rating Red New Rating Rating Affirmed Baa3 Ba1 Baa3 Baa3 Baa3 Baa3 Baa3 Ba1 Ba1 Ba1 Baa3 Baa3 Ba1 Ba1 Baa3 Ba1 Ba1 Ba1 Ba1 Appalachian Company Ba2 Baa3 Ba2 Ba2 Ba3 Baa3 Ba3 Ba3 Ba3 Ba3 Ba3 Ba3 Ba3 B1 B2 B3 Baa3 Baa3 Baa3 Of the 21 public U.S. Baa and Ba rated E&P operators, Antero was one of only five companies that received an affirmed rating from Moody s B1 B1 B1 B2 B2 B2 B3 Baa3 Caa1 Caa1 Caa2 Baa3 Caa2 Caa3 -Baa3 NBL XEC EQT PXD APC HES CXO AR CLR MUR NFX RRC SWN EGN QEP SM WPX UNT EPE WLL DNR Source: Moody s releases on 02/11/2016 and 02/18/2016. Note: Issuers are sorted based on rating following review. 4
HEDGE BOOK SUPPORTS FINANCIAL PROFILE $3,500 $3,000 $2,500 $2,000 $1,500 $1,000 $500 $0 $3,117 Mark-to-Market Hedge Value ($MM) Antero exceeds closest credit peer by $2.3 billion Ba1 Credit Peer Ba3 Credit Peer AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 $16,000 $14,000 $12,000 $10,000 $8,000 $6,000 $4,000 $2,000 $0 6.0x 5.0x 4.0x 3.0x 2.0x 1.0x 0.0x Only credit peer with less than $1.0 billion of E&P debt $941 AR Peer 2 Peer 1 Peer 3 Peer 6 Peer 7 Peer 5 Peer 4 AR net leverage maps with strong Baa credit peers 1.2x E&P Debt (Net of Cash and M-T-M Hedge Value) (1) E&P Debt (Net of Cash and M-T-M Hedge Value) / LTM EBITDAX (Exclud. Realized Hedging Revenue) AR Peer 6 Peer 1 Peer 2 Peer 4 Peer 3 Peer 5 Peer 7 Note: Data presented as filed for the year ended December 31, 2015 ($ in millions). Peer group comprised of Ba1 and Ba3 credit peers including APC, CLR, CXO, HES, MUR, NFX, RRC. 1. Represents total E&P debt less cash and mark-to-market hedge value. 5
OUTSTANDING RESERVE GROWTH (Tcfe) 14.0 12.0 10.0 8.0 6.0 4.0 2.0 0.0 NET PROVED RESERVES (Tcfe) (1) Marcellus Utica 12.7 13.2 7.6 4.3 2.8 0.7 2010 2011 2012 2013 2014 2015 2015 RESERVE ADDITIONS Proved reserves increased 4% to 13.2 Tcfe at 12/31/2015 with a pre-tax PV-10 of $6.7 billion at SEC pricing, including $3.1 billion of hedges Proved PV-10 at strip pricing of $8.2 billion, including $2.5 billion of hedges 3P reserves were 37.1 Tcfe at 12/31/2015 with a pre-tax PV-10 of $6.8 billion at SEC pricing, including $3.1 billion of hedges 3P PV-10 at strip pricing of $13.7 billion, including $2.5 billion of hedges All-in finding and development cost of $0.80/Mcfe for 2015 (includes land and all price and performance revisions) Drill bit only development cost of $0.71/Mcfe for 2015 Only 69% of 3P Marcellus locations booked as SSL (1.7 Bcf/1,000 type curve) at 12/31/2015 Negligible Utica Shale WV/PA dry gas reserves booked estimated net resource of 12.5 16 Tcf (Tcfe) 7.0 6.0 5.0 4.0 3.0 2.0 1.0 0.0 $550 MM 0.1 NET PDP RESERVES (Tcfe) (1) Utica Marcellus Borrowing Base 0.4 0.9 1.8 $4.5 Bn 3.5 TBD 5.6 2010 2011 2012 2013 2014 2015 $Bn 1. 2012, 2013, 2014 and 2015 reserves assuming ethane rejection. 2015 SEC prices were $2.56/MMBtu for natural gas and $50.13/Bbl for oil on a weighted average Appalachian index basis. $5.0 $4.5 $4.0 $3.5 $3.0 $2.5 $2.0 $1.5 $1.0 $0.5 $0.0 Proved Probable Possible 3P RESERVES BY VOLUME 2015 (1) 2.5 Tcfe Possible 21.4 Tcfe Probable 37.1 Tcfe 3P 13.2 Tcfe Proved 93% 2P Reserves 6
LEADING UNCONVENTIONAL BUSINESS MODEL Growing Through the Down Cycle Largest Core Liquids- Rich Position in Appalachia 2 3 Growth Liquids-Rich Most Active Operator in Appalachia 1 Drilling 4 Well Economics Sustainable Business Model Highest Realizations and Margins Among Large Cap Appalachian Peers 8 Realizations 7 Premier Appalachian E&P Company Hedging & Liquidity Run by Co-Founders 6 Takeaway 5 Midstream MLP (NYSE: AM) Highlights Substantial Value in Midstream Business Largest Gas Hedge Position in U.S. E&P + Strong Financial Liquidity Largest Firm Transport and Processing Portfolio in Appalachia 7
DRILLING MOST ACTIVE OPERATOR IN APPALACHIA 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 Rig Count 12 10 8 6 4 2 0 January 2016 SW Marcellus & Utica (3) 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 Operators WV/PA UTICA SHALE DRY GAS Net Resource 12.5 to 16 Tcf Net Acres 188,000 Undrilled Locations 1,889 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 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 1/29/2016, and average rig count for January 2016, per RigData. 8
GROWTH GROWING THROUGH THE DOWN CYCLE Antero is in the unique position of being able to sustain growth and value creation through the price down cycle AVERAGE NET DAILY PRODUCTION (MMcfe/d) Marcellus Utica Guidance 2,400 1,800 1,715 1,493 AVERAGE NET DAILY LIQUIDS PRODUCTION (Bbl/d) NGLs (C3+) Oil 60,000 60,000 50,000 48,298 40,000 1,200 600 0 30 124 239 522 1,007 2010 2011 2012 2013 2014 2015 2016E 2017E OPERATED GROSS WELLS COMPLETED 200 150 100 50 0 19 Marcellus Utica Deferred Completions 177 38 60 114 15% Growth Guidance 181 131 20% Growth Target 180 110 2010 2011 2012 2013 2014 2015 2016E 30,000 20,000 10,000 $1,600 $1,400 $1,200 $1,000 $800 $600 $400 $200 $0 0 2010 2011 2012 2013 2014 2015 2016E $198 5 246 CONSOLIDATED EBITDAX ($MM) $341 $434 6,436 $649 23,051 $1,164 $1,221 24% Growth Guidance 2010 2011 2012 2013 2014 2015 2016E 1. Assumes ethane rejection. 2015 proved reserves include 1.1 Tcfe of ethane due to de-ethanizer being placed online at Sherwood facility and commencement of ethane delivery contracts in 2017. 2. Represents Bloomberg street consensus estimates as of 02/19/2016. Street Consensus (2) 9
LIQUIDS-RICH LARGEST CORE POSITION 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 Antero controls an estimated 37% of the NGLs in the liquids-rich core of the two plays Antero has the largest core liquidsrich position in Appalachia with 371,000 net acres (> 1100 Btu) Represents over 21% of core liquidsrich acreage in Marcellus and Utica plays combined 400 Core Liquids-Rich Net Acres (1) 300 (000s) 200 100 0 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. 10
ROR WELL ECONOMICS SUSTAINABLE BUSINESS MODEL At 12/31/2015 strip pricing, Antero has 2,227 locations with well economics that exceed 20% rate of return (excluding hedges) Including hedges, these locations generate rates of return of approximately 47% to 83% Rates of return include pad, facilities, cash production expenses (including midstream and FT costs) See assumptions pages in appendix for further detail ANTERO MARCELLUS & UTICA WELL ECONOMICS (1)(2) 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 29% 83% 26% 80% 23% 71% 34% 63% 2016 and 2017 Antero Drilling Plan 27% 57% 22% 47% 2021-25 $3.31-$3.88 $55-$56 $27-$28 28% 24% 11% $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL ($/Bbl) 2016 $2.50 $41 $15 2017 $2.79 $46 $23 2018 $2.91 $49 $25 2019 $3.03 $52 $26 2020 $3.18 $54 $27 12/31/15 NYMEX Strip Pricing - Before Hedges 12/31/15 Strip Pricing - After Hedges $4.19 $2.50 $3.72 $3.70 $3.60 $3.38 $2.79 $2.91 $3.03 $3.18 2016 2017 2018 2019 2020 12/31/15 Strip Pricing 12/31/15 Hedge Pricing 16% 9% 10% NYMEX ($/MMBtu) C3+ NGL ($/Bbl) $4.19 $18 $3.72 $22 $3.70 $25 $3.60 $26 $3.38 $27 $3.31 - $3.88 $27-$28 0% Utica Highly- Rich Gas Locations Utica Dry Gas - Ohio Utica Rich Gas Marcellus Highly-Rich Gas/ Condensate Utica Highly- Rich Gas/ Condensate ROR @ 12/31/2015 Strip Pricing - Before Hedges Marcellus Highly-Rich Gas Marcellus Dry Gas Marcellus Rich Gas ROR @ 12/31/2015 Strip Pricing - After Hedges Utica Condensate 2,227 High Grade Drilling Locations 108 263 161 626 98 971 755 553 184 1. 12/31/2015 pre-tax well economics based on a 9,000 lateral, 12/31/2015 natural gas and WTI strip pricing for 2016-2024, 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, assume Antero will begin to realize lower well costs in 2016 as the company utilizes incremental completion crews for deferred completions beginning at year end 2015 and as existing drilling rig contracts begin to roll off during 2016. 2. ROR @ 12/31/2015 Strip Pricing After 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. 11
WELL ECONOMICS HEDGING UNDEVELOPED PRODUCTION Antero has hedged a significant portion of its forecasted undeveloped production stream from wells yet to be drilled at prices well above current strip pricing, including virtually all of its undeveloped production forecast through the end of 2017 Natural Gas Hedged Volume vs. Production (BBtu/d) (1) 4,000 Proved Developed Production (BBtu/d) 3,500 3,000 2,500 Undeveloped Production (BBtu/d) Hedged Volume (BBtu/d) Antero has hedged virtually all of its undeveloped production through the end of 2017 (1) No Production Guidance or Targets Disclosed Beyond 2017 2,000 $3.94/Mcfe $3.57/Mcfe $3.91/Mcfe $3.87/Mcfe 1,500 1,000 Undeveloped (Illustrative) $3.72/Mcfe 500 0 Developed (Illustrative) (1) Represents illustrative Antero production forecast, adjusted for residue gas BTU content of 1100 BTU. 12
MIDSTREAM MLP (NYSE: AM) HIGHLIGHTS SUBSTANTIAL VALUE IN MIDSTREAM BUSINESS Corporate Structure Overview (1) Public Antero Resources Corporation (NYSE: AR) $11.6 Billion Enterprise Value (1) Ba2/BB Corporate Rating 34% LP Interest $1.2 Billion MV (1) 66% LP Interest $2.3 Billion MV (1) Antero Midstream Partners LP (NYSE: AM) $4.1 Billion Enterprise Value (1) $3.1 Bn MTM Hedge Position (3) $11.2 Bn 3P PV-10 (4) E&P Assets Gathering/Compression Assets Water Infrastructure Assets MLP Benefits: - Funding vehicle to expand midstream business - Highlights value of Antero Midstream - Liquid asset for Antero Resources Market Valuation of AR Ownership in AM: AR ownership: 66% LP Interest = 116.7 million units AM Price per Unit AM Units Owned by AR (MM) AR Value in AM LP Units ($MMs) Value Per AR Share (2) $20 117 $2,338 $8 $21 117 $2,455 $9 $22 117 $2,572 $9 $23 117 $2,689 $10 $24 117 $2,806 $10 $25 117 $2,923 $11 1. AR enterprise value excludes AM debt, minority interest and cash. Market values (MV) as of 1/31/2015 and includes subordinated units; balance sheet data as of 12/31/2015. 2. Based on 277.0 million AR shares outstanding and 175.8 million AM units outstanding. 3. 3.5 Tcfe hedged at $3.81/Mcfe average price through 2022 with mark-to-market (MTM) value of $3.1 billion as of 12/31/2015. 4. 3P 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. 13
TAKEAWAY LARGEST FT AND PROCESSING PORTFOLIO IN APPALACHIA 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 $0.40/MMBtu and positive weighted average basis differential to NYMEX after assumed Btu uplift for gas Antero Long Term Firm Processing & Takeaway Position (YE 2018) Accessing Favorable Markets Mariner East 2 YE 2018 Gas Market Mix Chicago (1) 62 MBbl/d Commitment Antero 4.85 Bcf/d FT $0.25 / Marcus Hook Export $0.02 13% Dom S/TETCO (PA) 13% TCO 13% Atlantic Seaboard 17% Midwest 44% Gulf Coast Positive weighted average basis differential CGTLA (1) $(0.07) / $(0.06) 4.85 Bcf/d Firm Gas Takeaway By YE 2018 Sabine Pass (Trains 1-4) 50 MMcf/d per Train Lake Charles LNG (3) 150 MMcf/d Freeport LNG 70 MMcf/d TCO (1) $(0.16) / $(0.18) Antero Commitments (3) (2) Cove Point LNG Shell 20 MBbl/d Commitment Beaver County Cracker (2) 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. 14
TAKEAWAY FIRM TRANSPORTATION AND SALES PORTFOLIO While Antero has excess FT in place through 2017, the expected cost of unutilized FT is estimated to be manageable at <10% of EBITDA through 2017 MMBtu/d 5,500,000 5,000,000 4,500,000 4,000,000 3,500,000 3,000,000 2,500,000 2,000,000 1,500,000 1,000,000 500,000 - Columbia 7/26/2009 9/30/2025 ANR 3/1/2015 2/28/2045 Tennessee 11/1/2015 9/30/2030 Local Distribution 11/1/2015 9/30/2037 Antero Transportation Portfolio Lowest cost, local unfavorable FT projected to not be used through 2017 Projected cost after mitigation due to positive futures spreads Momentum III 9/1/2012 12/31/2023 Firm Sales #1 10/1/2011 10/31/2019 EQT 8/1/2012 6/30/2025 Firm Sales #2 10/1/2011 11/30/2015 Gross Gas Production (Actuals) Illustrative Gross Gas Production (1) 2016E Total Net Marketing Expenses: $95 to $125 Million ($0.15 to $0.20 per Mcfe) (2) 2016E Net Marketing Expenses: $15 Million 2016E Net Marketing Expenses: $20 Million 2016E Net Marketing Expenses: $30 to $35 million (3) 2016E Net Marketing Expenses: $30 to $55 Million (3) REX/MGT/ANR 7/1/2014 12/31/2034 Firm Sales #3 1/1/2013 5/31/2022 2017E Net Marketing Expenses: $ Amounts in line with 2016 Appalachia Appalachia (ANR/Rover) Gulf Coast (Stonewall/TGP) Gulf Coast (REX/ANR/NGPL/MGT) Midwest (Stonewall/WB) Mid-Atlantic/NYMEX (TCO) Appalachia or Gulf Coast 250 BBtu/d 375 BBtu/d 600 BBtu/d 590 BBtu/d 800 BBtu/d 630 BBtu/d 1,280 BBtu/d 40 BBtu/d 1. Assumes production growth guidance of 15% in 2016 and targeted 20% annual production growth in 2017. 2. Based on 2016 production guidance of 1.715 Bcfe/d. 3. Assumes 25% to 50% mitigation on excess capacity and current spreads based on strip pricing as of 12/31/2015. 15
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) $300 $250 Realized $1.7 Billion in Hedge Gains Since 2009 $3.1 Billion on Balance Sheet in Hedge Gains Through 2022 3.5 Tcfe Hedged at average price of $3.79/Mcfe through 2022 $6.00 $5.00 $MM $200 $150 $3.94 $3.57 $3.91 $3.87 $3.72 $3.48 $3.30 $4.00 $3.00 ($/MMBtu) $100 $2.00 $50 $1.00 $0 $0.00 Realized Hedge Gains Projected Hedge Gains NYMEX Natural Gas Historical Spot Prices NYMEX Natural Gas Futures Prices Average Hedge Prices ($/Mcfe) 16
HEDGING HIGHEST PROPORTION HEDGED AMONG E&P OPERATORS 100.0% Antero has substantially de-risked its cash flow profile and differentiated itself versus its peer group through its extensive hedge portfolio, with 100% of forecasted production hedged in 2016 and 2017 and 80% of consensus estimated production hedged in 2018 Total Production Hedged (% of Forecasted / Consensus Production) 90.0% 80.0% 70.0% 60.0% 50.0% 40.0% 30.0% 20.0% 10.0% 0.0% 100%+ 80% 90% 39% 83% 22% 80% 13% Antero has 3.5 Tcfe hedged at average price of $3.79/MMBtu and $3.1 Billion mark-to-market (1) 94% hedged through 2018 at $3.81/MMBtu 74% 44% 31% 69% 53% 14% 51% 2% 46% 45% 23% 8% 22% 39% 19% 5% 25% 2016 2017 2018 Antero Production Hedged Through 2018: 94% Peer Group Average Production Hedged Through 2018: 20% 2016 Average Peer Production Hedged: 43% 2017 Average Peer 15% 14% Production Hedged: 16% 11% 6% 2018 Average Peer Production Hedged: 4% 1% 0% - > 0% - > 0% - > 0% - > AR Peer 1 Peer2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Peer 14 Peer 15 Source: Public filings. Projected production for peers based on consensus estimates. Projected production for AR based on 2016 guidance of 15% growth, 2017 target of 20% growth, and 2018 consensus estimates. Note: Operators include APC, CHK, CLR, COG, CXO, EOG, EQT, GPOR, NBL, NFX, PXD, RICE, RRC, SWN, WPX (1) As of December 31, 2015. 17
LIQUIDITY STRONG BALANCE SHEET AND FLEXIBILITY 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 Asset Type $MM Debt Type $MM Asset Type $MM Credit facility $707 Commodity derivatives (1) $3,117 Credit facility $620 Cash $7 6.00% senior notes due 2020 525 AM equity ownership (2) 2,318 Total $620 Total $7 5.375% senior notes due 2021 1,000 Cash 16 5.125% senior notes due 2022 1,100 5.625% senior notes due 2023 750 Total $4,082 Total $5,451 Liquid non-e&p assets of $5.5 Bn significantly exceeds total debt of $4.1 Bn Liquidity Asset Type $MM Cash $16 Credit facility commitments (3) 4,000 Credit facility drawn (707) Credit facility letters of credit (702) Total $2,607 Approximately $2.6 billion of liquidity at AR plus an additional $2.3 billion of AM units Asset Type Only 41% of AM credit facility capacity drawn Liquidity $MM Cash $7 Credit facility capacity 1,500 Credit facility drawn (620) Credit facility letters of credit - Total $887 Approximately $900 million of liquidity at AM Note: All balance sheet data as of 12/31/2015, inclusive of water drop down and associated financing. 1. Mark-to-market as of 12/31/2015. 2. Based on AR ownership of AM units (116.7 million common and subordinated units) and AM s closing price as of 1/31/2015. 3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion. 18
REALIZATIONS A LEADER IN REALIZATIONS & MARGINS AMONG LARGE-CAP APPALACHIAN PEERS $/Mcf Antero continues to be a leader in its peer group in price realizations and EBITDAX unit margins 4Q 2015 Natural Gas Realizations ($/Mcf) Region 4Q 2015 % Sales Average NYMEX Price Average Differential Average BTU Upgrade Hedge Effect Average 4Q 2015 Realized Gas Price NYMEX Premium/ Discount TCO 42% $2.27 $(0.32) $0.15 $0.25 $2.35 $0.08 Dom South/TETCO 26% $2.27 $(0.76) $0.10 $0.87 $2.48 $0.21 Gulf Coast (1) 5% $2.27 $(0.17) $0.17 $1.15 $3.42 $1.15 Chicago/Michigan 27% $2.27 $0.12 $0.26 $0.00 $2.65 $0.38 Total Wtd. Avg. 100% $2.27 $(0.31) $0.17 $2.27 $4.40 $2.13 4Q 2015 Natural Gas Realizations (1)(2) 4Q 2015 Price Realization & EBITDAX Margin vs F&D (2)(3) $5.00 $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 $4.40 $3.08 $3.00 $2.78 4Q 2015 NYMEX = $2.27/Mcf $2.07 $1.94 AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 $/Mcfe $5.00 $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 $4.34 $2.03 $0.58 $3.22 $1.88 $0.73 $3.06 $1.59 $0.88 $2.75 $1.35 $1.14 $0.75 $2.21 $2.20 $0.85 $1.11 $0.72 AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Noncontrolling Interest of Midstream MLP EBITDA LOE Production Taxes GPT G&A EBITDAX 1. Includes natural gas hedges. 4-year Avg. All-in F&D ($/Mcfe) 19 2. Source: Public data from 4Q 2015 10-Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp., Range Resources and Southwestern. 3. Includes realized hedge gains and losses. Operating costs include lease operating expenses, production taxes, gathering, processing and firm transport costs and general and administrative costs. 4-year proved reserve average all-in F&D from 2011-2014. Calculation = (Development costs + exploration costs + leasehold costs) / Total reserves added (2014 ending reserves 2011 beginning reserves + 4-year reserve sales 4-year reserve purchases + 4-year accumulated production). AR price realization includes $0.06 of midstream revenues; EBITDAX excludes AR s midstream EBITDA not attributable to AR s ownership.
REALIZATIONS FAVORABLE PRICE INDICES Antero s exposure to favorable gas price indices like Chicago, Gulf Coast, NYMEX and TCO is expected to increase to >99% in 2016 Improved 2016 realizations driven by Stonewall gathering pipeline which was placed in-service December 1, 2015 and will eliminate virtually all swing sales at Dominion South and Tetco in 2016 69% exposure to favorable price indices 99% exposure to favorable price indices 97% exposure to favorable price indices Marketed % of Target Residue Gas Production 100% 90% 80% 70% 60% 50% 2015 2015 2016 2016 2017 Basis (1) 2015A Hedges Basis (1) 2016E Hedges Basis (1) 2017E Wtd. Avg. Basis ($0.53) +$0.02/MMBtu $(0.10)/MMBtu $(0.12)/MMBtu (2) $(0.28)/MMBtu Chicago 18% Gulf Coast 2% NYMEX 10% TCO 40% 1,160,000 MMBtu/d @ $4.34/MMBtu 40,000 MMBtu/d @ $4.00/MMBtu 380,000 MMBtu/d @ $3.88/MMBtu Wtd. Avg. Basis $(0.12) $0.01/MMBtu $(0.05)/MMBtu Gulf Coast 28% 40% 510,000 MMBtu/d NYMEX $(0.43)/MMBtu (2) 10% 990,000 MMBtu/d @ $3.87/MMBtu (3) @ $3.49/MMBtu 30% NYMEX TETCO M2 10% $(1.00)/MMBtu 7% $(0.18)/MMBtu 180,000 MMBtu/d $(0.43)/MMBtu (2) 1,370,000 MMBtu/d 20% TCO @ $3.54/MMBtu (4) DOM S 33% $(0.25)/MMBtu @ $3.40/MMBtu TCO, 21% 10% $(1.30)/MMBtu 23% 230,000 MMBtu/d 272,500 MMBtu/d @ $5.74/MMBtu $(0.93)/MMBtu 0% @ $5.35/MMBtu $(0.78)/MMBtu TETCO M2 DOM S, 3% 1% ($/Mcf) 2015A 2016E Note: Hedge volumes as of 12/31/2015. NYMEX Strip Price (1) 1. Based on 12/31/2015 strip pricing and actuals for 2015. $2.66 $2.47 Current markets 2. Differential represents contractual deduct to NYMEX-based firm sales contract. Basis Differential to NYMEX (1) $(0.53) $(0.12) 3. Represents 120,000 MMBtu/d of TCO index hedges and 390,000 MMBtu/d of indicate positive BTU Upgrade (5) $0.24 $0.24 TCO basis hedges that are matched with NYMEX hedges for presentation differential in 2016 purposes. Estimated Realized Hedge Gains $1.44 $1.50 4. Represents 60,000 MMBtu/d of TCO index hedges and 120,000 MMBtu/d of Realized Gas Price with Hedges $3.81 $4.10 TCO basis hedges that are matched with NYMEX hedges for presentation Premium to NYMEX +$1.15 +$1.63 purposes. Liquids Impact +$0.29 +$0.10 5. Based on BTU content of residue sales gas. Premium to NYMEX w/ Liquids +$1.44 +$1.73 20 Realized Gas-Equivalent Price $4.10 $4.16 Chicago 28% 1,612,500 MMBtu/d @ $3.92/MMBtu 170,000 MMBtu/d @ $4.09/MMBtu Wtd. Avg. Basis $(0.15) $(0.04)/MMBtu $(0.06)/MMBtu Chicago 17% Gulf Coast 49% 2017 Hedges 1,860,000 MMBtu/d @ $3.63/MMBtu 70,000 MMBtu/d @ $4.57/MMBtu 420,000 MMBtu/d @ $4.27/MMBtu
REALIZATIONS NGL REALIZATIONS AND PROPANE HEDGES Realized NGL Prices as % of WTI (1) ($/Bbl) $120.00 $100.00 $80.00 $60.00 $40.00 $20.00 $0.00 $98.01 $93.03 Realized NGL C3+ Price $52.61 $53.71 $46.23 $51.98 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 $48.63 $17.15 $25.05 $15.17 35% 37% Hedged Volume Average Hedge Price Strip (12/31/2015) Mark-to-Market Value (2) $0.59 $0.40 $41.00 $0.43 $0.41 $21.89 AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu 2013 2014 2015 2016E NGL Marketing 54% 50% Realized NGL (C3+) price was 50% of WTI in 2014 and 35% of WTI for 2015 Including propane hedges, 2015 realizations were 42% of WTI Antero has guided to realized C3+ NGL prices of 35% to 40% of WTI for 2016 (before hedging) Antero has hedged 30,000 Bbl/d of propane in 2016 at $0.59 per gallon By 2017, Antero will market a significant portion of its NGL volumes out of Marcus Hook to export markets once Mariner East 2 is in service 61,500 Bbl/d firm commitment with expansion rights Propane Hedges (Bbl/d) WTI $82 MM $7 MM Target 2016 C3+ NGL pricing of 37% of WTI based on 12/31/15 strip pricing $0.70 $0.60 $0.50 $0.40 $0.30 $0.20 ($/Gal) 1. Based on 2016 NGL and WTI strip prices as of 12/31/2015. 2. As of 12/31/2015. 0 2016 2017 $0.10 21
LEADERSHIP IN APPALACHIAN BASIN Antero has the largest proved reserve base, largest core liquids-rich acreage position and is one of the largest producers in the Appalachian Basin Appalachian Producers by Proved Reserves (Bcfe) YE 2015 (1)(2) Appalachian Producers by Core Net Acres (000 s) December 2015 (3)(4) 14,000 12,000 10,000 8,000 6,000 4,000 2,000 Largest Proved Reserve Base In Appalachia 600 500 400 300 200 100 Core Net Acres - Dry Core Net Acres - Liquids Rich Largest Liquids- Rich Core Position in Appalachia 0 AR EQT RRC COG CNX CHK SWN (4) (5) - AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Top Producers in Appalachia (Net MMcfe/d) 4Q 2015 (1)(2) Top 12 U.S. Natural Gas Producers (Net MMcf/d) 4Q 2015 (1) 1,800 1,600 1,400 1,200 1,000 4 th Largest Appalachian Producer 3,500 3,000 2,500 2,000 Appalachian Peers 11 th Largest U.S. Gas Producer 800 600 400 200 1,500 1,000 500 0 EQT CHK COG AR SWN RRC CNX 0 1. Based on company filings and presentations. 2. Appalachian only production and reserves where available. Excludes companies that do not break out Appalachian production including CVX, HES and XOM. 3. Based on Antero geologic interpretation supported by state well data, company presentations and public land data. Peer group includes CNX, COG, EQT, RRC, SWN, CHK. 4. Southwestern leasehold and reserves include the impact from STO and WPX property acquisitions closed in January 2015. 5. Includes proved reserves categorized in Northern Division consisting of Utica Shale, Marcellus Shale and Powder River Basin. 22
ANTERO OUTPERFORMANCE HIGHEST EBITDAX & EBITDAX MARGINS AMONG PEERS Quarterly Appalachian Peer Group EBITDAX ($MM) (1) $600 $500 For the first quarter AR has ranked first for the highest EBITDAX margin and EBITDAX among Appalachian peers Y-O-Y AR: $22MM Peer Avg: $129MM NYMEX Gas: 43% NYMEX Oil: 43% $400 $300 $330 $355 $269 $291 $308 $200 $100 $0 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 P5 P2 P4 AR P3 P1 P5 P2 AR P4 P3 P1 P5 AR P2 P3 P4 P1 4Q 2014 1Q 2015 2Q 2015 $2.84 $2.56 $1.90 AR P5 P2 P3 P4 P1 P2 AR P5 P3 P4 P1 AR P3 P4 P2 P5 P1 4Q 2014 1Q 2015 2Q 2015 P5 AR P3 P2 P4 P1 3Q 2015 AR Peer Group Ranking Improving Over Time Quarterly Appalachian Peer Group EBITDAX Margin ($/Mcfe) (1) AR Peer Group Ranking Top Tier Note: AR and EQT EBITDAX margin excludes EBITDA from midstream MLP associated with noncontrolling interest. CNX excludes EBITDAX contribution from coal operations. 1) Source: Public data from form 10-Qs and 10-Ks. Peers include COG, CNX, EQT, RRC and SWN. AR P5 P3 P2 P4 P1 4Q 2015 #4 #3 #2 #2 #1 AR P3 P5 P4 P2 P1 3Q 2015 (2) $2.03 AR P3 P2 P1 P5 P4 4Q 2015 #1 #2 #1 #1 #1 $1.97 Y-O-Y AR: 28% Peer Avg: 43% NYMEX Gas: 43% NYMEX Oil: 43% 23
Antero Midstream (NYSE: AM) Asset Overview 24
ANTERO MIDSTREAM GATHERING AND COMPRESSION ASSET OVERVIEW Gathering and Compression Assets Gathering and compression assets in core of rapidly growing Marcellus and Utica Shale plays Acreage dedication of ~438,000 net leasehold acres for gathering and compression services Additional stacked pay potential with dedication on ~147,000 acres of Utica deep rights underlying the Marcellus in WV and PA 100% fixed fee long term contracts AR owns 66% of AM units (NYSE: AM) Utica Shale Projected Gathering and Compression Infrastructure (1) Marcellus Shale Utica Shale Total YE 2015 Cumulative Gathering/ Compression Capex ($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 0 240 Condensate Gathering Pipelines (Miles) - - - 1. Represents inception to date actuals as of 12/31/2015 and 2016 midpoint guidance. 2. Includes both expansion capital and maintenance capital. Marcellus Shale 25
ANTERO MIDSTREAM WATER BUSINESS OVERVIEW 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 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 Advanced wastewater capex of $130 million budgeted in 2016 Projected Water Business Infrastructure (1) Marcellus Shale Utica Shale Total YE 2015 Cumulative Fresh Water Delivery Capex ($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 $700k Margin per Well (4) $750k $775k - $825k 2016E Advanced Waste Water Treatment Budget ($MM) $130 2016E Total Water Business Budget ($MM) $180 Antero advanced wastewater treatment facility to be constructed connects to Antero freshwater delivery system 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 midpoint 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 $3.635 per barrel subject to annual inflation and 275,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes G&A. 26
ANTERO MIDSTREAM ADVANCED WASTEWATER TREATMENT ASSET OVERVIEW Antero has contracted with Veolia to integrate an advanced wastewater treatment complex into its water business Advanced Wastewater Treatment Veolia will build and operate, and Antero will own largest advanced wastewater treatment complex in Appalachia Will treat and recycle AR produced and flowback water Creates additional year-round water source for completions Will have capacity for third party business over first two years Advanced Wastewater Treatment Complex Estimated capital expenditures ($ million) (1) ~$275 Standalone EBITDA at 100% utilization (2) ~$55 $65 Implied investment to standalone EBITDA build-out multiple ~4x 5x Estimated per well savings to Antero Resources ~$150,000 Estimated in-service date Late 2017 Operating capacity (Bbl/d) 60,000 Operating agreement 20 Years, Extendable (Bbl/d) 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 Illustrative Produced & Flowback Water Volumes Antero Clearwater Advanced Wastewater Treatment Capacity (Bbl/d) Produced/Flowback Volumes (Bbl/d) 3 rd Party Recycling and Well Disposal Antero Advanced Wastewater Treatment Antero Produced Water Services and Freshwater Delivery Business Well Pad Antero Advanced Wastewater Treatment Freshwater delivery system Well Pad Flowback and produced Freshwater Water Salt Marketable byproduct Producing Calcium Chloride Integrated Water Business Marketable byproduct used in oil and gas operations Completion Operations 27 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 $4.00 per barrel and 60,000 barrels per day of capacity. Does not include potential sales of marketable byproducts.
HIGH GROWTH MIDSTREAM THROUGHPUT Low Pressure Gathering (MMcf/d) High Pressure Gathering (MMcf/d) 1,800 Utica Marcellus 1,600 1,400 1,200 1,000 738 800 531 600 281 331 386 400 216 108 200 0 935 965 1,038 1,124 1,800 Utica Marcellus 1,600 1,400 1,200 1,000 908 800 600 531 400 266 10 38 80 126 200 0 1,134 1,197 1,216 1,195 Compression (MMcf/d) Adjusted EBITDA ($MM) (1) 800 Utica Marcellus 700 600 500 400 300 222 200 116 100 26 31 40 36 41 0 358 454 435 478 $90 $80 $70 $60 $50 $40 $30 $20 $10 $0 $1 $5 $7 $8 $11 $19 $28 $36 $41 $55 $83 $313 Note: Y-O-Y growth based on 4Q 14 to 4Q 15. 1. 2016E EBITDA guidance per 2/17/2016 Partnership press release. 28
KEY CATALYSTS FOR ANTERO 1 Sustainability of Antero s Integrated Business Model Large, low unit cost core Marcellus and Utica natural gas drilling inventory with associated liquids generates attractive returns supported by long-term natural gas hedges, takeaway portfolio and downstream LNG and NGL sales agreements 2 Production and Cash Flow Growth Guiding to 15% production growth in 2016 and targeting 20% in 2017 with ~100% hedged at $3.94/MMBtu and $3.57/MMBtu, respectively; capital budget flexibility to adapt to commodity price changes 3 4 5 Downstream LNG and NGL Sales Utica Dry Gas Activity Midstream MLP Growth Pursuing additional value enhancing long-term LNG and NGL sales agreements, as well as additional NGL firm takeaway Antero has completed its first Utica dry gas well with encouraging early results; has 229,000 net acres in OH, WV and PA highly prospective for Utica dry gas Antero owns 66% of Antero Midstream Partners and thereby participates directly in its growth and value creation; acquisition of integrated water business from Antero expected to result in distributable cash flow per unit accretion in 2016 29
APPENDIX 30
ANTERO RESOURCES 2016 GUIDANCE Key Operating & Financial Assumptions Key Variable 2016 Guidance Net Daily Production (MMcfe/d) 1,715 Net Residue Natural Gas Production (MMcf/d) 1,355 Net C3+ NGL Production (Bbl/d) 46,500 Net Ethane Production (Bbl/d) 10,000 Net Oil Production (Bbl/d) 3,500 Net Liquids Production (Bbl/d) 60,000 Natural Gas Realized Price Premium to NYMEX Henry Hub Before Hedging ($/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) $1,400 1. Based on current strip pricing as of December 31, 2015. 2. Includes Btu upgrade as Antero s processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average. 3. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes. 31
ANTERO MIDSTREAM 2016 GUIDANCE Key Operating & Financial Assumptions Key Variable 2016 Guidance Financial: Adjusted EBITDA ($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. 32
ANTERO FT PORTFOLIO APPROPRIATELY DESIGNED TO ACCOMMODATE GROWTH Antero projects firm transportation in excess of equity gas production of approximately 1,640 BBtu/d in 2016 Excess Capacity Marketable / FT Segment (Location) (BBtu/d) Unmarketable Columbia / TGP (Marcellus) 550 Marketable ANR North / ANR South (Utica) 465 Marketable EQT / M3 (Marcellus) 625 Unmarketable Total Excess Firm Transport 1,640 Expects to market or mitigate the cost of approximately 1,015 BBtu/d of the excess FT with 3 rd party gas Expect to fully utilize FT portfolio by 2019, based on five year development plan (excludes Appalachia based FT directed to unfavorable indices) 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 0 2016 FT Portfolio and Projected Gas Sales Net Production Target (MMcfe/d) (1) 1,715 Net Gas Production Target (MMcf/d) (80% of Net Production) 1,372 Net Revenue Interest Gross-up 80% Gross Gas Production Target (MMcf/d) 1,715 BTU Upgrade (2) x1.100 Gross Gas Production Target (BBtu/d) 1,885 Firm Transportation / Firm Sales (BBtu/d) 3,525 Estimated % Utilization of FT/FS 53% Excess Firm Transportation 1,640 Marketable Firm Transport (BBtu/d) (3) 1,015 Unmarketable Firm Transportation 625 Estimated % Utilization of FT/FS Portfolio (Including Marketable FT) 82% 1. Represents 2016 forecasted net daily production. 2. Assumes 1100 BTU residue sales gas. 3. Represents excess firm transportation that is deemed marketable to 3 rd parties based on a positive differential between the receipt and delivery points of the FT capacity, less variable transport cost. (BBtu/d) 2016 Targeted Gross Gas Production (1) 1,885 BBtu/d 2016 Firm Transport Total Firm Transport 3,525 BBtu/d Unmarketable Unutilized Firm Transport ~625 BBtu/d ($0.15 / MMBtu) Marketable Unutilized Firm Transport ~1,015 BBtu/d ($0.39 / MMBtu) Utilized Firm Transport / Firm Sales ~1,885 BBtu/d ($0.45 / MMBtu) Decreasing Cost of FT 33
FT PORTFOLIO UPDATE 2016 Projected Marketing Expenses: ($ in millions, except per unit amounts) Demand 2016E 2016E 2016E Fee Marketing Marketing Marketing ($ / MMBtu) Expenses Revenue Expenses, Net "Unmarketable" Firm Transport 625 BBtu/d of EQT / M3 Appalachia FT $0.15 $35 - $35 Illustrative Marketing Example: No Spread Unmarketable (EQT / M3) ($/MMBtu) 2016 TETCO M2 Pricing (Sold Gas) $1.56 2016 TETCO M2 Pricing (Bought Gas) (1.56) Total Spread $0.00 "Marketable" Firm Transport Capacity 550 BBtu/d of Columbia / TGP $0.49 $99 $43 - $72 $27 - $56 465 BBtu/d of ANR North / ANR South $0.24 42 $6 - $11 $31 - $36 Sub-Total $141 $49 - $83 $58 - $92 Grand Total - 2016 Marketing Expenses, Net $176 $49 - $83 ~$95 to $125 MM $ / Mcfe - 2016 Targeted Production (1) $0.28 $0.08 - $0.13 $0.15 - $0.20 2016 Marketing Revenue Projection: 2016E Marketing 2016E Marketing Revenue Spread Assuming % Volume Mitigated ($ / MMBtu) (2) 30% 50% "Marketable" Firm Transport Capacity 550 BBtu/d of Columbia / TGP $0.72 $43 $72 465 BBtu/d of ANR North / ANR South $0.12 6 11 Sub-Total $49 $83 $ / Mcfe - 2016E Targeted Production (1) $0.08 $0.13 Based on the 2016 guidance of 15% annual production growth, Antero projects net marketing expenses of $0.15 to $0.20 per Mcfe in 2016 2016 FT and Marketing Expenses per Unit: (BBtu/d) 3,600 3,000 2,400 1,800 1,200 600 $0.06 / Mcfe of 2016E Production (2) Positive Spread Marketable (TCO / TGP) ($/MMBtu) 2016 TGP-500 Pricing (Sold Gas) $2.43 2016 TETCO M2 Pricing (Bought Gas) (1.56) Less: Variable FT Costs (0.15) Total Spread ("In the Money") $0.72 $0.09 to $0.14 / Mcfe of 2016E Production (2) Utilized FT $0.45 / Mcfe of 2016E Production (2) Unmarketable Net Marketing Expense Marketable Net Marketing Expense 2016 Targeted Gross Gas Production 1,885 BBtu/d Gathering & Transportation Costs NOTE: Analysis based on strip pricing as of 12/31/15. 1. Represents 2016 production growth guidance of 15% to 1,715 MMcfe/d. 2. Spread for each respective marketable firm transport represents the difference between the gas price Antero would receive at the delivery point of each pipeline versus the price Antero would pay to buy gas at the receipt point of each piece of capacity, less the variable costs to transport on each segment of firm transportation. 0 34
ANTERO S FIRST UTICA DRY GAS WELL Antero recently drilled and completed its first dry gas Utica well in Tyler County, WV (Rymer 4HD) 11,409 Total Vertical Depth (TVD) 6,620 lateral length 100% working interest Well has been flowing for nearly 60 days and is currently producing at a restricted rate of 20 MMcf/d 25 Rymer Unit 4HD - Gas Rate vs Time IP / 1,000 Lateral (MMcf/d) 5.0 10.0 10.0 15.0 15.0 25.0 Gulfport Irons #1-4H 5,714 Lateral IP/1,000 : 5.3 MMcf/d Gastar Blake U-7H 6,617 Lateral IP/1,000 : 5.6 MMcf/d Range Claysville SC #11H 5,420 Lateral IP/1,000 : 10.9 MMcf/d EQT Scotts Run 3,221 Lateral IP/1,000 : 22.6 MMcf/d Utica Dry Gas Fairway CNX Gaut 4IH 5,840 Lateral IP/1,000 : 10.4 MMcf/d Gas Rate (MMCFD) 20 15 10 5 TBU 0 12/23/15 01/06/16 01/20/16 02/03/16 02/17/16 03/02/16 Dry gas fairway extends from the Antero Utica acreage in eastern Ohio to the Antero Marcellus play acreage in northern West Virginia In total, Antero has 229,000 net acres and 2,152 potential locations in the Point Pleasant high pressure, high porosity dry gas fairway in OH, WV and PA 10,000 to 14,500 TVD Density log porosity values average > 8.5% 120 to 130 total thickness 25 MMcf/d to 73 MMcf/d industry 24-hr IP flow rates 1000 to 1040 BTU expected Stone Energy Pribble 6HU 3,605 Lateral IP/1,000 : 8.3 MMcf/d Magnum Hunter Stalder #3UH 5,050 Lateral IP/1,000 : 6.4 MMcf/d Magnum Hunter Stewart Winland 1300U 5,280 Lateral IP/1,000 : 8.8 MMcf/d Targeted Pay Zone Gastar Sims U-5H 4,447 Lateral IP/1,000 : 6.6 MMcf/d Antero Utica Producing Well Rymer 4HD NOTE: Wellbore diagram for illustrative purposes only. 35
ANTERO CAPITALIZATION CONSOLIDATED ($ in millions) 12/31/2015 Cash $23 Senior Secured Revolving Credit Facility 707 Midstream Bank Credit Facility 620 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 Net Unamortized Premium 7 Total Debt $4,709 Net Debt $4,686 Financial & Operating Statistics LTM EBITDAX (1) $1,221 LTM Interest Expense (2) $237 Proved Reserves (Bcfe) (12/31/2015) 13,215 Proved Developed Reserves (Bcfe) (12/31/2015) 5,838 Credit Statistics Net Debt / LTM EBITDAX 3.8x Net Debt / Net Book Capitalization 39% Net Debt / Proved Developed Reserves ($/Mcfe) $0.80 Net Debt / Proved Reserves ($/Mcfe) $0.35 Liquidity Credit Facility Commitments (3) $5,500 Less: Borrowings (1,327) Less: Letters of Credit (702) Plus: Cash 23 Liquidity (Credit Facility + Cash) $3,494 1. LTM and 12/31/2015 EBITDAX reconciliation provided on page 44. 2. LTM interest expense adjusted for all capital market transactions since 1/1/2015. 3. AR lender commitments under the facility increased to $4.0 billion from $3.0 billion on 2/17/2015; borrowing base capacity increased to $4.5 billion from $4.0 billion on 10/26/2015. AM credit facility increased to $1.5 billion concurrent with water drop down on 9/23/2015. 36
MARCELLUS SINGLE WELL ECONOMICS IN ETHANE REJECTION Assumptions Natural Gas 12/31/2015 strip Oil 12/31/2015 strip NGLs 37% of Oil Price 2016; 50% of Oil Price 2017+ NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL (2) ($/Bbl) 2016 $2.50 $41 $15 2017 $2.79 $46 $23 2018 $2.91 $49 $25 2019 $3.03 $52 $26 2020 $3.18 $54 $27 2021-25 $3.31-$3.88 $55-$56 $27-$28 DRY GAS LOCATIONS Marcellus Well Economics and Total Gross Locations (1) ROR 2016 Drilling Plan 80% 60% 40% 20% 0% 63% 626 34% Highly-Rich Gas/ Condensate RICH GAS LOCATIONS 971 47% 22% 1,200 1,000 755 800 553 24% 28% 600 400 200 9% 11% 0 Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR @ 12/31/2015 Strip Pricing - After Hedges ROR @ 12/31/2015 Strip Pricing - Before Hedges Highly-Rich Gas/ Highly-Rich Classification Condensate Gas Rich Gas Dry Gas Modeled BTU 1313 1250 1150 1050 EUR (Bcfe): 20.8 18.8 16.8 15.3 EUR (MMBoe) : 3.5 3.1 2.8 2.6 % Liquids: 33% 24% 12% 0% Lateral Length (ft): 9,000 9,000 9,000 9,000 Well Cost ($MM): $9.1 $9.1 $9.1 $9.1 Bcfe/1,000 : 2.3 2.1 1.9 1.7 Net F&D ($/Mcfe): $0.52 $0.57 $0.64 $0.70 Direct Operating Expense ($/well/month): $1,498 $1,498 $1,498 $1,498 HIGHLY RICH GAS LOCATIONS Direct Operating Expense ($/Mcf): $0.92 $0.92 $1.17 $0.70 Transportation Expense ($/Mcf): $0.28 $0.28 $0.28 $0.28 Pre-Tax NPV10 ($MM): $8.9 $5.1 ($0.7) $0.2 Pre-Tax ROR: 34% 22% 9% 11% Payout (Years): 2.0 2.8 6.5 5.5 Gross 3P Locations (3) : 626 971 553 755 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 $1.2 million for road, pad and production facilities, assume Antero will begin to realize lower well costs in 2016 as the company utilizes incremental completion crews for deferred completions beginning at year end 2015 and as existing drilling rig contracts begin to roll off during 2016. 2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 2016 and 50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship. 3. Undeveloped well locations as of 12/31/2015. Total 3P Locations 37
UTICA SINGLE WELL ECONOMICS IN ETHANE REJECTION Assumptions Natural Gas 12/31/2015 strip Oil 12/31/2015 strip NGLs 37% of Oil Price 2016; 50% of Oil Price 2017+ NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL (2) ($/Bbl) 2016 $2.50 $41 $15 2017 $2.79 $46 $23 2018 $2.91 $49 $25 2019 $3.03 $52 $26 2020 $3.18 $54 $27 2021-25 $3.31-$3.88 $55-$56 $27-$28 DRY GAS LOCATIONS Utica Well Economics and Gross Locations (1) ROR 2016 Drilling Plan 100% 80% 60% 40% 20% 0% 184 16% 10% Condensate 57% 98 RICH GAS LOCATIONS 83% 27% 29% 108 71% 23% 80% 26% 161 263 Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR @ 12/31/2015 Strip Pricing - After Hedges ROR @ 12/31/2015 Strip Pricing - Before Hedges Classification Condensate Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Modeled BTU 1275 1235 1215 1175 1050 EUR (Bcfe): 9.4 17.0 25.3 23.8 21.4 EUR (MMBoe) : 1.6 2.8 4.2 4.0 3.6 % Liquids 35% 26% 21% 14% 0% Lateral Length (ft): 9,000 9,000 9,000 9,000 9,000 Well Cost ($MM): $10.2 $10.2 $10.2 $10.2 $10.2 Bcfe/1,000 : 1.0 1.9 2.8 2.7 2.4 Net F&D ($/Mcfe): $1.34 $0.74 $0.50 $0.53 $0.59 Fixed Operating Expense ($/well/month): $2,788 $2,788 $2,788 $2,788 $1,498 Direct Operating Expense ($/Mcf): $0.99 $0.99 $0.99 $0.99 $0.50 Direct Operating Expense ($/Bbl): $2.73 $2.73 $2.73 - - Transportation Expense ($/Mcf): $0.55 $0.55 $0.55 $0.55 $0.55 HIGHLY RICH GAS LOCATIONS Pre-Tax NPV10 ($MM): $0.0 $5.8 $7.6 $5.6 $6.4 Pre-Tax ROR: 10% 27% 29% 23% 26% Payout (Years): 7.8 3.1 2.9 3.7 3.2 Gross 3P Locations (3) : 184 98 108 161 263 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, assume Antero will begin to realize lower well costs in 2016 as the company utilizes incremental completion crews for deferred completions beginning at year end 2015 and as existing drilling rig contracts begin to roll off during 2016. 2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 2016 and 50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship. 3. Undeveloped well locations as of 12/31/2015. 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content. 300 250 200 150 100 50 0 Total 3P Locations 38
CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY 27 year proved reserve life based on 2015 production annualized Reserve base provides significant exposure to liquids-rich projects 3P reserves of over 2.4 BBbl of NGLs and condensate in ethane recovery mode; 35% liquids ETHANE REJECTION (1)(2) ETHANE RECOVERY (1) Marcellus 29.6 Tcfe Utica 7.5 Tcfe Upper Devonian 0.0 Tcfe 37.1 Tcfe Marcellus 34.0 Tcfe Utica 8.4 Tcfe Upper Devonian 0.0 Tcfe 42.4 Tcfe Gas 29.7 Tcf Oil 92 MMBbls NGLs 1,145 MMBbls 20% Liquids Gas 27.6 Tcf Oil 92 MMBbls NGLs 2,382 MMBbls 35% Liquids 1. Ethane rejection occurs when ethane is left in the wellhead gas stream as the gas is processed, rather than being separated out and sold as a liquid after fractionation. When ethane is left in the gas stream, the BTU content of the residue gas at the outlet of the processing plant is higher. Producers will elect to reject ethane when the price received for the higher BTU residue gas is greater than the price received for the ethane being sold as a liquid after fractionation. When ethane is recovered, the BTU content of the residue gas is lower, but a producer is then able to recover the value of the ethane sold as a separate NGL product. 2. 1.1 Tcfe of ethane reserves (182 million barrels) was included in 12/31/2015 reserves from the Marcellus Shale as the first de-ethanizer was placed online at the MarkWest Sherwood facility in December 2015 and Antero s first ethane sales contract is expected to commence in 2017 upon the completion of Mariner East 2. 39
POSITIVE RATINGS MOMENTUM Antero s corporate credit ratings were recently affirmed at Ba2/BB by Moody s and S&P, respectively, despite the severe commodity price down cycle Moody s / S&P Historical Corporate Credit Ratings Moody s Rating Rationale Moody s confirmed Antero Resources rating, which reflects its strong hedge book through 2018 and good liquidity. Antero has $3.1 billion in unrealized hedge gains, $3 billion of availability under its $4 billion committed revolving credit facility and a 67% interest in Antero Midstream Partners LP. S&P Rating Rationale Outlook Stable. The affirmation reflects our view that Antero will maintain funds from operations (FFO)/Debt above 20% in 2016, as it continues to invest and grow production in the Marcellus Shale. The company has very good hedges in place, which will limit exposure to commodity prices. - Moody s Credit Research, February 2016 - S&P Credit Research, February 2016 Corporate Credit Rating (Moody s / S&P) Baa3 / BBB- Ba1 / BB+ Ratings Affirmed February 2016 Ba2/BB Ba2 / BB Ba3 / BB- B1 / B+ B2 / B B3 / B- Caa1 / CCC+ 9/1/2010 2/24/2011 5/31/13 10/21/2013 9/4/2014 3/31/2015 2/12/2016 Moody's 1. Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC. S&P (1) 40
NGL EXPORTS AND NETBACKS STEP-UP BY 2017 Upon in-service of Mariner East II, Antero will have the ability to market its propane and n-butane to international buyers, which we expect will provide uplifts of $0.16/Gal and $0.18/Gal, respectively, to the current netbacks received from propane and n-butane volumes shipped to Mont Belvieu today In the meantime, Antero has 30,000 Bbl/d of propane hedged at $0.59/Bbl in 2016 Commitment to Mariner East II results in approximately $127 million in combined incremental annualized cash flow from propane and n-butane sales (~$86 MM from propane and ~$41 MM from n-butane) based on current product pricing Mont Belvieu Propane Netback ($/Gal) Propane N-Butane January Mont Belvieu Price (1) : $0.39 $0.56 Less: Shipping Costs to Mont Belvieu (2) : (0.25) (0.25) Appalachia Propane Netback to AR: $0.14 $0.31 Europe Pricing Propane: $0.56/Gal N-Butane: $0.76/Gal Pricing Propane: $0.39/Gal N-Butane: $0.56/Gal Shipping $0.25/Gal Mariner East II 61,500 Bbl/d AR Commitment (see table below) (3) 4Q 2016 In-Service 1. Source: Intercontinental exchange as of 12/31/2015. 2. Source of graphic: Tudor Pickering Holt & Co. research presentation dated June 16, 2015. 3. As an anchor shipper on Mariner East II, Antero has the right to expand its NGL commitment with notice to operator. Mariner East II AR Mariner East II Commitment (Bbl/d) Product Base Option (3) Total Ethane (C2) 11,500-11,500 Propane (C3) 35,000 35,000 70,000 Butane (C4) 15,000 15,000 30,000 Total 61,500 50,000 111,500 Shipping Propane: $0.07/Gal N-Butane: $0.08/Gal NWE Netback ($/Gal) Propane N-Butane January NWE Price (1) : $0.56 $0.76 Less: Spot Freight (4) : ($0.07) ($0.08) FOB Margin at Marcus Hook: $0.49 $0.68 Less: Pipeline & Terminal Fee (5) : (0.19) (0.19) Appalachia Netback to AR: $0.30 $0.49 Upside to Appalachia Netback: $0.16 $0.18 4. Shipping rates based on benchmark Baltic shipping rate of $59.57/ton as of 12/31/15, adjusted for number of shipping days to NWE. 5. Pipeline fee equal to $0.0725/gal, per Mariner East I tariff. Terminal fee equal to $0.12/gal, per TPH report dated June 16, 2015. 41