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http://investors.anteroresources.com 1268
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Company website presentation March 2014 Presentation Transcript

  • 1. Company Overview March 2014
  • 2. FORWARD-LOOKING STATEMENTS This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 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, 2013 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 the Registration Statement 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. 1
  • 3. ANTERO: A “PURE PLAY” ON THE MARCELLUS / UTICA Critical Mass In Two World Class Shale Plays ● Marcellus is the largest gas field in the U.S., 2nd largest in the world – Industry production approximately 14 Bcf/d today ● Antero has 35 Tcfe of fully engineered and audited 3P reserves in Marcellus and Utica Shales ● 678 MMcfe/d of average net production in 4Q 2013 including approximately 11,100 Bbl/d of liquids Market Leading Growth ● 159% Appalachian production CAGR for 2010 to 2013 ● Most active driller in Appalachia – 20 rigs running − Most active driller in Marcellus Shale – 15 rigs running − 3rd most active driller in the Utica Shale – 5 rigs running Industry Leading Capital Efficiency and Recycle Ratio ● Low development cost leader: $1.03/Mcfe(1) ● Industry leading growth-adjusted recycle ratio: 6.1x(1) ● Top quartile return on productive capital: 27% for 2013E Significant Emphasis on Takeaway and Liquids Processing ● 1.6 Bcf/d of processing capacity and 1.7 Bcf/d of gas takeaway ● Liquids expected to grow from 10% of fourth quarter 2013 production to ~ 16% in 2014 due to focus on liquids-rich development Liquidity and Hedge Position Support High Growth Story ● ~$1.2 billion pro forma available liquidity with current $1.5 billion bank commitment(2) ● 1.3 Tcfe hedged through 2019 at an average index price of $4.62/MMBtu and $96.54/Bbl Outstanding Management Team 1. Three year average through 2012; pro forma for Arkoma and Piceance divestitures. 2. See page 23 for the derivation of 12/31/2013 liquidity. ● Over 30 years as a team (over 20 years in unconventional) ● “Shale Pioneers” – early mover and driller of over 500 horizontal shale wells in the Barnett, Woodford, Marcellus and Utica Shales 2
  • 4. PREMIER UNCONVENTIONAL RESOURCE PLATFORM TOTAL – 12/31/13 RESERVES(1) Assumes Ethane Rejection Net Proved Reserves(1) Net 3P Reserves(1) Pre-Tax 3P PV-10(1) 902 MMBbls 15% 678 MMcfe/d 11,190 Bbl/d 456,000 4,778 “Pure-Play” Appalachian-Focused Shale Company Reserves(1) Net Proved Net 3P Reserves (1) Pre-Tax 3P PV-10(1) 7.2 Tcfe 25.0 Tcfe $15,729 MM % Liquids – Net 3P 4Q 2013 Net Production Undrilled 3P Locations 7.6 Tcfe 35.0 Tcfe $20,362 MM Net 3P Liquids % Liquids – Net 3P 4Q 2013 Net Production(2) - 4Q 2013 Net Liquids(2) Net Acres(3) Undrilled 3P Locations A MARCELLUS SHALE 17% 621 MMcfe/d 3,068 B UTICA SHALE – LIQUIDS RICH Reserves(1) C B D C 362 Bcfe 5.8 Tcfe $4,666 MM % Liquids – Net 3P 4Q 2013 Net Production Undrilled 3P Locations A Net Proved Net 3P Reserves (1) Pre-Tax 3P PV-10(1) 15% 54 MMcfe/d 759 Net Proved Reserves(1) Net 3P Reserves (1) Pre-Tax 3P PV-10(1) % Liquids – Net 3P 4Q 2013 Net Production Undrilled 3P Locations Net Acres(3) Net Resource Undrilled Locations 2. 3. 100% operated • Stable acreage base − Marcellus Shale: 51% HBP, with additional 21% not expiring for 5+ years − Utica Shale: 20% HBP, with additional 79% not expiring for 5+ years • Portfolio flexibility across dry gas to liquids-rich and condensate windows • Significant investment in midstream infrastructure and secured takeaway capacity • Financial flexibility to pursue planned 2014 and 2015 development drilling activities • Full scale development underway − 20 rigs currently operating UPPER DEVONIAN SHALE 44 Bcfe 4.2 Tcfe NM 7% 3 MMcfe/d 951 Additional Hedge Value 128,000 5.0 Tcfe 950 • 1.3 Tcfe hedged from 1/1/2014 through 12/31/2019 at an average index price of $4.62/MMBtu and $96.54/Bbl • ~ $760 million mark-to-market hedge value as of 2/24/2014 • D UTICA SHALE – DRY GAS 1. • ~ 50% hedged through NYMEX; 50% hedged through regional hubs Proved, probable, and possible reserves as of December 31, 2013, assuming ethane rejection using SEC methodology and SEC pricing. Evaluations prepared by our internal reserve engineers and audited by DeGolyer & MacNaughton (D&M). Pre-Tax 3P PV-10 is a non-GAAP financial measure. Represents the average net daily production for the period October 1, 2013 through December 31, 2013. All net acres allocated to the Dry Gas Utica 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 leases. 3
  • 5. STRONG TRACK RECORD OF GROWTH AVERAGE NET DAILY PRODUCTION (MMcfe/d) Woodford Piceance Marcellus APPALACHIAN PRODUCTION (MMcfe/d) Utica 800 Marcellus 950 1,000 600 522 400 950 800 Sold Woodford and Piceance 600 522 400 334 244 200 0 6 2006 31 2007 105 87 2008 2009 2010 2011 2012 2013 Piceance 0 (4) 2014E 2010 2011 2012 (4) 2013 2014E OPERATED GROSS WELLS SPUD Marcellus(3) Utica Woodford Piceance Marcellus Utica 193 200 7,632 8,000 Sold Woodford and Piceance 7,000 6,000 5,017 5,000 4,000 680 87 4,283 100 2007 2009 85 96 119 91 Financial Crisis 66 50 1,141 2008 126 75 18 25 235 2006 162 125 3,231 2,000 175 150 3,000 0 124 30 9,000 1,000 239 200 133 NET PROVED SEC RESERVES (Bcfe)(2) Woodford Utica 1,000 2010 2011 2012 (5) (5) 2013 0 2006 2007 2008 2009 2010 2011 2012 2013 (4) 2014E 1. CAGR = Compound Annual Growth Rate. 2. Proved reserves for 2006, 2007, and 2008 represent previously effective SEC methodology. 2009, 2010, 2011, 2012 and 2013 proved reserves based on current SEC reserve methodology and SEC pricing and are audited by independent third-party engineers. 3. Includes Upper Devonian Shale proved reserves (10 Bcfe in 2012 and 44 Bcfe in 2013). 4. Per Company press release dated January 29, 2014; production mid-point of 925-975 MMcfe/d guidance. 5. 2012 and 2013 proved reserves are both in ethane rejection mode. 4
  • 6. OUTSTANDING RESERVE GROWTH PROVED RESERVE GROWTH(1) (Tcfe) 10 7.6 0.4 8 6 4 4.2 0.1 2 4.1 7.2 Drivers • Successful drilling • Expanded proved footprint (HDA) 2013 Marcellus 3P RESERVE GROWTH(1) 30 20 10 35.0 4.2 5.8 21.6 4.0 Drivers • 80,000 net acres added in 2013 • SSL results • Utica results • All-in finding cost of $0.58/Mcfe • 2013 “top-down” development cost of $1.25/Mcfe • 2013 “bottoms-up” development cost of $1.10/Mcfe Driver 2014 Action • Marcellus SSL completions Complete transition to SSL type curve • Full scale Utica program 41 wells to be completed; only 21 PUD locations booked as proved at YE 2013 0 2012 • Utica increased density drilling Drilling 2 increased density pilots in Utica • Utica dry gas drilling 25.0 17.6 Marcellus • Replaced 1,857% of 2013 production FUTURE RESERVE GROWTH DRIVERS (Tcfe) 40 • 3P PV-10 increased 82% to $21.4 billion (including hedges) • No Utica Shale WV/PA dry gas reserves booked Utica 50 • Proved PV-10 increased 133% to $7.0 billion (including hedges) • Only 14% of 1P and 58% of 3P locations booked as SSL (1.73 Bcf/1,000’ type curve) 0 2012 2013 RESERVE UPDATE Drilling first Utica dry gas well in WV (126,000 net acres WV/PA) • Core acreage acquisitions $200 million leasehold budget 2013 Utica 1. 2012 and 2013 reserves assume ethane rejection. Upper Devonian 5
  • 7. MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW-RISK, HIGH-RETURN GROWTH PROFILE 890 834 707 ROR 100% 0% 800 600 117% 50% 400 65% 200 32% Highly-Rich Gas/ Condensate 1000 1,000 Highly-Rich Gas 21% Rich Gas Dry Gas Locations 200% 100% 161 0% ROR 250 211 182 200 169% 150 137% 100 95% 50% 0  71% of Marcellus locations are processable (1100-plus Btu) 205 150% ROR 637 Total 3P Locations 150% UTICA WELL ECONOMICS(1) 50 56% Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Locations 0 Dry Gas Total 3P Locations MARCELLUS SSL WELL ECONOMICS(1)(2) ROR  72% of Utica locations are processable (1100-plus Btu) $ / MMBtu NYMEX (Gas) Large Inventory of Low Breakeven Projects(3) $7.00 $6.00 $5.00 $3.00 $2.00 $0.00 1,541 366 Locations 637 182 $2.47 $2.50 Locations 890 Locations $3.75 $3.80 $3.81 $4.00 $1.00 1. 2. 3. 4. 3 Yr Strip - $4.38/MMBtu(4) 2,726 Antero Liquids-Rich Locations $2.60 $2.94 $3.20 $3.27 $3.51 $4.13 $4.25 $4.66 $5.05 $5.37 $5.49 $3.65 $3.66 $3.70 Locations Locations $0.89 $1.15 $0.00 $0.00 $0.00 $0.00 ` Well economics based on 12/31/2013 3P SSL reserves and strip pricing as of 12/31/2013. A portion of these locations do not assume SSL completions. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI. 3-year NYMEX STRIP as of 2/24/2014. 6
  • 8. LOW DEVELOPMENT COST DRIVES BEST-IN-CLASS RECYCLE RATIOS 3-Year All-in Development Costs ($/Mcfe) through 2012 $/Mcfe $4.00 Antero $3.00 $2.00 $1.00 $1.03 $1.14 Appalachia-Focused Peers $1.41 $1.71 $1.57 $0.00 Source: Proved developed F&D research prepared by JP Morgan Research report dated 07/22/2013. Defined as total drilling and completion capital expenditures for the period divided by PDP and PDNP volumes added after adding back production for the period. Includes all drilling and completion costs but excludes land and acquisition costs for all companies. 1. Antero internal estimate using JP Morgan development cost methodology; excludes Arkoma and Piceance operations. 2. Antero estimate based on public information; includes Arkoma and Piceance operations. 3-Year Average Growth – Adjusted Recycle Ratio through 2012 8.0x 6.0x 4.0x 6.1x Antero 3.5x Appalachia-Focused Peers 3.1x 2.7x 2.0x 0.0x Source: Wall Street research. Defined as 2010-2012 average (Cash Operating Netback / PD F&D costs) x (1 + 2012-2014 production CAGR). PD F&D Costs defined as total drilling and completion capital expenditures for the period divided by PDP and PDNP volumes added after adding back production for the period per JP Morgan analysis. Includes all drilling and completion costs but excludes land and acquisition costs for all companies. 1. Antero data pro forma for Woodford and Piceance divestitures; Antero production growth based on first half of 2013 only. 7
  • 9. MARCELLUS/UTICA – ADVANTAGED ECONOMICS  Low-cost, liquids-rich Utica and Marcellus Shales will remain attractive in most commodity price environments U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE(1) Downside risks to breakeven costs for older shale plays once exploration resumes with higher natural gas prices? ? ? 1. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI Haynesville ? Barnett ? Eagle Ford Shale Niobrara Utica Shale SW (Rich) Marcellus Shale NE (Dry) Marcellus Shale Permian Needed to make up for base declines in conventional and GOM production Granite Wash Over 2,700 Antero Drilling Locations 8
  • 10. INTEGRATED MIDSTREAM PROCESSING AND TAKEAWAY Infrastructure and commitments in place to handle strong natural gas, NGL and oil production growth – Portfolio of firm transportation and sales and West Virginia location minimizes basis risk Producers located in northern West Virginia have seen much less basis widening and volatility than Pennsylvania producers Antero sold ~67% of its 2013 production at TCO index at NYMEX less $0.06/MMbtu prior to the Btu upgrade Antero Transport and Processing 2014 1,369,000 330,000 1,400,000 20,000 Chicago Basis to NYMEX Current 2015 +$3.23 -$0.07 1,407,000 320,000 Firm Processing Capacity (Mcf/d) Ethane FT (Bbl/d) Dom South Basis to NYMEX Current 2015 -$0.17 -$0.93 2015 Firm Transport (FT) (MMBtu/d) Firm Sales (MMBtu/d)(1) Leidy Basis to NYMEX Current 2015 -$2.78 -$2.17 1,550,000 20,000 TCO Basis to NYMEX Current 2015 +$0.13 -$0.43 Growing Processing Capacity Total Capacity 1,550 1,600 Seneca IV 1,400 CGTLA Basis to NYMEX Current 2015 -$0.02 -$0.09 1,200 Seneca III (MMcf/d) 1,000 800 Seneca II 600 Seneca I 400 Sherwood III 200 Sherwood V Sherwood IV Appalachian Basis to NYMEX(2) 2013 % of Production Sold Sherwood II 2014 TCO Sherwood II Sherwood III Sherwood IV Utica 1. 2. Sherwood I Seneca I Seneca II Seneca III Dom South 5% TETCO M2 NYMEX Marcellus 22% TETCO 0 67% Dom South Sherwood I TCO 6% Sherwood V Seneca IV 80,000 MMBtu/d and 70,000 MMbtu/d also utilize firm transportation in 2014 and 2015, respectively. Basis data from Wells Fargo daily indications and various private quotes as of 2/24/2014. 2015 2016 2017 2018 2019 -$0.20 -$0.60 -$1.00 -$1.40 -$1.80 Leidy -$2.20 -$2.60 9
  • 11. LONG HAUL PIPELINE AND TRANSPORTATION NETWORK  Antero has a leading firm transportation capacity position and is well-positioned in the southern portion of the Marcellus and Utica Shale from a gas takeaway perspective Leidy Basis to NYMEX Current 2015 -$2.78 -$2.17 Chicago Basis to NYMEX Current 2015 +$3.23 -$0.07 Dom South Basis to NYMEX Current 2015 -$0.17 -$0.93 (1) TCO Basis to NYMEX Current 2015 +$0.13 -$0.43 Appalachian Firm Transportation/Sales Commitment by Operator 2,000,000 Firm Sales Firm Transportation CGTLA Basis to NYMEX Current 2015 -$0.02 -$0.09 Mcf/d 1,600,000 1,200,000 800,000 400,000 0 (2) AR RRC EQT CNX COG CHK TLM STO SWN WPX RDS APC NFG Source: Tudor Pickering & Holt research report dated 9/3/2013 and company presentations, press releases. Note: Antero firm transportation and firm sales positions listed by pipeline in colored-coded boxes. 1. Firm transport as of year-end 2014. See Page 27 for timing of firm transportation graph. 2. Antero firm transportation as of 2/24/2014; includes 250 MMcf/d of firm sales. 10
  • 12. SIGNIFICANT LONG-TERM COMMODITY HEDGE POSITION NATURAL GAS HEDGES – 2/24/2014 BBtu/d 600 400 Average Index Price ($/MMBtu)(1) Hedged Volume 800 $4.92 $4.85 $4.91 $4.20 NYMEX Strip (2/24/2014) ($/MMBtu) $7.00 $6.00 $4.71 $4.65 $4.34 $4.10 $4.09 $4.14 $4.46 $4.22 $4.00 $3.00 $2.00 200 729 550 643 740 630 358 2014 0 $5.00 2015 2016 2017 2018 $1.00 2019 $0.00 1. Reflects weighted average index price per annum based on volumes hedged and 6:1 gas to oil ratio. Antero has hedged ~3,000 Bbl/d for 2014, WTI hedges comprise ~1% of overall hedge book.  ~$760 million mark-to-market unrealized gain as of February 24, 2014  1.3 Tcfe hedged from January 1, 2014 through year-end 2019 % HEDGE VOLUMES BY INDEX – 2/24/2014 Chicago 2% NYMEX TCO 12% 18% Dom South 50% 18% CGTLA 11
  • 13. ASSET OVERVIEW 12
  • 14. WORLD-CLASS POSITION IN THE CORE OF THE MARCELLUS AND UTICA LIQUIDS-RICH FAIRWAYS ANTERO LIQUIDS-RICH UTICA SHALE Utica Shale Liquids-Rich Fairway 106,000 Net Acres 18 Horizontals Completed 5 Rigs Currently Running Utica Shale Core Area Marcellus Shale Southwestern & Northeastern Core Areas Marcellus Shale Liquids-Rich Fairway ANTERO MARCELLUS SHALE SW PA 25,000 Net Acres 2 Horizontals Completed Strong Results ANTERO MARCELLUS SHALE NW WV 325,000 Net Acres (Primarily Liquids-Rich Fairway) 234 Horizontals Completed 15 Rigs Currently Running Utica Shale Dry Gas Resource Underlies Marcellus Acreage Upper Devonian Shale Resource Overlies Marcellus Acreage 13 Source: Company presentations and press releases.
  • 15. WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT Antero Has Delineated And De-Risked Its Large Scale Acreage Position  100% operated  350,000 net acres in Southwestern Core – 51% HBP with additional 21% not expiring for 5+ years  236 horizontal wells completed and online – Laterals average 7,000’ – 100% drilling success rate  Net production of 621 MMcfe/d in 4Q 2013, including 8,900 Bbl/d of liquids MHR WEESE UNIT 30-Day Rate 4-well average 9.3 MMcfe/d (31% liquids) BLANCHE UNIT 30-Day Rate 2H: 10.0 MMcfe/d (29% liquids) DOTSON UNIT 30-Day Rate 1H: 12.4 MMcfe/d 2H: 11.8 MMcfe/d (27% liquids) EQT 30-Day Rate 12 Recent Wells 9.2 MMcfe/d (20% Liquids) CHK HADLEY UNIT 24-Hour IP 9.1 MMcfe/d (32% liquids) MOORE UNIT 30-Day Rate 1H: 9.9 MMcfe/d 2H: 10.0 MMcfe/d (17% liquids) Sherwood Processing Plant EQT PENN 15 UNIT 30-Day Rate 5-well average 9.3 MMcfe/d (29% liquids) 142 Horizontals Completed 30-Day Rate 10.3 Bcf average EUR 8.1 MMcf/d 6,915’ average lateral length  3,068 future drilling locations in the Marcellus (71% are processable)  Operating 15 drilling rigs including 4 shallow rigs  25.0 Tcfe of net 3P (17% liquids), includes 7.2 Tcfe of proved reserves (assuming ethane rejection) CONSTABLE UNIT 30-Day Rate 1H: 15.2 MMcfe/d (30% liquids) PRUNTY UNIT 30-Day Rate 1H: 11.0 MMcfe/d (29% liquids) Highly-Rich/Condensate 60,000 Net Acres 637 Gross Locations Highly-Rich Gas 100,000 Net Acres 834 Gross Locations HINTERER UNIT 30-Day Rate 1H: 12.9 MMcfe/d (20% liquids) Rich Gas 86,000 Net Acres 707 Gross Locations RUTH UNIT 30-Day Rate 1H: 19.3 MMcfe/d (14% liquids) Dry Gas 104,000 Net Acres 890 Gross Locations 14 Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned. Note: Rates assume ethane rejection.
  • 16. MARCELLUS – SIMPLE STRUCTURE  Several regional anticlines in core area − Predictable “layer cake” geology − No faults at Marcellus level • Over 1.7 million feet (315 miles) drilled horizontally without crossing a fault − 3-D seismic not required to guide horizontal wells  Regional East-West seismic line shows gentle structure at Marcellus level  Allegheny Front and complex structure located many miles east of core area  Favorable geology allows for longer laterals Regional Seismic Line Average Marcellus Lateral Lengths 8,000 7,300 Feet 6,000 4,800 4,500 4,100 4,000 100’ Contours Top Marcellus W Profile along regional seismic line (time) No Data 2,000 0 Antero EQT Source: Company presentations. RRC COG Big Moses Arches Fork Wolf Summit E Benson Rhinestreet Tully Marcellus Onondaga 15
  • 17. ANTERO’S MARCELLUS SHALE TYPE CURVE SUPPORT  Antero has over four years of production history to support its 1.5 Bcf/1,000’ type curve (non-SSL)  Antero’s SSL type curve has been increased to 1.73 Bcf/1,000’ with only 12% higher well costs  Lack of faulting and contiguous acreage position allows for drilling of long laterals ~ 7,300’ − Drives down costs per 1,000’ of lateral resulting in best-in-class development costs Marcellus Type Curve – Normalized to 7,000’ Lateral Antero Non-SSL Type Curve Actual Non-SSL Production (1) Non-SSL Type Curve Cumulative Production 1.7 Bcf/1,000' SSL Type Curve 15.0 SSL Actual Production (2) 12.0 12.0 MMcf/d 24-Hour Peak Rate 9.0 90-Day Avg. Rate 180-Day Avg. Rate One-Year Avg. Rate Two-Year Avg. Rate Three-Year Avg. Rate 14.3 236 Wellhead (MMcf/d) # of wells 30-Day Avg. Rate 8.1 224 6.3 221 5.3 193 4.2 131 3.1 65 2.3 26 Cumulative Bcf 15.0 9.0 6.0 6.0 3.0 3.0 0.0 0.0 0 1 2 3 4 5 6 7 8 9 10 Production Year EURs Increase With Lateral Length Well Cost / 1,000’ Decreases with Lateral Length Wellhead 24-hour Peak Rates (IPs) - 236 Wells $1.6 25 $1.4 20 12 8 4 0 2,000 MMcf/d 30 $MM / 1,000' $1.8 16 EUR, BCF 20 $1.2 $1.0 $0.8 4,000 6,000 8,000 Lateral Length, ft 10,000 $0.6 2,000 Average IP – 14.3 MMcf/d 15 10 5 4,000 6,000 8,000 Lateral length, ft 1. 236 Antero Marcellus wells normalized to time zero, production for each well normalized to 7,000’ lateral length. 2. 32 Antero Marcellus SSL wells normalized to time zero, production for each well normalized to 7,000’ lateral length. 10,000 0 1st Production from All Wells 2009 - 2013 16
  • 18. MARCELLUS SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION Marcellus SSL Well Economics and Total Locations(1)  12/31/2013 Strip Pricing & SEC Reserves WTI ($/Bbl) 2014 $4.24 $95 $54 2015 $4.16 $88 $50 2016 $4.09 $83 $50 2017 $4.09 $80 $50 2018+ $4.14 $79 150% C3+ NGL(2) ($/Bbl) 1,000 890 834 637 $50 800 707 100% ROR NYMEX ($/MMBtu) 117% 600 50% 0% 400 65% 200 32% Highly-Rich Gas/ Condensate Highly-Rich Gas Locations 21% Rich Gas Total 3P Locations Assumptions 0 Dry Gas ROR Classification Highly-Rich/ Condensate Highly-Rich Gas Rich Gas Dry Gas BTU Range Modeled BTU 1275-1350 1313 1200-1275 1250 1100-1200 1150 <1100 1050 16.5 2.8 34% 7,000 225 $9.5 1.7 2.4 14.9 2.5 24% 7,000 225 $9.5 1.7 2.1 EUR (Bcfe): EUR (MMBoe): % Liquids: Lateral Length (ft): Stage Length (ft): Well Cost ($MM): Bcf/1,000’: Bcfe/1,000’: Pre-Tax NPV10DRY GAS LOCATIONS ($MM): Pre-Tax ROR: Net F&D ($/Mcfe): Payout (Years): Gross 3P Locations: RICH GAS LOCATIONS $20.5 13.3 2.2 12% 7,000 225 $9.5 1.7 1.9 HIGHLY RICH GAS $6.6 LOCATIONS 12.1 2.0 0% 7,000 225 $9.5 1.7 1.7 117% $0.68 0.9 $13.7 65% $0.75 1.3 32% $0.84 2.4 $3.7 21% $0.92 3.6 637 834 707 890 1. Well economics are based on 12/31/2013 proved SSL reserves (P90) and strip pricing. Includes gathering, compression and processing fees. A portion of the locations do not include SSL completions. 2. Pricing for a 1225 BTU y-grade rejection barrel. 17
  • 19. SHORTER STAGE LENGTHS (“SSL”) – ENHANCING MARCELLUS RECOVERIES Enhancing Recoveries SSL Well Count SSL Avg Wellhead Rate – MMcf/d(1) 22 10.0 19 8.6 19 8.1 10 7.9 Wellhead Type Curve – MMcf/d(2) SSL % Rate Improvement 7.6 31% 7.1 21% 6.6 24% 6.2 27% SSL Avg Processed Rate – MMcfe/d(1) Processed Type Curve – MMcfe/d(3) 11.5 8.1 9.9 7.5 9.3 7.0 9.1 6.6 SSL % Rate Improvement 42% 32% 34% 38% (1) (2) (3) Wellhead condensate production is converted on a 6:1 basis 1.5 Bcf/1,000’ Type Curve. 1.5 Bcf/1,000’ Type Curve processed assuming 1225 BTU. Normalized production increase for 22 SSL wells vs. 1.5 Bcf/1,000' Type Curve Gas Production (Mcfe/d)  Shorter stage length (SSL) summary: – 32 SSL wells completed – 22 SSL wells have at least 30 days of production history – 150’ to 225’ (SSL) vs. 350’ stages previously  31% higher 30-day wellhead rate for first 22 SSL wells vs. the Antero type curve – 27% higher 120-day rate vs. the Antero type curve – Other Marcellus operators have indicated 20% to 30% improvement in IPs and EURs  The 30-day processed rate for Antero’s first 22 SSL wells has averaged 42% higher than the Antero type curve  Estimated 12% increase in well costs for SSL completions as compared to non-SSL SSL vs Non-SSL Wellhead Average Rate Comparison 60-day 90-day 120-day 30-day Rate Rate Rate Rate 10,000 1.5 Bcf/1,000’ Type Curve 1,000 0 30 Antero Type Curve 60 90 Days From Peak Gas SSL Average Wellhead 120 150 SSL Average Processed 180 18
  • 20. EXCITING CORE UTICA SHALE POSITION DELIVERS CONDENSATE AND NGLS  100% operated Utica Shale Industry Activity(1)  106,000 net acres in the core rich gas / condensate window – 20% HBP with additional 79% not expiring for 5+ years – 75% of acreage has rich gas processing potential  18 Antero-operated horizontal wells completed and online − 100% drilling success rate  Net production of 54 MMcfe/d in 4Q 2013 including 2,200 Bbl/d of liquids − First production in early August 2013 had access to Cadiz pipeline and processing − Seneca I processing plant came online in November 2013 and Seneca II came online in January 2014 − First 120 MMcf/d compressor station went into service in late January with an additional 120 MMcf/d compressor station expected by late 1Q 2014  759 future drilling locations – Approximately 15% of EUR is liquids assuming ethane rejection  Operating 5 rigs including 1 shallow rig  5.8 Tcfe of net 3P (15% liquids), includes 362 Bcfe of proved reserves (assuming ethane rejection) GULFPORT 24-Hour IP Wagner 1-28H, Shugert 1-1H, 1-12H Average 21.0 MMcf/d + 2,270 Bbl/d NGL + 292 Bbl/d Oil GULFPORT 24-Hour IP Boy Scout 1-33H, Ryser 1-25H, Groh 1-12H Average 5.3 MMcf/d + 675 Bbl/d NGL + 1,411 Bbl/d Oil REXX 24-Hour IP Guernsey 1H, 2H, Noble 1H Average 7.9 MMcf/d + 1,192 Bbl/d NGL + 502 Bbl/d Oil CHESAPEAKE 24-Hour IP Buell #8H 9.5 MMcf/d + 1,425 Bbl/d liquids Cadiz Processing Plant Seneca Processing Plant RUBEL UNIT 30-Day Rate 3 wells average 13.5 MMcf/d + 583 Bbl/d NGL + 45 Bbl/d Oil Utica Core Area WAYNE UNIT 30-Day Rate 3 wells average 5.4 MMcf/d + 335 Bbl/d NGL + 548 Bbl/d Oil DOLLISON UNIT 1H 24-Hour IP 10.2 MMcf/d + 1,488 Bbl/d NGL + 1,397 Bbl/d Oil MILEY UNIT 30-Day Rate 2 wells average 3.0 MMcf/d + 187 Bbl/d NGL + 559 Bbl/d Oil COAL UNIT 1H 24-Hour IP 11.8 MMcf/d + 2,063 Bbl/d NGL + 1,850 Bbl/d Oil Highly-Rich/Cond 30,000 Net Acres 205 Locations MILLIGAN UNIT 24-Hour IP 3 wells average 11.3 MMcf/d + 1,971 Bbl/d NGL + 1,586 Bbl/d Oil Highly-Rich Gas 25,000 Net Acres 161 Locations GULFPORT 24-Hour IP McCort1-28H, 2-28H, Stutzman 1-14H Average 13.1 MMcf/d + 922 Bbl/d NGL + 21 Bbl/d Oil Rich Gas 24,000 Net Acres 182 Locations YONTZ UNIT 1H 30-Day Rate 14.6 MMcf/d + 392 Bbl/d NGL + 1 Bbl/d Oil GARY UNIT 1H 30-Day Rate 23.1 MMcf/d + 1,023 Bbl/d NGL + 65 Bbl/d Oil NORMAN UNIT 1H 30-Day Rate 13.6 MMcf/d + 461 Bbl/d NGL + 2 Bbl/d Oil Dry Gas 27,000 Net Acres 211 Locations Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are owned. Note: Third party peak rates assume ethane recovery; Antero 24-hour peak rates assume ethane recovery; Antero 30-day rates assume ethane rejection. 1. For non-Antero wells, Antero has converted rich gas rates where BTU has been disclosed to NGLs, assuming ethane recovery. Where BTU has not been disclosed, Antero has estimated BTU and gas composition. 19
  • 21. ANTERO HAS MOST OF THE TOP UTICA 24-HOUR IPS – STRONG SUPPORT FOR CORE POSITION UTICA 24-HOUR IPs  Antero has 11 of the top 12 Utica 24-hour peak rates (IPs) announced to date Core 12 to 53 60.0  Represent some of the best 24hour peak rates of any shale play in North America – 20 to 53 MMcfe/d per well 24hour peak rate in the core area – Excellent reservoir pressure with gradients in the 0.7 psi/ft range 50.0 40.0 MMcfe/d  Liquids content ranges from 40%-70% (assumes ethane recovery) in the liquids-rich window MMcfe/d IPs  Antero recently announced 30day rates on some of these wells (see page 29) 30.0 Tier 1 6 to 12 20.0 MMcfe/d IPs 10.0 0.0 Antero Utica Wells Source: Antero, press releases and company presentations. Note: Assumes ethane recovery. 3rd Party Core Utica Wells 3rd Party Non-Core Utica Wells 20
  • 22. UTICA SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION Utica Well Economics and Locations(1)  12/31/2013 Strip Pricing & SEC Reserves 200% NGL(2) WTI ($/Bbl) C3+ ($/Bbl) 2014 $4.24 $95 $54 2015 $4.16 $88 $50 2016 $4.09 $83 $49 2017 $4.09 $80 $49 2018+ $4.14 $79 $49 150% ROR NYMEX ($/MMBtu) 161 205 100% 250 211 169% 200 182 150 137% 100 95% 50% 0% 56% Highly-Rich Gas/ Condensate Highly-Rich Gas Locations Rich Gas Dry Gas 50 Total 3P Locations Assumptions 0 ROR Classification Highly-Rich/ Condensate Highly-Rich Gas Rich Gas Dry Gas BTU Range Modeled BTU 1250-1300 1275 1200-1250 1225 1100-1200 1175 <1100 11.3 1.9 32% 7,000 240 $11.0 1.2 1.6 20.5 3.4 23% 7,000 240 $11.0 2.4 2.9 18.8 3.1 15% 7,000 240 $11.0 2.4 2.7 16.6 2.8 0% 7,000 240 $11.0 2.4 2.4 $15.7 137% $1.21 0.5 $26.6 169% $0.66 0.5 95% $0.72 0.8 $11.7 56% $0.82 1.3 205 161 182 211 EUR (Bcfe): EUR (MMBoe): % Liquids Lateral Length (ft): Stage Length (ft): Well Cost ($MM): Bcf/1,000’: Bcfe/1,000’: Pre-Tax NPV10 ($MM): DRY GAS LOCATIONS Pre-Tax ROR: Net F&D ($/Mcfe): Payout (Years): Gross 3P Locations(3): RICH GAS LOCATIONS 1. Well economics are based on 12/31/2013 proved (P90) reserves and strip pricing. Includes gathering, compression and processing fees. 2. Pricing for a 1225 BTU y-grade rejection barrel. 3. Gross 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content. HIGHLY RICH GAS $18.4 LOCATIONS 21
  • 23. LARGE MIDSTREAM FOOTPRINT  Antero Midstream estimated cumulative YE 2014 total capital investment in midstream ~ $1,580 million – Includes gathering lines, compressor stations and water distribution infrastructure  Proprietary water sourcing and distribution system − Improves operational efficiency and reduces water truck traffic − Cost savings of $600,000 -$800,000 per well − One of the benefits of a consolidated acreage position Projected Midstream Infrastructure(1) Marcellus Utica Shale Shale Utica Shale Marcellus Shale Ohio River Withdrawal System Completed Total YE 2014E Cumulative Gathering / Compression Capex ($MM) Gathering Pipelines (Miles) Compression Capacity (MMcf/d) $835 192 410 $295 92 N/A $1,130 284 410 YE 2014 Cumulative Water System Capex ($MM) Water Pipeline (Miles) Water Storage Facilities $350 122 31 $100 48 16 $450 170 47 $1,185 $395 $1,580 YE 2014E Total Midstream ($MM) 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 9/30/2013 and remaining 2013 and 2014 budget. 22
  • 24. PRO FORMA CAPITALIZATION CAPITALIZATION 12/31/2013 (PF Financing) 12/31/2013 (2) $17 $17 Senior Secured Revolving Credit Facility 288 288 7.25% Senior Notes Due 2019 260 260 6.00% Senior Notes Due 2020 525 525 1,000 1,000 ($ in millions) Cash 5.375% Senior Notes Due 2021 Net Unamortized Premium 6 6 Total Debt $2,079 $2,079 Net Debt $2,062 $2,062 Shareholders' Equity $3,599 $3,599 Net Book Capitalization $5,660 $5,660 $17,328 $17,328 LTM EBITDAX $649 $649 LTM Interest Expense(2) $137 $106 Proved Reserves (Bcfe) (12/31/2013) 7,632 7,632 Proved Developed Reserves (Bcfe) (12/31/2013) 2,023 2,023 Net Market Capitalization(1) Financial & Operating Statistics Credit Statistics Net Debt / LTM EBITDAX 3.2x 3.2x LTM EBITDAX / Interest Expense 4.8x 6.1x Net Debt / Net Book Capitalization 36.4% 36.4% Net Debt / Net Market Capitalization 11.9% 11.9% Net Debt / Proved Developed Reserves ($/Mcfe) $1.02 $1.02 Net Debt / Proved Reserves ($/Mcfe) $0.27 $0.27 $1,500 $1,500 (288) (288) (32) (32) 17 17 $1,197 $1,197 Liquidity Credit Facility Commitments(3) Less: Borrowings Less: Letters of Credit Plus: Cash Liquidity (Credit Facility + Cash) 1. Equity valuation based on 262.0 million shares outstanding and a share price of $58.27 as of 2/24/2014. Enterprise value includes net debt. 2. Pro forma interest expense adjusted for $1,578 million net proceeds from IPO priced on 10/14/2013 and $1,000 million 5.375% Senior Notes priced on 10/24/2013 net of fees; assumes $525 million 9.375% Senior Notes, $25 million 9.00% Senior Note and $140 million 7.25% Senior Notes repaid at beginning of year along with residual cash used to repay bank debt. 3. Lender commitments under the facility reduced to $1.5 billion from $1.75 billion on 10/21/2013; commitments can be expanded to the full $2.0 billion borrowing base upon bank approval. 23
  • 25. HEALTH, SAFETY, ENVIRONMENT & COMMUNITY Protection Of Our People And The Environment Is An Antero Core Value Strong West Virginia Presence  Over 75% of Antero Marcellus employees and contract workers are West Virginia residents Keys to Execution  All Antero well completions use green completion units for completion flowback, essentially eliminating methane emissions (full compliance with EPA 2015 requirements) Central Fresh Water System & Water Recycling  Numerous sources of water – building central water system to source water for completion  Antero recycles over 95% of its flowback water with the remainder injected into disposal wells – no discharge to water treatment plants in West Virginia Natural Gas Powered Drilling Rigs  Nine of Antero’s contracted drilling rigs are currently running on natural gas Natural Gas Vehicles (NGV) the Year for 2013 in Harrison County, West Virginia “For outstanding corporate citizenship and community involvement”  Closed loop mud system – no mud pits  Protective liners or mats on all well pads in addition to berms Green Completion Units  Antero named Business of Pad Impact Mitigation  Antero supported the first natural gas fueling station in West Virginia which recently opened  Antero has a dozen NGV trucks and plans to continue to convert its truck fleet to NGV Safety & Environmental  Five company safety representatives and 45 safety consultants cover all material field operations 24/7 including drilling, completion, construction and pipelining  23-person company environmental staff plus outside consultants monitor all operations and perform baseline water well testing Local Presence  Land office in Ellenboro, WV  Recently moved into new 50,000 square foot district office in Bridgeport, WV  105 of Antero’s 258 employees are located in West Virginia and Ohio LEED Gold Headquarters Building  Antero’s new corporate headquarters in Denver has been LEED Gold Certified  Completion expected by spring of 2014  Antero representatives recently participated in a ribbon cutting with the Governor of West Virginia for the grand opening of the first natural gas fueling station in the state; Antero supported the station with volume commitments for its NGV truck fleet 24
  • 26. ANTERO KEY ATTRIBUTES 456,000 Net Acres in the Core Marcellus and Utica Shales “Triple Digit” Historical Production and Reserve Growth Low Cost Leader / High Return Projects Significant Takeaway and Processing Capacity Already in Place Clean Balance Sheet Supports High Growth Story “Forward Thinking” Management Team with a History of Success 25
  • 27. APPENDIX 26
  • 28. ANTERO FIRM TRANSPORTATION AND FIRM SALES Columbia Firm Sales #1 Firm Sales #2 Firm Sales #3 7/26/2009 – 9/30/2025 10/1/2011– 10/31/2019 10/1/2011 – 5/31/2017 1/1/2013 – 5/31/2022 Momentum III EQT Chicago Direct 9/1/2012 – 12/31/2021 8/1/2012 – 8/31/2021 4/1/2013 – 9/30/2021 MMBtu/d 1,800,000 1,600,000 1,400,000 1,200,000 1,000,000 800,000 600,000 400,000 200,000 - 27
  • 29. ANTERO UTICA SHALE WELLS – 24 HOUR IPS Well Name Yontz 1H Rubel 1H Gary 2H Rubel 3H Milligan 2H Rubel 2H Norman 1H Coal 3H Wayne 3HA Wayne 4H Milligan 3H Dollison 1H Milligan 1H Wayne 2H Miley 2H Miley 5HA County Monroe Monroe Monroe Monroe Noble Monroe Monroe Noble Noble Noble Noble Noble Noble Noble Noble Noble Average ‐ Ethane Recovery(1) Average ‐ Ethane Rejection(2) 1. 2. 24‐hr Peak Rate Gas Equivalent Rate Wellhead Gas Shrunk Gas (MMcfe/d) (MMcf/d) (MMcf/d) 53.3 38.9 33.9 47.5 31.1 25.9 43.5 28.9 24.2 42.6 28.4 23.7 40.2 17.2 13.5 37.4 24.8 20.7 37.1 26.1 22.3 35.3 15.1 11.8 35.1 14.7 11.6 34.2 14.2 11.2 32.1 15.4 12.1 27.5 12.5 10.2 25.8 10.6 8.3 25.5 10.9 8.5 22.4 8.6 6.7 20.2 7.7 6.0 35.0 28.1 19.1 19.1 15.7 18.5 NGL (Bbl/d) 3,177 3,391 3,053 3,003 2,361 2,635 2,419 2,063 2,018 1,907 2,111 1,488 1,461 1,503 1,172 1,090 2,178 819 Condensate % Total (Bbl/d) Liquids 52 36% 214 46% 162 44% 142 44% 2,087 68% 156 45% 45 40% 1,850 67% 1,905 67% 1,922 67% 1,228 62% 1,397 63% 1,442 68% 1,331 67% 1,450 70% 1,285 70% 1,042 1,042 58% 40% BTU 1161 1231 1224 1220 1276 1217 1186 1278 1272 1265 1276 1238 1276 1281 1278 1291 Lateral Length (Feet) 5,115 6,554 8,882 6,424 5,989 6,571 5,498 7,768 6,712 6,493 5,267 6,253 6,436 6,094 6,153 6,296 1248 1248 6,407 6,407 24-hour peak rates assume full ethane recovery (assuming typical ethane plant product recoveries of 85% to 90%) however Antero is currently rejecting ethane due to current market prices. Average of Antero’s first 16 core area wells, assuming ethane rejection. 28
  • 30. ANTERO UTICA SHALE WELLS – 30-DAY RATES  Antero’s wells have been producing against 1,100 psi line pressure due to lack of compression facilities − First 120 MMcf/d compressor station started up in late January 2014 Well Name Gary 2H Rubel 2H Rubel 3H Yontz 1H Norman 1H Rubel 1H Wayne 2H Wayne 3HA Wayne 4H Miley 2H Miley 5HA County Monroe Monroe Monroe Monroe Monroe Monroe Noble Noble Noble Noble Noble Average ‐ Ethane Rejection Average ‐ Ethane Recovery(1) 1. 30‐Day Rates ‐ Antero Core Area Gas Eq. Rate Wellhead Gas Shrunk Gas NGL (MMcfe/d) (MMcf/d) (MMcf/d) (Bbl/d) 29.7 24.6 23.1 1,023 19.2 15.9 15.0 625 18.7 15.6 14.7 623 17.0 15.2 14.6 392 16.4 14.3 13.6 461 14.0 11.5 10.8 501 12.1 6.5 6.0 367 11.0 6.1 5.6 354 9.2 5.2 4.7 284 9.0 3.8 3.5 213 5.9 2.7 2.5 161 14.7 17.9 Average of Antero’s first 11 core area wells, assuming ethane recovery. 11.0 11.0 10.4 9.2 455 1,189 Condensate % Total Estimated (Bbl/d) Liquids BTU 65 22% 1224 64 22% 1217 43 21% 1220 1 14% 1161 2 17% 1186 28 23% 1231 653 51% 1281 540 49% 1272 452 48% 1265 700 61% 1278 418 59% 1291 270 270 35% 53% 1239 1239 Lateral Length (Feet) 8,882 6,571 6,424 5,115 5,498 6,554 6,094 6,712 6,493 6,153 6,296 6,436 6,436 29
  • 31. CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY  40 year proved reserve life based on 2013E production  Reserve base provides significant exposure to liquids-rich projects – 3P reserves of over 2.2 BBbl of NGLs and condensate in ethane recovery mode; 33% liquids ETHANE REJECTION(1) ETHANE RECOVERY(1) Marcellus – 25.0 Tcfe Marcellus – 29.5 Tcfe Utica – 5.8 Tcfe Utica – 6.7 Tcfe Upper Devonian – 4.2 Tcfe Upper Devonian – 4.7 Tcfe 35.0 Tcfe 40.8 Tcfe Gas – 29.6 Tcf Gas – 27.4 Tcf Oil – 91 MMBbls Oil – 91 MMBbls NGLs – 811 MMBbls NGLs – 2,151 MMBbls 15% Liquids 33% 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. 30
  • 32. MARCELLUS SHALE RICH GAS – LIQUIDS AND PROCESSING UPGRADE  Marcellus Shale rich gas and highly-rich gas acreage provides a significant advantage in well economics – assuming $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current spot NGL pricing $/Wellhead Mcf(1)(2) ($/Mcf) +$4.13 Upgrade +$2.79 $9.00 $8.28 Upgrade $8.00 +$1.04 $7.00 $6.95 Upgrade NGLs (C3+) $3.92 $6.00 $5.19 $5.00 $4.15 NGLs (C3+) $1.30 Gas $4.15 NGLs (C3+) $2.93 Gas $3.90 $4.00 Condensate $0.16 Condensate $0.56 Gas $3.86 Gas $3.80 $3.00 $2.00 $1.00 (1076 BTU) (1109 BTU) (1119 BTU) 8% shrink 12% shrink 14% shrink $0.00 1050 BTU Dry Gas 1150 BTU Dry Gas 1250 BTU 1300 BTU Highly Rich Gas Highly Rich/ Condensate Current – Ethane Rejection 1. Assumes $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current NGL spot prices. 1.054 and 2.070 (ethane rejection) and 3.332 and 5.145 (ethane recovery) GPM s used, all processing costs, shrink and fuel included. No ethane takeaway available until Enterprise ethane pipeline is online (expected 1Q 2014). Ethane recovery well economics include fixed fee cost tariff on ATEX ethane pipeline. 2. NGL prices as of 2/3/2014 from IntercontinentalExchange. 31
  • 33. 2013 REALIZATIONS 2013 NATURAL GAS REALIZATIONS ($/MCF) TCO Dominion South NYMEX(1) TETCO Total 2013 % Sales 67% 22% 6% 5% 100% Average NYMEX Price $3.65 $3.65 $3.65 $3.65 $3.65 Average Differential(2) $(0.06) $(0.41) $(0.40) $(0.26) $(0.16) Average BTU Upgrade $0.42 $0.39 $0.39 $0.41 $0.42 Average Premium / (Discount) $0.37 $(0.01) − $0.15 $0.25 Average 2013 Realized Price $4.02 $3.64 $3.65 $3.80 $3.90 2013 NGL Y-GRADE (C3+) REALIZATIONS 2% 17% Propane (C3) Iso Butane (C4) 15% $0.72 Ethane (C2) 55% 11% $14.57 $23.49 Normal Butane Natural Gasoline $7.55 $6.27 Antero Barrel 1. NYMEX differential represents contractual deduct to NYMEX-based sales. 2. Includes firm sales. 3. Based on monthly prices through 12/31/2013 WTI. Total $52.61 per Bbl 54% of WTI(4) 32
  • 34. POSITIVE RATINGS MOMENTUM Moody’s / S&P Historical Credit Ratings Moody’s Upgrade Criteria S&P Upgrade Criteria “An upgrade could be considered if debt / average daily production is sustained below $20,000 per boe and debt / proved-developed reserves is sustained below $8.00 per boe. An upgrade would also be contingent on Antero maintaining unleveraged cash margins greater than $25.00 per boe and retained cash flow to debt over 40% as it builds out infrastructure needs to support production growth.” “We would consider a positive rating action if the company continued to convert its PUD reserves to proved developed reserves and improved profitability, while maintaining leverage below 3x.” - S&P Credit Research, October 2013 - Moody’s Credit Research, October 2013 Credit Rating (Moody’s / S&P) Baa3 / BBBBa1 / BB+ Ba2 / BB Ba3 / BBB1 / B+ B2 / B B3 / BCaa1 / CCC+ 9/1/2010 2/24/2011 5/27/2011 8/27/2011 Moody's 2/28/2012 ___________________________ 1. Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC. 11/28/2011 5/31/2012 S&P (1) 10/21/2013 2/18//2014 33
  • 35. ANTERO EBITDAX RECONCILIATION EBITDAX Reconciliation ($ in millions) Antero Resources LLC (12 Months Ended) 12/31/2012 12/31/2013 EBITDAX: Net income (loss) from continuing operations $225.3 $(24.2) Commodity derivative fair value (gains) losses (179.5) (491.7) 178.5 163.6 Net cash receipts on settled commodity derivatives instruments (Gain) loss on sale of assets Interest expense and other Loss on early extinguishment of debt (291.2) - 97.5 136.6 - 42.6 Provision (benefit) for income taxes 121.2 186.2 Depreciation, depletion, amortization and accretion 102.1 234.9 Impairment of unproved properties 12.1 10.9 Exploration expense 14.7 22.3 - 365.3 4.1 2.9 $284.7 $649.4 Net income (loss) from discontinued operations ($510.3) 5.3 Commodity derivative fair value (gains) losses (46.4) - Net cash receipts on settled commodity derivatives instruments 92.2 - (Gain) loss on sale of assets 795.9 (8.5) Stock compensation expense Other EBITDAX from continuing operations EBITDAX: Provision (benefit) for income taxes (272.6) 3.2 Depreciation, depletion, amortization and accretion 89.1 - Impairment of unproved properties 1.0 - Exploration expense 1.0 - EBITDAX from discontinued operations $149.6 - EBITDAX $434.3 $649.4 34
  • 36. CAUTIONARY NOTE Regarding Hydrocarbon Quantities The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates (collectively, “3P”). Antero has provided internally generated estimates for proved, probable and possible reserves in this presentation in accordance with SEC guidelines and definitions. The estimates of proved, probable and possible reserves as of December 31, 2013 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates are as of December 31, 2013, assuming 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, 2013. 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.  “Highly-rich/condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1250 BTU and 1300 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 1250 BTU in the Utica Shale.  “Rich gas” refers to gas having a heat content of between 1100 BTU to 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. 35