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Company Overview November 2013

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Company Overview November 2013

Company Overview November 2013

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  • 1. Company Overview November 2013
  • 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 in the Company’s Registration Statement on Form S-1 (File No. 333 – 189284) (the “Registration Statement”) with the U.S. Securities and Exchange Commission (the “SEC”) 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. – 20 Bcf/d projected by 2020(1) ● Antero has 28 Tcfe of 3P reserves in Marcellus and Utica Shales ● 566 MMcfe/d of average net production in 3Q 2013 including 7,900 Bbl/d of liquids Market Leading Growth ● 191% Appalachian production CAGR since 2010 ● Most active driller in Marcellus Shale – 15 rigs running ● Drilled 8 of the top 9 initial producers in the Utica Shale – 4 rigs running Industry Leading Capital Efficiency and Recycle Ratio ● Low development cost leader: $1.03/Mcfe(2) ● Industry leading growth-adjusted recycle ratio: 6.1x(2) ● Top quartile return on productive capital: 27% for 2013E Significant Emphasis on Takeaway and Liquids Processing ● 1.3 Bcf/d of processing capacity by 2014 and 20,000 Bbl/d of ethane takeaway by 2014 ● Liquids expected to grow from 8% of third quarter 2013 production due to focus on liquids-rich development Liquidity and Hedge Position Support High Growth Story ● ~$1.8 billion pro forma available liquidity with current $1.5 billion bank commitment(3) ● 1.1 Tcfe hedged through 2019 at average index prices of $4.71 / MMBtu and $98.50/Bbl ● Midstream MLP potential adds a low cost equity financing vehicle Outstanding Management Team ● Over 30 years as a team (over 20 years in unconventional) ● “Shale Pioneers” – early mover and driller of over 450 horizontal shale wells in the Barnett, Woodford, Marcellus and Utica Shales 1. Tudor Pickering Holt research report dated 9/3/2013. 2. Three year average through 2012; pro forma for Arkoma and Piceance divestitures. 3. See page 22 for the derivation of 9/30/2013 liquidity. 2
  • 4. PREMIER UNCONVENTIONAL RESOURCE PLATFORM TOTAL – 6/30/13 RESERVES(1) Assumes Ethane Rejection Net Proved Reserves(1) Net 3P Reserves(1) Pre-Tax 3P PV-10(1) 667 MMBbls 14% 566 MMcfe/d 7,900 Bbl/d 438,000 4,576 “Pure-Play” Appalachian-Focused Shale Company Reserves(1) Net Proved Net 3P Reserves (1) Pre-Tax 3P PV-10(1) 6.0 Tcfe 18.7 Tcfe $13,656 MM % Liquids – Net 3P 3Q 2013 Net Production Undrilled 3P Locations 6.3 Tcfe 27.7 Tcfe $19,100 MM Net 3P Liquids % Liquids – Net 3P 3Q 2013 Net Production(2) 3Q 2013 Net Liquids(2) Net Acres(3) Undrilled 3P Locations A MARCELLUS SHALE 15% 519 MMcfe/d 2,941 B UTICA SHALE – LIQUIDS RICH B D C 279 Bcfe 5.3 Tcfe $5,223 MM 19% 44 MMcfe/d 720 100% operated • Stable acreage base − Marcellus Shale: 49% HBP, with additional 29% 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 2013 and 2014 development drilling activities • Full scale development underway − 19 rigs currently operating UPPER DEVONIAN SHALE Net Proved Reserves(1) Net 3P Reserves (1) Pre-Tax 3P PV-10(1) % Liquids – Net 3P 3Q 2013 Net Production Undrilled 3P Locations 44 Bcfe 3.8 Tcfe $220 MM 6% 3 MMcfe/d 915 D UTICA SHALE – DRY GAS Net Acres(3) Net Resource Undrilled Locations Appalachia Rig Count vs. Peers(4) 20 15 Rigs C Net Proved Net 3P Reserves (1) Pre-Tax 3P PV-10(1) % Liquids – Net 3P 3Q 2013 Net Production Undrilled 3P Locations A Reserves(1) • 116,000 5.0 Tcfe 950 10 19 4 10 15 6 5 5 5 COG CNX RRC 0 Antero EQT Marcellus Shale 1. 2. 3. 4. Utica Shale Proved, probable, and possible reserves as of June 30, 2013, assuming ethane rejection using SEC methodology and strip 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 July 1, 2013 through September 30, 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. RigData, other industry sources as of 10/31/2013. 3
  • 5. STRONG TRACK RECORD OF GROWTH AVERAGE NET DAILY PRODUCTION (MMcfe/d) Woodford Piceance 600 Marcellus APPALACHIAN PRODUCTION (MMcfe/d) Utica Marcellus 566 44 Sold Woodford and Piceance 500 458 400 334 300 383 87 100 522 2006 2007 2008 2009 2010 2011 2012 NET PROVED SEC RESERVES (Bcfe) Woodford Piceance 1Q 2013 2Q 2013 3Q 2013 (2) Marcellus(3) 30 2010 2011 Woodford 6,282 5,017 4,929 5,000 0 Piceance 680 87 100 2007 2008 Marcellus 126 85 96 Utica 197 119 91 Economic Crisis 66 18 25 2009 3Q 2013 50 1,141 235 2006 2Q 2013 157 75 2,000 1Q 2013 175 150 3,231 3,000 2012 200 125 4,000 522 124 Utica 6,000 0 239 OPERATED GROSS WELLS SPUD 7,000 1,000 383 300 100 566 44 458 200 133 31 6 0 105 500 400 244 200 Utica 600 2010 2011 2012 6/30/2013 0 2006 2007 2008 2009 2010 2011 2012 2013E 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 mid-year 2013 proved reserves based on current SEC reserve methodology and SEC pricing and are audited by independent third-party engineers; excludes Arkoma Basin reserves which were sold on June 20, 2012 and Piceance Basin reserves which were sold on December 21, 2012. 3. Includes 44 Bcfe of Upper Devonian Shale proved reserves. 4
  • 6. MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW RISK, HIGH-RETURN GROWTH PROFILE 600 505 40% 400 58% 38% 20% 0% 800 673 Highly-Rich Gas/ Condensate Highly-Rich Gas 29% Rich Gas Locations Dry Gas 200 250% 200% ROR ROR 60% 777 93% 1000 1,000 Gross Locations 986 100% 80% UTICA WELL ECONOMICS(1) 208 220% 150% 250 198 177 194% 100% 200 137 150 100 114% 50% 0 0% ROR  66% of Marcellus locations are processable (1100-plus Btu) 50 40% Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Locations Gross Locations MARCELLUS WELL ECONOMICS(1) 0 Dry Gas ROR  75% of Utica locations are processable (1100-plus Btu) $ / MMBtu NYMEX (Gas) Large Inventory of Low Breakeven Projects(2) $6.75 $7.00 $6.00 986 $4.00 3 Yr Strip - $3.74/MMBtu(3) $3.00 $0.00 $3.26 1,450 $2.00 $1.00 $5.05 Locations $5.00 208 Locations 505 Locations Locations $0.00 $0.00 $0.00 $0.29 335 Locations $2.47 $2.50 $3.27 $3.34 $3.65 $3.66 $3.70 $3.75 $3.81 $4.13 $5.37 $5.49 $4.25 $2.94 $3.02 $1.35 $0.62 ` 1. Well economics based on 6/30/2013 3P reserves. 2. Source: Credit Suisse report dated 06/18/2013 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI. 3. 3-year STRIP as of 11/4/2013. 5
  • 7. LOW DEVELOPMENT COST DRIVES BEST-IN-CLASS RECYCLE RATIOS 3-Year All-in Development Costs ($/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. 6
  • 8. INTEGRATED MIDSTREAM INFRASTRUCTURE “Infrastructure-Ready” for Rapid, Large Scale Marcellus And Utica Development Programs 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 at the southern end of the Marcellus have seen much less basis widening and volatility than Pennsylvania producers Antero has sold ~76% of its year-to-date production at TCO at NYMEX less $0.07/MMbtu Antero Transport and Processing Leidy Basis to NYMEX Current 2015 -$0.69 -$1.21 Dom South Basis to NYMEX Current 2015 -$0.33 -$0.63 2013 2014 2015 Firm Transport (FT) (MMBtu/d) Firm Sales (MMBtu/d)(1) 542,000 143,000 882,000 230,000 1,152,000 220,000 Firm Processing Capacity (Mcf/d) Ethane FT (Bbl/d) 800,000 0 1,250,000 20,000 Chicago Basis to NYMEX Current 2015 +$0.12 -$0.12 1,250,000 20,000 Growing Processing Capacity TCO Basis to NYMEX Current 2015 -$0.08 -$0.32 Total Capacity 1,300 1,400 1,200 Seneca III (MMcf/d) 1,000 Seneca II 800 Seneca I CGTLA Basis to NYMEX Current 2015 -$0.04 -$0.06 Sherwood V Sherwood IV 600 400 Cadiz I Sherwood III YTD % of Production Sold Sherwood II 200 Appalachian Basis to NYMEX(2) 2013 TCO 0 76% TCO Dom South Sherwood I 18% Dom South TETCO M2 NYMEX Marcellus Sherwood II Sherwood III Sherwood IV Utica 1. 2. Sherwood I Cadiz I Seneca I Seneca II Seneca III Sherwood V 80,000 MMBtu/d and 70,000 MMbtu/d are related to firm transportation in 2014 and 2015, respectively. Basis data from Wells Fargo daily indications and various private quotes. 5% 2014 2015 2016 2017 2018 2019 $0.00 -$0.20 -$0.40 -$0.60 -$0.80 Leidy -$1.00 -$1.20 7
  • 9. LONG HAUL PIPELINE AND TRANSPORTATION NETWORK  Antero has the most firm transportation capacity of any Appalachian operator 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 -$0.69 -$1.21 Chicago Basis to NYMEX Current 2015 +$0.12 -$0.12 Dom South Basis to NYMEX Current 2015 -$0.33 -$0.63 (1) TCO Basis to NYMEX Current 2015 -$0.08 -$0.32 CGTLA Basis to NYMEX Current 2015 -$0.04 -$0.06 Mcf/d Appalachian Firm Transportation Capacity by Operator 1,400,000 1,200,000 1,000,000 800,000 600,000 400,000 200,000 0 (2) Antero CHK EQT TLM STO SWN RRC CNX WPX RDS COG APC NFG Source: Tudor Pickering & Holt research report dated 9/3/2013. Note: Antero firm transportation and firm sales positions listed by pipeline in colored-coded boxes. 1. See Page 26 for timing of firm transportation. 2. Antero firm transportation as of 9/25/2013; excludes 150 MMcf/d of firm sales. 8
  • 10. SIGNIFICANT LONG-TERM COMMODITY HEDGE POSITION NATURAL GAS HEDGES – CURRENT BBtu/d 800 Hedged NYMEX-Equivalent Price(1) Hedged Volume $5.25 $5.40 $5.40 $5.13 $4.40 600 $3.43 $7.00 NYMEX Strip (11/4/2013) $4.72 $4.74 $4.20 $4.41 $3.79 $3.58 400 $3.94 $4.07 477 548 480 583 730 540 98 2013 1. $5.00 $4.00 $3.00 $2.00 200 0 $6.00 2014 2015 2016 2017 2018 $1.00 2019 $0.00 In order to compare hedges across basins and commodities, hedged basin prices are converted by Antero to NYMEX-equivalent prices using current basis differentials in the over-the-counter futures market and 6:1 gas to oil ratio. Antero has hedged ~3,000 Bbl/d for 2013 and 2014, WTI hedges comprise ~1% of overall hedge book.  ~$1,100 million mark-to-market unrealized gain as of November 4, 2013.  1.1 Tcfe hedged from October 1, 2013 through year-end 2019. % HEDGE VOLUMES BY INDEX – 9/30/2013 2% Chicago TCO 17% NYMEX 34% 24% Dom South 23% CGTLA 9
  • 11. ASSET OVERVIEW 10
  • 12. PREMIER POSITION IN THE CORE OF THE MARCELLUS AND UTICA LIQUIDS-RICH FAIRWAYS ANTERO LIQUIDS-RICH UTICA SHALE Utica Shale Liquids-Rich Fairway 104,000 Net Acres 12 Horizontals Completed 4 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 309,000 Net Acres (Primarily Liquids-Rich Fairway) 215 Horizontals Completed 15 Rigs Currently Running Utica Shale Dry Gas Resource Underlies Marcellus Acreage Upper Devonian Shale Resource Overlies Marcellus Acreage 11 Source: Company presentations and press releases.
  • 13. WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT Antero Has Delineated And De-Risked Its Large Scale Acreage Position  100% operated  334,000 net acres in Southwestern Core – 49% HBP with additional 29% not expiring for 5+ years  217 horizontal wells completed and online – Laterals average 7,000’ – 100% drilling success rate  Net production of 522 MMcfe/d in 3Q 2013 including 6,100 Bbl/d of liquids MHR WEESE UNIT 4-well average 9.3 MMcfe/d 30-day rate (54% liquids) BLANCHE UNIT 2H: 18.1MMcfe/d IP (52% liquids) DOTSON UNIT 1H: 22.7 MMcfe/d IP 2H: 27.3 MMcfe/d IP (50% liquids) EQT 12 Recent Wells 11.6 MMcfe/d 30-day rate 44% Liquids CHK HADLEY UNIT 11.3 MMcfe/d IP (58% liquids) MOORE UNIT 1H: 13.0 MMcfe/d 2H: 13.0 MMcfe/d 30-day rates (41% liquids) Sherwood Processing Plant EQT PENN 15 UNIT 5-well average 9.3 MMcfe/d 30-day rate (51% liquids) 141 Horizontals Completed 10.1 Bcfe average EUR 8.3 MMcfe/d average 30-day rate 6,917’ average lateral length  2,941 future drilling locations (66% are processable)  Operating 15 drilling rigs including 4 shallow rigs  18.7 Tcfe of net 3P (15% liquids), includes 6.0 Tcfe of proved reserves CONSTABLE UNIT 1H: 19.3 MMcfe/d 30-day rate (51% liquids) PRUNTY UNIT 1H: 15.2 MMcfe/d 30-day rate (50% liquids) Highly-Rich/Condensate 54,000 Net Acres 505 Gross Locations Highly-Rich Gas 94,000 Net Acres 777 Gross Locations LITTLE TOM UNIT 1H: 16.0 MMcfe/d 30-day rate (41% liquids) Rich Gas 82,000 Net Acres 673 Gross Locations RUTH UNIT 1H: 22.9 MMcfe/d 30-day rate (38% liquids) Dry Gas 104,000 Net Acres 986 Gross Locations Source: Company presentations and press releases. Note: Rates assume ethane recovery. Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned. 12
  • 14. MARCELLUS – SIMPLE STRUCTURE  Several regional anticlines in core area − Predictable “layer cake” geology − No faults at Marcellus level • Over 1.5 million feet (280 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 7,000 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 RRC COG Big Moses Arches Fork Source: Company presentations. Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned. Wolf Summit E Benson Rhinestreet Tully Marcellus Onondaga 13
  • 15. ANTERO’S MARCELLUS SHALE TYPE CURVE SUPPORT  Antero has four years of production data, from over 210 operated horizontal wells, to support its 1.5 Bcf / 1,000’ of lateral type curve – DeGolyer & MacNaughton (D&M), Antero’s third-party reserve auditor, fully supports this type curve  Average 24-hour wellhead peak rate (IP) of 14.1 MMcf/d; 14.9 MMcfe/d assuming ethane rejection  Lack of faulting and contiguous acreage position allows for drilling of long laterals − Drives down costs per 1,000’ of lateral resulting in best-in-class development costs Marcellus Type Curve Support 10.0 Type Curve Cumulative Production (7,000' Lateral) 30-Day Avg. Rate 90-Day Avg. Rate 180-Day Avg. Rate One-Year Avg. Rate Two-Year Avg. Rate Three-Year Avg. Rate 14.1 217 8.0 209 6.3 180 5.4 158 4.2 109 3.0 56 2.3 18 Wellhead (MMcf/d) # of wells 8.0 14.0 12.0 10.0 8.0 6.0 6.0 4.0 4.0 2.0 Cumulative Bcf 12.0 Actual Production (Normalized to 7,000' Lateral) 24-Hour Peak Rate 14.0 MMcf/d (1) Type Curve (7,000' Lateral) 2.0 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) - 217 Wells $1.6 30 $1.4 25 12 8 MMcf/d 35 $MM / 1,000' $1.8 16 EUR, BCF 20 $1.2 $1.0 4 $0.6 2,000 20 15 10 $0.8 0 2,000 Average IP – 14.1 MMcf/d 5 4,000 6,000 8,000 Lateral Length, ft 10,000 4,000 1. All 217 Antero Marcellus wells normalized to time zero, production for each well normalized to 7,000’ lateral length. 6,000 8,000 Lateral length, ft 10,000 0 1st Production from All Wells 2009 - 2013 14
  • 16. MARCELLUS SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION Marcellus Well Economics and Locations(1)  6/30/2013 Strip Pricing & SEC Reserves 986 100% NGL(2) WTI ($/Bbl) ($/Bbl) 80% 93% 2013 $3.64 $95 $46.10 60% $3.91 $90 $44.89 2015 $4.14 $86 $43.86 2016 $4.28 $83 $43.34 20% 2017+ $4.46 $81 $43.34 1,000 1000 505 2014 0% ROR NYMEX ($/MMBtu) 777 800 673 600 60% 40% 400 38% 29% 200 Gross Locations Assumptions 0 Highly-Rich Gas/ Condensate Highly-Rich Gas 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 14.3 2.4 34% 7,000 350 $7.6 1.5 2.0 12.8 2.1 24% 7,000 350 $7.6 1.5 1.8 EUR (Bcfe): EUR (MMBoe): % Liquids: Lateral Length (ft): Stage Length (ft): Well Cost ($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: Locations RICH GAS LOCATIONS $17.0 Rich Gas Dry Gas ROR 11.5 1.9 11% 7,000 350 $7.6 1.5 1.6 HIGHLY RICH GAS $7.1 LOCATIONS 10.5 1.8 0% 7,000 350 $7.6 1.5 1.5 93% $0.62 1.2 $12.0 60% $0.69 1.6 38% $0.77 2.4 $5.3 29% $0.85 3.0 505 777 673 986 1. Well economics are based on 6/30/13 3P reserves. Includes gathering, compression and processing fees. 2. Pricing for a 1225 BTU y-grade barrel. 15
  • 17. ENHANCING MARCELLUS RECOVERIES – SHORTER STAGE LENGTHS (“SSL”) Antero’s Mid-Year 2013 3P Reserves Do Not Assume SSL Completions Antero’s First 15 Unconstrained SSL Wells – 24-hour Peak Rate 30.0 28.4 Average Antero SSL 24-hour Peak Rate: 18.1 MMcf/d 19.5 19.5 19.1 17.9 17.4 17.2 16.9 16.3 16.0 15.6 20.0 13.4 15.0 10.0 Average Antero 24-hour Peak Rate: 13.8 MMcf/d(1) 9.1 5.0 0.0 Normalized production increase for 13 SSL wells over 1.5 Bcf/1,000' Type Curve 10,000 1.5 Bcf/1,000' Type Curve 1,000 0 1. Excludes 15 SSL wells 2. Based on 13 relatively unconstrained wells. 31% Increase in IPs for SSL 22.9 22.2 25.0 MMcf/d  Since June 2013 Antero has implemented shorter stage lengths (SSL) in the Marcellus Shale – 22 SSL wells completed – 150’ to 225’ vs. 350’ stages previously  The 24-hour peak rate for Antero’s first 15 unconstrained SSL wells has averaged 18.1 MMcf/d or 31% higher than the overall average Marcellus IP of 13.8 MMcf/d (excluding SSL wells) – Other Marcellus Southwestern Core operators (EQT and Range) have announced 20% to 30% improvement in IPs and EURs  Early production ≈ 20% to 30% higher than 1.5 Bcf/1,000’ of lateral type curve(2) (90+ days aggregated for 13 unconstrained SSL wells)  Estimated 20% increase in well costs for SSL Antero SSL Wells Gas Production (Mcf/d) Enhancing Recoveries 30 60 Days From Peak Gas Unconstrained Normalized SSL Aggregated Production 90 1.5 Bcf/1,000' Type Curve 120 16
  • 18. EXCITING CORE UTICA SHALE POSITION DELIVERS CONDENSATE AND NGLS  100% operated  ~104,000 net acres in the core rich gas / condensate window – 20% HBP with additional 79% not expiring for 5+ years – 73%+ of acreage has rich gas processing potential  12 horizontal wells completed - all online − 100% drilling success rate  Net production of 44 MMcfe/d in 3Q 2013 including 1,800 Bbl/d of liquids − First production in early August 2013 with access to Cadiz pipeline and processing − Production constrained until completion of initial compressor stations with first compression expected in 4Q 2013  720 future drilling locations – Approximately 36% of EUR is liquids assuming ethane recovery  Operating 4 rigs including 1 shallow rig  5.3 Tcfe of net 3P (19% liquids), includes 279 Bcfe of proved reserves Utica Shale Industry Activity and 24-Hour Peak Rates(1) CHESAPEAKE 8 Wells Average 8.3 MMcfe/d (1,391 Boe/d) GULFPORT 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 Guernsey 1H, 2H, Noble 1H Average 7.9 MMcf/d + 1,192 Bbl/d NGL + 502 Bbl/d Oil CHESAPEAKE Buell #8H 9.5 MMcf/d + 1,425 Bbl/d liquids Cadiz Processing Plant GULFPORT Wagner 1-28H, Shugert 1-1H, 1-12H Average 21.0 MMcf/d + 2,270 Bbl/d NGL + 292 Bbl/d Oil GULFPORT McCort1-28H, 2-28H, Stutzman 1-14H Average 13.1 MMcf/d + 922 Bbl/d NGL + 21 Bbl/d Oil Seneca Processing Plant CNX/HESS Noble 1A, 16A Average 7.9 MMcf/d + 1,184 Bbl/d NGL + 389 Bbl/d Oil Utica Core Area WAYNE UNIT 3 wells average 10.4 MMcf/d + 1,809 Bbl/d NGL + 1,719 Bbl/d Oil RUBEL UNIT 3 wells average 23.4 MMcf/d + 3,010 Bbl/d NGL + 171 Bbl/d Oil MILEY UNIT 2 wells average 6.3 MMcf/d + 1,131 Bbl/d NGL + 1,368 Bbl/d Oil DOLLISON UNIT 1H Testing NORMAN UNIT 1H 22.3 MMcf/d + 2,419 Bbl/d NGL + 45 Bbl/d Oil YONTZ UNIT 1H 33.9 MMcf/d + 3,177 Bbl/d NGL + 52 Bbl/d Oil GARY UNIT 1H 24.2 MMcf/d + 3,053 Bbl/d NGL + 162 Bbl/d Oil Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are owned. 1. In some cases, 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. 17
  • 19. ANTERO HAS MOST OF THE TOP UTICA IPS  Antero has 8 of the top 9 Utica 24-hour peak rates (IPs) announced to date  Liquids content ranges from 40%-70% (assumes ethane recovery) in the liquids-rich window  Core located in Noble, Monroe, Guernsey, Belmont and Harrison Counties, Ohio − Actual core is a subset of these counties and ties to Antero’s geologic model Core 2,000 to 9,000 10,000 Boe/d IPs 9,000 8,000 7,000 6,000 Boe/d  Completed wells represent some of the best 24-hour peak rates of any shale play in North America – 3,000 to 9,000 Boe/d per well in the core area – Excellent reservoir pressure with gradients in the 0.7 psi/ft range UTICA IPs 5,000 Tier 1 4,000 1,000 to 2,000 Boe/d IPs 3,000 2,000 1,000 0 Antero Utica Wells Source: Antero, press releases and company presentations. 3rd Party Core Utica Wells 3rd Party Non-Core Utica Wells 18
  • 20. UTICA WELL RESULTS SUPPORT EUR REGIMES  Antero’s acreage position is “blocked-up” compared to other operators in the Utica core  EUR regimes are well-supported by Antero and third-party results Highly-Rich/Cond 34,000 Net Acres 208 Locations Note: Antero acreage position reflects townships in which greater than 3,000 net acres are owned. Highly-Rich Gas 19,000 Net Acres 198 Locations Rich Gas 25,000 Net Acres 137 Locations Dry Gas 26,000 Net Acres 177 Locations 19
  • 21. UTICA SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION Utica Well Economics and Locations(1)  6/30/2013 Strip Pricing & SEC Reserves 250% WTI ($/Bbl) NGL(2) ($/Bbl) 200% 2013 $3.64 $95 $50.24 2014 $3.91 $90 $48.78 2015 $4.14 $86 $47.43 2016 $4.28 $83 $46.72 $4.46 $81 $46.72 0% 200 50% 2017+ 198 150% ROR NYMEX ($/MMBtu) 250 208 220% 177 194% 150 114% 100% 137 100 50 40% Highly-Rich Gas/ Condensate Highly-Rich Gas Locations Rich Gas Dry Gas Gross 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 1050 13.7 2.3 35% 7,000 250 $11.3 1.5 2.0 19.9 3.3 26% 7,000 250 $11.3 2.4 2.8 18.0 3.0 16% 7,000 250 $11.3 2.4 2.6 15.3 2.5 0% 7,000 250 $11.3 2.2 2.2 $20.8 220% $1.02 0.7 $28.1 194% $0.70 0.7 114% $0.78 1.0 $10.3 40% $0.92 2.3 208 198 137 177 EUR (Bcfe): EUR (MMBoe): % Liquids Lateral Length (ft): Stage Length (ft): Well Cost ($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 6/30/13 3P reserves. Includes gathering, compression and processing fees. 2. Pricing for a 1225 BTU y-grade barrel. 3. Gross 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content. HIGHLY RICH GAS $19.9 LOCATIONS 20
  • 22. SIGNIFICANT MIDSTREAM INFRASTRUCTURE POSITION  Antero estimated YE 2013 total capital investment in midstream ≈ $980 million – Includes gathering lines, compressor stations and water handling infrastructure  Proprietary water sourcing and distribution system − Improves operational efficiency and reduces water truck traffic − Cost savings of up to $600,000 $800,000 / well − One of the benefits of a consolidated acreage position  Qualifies for midstream MLP Midstream Infrastructure(1) Marcellus Shale Utica Shale Total YE 2013 Estimated Total Gathering / Compression Capex ($MM) Gathering Pipelines (Miles) Compressor Stations $510 83 4 $220 20 0 $200 71 17 $50 37 2 $710 $270 Ohio River Withdrawal December 2013 completion date $250 108 19 YE 2013 Estimated Total Midstream ($MM) Marcellus Shale $730 103 4 YE 2013 Estimated Total Water System Capex ($MM) Water Pipeline (Miles) Water Storage Facilities Utica Shale $980 1. Represents inception to date actuals as of 9/30/2013 and remaining 2013 budget. 21
  • 23. PRO FORMA CAPITALIZATION CAPITALIZATION Cash Senior Secured Revolving Credit Facility 9.375% Senior Notes Due 2017 9.00% Senior Note 9/30/2013 (PF IPO) 9/30/2013 (1) (PF Bond Offering) 9/30/2013(3) $12 ($ in millions) $77 $339 1,513 – – 525 525 – 25 25 – 7.25% Senior Notes Due 2019 400 400 260 6.00% Senior Notes Due 2020 525 525 525 – – 1,000 5.375% Senior Notes Due 2021 Net Unamortized Premium 8 8 6 Total Debt $2,996 $1,483 $1,791 Net Debt $2,984 $1,406 $1,452 Shareholders' Equity $1,875 $3,453 $3,427 Net Book Capitalization $4,859 $4,859 $4,879 N/M $15,811 $15,857 $521 $521 $521 Net Market Capitalization(1) Financial & Operating Statistics LTM EBITDAX Proved Reserves (Bcfe) (6/30/2013) 6,282 6,282 6,282 Proved Developed Reserves (Bcfe) (6/30/2013) 1,445 1,445 1,445 Credit Statistics Net Debt / LTM EBITDAX 5.7x 2.7x 2.8x LTM EBITDAX / Interest Expense 4.1x 4.7x 5.1x Net Debt / Net Book Capitalization 61.4% 28.9% 29.8% N/M 8.9% 9.2% Net Debt / Proved Developed Reserves ($/Mcfe) $2.07 $0.97 $1.01 Net Debt / Proved Reserves ($/Mcfe) $0.48 $0.22 $0.23 Credit Facility Commitments(2) $1,750 $1,500 $1,500 Less: Borrowings (1,513) – – (32) (32) (32) Net Debt / Net Market Capitalization Liquidity Less: Letters of Credit Plus: Cash Liquidity (Credit Facility + Cash) 12 77 339 $217 $1,545 $1,807 1. Initial public offering priced on 10/10/2013; equity valuation based on 262.0 million shares outstanding and a share price of $54.98 as of 11/4/2013. 2. 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. 3. $1,000 million 5.375% Senior Notes priced on 10/24/2013, $525 million 9.375% Senior Notes called, $25 million 9.00% Senior Note redeemed, 35% of $400 million 7.25% Senior Notes redeemed and transaction fees. 22
  • 24. 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 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  All Antero well completions use green completion units for completion flowback, essentially eliminating methane emissions (full compliance with EPA 2015 requirements) Central 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  Five of Antero’s contracted drilling rigs are running on natural gas and the majority of its rigs should run on natural gas by year-end 2013 Natural Gas Vehicles (NGV)  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 40 safety consultants cover all material field operations 24/7 including drilling, completion, construction and pipelining  10-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  81 of Antero’s 218 employees are located in West Virginia and Ohio LEED Gold Headquarters Building  Antero’s new corporate headquarters in Denver, Colorado 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 23
  • 25. WHY INVEST IN ANTERO? Over 400,000 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 24
  • 26. APPENDIX 25 25
  • 27. 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 1,400,000 1,200,000 1,000,000 800,000 600,000 400,000 200,000 - 26
  • 28. UTICA SHALE WELLS – ANTERO INITIAL RESULTS 24‐hr Peak Rate Oil Eq. Rate Wellhead Gas Shrunk Gas (MMcf/d) (MMcf/d) (Boe/d)(1) 8,879 38.9 33.9 7,917 31.1 25.9 7,246 28.9 24.2 BTU 1161 1231 1224 44% 1220 6,424 156 45 1,905 1,922 1,331 1,450 1,285 653 45% 40% 67% 67% 67% 70% 70% 79% 1217 1186 1272 1265 1281 1278 1291 1316 6,571 5,498 6,712 6,493 6,094 6,153 6,296 7,159 776 776 56% 40% 1245 1245 6,496 6,496 Well Name Yontz 1H Rubel 1H Gary 2H County Monroe Monroe Monroe Rubel 3H Monroe 7,097 28.4 23.7 3,003 142 Rubel 2H Norman 1H Wayne 3HA Wayne 4H Wayne 2H Miley 2H Miley 5HA Sanford Monroe Monroe Noble Noble Noble Noble Noble Noble 6,241 6,181 5,852 5,698 4,257 3,740 3,369 1,148 24.8 26.1 14.7 14.2 10.9 8.6 7.7 1.8 20.7 22.3 11.6 11.2 8.5 6.7 6.0 1.4 2,635 2,419 2,018 1,907 1,503 1,172 1,090 256 5,635 4,677 19.7 19.7 16.3 18.5 2,135 819 Average ‐ Ethane Recovery Average ‐ Ethane Rejection(2) 1. 2. NGL (Bbl/d) 3,177 3,391 3,053 Lateral Length (Feet) 5,115 6,554 8,882 Condensate % Total (Bbl/d) Liquids 52 36% 214 46% 162 44% 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 12 wells, assuming ethane rejection. 27
  • 29. CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY  26 year proved reserve life from current production annualized  Reserve base provides significant exposure to liquids-rich projects – 3P reserves of over 1.6 BBbl of NGLs and condensate in ethane recovery mode; 31% liquids ETHANE REJECTION(1) ETHANE RECOVERY(1) Marcellus – 18.7 Tcfe Marcellus – 21.8 Tcfe Utica – 5.3 Tcfe Utica – 6.1 Tcfe Upper Devonian – 3.8 Tcfe Upper Devonian – 4.2 Tcfe 27.7 Tcfe 32.1 Tcfe Gas – 23.8 Tcf Gas – 22.2 Tcf Oil – 71 MMBbls Oil – 71 MMBbls NGLs – 595 MMBbls NGLs – 1,580 MMBbls 14% Liquids 31% 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. 28
  • 30. 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 correlation  Upgrade analysis demonstrates that ethane recovery is not economic at current ethane price $/Wellhead Mcf(1) ($/Mcf) $9.00 +$2.45 $7.94 Upgrade $8.00 $6.84 +$0.77 $7.00 NGLs (C3+) $3.23 Upgrade NGLs (C3+) $2.39 $6.00 $5.00 +$3.55 Upgrade $5.16 $4.39 NGLs (C3+) $1.04 Gas $4.39 Gas $4.12 Condensate $0.37 Condensate $0.70 Gas $4.07 $4.00 Gas $4.00 $3.00 $2.00 $1.00 (1073 BTU) (1103 BTU) (1110 BTU) 8% shrink 12% shrink 14% shrink $0.00 1050 BTU Dry Gas 1150 BTU 1250 BTU 1300 BTU Rich Gas 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. 29
  • 31. 2013 YEAR-TO-DATE REALIZATIONS 9/30/2013 YTD NATURAL GAS REALIZATIONS YTD % Sales 76% 18% 5% 1% 100% TCO Dominion South NYMEX(1) TETCO Total Average Average NYMEX Price Differential(2) $3.68 $(0.07) $3.68 $(0.39) $3.68 $(0.40) $3.68 $(0.34) $3.68 $(0.15) Average BTU Upgrade $0.44 $0.42 $0.41 $0.47 $0.44 Average YTD Realized Price $4.05 $3.71 $3.69 $3.80 $3.97 9/30/2013 YTD NGL Y-GRADE (C3+) REALIZATIONS 1% $0.59 Ethane (C2) 17% Propane (C3) $8.69 Iso Butane (C4) 16% 55% $27.69 Normal Butane Natural Gasoline $8.04 11% Antero Barrel 1. NYMEX differential represents contractual deduct to NYMEX-based sales. 2. Includes firm sales. 3. Based on monthly prices through 9/30/2013 WTI. $5.72 Total $50.73 per Bbl 48% of WTI(3) 30
  • 32. ANTERO EBITDAX RECONCILIATION EBITDAX Reconciliation (9 Months Ended) ($ in thousands) Antero Resources LLC 9/30/12 9/30/2013 EBITDAX: Net income (loss) from continuing operations $140,431 $200,990 Commodity derivative fair value (gains) losses (52,210) (285,510) Net cash receipts on settled commodity derivatives instruments 141,506 109,311 (Gain) loss on sale of assets (291,190) - Interest expense and other 71,046 100,840 Provision (benefit) for income taxes 108,525 120,695 Depreciation, depletion, amortization and accretion 65,360 159,447 Impairment of unproved properties 4,019 9,564 Exploration expense 7,912 17,034 Other EBITDAX from continuing operations 2,992 1,820 $198,391 $434,191 EBITDAX: Net income (loss) from discontinued operations ($418,465) Commodity derivative fair value (gains) losses (46,358) Net cash receipts on settled commodity derivatives instruments 79,736 (Gain) loss on sale of assets 427,232 Provision (benefit) for income taxes 4,085 Depreciation, depletion, amortization and accretion 77,654 Impairment of unproved properties Exploration expense 962 507 EBITDAX from discontinued operations $125,353 EBITDAX $323,744 $434,191 31
  • 33. 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 June 30, 2013 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates are as of June 30, 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 June 30, 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. 32

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