Company Overview September 2013

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Company Overview September 2013

Company Overview September 2013

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  • 1. September 2013 Company Overview
  • 2. 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 LLC and its subsidiaries (collectively, the “Company”) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include 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 filings with the SEC. We caution 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 “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012. 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. Forward-Looking Statements 1
  • 3. Antero Resources Snapshot • Private E&P company headquartered in Denver, Colorado – extensive shale experience − Drilled and operated over 450 horizontal shale wells in Barnett, Woodford, Marcellus and Utica Shales • Appalachian Shale-Focused – a “pure play” company with upstream and midstream assets − Marcellus Shale: 328,000 net acres all located in the Southwestern Core area, 195 horizontal wells completed − Utica Shale: 101,000 net acres all located in the Core of the play, 11 horizontal wells completed − Upper Devonian Shale: 170,000 net acres (overlying Marcellus Shale), 2 horizontal wells completed • High production growth – Appalachian production has increased 115% year-over-year to 458 MMcfe/d net for 2Q 2013, including 3,300 Bbl/d of liquids − Estimated August 2013 net production averaged 590 MMcfe/d including 9,000 Bbl/d of liquids − Current net production is 680 MMcfe/d including 13,500 Bbl/d of liquids, with an additional 115 MMcfe/d of net production including 4,300 Bbl/d of liquids constrained/shut-in waiting on pipeline, compression or processing • Large, low risk drilling inventory – Over 4,500 horizontal drilling locations will continue to feed high growth in existing 6.3 Tcfe(1) proved reserve base as of June 30, 2013 (assuming ethane rejection) • Low cost leader – $1.03/Mcfe 3-year pro forma development cost calculated using 2012 J.P. Morgan methodology(2) − $0.90/Mcfe estimated net future development cost in 6/30/2013 3P reserve base (assuming ethane rejection) • Rapidly growing liquids exposure – 12% by production volume today, forecast to grow to ~20% by 2014 assuming ethane rejection (~40% liquids exposure if assume ethane recovery in 2014 and beyond) • Large long-term hedge position – 1,024 Bcfe hedged at $5.11/MMBtu NYMEX-equivalent(3) through 2019 • Infrastructure emphasis – Gathering, compression and processing infrastructure either in place or committed and underway – well positioned in southern portion of Marcellus and Utica Shale plays for access to gas takeaway • Strong liquidity to fuel low cost growth – ~$1.0 billion(4) of undrawn borrowing base capacity as of June 30, 2013 2 ___________________________ 1. 6/30/2013 SEC reserves assuming ethane rejection using a price deck of $3.43/MMBtu for Appalachia. WTI SEC price averaged $91.65/Bbl. Reserves audited by independent third-party engineers DeGolyger & MacNaughton using SEC reserve methodology and pricing. 2. Source: Proved developed F&D research report prepared by J.P. Morgan dated 7/22/2013. Includes total drilling and completion costs but excludes land and acquisition costs for all companies. 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. Calculated by Antero using J.P. Morgan methodology; Marcellus and Utica only. 3. 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. 4. Lender commitments under the facility are $1.75 billion which can be expanded to the full $2.0 billion borrowing base. Undrawn capacity as of 6/30/2013.
  • 4. Appalachia Total – SEC Reserves ___________________________ 1. 6/30/2013 SEC reserves assuming ethane rejection and using a price deck of $3.43/MMBtu for Appalachia. WTI SEC price averaged $91.65/Bbl. Reserves prepared internally using SEC reserve methodology and pricing and audited by independent third-party engineers DeGolyer & MacNaughton. 2. See note on page 38 for 3P definition. 3. Includes hedge PV-10 value of $944 million. 4. All net acres allocated to the Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as formations attributable to the same leases. Marcellus Shale Low Cost Liquids-Rich Reserve Base SEC Proved Reserves(1) 5,959 Bcfe Net 3P Gas Equivalent(1,2) 18,714 Bcfe Net 3P Liquids(1,2) 465 MMBbls % Liquids – Net 3P 15% 2Q 2013 Net Production 453 MMcfe/d Net Acreage 328,000 Undrilled Locations 2,941 SEC Proved Reserves(1) 6.3 Tcfe Net 3P Gas Equivalent(1,2) 27.7 Tcfe Net 3P Liquids(1,2) 667 MMBbls % Liquids – Net 3P 14% Proved Developed PV-10(3) $3.0 Billion Proved PV-10(3) $5.4 Billion 2Q 2013 Net Production 458 MMcfe/d Net Acreage(4) 429,000 Utica Shale SEC Proved Reserves(1) 279 Bcfe Net 3P Gas Equivalent(1,2) 5,254 Bcfe Net 3P Liquids(1,2) 164 MMBbls % Liquids – Net 3P 19% 2Q 2013 Net Production 1 MMcfe/d Net Acreage 101,000 Undrilled Locations 720 Upper Devonian Shale SEC Proved Reserves(1) 44 Bcfe Net 3P Gas Equivalent(1,2) 3,780 Bcfe Net 3P Liquids(1,2) 38 MMBbls % Liquids – Net 3P 6% 2Q 2013 Net Production 4 MMcfe/d Net Acreage(4) 170,000 Undrilled Locations 915 3 ● Antero increased Appalachian proved reserves by 44% at mid-year 2013, assuming ethane recovery, and 47% assuming ethane rejection, from year-end 2012
  • 5. Marcellus, 18.7 Tcfe Utica, 5.3 Tcfe Upper Devonian, 3.8 Tcfe • Antero’s liquids-rich position provides significant upside to improving NGL pricing – 3P reserves of over 1.6 BBbls of NGLs and condensate assuming ethane recovery mode – 31% liquids Significant Ethane Optionality Ethane Rejection(1) Ethane Recovery(1) Gas, 23.8 Tcf Oil, 71 MMBbls NGLs, 595 MMBbls Gas, 22.2 Tcf Oil, 71 MMBbls NGLs, 1,580 MMBbls 27.7 Tcfe 32.1 Tcfe 14% Liquids 31% Liquids ___________________________ 1. Ethane rejection occurs when ethane is left in the wellhead gas stream when 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. 4 Marcellus, 21.8 Tcfe Utica, 6.1 Tcfe Upper Devonian, 4.2 Tcfe
  • 6. Strong Track Record of Growth ___________________________ 1. Proved reserves for 2006, 2007 and 2008 represent previously effective SEC methodology. 2009, 2010, 2011, 2012 and 6/30/2013 proved reserves based on current SEC reserve methodology and pricing and audited by independent third-party engineers. 2012 excludes Arkoma Basin reserves which were sold on June 29, 2012 and Piceance Basin reserves which were sold on December 21, 2012. Marcellus includes Upper Devonian Shale proved reserves. 2. CAGR = Compound Annual Growth Rate. Average Net Daily Production Net Proved SEC Reserves (1) Appalachia Production Operated Wells Spud 6 31 87 105 133 244 87 235 680 1,141 3,231 5,017 85 96 126 18 66 91Economic Crisis 119 5 334 4,929 156 21 458 2Q 2013 6,282 30 124 239 458 1Q 2013 383 383
  • 7. $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 Range Cabot EQT SMEnergy Noble Cimarex Southwestern Pioneer Concho Devon Chesapeake EOG Newfield 0% 20% 40% 60% 80% 100% Industry Leading Finding Costs Industry 3-Year All-in Finding Costs Through 2012(1)(2) 3‐Year Comp Median = $2.75/Mcfe(3) • Based on the Howard Weil 2012 F&D Cost Study, Antero had the lowest three-year average all-in finding cost through 2012 of $0.48/Mcfe $/Mcfe Antero ___________________________ 1. Source: Howard Weil 2012 Finding & Development Cost Study. 2. Antero finding costs calculated over 3 years using 12/31/2012 SEC reserves, including Arkoma, Fayetteville and Piceance. Reserves were audited by DeGolyer & MacNaughton (Appalachia, Arkoma and Fayetteville) and Ryder Scott (Piceance). Antero % Gas Reserves reflects MY 2013 proved reserves assuming ethane rejection. 3. Median calculated for comparable company set used in this graph; excludes Antero. ● Includes all drilling, land and acquisition expenditures - Most direct Antero comparables 6 % Gas Proved Reserves $0.48 Marcellus Producers $0.84 $1.02 $1.31
  • 8. $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 Cabot Range Southwestern EQT Ultra Chesapeake Devon Concho Newfield Pioneer Cimarex EOG SMEnergy Noble 0% 20% 40% 60% 80% 100% $1.03 $1.14 $1.41 $1.57 $1.71 Most-direct Antero comparables___________________________ 1. Source: Proved developed F&D research report prepared by J.P. Morgan Research dated 7/22/2013. Includes all total drilling and completion costs but excludes land and acquisition costs for all companies. Defined as total drilling and completion capital expenditures for the period divided by PDP and PDNP volumes after adding back production for the period. Antero % Gas Reserves calculated from 6/30/2013 proved reserves. 2. Median calculated for comparable company set used in this graph; excludes Antero. 3. Calculated by Antero using J.P. Morgan methodology – pro forma for divestiture of Arkoma and Piceance properties. 4. Calculated by Antero using J.P. Morgan methodology. Industry 3-Year Development Costs Through 2012(1) AnteroPF(3) $/Mcfe ● Per Mcfe development cost excluding land is a better measure of capital efficiency than finding costs − Antero was the leader in 3-year development costs through 2012 Industry Leading Development Costs 7 Antero(4) 3‐Year Comp Median = $3.04(2) % Gas Proved Reserves • Based on the J.P. Morgan proved developed F&D methodology, Antero ranks as the lowest cost developer with a three-year average pro forma development cost of $1.03/Mcfe
  • 9. ● Antero expects to realize approximately $771 million(1) of hedge gains over the next seven years from its current 1,024 Bcfe hedge book which averages $5.11/MMBtu NYMEX-equivalent, assuming current strip prices − Protects future cash flow thereby supporting drilling plans and production growth Current Antero Hedge Position – July 1, 2013 through 2019(2)Current Antero Hedge Position – July 1, 2013 through 2019(2) Natural Gas Swaps Hedged Volume (MMBtu/d) NYMEX-Equivalent Price ($/MMBtu)(2) 2013 470,270 $5.25 2014 398,000 $5.93 2015 390,000 $5.69 2016 522,500 $5.23 2017 640,000 $4.41 2018 530,000 $4.73 2019 87,500 $4.75 ___________________________ 1. Undiscounted value based on STRIP natural gas prices as of August 30, 2013. 2. Virtually all hedges are fixed price swaps, hedged to the basin. Basin prices are converted by Antero to NYMEX-equivalent prices using current basis differentials in the over-the-counter futures market and a gas to oil conversion ration of 6:1. Strong Hedge Position 8 $91 $206 $217 $182 $24 $52 $- $62 $(50) $- $50 $100 $150 $200 $250 2013 2014 2015 2016 2017 2018 2019 $MM Projected Annual Hedging Gains (1)(2) Realized Gains Unrealized Gains $154
  • 10. 9 Asset Overview 9
  • 11. Appalachian Basin – Overview 10 Antero Marcellus SW PA 25,000 Net Acres 2 horizontal wells completed Antero Marcellus NW WV 303,000 Net Acres 193 horizontal wells completed 15 rigs running Southwestern and Northeastern Core Areas Marcellus Rich Gas Window in Southwestern Core Upper Devonian Shale Resource Overlies Antero Marcellus Acreage Antero Utica OH 101,000 Net Acres 11 horizontal wells completed 4 rigs running Utica Liquids Rich Fairway Source: Company presentations and press releases. Utica Core Area
  • 12. ● 328,000 net acres of leasehold in Southwestern Core of the Marcellus play – 52% HBP with additional 26% not expiring for 5-plus years – Over 80% of acreage has rich gas processing potential ● 100% operated by Antero ● 6.0 Tcfe of proved reserves; 18.7 Tcfe of 3P reserves ● 534 MMcfe/d net operated production estimated for August 2013 including 6,900 Bbl/d of liquids – 585 MMcfe/d of estimated current net production including 8,500 Bbl/d of liquids (including Upper Devonian Shale) ● Operating 15 drilling rigs currently and two frac crews 24/7 ● Antero has completed 195 consistently strong horizontal wells, 193 of which are online – Demonstrated ability to drill wells with long laterals 7,000 ft + in less than 30 days – 100% drilling success rate Fully Integrated ● Sherwood I (running at full capacity) and Sherwood II processing plants currently on line – 400 MMcf/d capacity fully dedicated to Antero – 200 MMcf/d Sherwood III processing plant expected to go on line in 4Q 2013 with 200 MMcf/d Sherwood IV expected in 2Q 2014 ● 1,300,000 MMBtu/d of long-haul firm transportation or firm sales secured – well positioned in southern portion of play − 530,000 MMBtu/d of back-haul firm transportation to Gulf Coast ● Committed to 20,000 Bbl/d ethane takeaway capacity on Enterprise ATEX pipeline to Mont Belvieu expected to be in service 1Q 2014 Antero Marcellus Shale SummarySummary 11
  • 13. Large Scale Position in Marcellus Core ● Antero has delineated and de-risked a large scale acreage position in the Southwestern Core of the Marcellus Shale in northern West Virginia – currently building more infrastructure to process highly rich gas Sherwood Processing Plant Webley Fork 1H: 13.3 MMcfe/d 30-day rate Little Tom 1H: 16.0 MMcfe/d 30-day rate Valentine Unit 1H: 5,232 Boe/d IP (50% Liquids) 2H: 3,726 Boe/d IP (50% Liquids) Moore Unit 1H: 21.5 MMcfe/d 30-day rate 2H: 20.5 MMcfe/d 30-day rate Dry Gas 65,000 Net Acres 588 Gross Locations Rich Gas 157,000 Net Acres 1,430 Gross Locations Highly Rich Gas 106,000 Net Acres 923 Gross Locations Dotson Unit 1H: 3,780 Boe/d IP (50% Liquids) 2H:4,547 Boe/d IP (50% Liquids) Constable Unit 1H: 5,257 Boe/d IP (51% Liquids) Source: Company presentations and press releases. Note: All IPs are 24-hour peak rate; Boe/d IPs assume processing and full ethane recovery. 12 Cleta Unit 1H: 15.9 MMcfe/d 30-day rate 2H: 17.0 MMcfe/d 30-day rate Triad Spencer Unit 4 wells averaged 1,550 Boe/d 30-day rate (54% Liquids) CHK Hadley Unit 1,884 Boe/d IP (58% Liquids) EQT PEN 15 Unit 5 wells averaged 1,553 Boe/d 30-day rate (51% Liquids) 141 Horizontals Completed 10.1 Bcfe average EUR 8.3 MMcfe/d average 30-day rate 6,917’ avg lateral length Prunty Unit 1H: 3,205 Boe/d IP (50% Liquids) Blanche Unit 2H:3,019 Boe/d IP (52% Liquids)
  • 14. 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 Dec-09 Feb-10 Apr-10 Jun-10 Aug-10 Oct-10 Dec-10 Feb-11 Apr-11 Jun-11 Aug-11 Oct-11 Dec-11 Feb-12 Apr-12 Jun-12 Aug-12 Oct-12 Dec-12 Feb-13 Apr-13 Jun-13 Aug-13 Mcf/d Gross Mcfd NET MCFD Strong Marcellus Production Growth Antero Gross Operated Marcellus Production 13 Bobcat Lateral online September 2010 Jarvisville Lateral online June 2011 Tichenal Lateral online September 2011 Shift to pad development drilling Tichenal Compressor repairs Dec 2012 Infrastructure Delays
  • 15. 14 ● Antero has over 3-½ years of production history to support its 1.5 Bcf/1,000’ of lateral recovery assumption as demonstrated by the graph and table below − DeGolyer & MacNaughton (D&M), Antero’s third party reserve auditor, supports this type curve ● Antero’s average 24-hour peak rate is 13.9 MMcf/d in the Marcellus 24-hour peak(3) 30-day avg. rate 90-day avg. rate 180-day avg. rate One-year avg. rate Two-year avg. rate Three-year avg. rate MMcf/d 13.9 7.9 6.2 5.3 4.0 2.9 2.3 # of wells 193 177 171 134 95 49 15 Antero Marcellus Type Curve Support ___________________________ Note: Type curve reflects pre-processed wellhead production. 1. Wells normalized to time-zero; production for each well normalized to 7,000’ lateral length. 2. Actual wellhead IPs, not normalized. 3. Excludes two wells that are shut-in and waiting on infrastructure. 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 12.0 13.0 14.0 15.0 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 12.0 13.0 14.0 15.0 0 1 2 3 4 5 6 7 8 9 10 CumulativeBcf MMcf/d Production Year Area 1 Type Curve (7,000' Lateral) Area 1 Actual Production (Normalized to 7,000' Lateral) Area 1 Type Curve Cumulative Production (7,000' Lateral) Antero Marcellus 1.5 Bcf/1,000’ Type Curve(1)Antero Marcellus 1.5 Bcf/1,000’ Type Curve(1) Antero Marcellus 24-hr Wellhead IPs(2)Antero Marcellus 24-hr Wellhead IPs(2) 0 5 10 15 20 25 30 35 MMcf/d 1st Production From All Wells 2009 - 2013 Average IP 13.9 MMcf/d
  • 16. - 100 200 300 400 500 600 700 800 0% 50% 100% 150% 200% 250% 300% 950 1000 1050 1100 1150 1200 1250 1300 1350 ROR DRY BTU Marcellus Processing Economics ___________________________ 1. Assumes 85% NRI and NGL price of 40% of WTI for 1200 BTU y-grade barrel. NGL WTI correlation changes to reflect y-grade barrel composition for different BTU regimes. 2. No ethane takeaway available until Enterprise ethane pipeline is online (expected 1Q 2014). Well economics include fixed fee cost tariff on ATEX ethane pipeline. • Dramatic improvement in returns by processing higher BTU gas – Antero’s Marcellus rich gas leasehold spans the 1050 to 1350 BTU spectrum • Antero has 2,353 gross processable horizontal locations (>1050 BTU) Representative of single well examples used for Marcellus rich gas in Appendix - Current Antero rigs 15 No Processing 128% ROR Dry Gas Locations Rich Gas Locations Highly Rich Gas Locations 57% ROR C2 Rejection C2 Recovery  Single well economics example(1)(2): – 10.0 Bcf well – $8.0 million well cost ($0.94/Mcf net F&D cost) – Assumes $4.25/MMBtu NYMEX 3-year STRIP, $90.00/Bbl oil and NGL pricing at 40% of WTI for 1200 BTU y-grade barrel 1250 BTU – NGL Margin C2 Rejection: $2.12/Mcf C2 Recovery: $2.17/Mcf 1150 BTU – NGL Margin C2 Rejection: $0.73/Mcf C2 Recovery: $0.76/Mcf
  • 17. Gas $4.38 Gas $4.07 Gas $4.04 Gas $3.55 Gas $3.36 Condensate $0.45 Condensate $0.45 NGLs (C3+) $0.96 NGLs (C3+) $2.26 NGLs (C2+) $1.22 NGLs (C2+) $2.62 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 1050 BTU 1150 BTU 1250 BTU 1150 BTU 1250 BTU Dry Gas Rich Gas Rich Gas +$2.04 Upgrade ___________________________ 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. Marcellus Rich Gas – Liquids and Processing Upgrade Current – Ethane Rejection Projected – Ethane Recovery (1085 BTU) 4% shrink (1100 BTU) 6% shrink (1006 BTU) 14% shrink (1008 BTU) 17% shrink $4.38 $5.03 $6.75 $4.77 $6.42 $/Wellhead Mcf(1) • Marcellus rich gas and highly rich gas acreage provides a significant advantage in well economics – assuming $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current spot NGL pricing correlation • Upgrade analysis demonstrates that ethane recovery is not economic at current ethane price 16 Dry Gas Rich Gas Rich Gas ($/Mcf) +$2.37 Upgrade +$0.65 Upgrade +$0.39 Upgrade
  • 18. Fresh Water Management System Water Management System MapSummary 17 December 2013 Expected Completion Date  158-mile Marcellus water sourcing and distribution system to improve operational efficiency and reduce water truck traffic – $375 million total project costs – $200 million in 2013E capital costs – 150-miles of temporary and reusable pipeline, 40 centralized water storage facilities equipped with transfer pumps and 4 pumping stations optimize water delivery  56-mile Utica water sourcing and distribution system to improve operational efficiency and reduce water truck traffic – $150 million total project costs – $50 million in 2013E capital costs – 45-miles of temporary and reusable pipeline and 22 centralized water storage facilities and equipped with transfer pumps  Reduces frac water costs from $6.00/Bbl to $2.00/Bbl – Cost savings of up to $600,000 per well  Reliable year-round water supply  Over 30% of wells drilled in 2013 and up to 90% of wells drilled in 2014 to utilize new water infrastructure
  • 19. CNX/Hess Noble 16A 8.8 MMcf/d + 1,556 Bbl/d NGL + 768 Bbl/d oil ● Based on geologic analysis and announced drilling results, the core area is in the southern portion of the play ● Antero has 101,000 net acres of leasehold in Core of the Utica play – 20% HBP and remaining 77% not expiring for 5-plus years – Over 90% of acreage has rich gas processing potential ● 100% operated by Antero ● Operating four drilling rigs currently; fifth rig to be added in 4Q 2013 ● 279 Bcfe of proved reserves; 5.3 Tcfe of 3P reserves ● 56 MMcfe/d net operated production estimated for August 2013 including 2,100 Bbl/d of liquids – 95 MMcfe/d of estimated current net production including 5,000 Bbl/d of liquids ● 11 wells on line – 30 MMcfe/d of estimated constrained production ● 100% drilling success rate Fully Integrated ● 80 MMcf/d of priority processing capacity until 4Q when Seneca I is expected on line ● 200 MMcf/d Seneca I cryogenic processing plant on line in early 4Q 2013 and 200 MMcf/d Seneca II expected on line late 4Q 2013 ● Access to 20,000 Bbl/d of ethane takeaway capacity on Enterprise ATEX pipeline to Mont Belvieu expected to be in service 1Q 2014 Antero Utica Shale SummarySummary 18 Gulfport Energy Wagner #1-28H 17.1 MMcf/d + 1,881 Bbl/d NGL + 432 Bbl/d oil Chesapeake Bailey #3H 5.7 MMcf/d + 270 Bbl/d NGL + 205 Bbl/d oil Chesapeake Brown #10H 1,445 Boe/d (Including 8.7 MMcf/d gas) Chesapeake Coniglio #6H 1,125 Boe/d with 290 Bbl/d Oil Chesapeake Mangun #8H 3.1 MMcf/d + 1,015 Bbl/d liquids Chesapeake Neider #3H 3.8 MMcf/d + 980 Bbl/d liquids Chesapeake Shaw #5H 1,435 Boe/d with 770 Bbl/d Oil + 180 Bbl/d NGL Chesapeake Burgett #8H 1,210 Boe/d with 70% Liquids Chesapeake Snoddy #6H 4.2 MMcf/d + 250 Bbl/d NGL + 320 Bbl/d oil Chesapeake Buell #8H 9.5 MMcf/d + 1,425 Bbl/d liquids Gulfport Energy Shugert #1-12H 26 MMcf/d + 2,907 Bbl/d NGL + 300 Bbl/d oil Gulfport Energy Shugert #1-1H 20 MMcf/d + 2,022 Bbl/d NGL + 144 Bbl/d oil Gulfport Energy BK Stephens #1-16H 6.9 MMcf/d + 759 Bbl/d NGL + 1,224 Bbl/d oil CNX/Hess Noble 1A 7.0 MMcf/d + 812 Bbl/d NGL + 10 Bbl/d oil Gulfport Energy Boy Scout #1-33H 7.1 MMcf/d + 1,008 Bbl/d NGL + 1,560 Bbl/d oil Gulfport Energy Ryser #1-25H 5.9 MMcf/d + 649 Bbl/d NGL + 1,488 Bbl/d oil Gulfport Energy Groh #1-12H 2.8 MMcf/d + 367 Bbl/d NGL + 1,186 Bbl/d oil Enervest Cairns #5H 2.2 MMcf/d + 1,316 Bbl/d liquids Antero Miley Unit 2H and 5HA Utica Shale Industry Activity(1)Utica Shale Industry Activity(1) Hess/CNX Athens A 1H-24 10.2 MMcf/d + 1,803 Bbl/d NGL + 1,056 Bbl/d oil Utica Core Area Gulfport Energy Stutzman #1-14H Peak rate 21 MMcf/d ___________________________ Source: Company presentations and press releases. Peak rates are 24-hour rates except where noted. 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. Rexx Guernsey 1H 7.7 MMcf/d + 1,158 Bbl/d NGL + 534 Bbl/d oil Rexx Noble 1H 7.9 MMcf/d + 1,205 Bbl/d NGL + 411 Bbl/d oil Rexx Guernsey 2H 8.0 MMcf/d + 1,213 Bbl/d NGL + 560 Bbl/d oil Antero Wayne Unit 2H, 3HA and 4H Antero Rubel Unit 1H, 2H and 3H Antero Norman Unit 1H Antero Yontz Unit 1H Gulfport Energy McCort 1-28H 8.3 MMcf/d + 835 Bbl/d NGL + 21 Bbl/d oil Gulfport Energy McCort 2-28H 10 MMcf/d + 1009 Bbl/d NGL Antero Sanford Unit 1H
  • 20. 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 Antero Has Many of the Top Utica IPs Announced ● Antero has achieved 7 of the top 8, and 10 of the top 17, announced Utica IPs to-date ● Some of the best 24-hour peak rates of any shale play in North America – 3,000 to 8,900 Boe/d per well in the core area ● Liquids content from 40% - 70% (assumes ethane recovery) ● Utica Core defined as Noble, Monroe, Guernsey, Belmont and Harrison Counties, Ohio – Actual core is a subset of these counties and ties to Antero’s geologic model ___________________________ Source: Antero, press releases and company presentations. 1. All rates converted to oil equivalent based on press release, assumed BTU and Antero processing model. Not normalized for lateral length. 2. Based on 6 and 4 hour tests, respectively. 3. Production data based on 7-day IPs. 19 Utica IPs (1)Summary Core 2,000 to 8,900 Boe/d IPs Antero Utica Wells 3rd Party Core Utica Wells 3rd Party Non-Core Utica Wells Tier 1 1,000 to 2,000 Boe/d IPs Boe/d (2)(2) (3) (3)
  • 21. Strong Utica Production Growth Antero Gross Operated Utica Production 20 • Antero brought on 10 Utica wells in August after gaining access to third-party processing 0 2,000 4,000 6,000 8,000 10,000 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 8/1/2013 8/8/2013 8/15/2013 8/22/2013 8/29/2013 9/5/2013 Bo/d Mcf/d Gross Gas Net Gas Gross Oil Net Oil
  • 22. Antero Marcellus PA 25,000 net acres 21 Integrated Marcellus and Utica Midstream Infrastructure Own and operate: • 77 miles of gathering pipelines in the Marcellus Shale • 1 mile of gathering pipelines in the Utica Shale • Four compressor stations in the Marcellus Shale • 2013 midstream capex of $500 million for gathering, compression and water system Third party access to: • 94 miles of third party gathering in the Marcellus Shale • Nine compressor stations in the Marcellus Shale and three in the Utica • Total compression capacity of 766 MMcf/d increasing to 2.3 Bcf/d by YE2014 • 1 Bcf/d of firm processing capacity (482 MMcf/d in service) • 1.3 Bcf/d of long-haul firm transportation or firm sales • 20,000 Bbl/d of committed ethane takeaway capacity Fresh Water Pipeline: • 158-mile proprietary water pipeline system in Marcellus Shale and 56-mile system in the Utica Shale • Total cost of $525 million, $250 million expected to be spent in 2013 • Reduces well completion costs by up to $600,000 per well Third Party Plant Processing Capacity (MMcf/d) Contracted Firm Processing Capacity (MMcf/d)(1) Anticipated Date of Completion Marcellus Shale Sherwood I 200 200 In service Sherwood II 200 200 In service Sherwood III 200 150 Fourth Quarter 2013 Sherwood IV 200 200 Second Quarter 2014 Marcellus Shale Total 800 750 Third Party Plant Processing Capacity (MMcf/d) Contracted Firm Processing Capacity (MMcf/d) (1) Anticipated Date of Completion Utica Shale Cadiz (2) 185 - In service Seneca I (3) 200 200 Fourth Quarter 2013 Seneca II (3) 200 - Fourth Quarter 2013 Seneca III (4) 200 100 First Quarter 2014 Utica Shale Total 785 300 1. Contracted firm capacity at the Sherwood and Seneca facilities as of the start-up date of each identified unit. 2. Firm interim capacity of 80 MMcf/d at Cadiz will be fixed at 50 MMcf/d capacity upon start-up of the Seneca I processing complex and will terminate upon start-up of the Seneca II processing complex. 3. Antero has an option on Seneca I firm capacity that, if exercised by a certain date, would result in an additional 50 MMcf/d of temporary interim capacity at the Seneca II processing facility. 4. Remaining 100 MMcf/d of capacity at the Seneca III processing complex is available for commitment at our option.
  • 23. $0.00 $0.00 $0.00 $0.29 $0.62 $1.35 $2.47 $2.50 $2.94 $3.02 $3.26 $3.27 $3.34 $3.65 $3.66 $3.70 $3.75 $3.81 $4.13 $4.25 $5.05 $5.37 $5.49 $6.75 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 Low Break Even Gas Price Portfolio Gross Location and Returns Data(1) Gross Horizontal Drilling Locations• 4,576 gross horizontal drilling locations − Supports significant production growth potential • Portfolio of rich gas locations provides significant flexibility to achieve reserve and production growth with less sensitivity to commodity price environment • Over 80% of 4,576 identified horizontal drilling locations target liquids-rich processable gas and many also have condensate ___________________________ 1. Source: Credit Suisse report dated 06/18/2013 – break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI. 1250 BTU 1050 BTU 22- Antero Projects 3 Yr Strip ~$4.25/MMBtu 923WellLocations 1,430WellLocations 208WellLocations 588WellLocations 512WellLocations $/MMBtuNYMEX Highly Rich Rich Dry Total Marcellus 923 1,430 588 2,941 Utica 208 512 0 720 Upper Devonian 6 659 250 915 Total 1,137 2,601 838 4,576 Processable 1,137 2,601 3,738 % Processable 82%
  • 24. Utica 21 Marcellus 135 2012 Capex Budget by Type 2012 Capex Budget by Project Total: $1,690MM Total: $1,690MM 2013E Capex Budget by Type 2013E Capex Budget by Project Total: $1,950MM Total: $1,950MM 2012 and 2013E Capital Budget 23 Land 41% 2012 Wells Spud by Project Total: 119 2013E Wells Planned by Project Total: 156 Piceance/Arkoma 33 Utica 3 Marcellus 83 Drilling 41%Midstream 8% Piceance/Arkoma 6% Utica 41% Marcellus 53% Utica 15% Marcellus 85% Land 13% Midstream 26% Drilling 62%
  • 25. 12 mos. 12 mos. 12 mos. 12 mos. LTM $ millions 12/31/2009 12/31/2010 12/31/2011 12/31/2012 6/30/2013 Summary Operating Results Production (Bcfe) (1) 38 49 89 122 138 Net Daily Production (MMcfe/d) (1) 105 133 244 334 378 EBITDAX (1) $201 $198 $341 $434 $457 Cash interest expense (1) $36 $56 $68 $90 $105 Proved reserves (Bcfe) (2) 1,141 3,231 5,017 4,929 6,282 Proved developed reserves (Bcfe) (2) 245 457 844 1,047 1,445 Pre-tax Proved PV 10 (2)(3) $625 $1,858 $4,103 $3,223 $5,412 Summary Capitalization Cash and cash equivalents $11 $9 $3 $19 $11 Bank credit facility 142 100 365 217 960 2nd lien credit facility 375 0 0 0 0 Subordinated debt 0 25 25 25 25 Senior notes 0 528 927 1,227 1,458 Total debt $517 $653 $1,317 $1,469 $2,443 Members' equity 1,393 1,490 1,461 1,461 1,461 Non-controlling interest 30 0 0 0 0 Total book capitalization $1,940 $2,143 $2,778 $2,930 $3,904 Net debt $506 $644 $1,314 $1,450 $2,432 Credit Statistics Net debt / net book capitalization 26.2% 30.2% 47.4% 49.8% 62.5% Net debt / EBITDAX 2.5x 3.3x 3.9x 3.3x 5.3x EBITDAX / interest expense 5.6x 3.5x 5.0x 4.8x 4.4x Net debt / proved reserves ($/Mcfe) $0.44 $0.20 $0.26 $0.29 $0.39 Net debt / proved developed reserves ($/Mcfe) $2.07 $1.41 $1.56 $1.38 $1.68 Net debt / production ($/Mcfed) $4,860 $4,794 $5,381 $4,338 $6,433 Pre-tax Proved PV 10 / net debt 1.2x 2.9x 3.1x 2.2x 2.2x Includes Discontinued Operations Financial Summary 24 Current Financial Summary ___________________________ 1. Production, EBITDAX and cash interest expense are non-GAAP as they include discontinued operations until transaction closing per 2009 - 2012 10-Ks and 6/30/2013 10-Q. Transactions include the Arkoma Woodford and Fayetteville Shale asset sale for $445 million on June 29, 2012, and the Piceance Basin upstream and midstream asset sale for $325 million on December 21, 2012. 2. LTM proved developed and proved reserves as at 6/30/2013. 3. Pre-tax PV-10 value includes hedge value for each year; 2012 includes hedge value of $1.3 billion and 2Q 2013 hedge value is $0.9 billion.
  • 26. Key Credit Strengths World class asset base with scale  Liquids-rich Marcellus and Utica shale plays are two of the premier U.S. shale plays  Antero has scale in both of these plays – 328,000 net acres in the Marcellus Shale and 101,000 net acres in the Utica Shale Large, low risk drilling inventory  $1.03/Mcfe 3-year development cost leader through 2012 per J.P. Morgan equity research methodology  $0.90/Mcfe average net development cost for 6/30/2013 3P reserves – assuming ethane rejection Low cost leader  115% average Marcellus production growth from 2Q 2012 to 2Q 2013  12% liquids by production volume today forecast to grow to ~20% by 2014 assuming ethane rejection (~40% assuming ethane recovery) Large long-term hedge position  1,024 Bcfe hedged at $5.11/MMBtu NYMEX-equivalent(1) through 2019 Rapid production growth with liquids exposure  100% drilling success rate in the 208 horizontal wells in Marcellus, Utica and Upper Devonian Shales to date  Over 3,600 horizontal drilling locations in the Marcellus and Utica; an additional 900 horizontal drilling locations have been identified in the Upper Devonian ___________________________ 1. Assumes 1000 Btu average heat content. Excluding Rockies hedges. 2. Lender commitments under the facility are $1.75 billion which can be expanded to the full $2.0 billion borrowing base. Undrawn borrowing base capacity as of 6/30/2013. 25 Strong liquidity  ~$1.0 billion of undrawn borrowing base capacity as of June 30, 2013(2)
  • 27. 2626 Appendix
  • 28. Firm Transportation/Sales Commitments – Appalachia 27 Firm Sales #1 10/1/2011 – 10/31/2019 Firm Sales #2 10/1/2011 – 5/31/2017 EQT 8/1/2012 – 8/31/2021 Momentum III 9/1/2012 – 12/31/2021 Firm Sales #3 1/1/2013 – 5/31/2022 Columbia 7/26/2009 – 9/30/2025 Chicago Direct 4/1/2013 – 9/30/2021 MMBtu/d - 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 Aug-13 Nov-13 Feb-14 May-14 Aug-14 Nov-14 Feb-15 May-15 Aug-15 Nov-15 Feb-16 May-16 Aug-16 Nov-16 Feb-17 May-17 Aug-17 Nov-17 Feb-18 May-18 Aug-18 Nov-18 Feb-19 May-19 Aug-19 Nov-19 Feb-20 May-20 Aug-20 Nov-20
  • 29. $3.6 -$7.6 $4.7 $25.3 $33.6 $29.0$27.9$26.1 $12.3 $16.2$17.4 $27.8$29.2 $19.3 $25.2 $42.8 $80.0$82.5 $58.7 $49.4$48.1 $14.1 ($1.50) ($1.00) ($0.50) $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 ($20.0) $0.0 $20.0 $40.0 $60.0 $80.0 $100.0 Q1 2008 Q2 2008 Q3 2008 Q4 2008 Q1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011 Q3 2011 Q4 2011 Q1 2012 Q2 2012 Q3 2012 Q4 2012 Q1 2013 Q2 2013 Quarterly Realized Gains/(Losses) 1Q '08 - 2Q '13 • Antero has realized over $665 million of gains on commodity hedges over the past 5-½ years – Gains realized in 21 of last 22 quarters Historical Antero Hedging Results 28 $MMs $/Mcfe
  • 30. Utica Shale Wells – Antero Initial Results ● Antero has drilled and completed 11 Utica Shale wells in the Core of the play to-date ___________________________ 1. 24-hour peak rates assume full ethane recovery however Antero is currently rejecting ethane due to current market prices. 2. Rubel 2H and 3H peak rates based on 6-hour and 4-hour flow tests, respectively. 3. Average of Antero’s first 11 wells, assuming ethane rejection. 29 Antero Utica Well Initial Production Data Lateral Well Oil Eq. Rate Wellhead Gas Condensate Shrunk Gas NGL % Total Length Name County (Boe/d)(1) (MMcf/d) (Bbl/d) (MMcf/d) (Bbl/d) Liquids BTU (Feet) Yontz 1H Monroe 8,879 38.9 52 33.9 3,177 36% 1161 5,115 Rubel 1H Monroe 7,917 31.1 214 25.9 3,391 46% 1231 6,554 Rubel 2H(2) Monroe 7,816 30.9 232 25.8 3,284 45% 1217 6,571 Rubel 3H(2) Monroe 7,097 28.4 142 23.7 3,003 44% 1220 6,424 Norman 1H Monroe 6,181 26.1 45 22.3 2,419 40% 1186 5,498 Wayne 3HA Noble 5,852 14.7 1,905 11.6 2,018 67% 1272 6,712 Wayne 4H Noble 5,698 14.2 1,922 11.2 1,907 67% 1265 6,493 Wayne 2H Noble 4,257 10.9 1,331 8.5 1,503 67% 1281 6,094 Miley 2H Noble 3,740 8.6 1,450 6.7 1,172 70% 1278 6,153 Miley 5HA Noble 3,369 7.7 1,285 6.0 1,090 70% 1291 6,296 Sanford 1H Noble 1,148 1.8 653 1.4 256 79% 1316 7,159 5,632 19.4 839 16.1 2,111 57% 1247 6,279 4,682 19.4 839 18.2 805 42% 1247 6,279 Average ‐ Ethane Recovery Average ‐ Ethane Rejection(3) 24‐hr Peak Rate
  • 31. 0% 20% 40% 60% 80% 100% 120% 140% 160% 180% 200% $3.00 $4.00 $5.00 $6.00 $7.00 BTAXROR NYMEX $/MMbtu $8.0 MM / 9.0 Bcf $8.0 MM / 10.0 Bcf $8.0 MM / 11.0 Bcf Lateral Length Well Cost ($MM) EUR (Bcf) Net F&D ($/Mcf) 7,000 $8.7 9.8 $1.03 ___________________________ 1. Fixed NYMEX gas prices with appropriate basis adjustment to the Marcellus area. 85% NRI assumed. 2. Defined as 10% before tax rate-of-return. • Assumes 1050 BTU gas – no processing, dry gas • Estimated 588 gross horizontal drilling locations in the dry gas category (950 to 1050 BTU) Antero Average for First 195 Horizontal Wells 30 Marcellus Shale Well Economics Horizontal Dry Gas (1)(1) (1) (1) (1) Well Cost ($MMs) EUR (Bcf) F&D ($/Mcf) NYMEX Breakeven(2) $8.00 9.0 $1.05 $3.03 $8.00 10.0 $0.94 $2.78 $8.00 11.0 $0.86 $2.59 3 Yr Strip $4.25/MMBtu 25-40% ROR Long-term $5.50/MMBtu 45-70% ROR Natural Gas, 100%
  • 32. • Assumes 1150 BTU gas and includes processing margin at $90.00/Bbl oil and 36% WTI NGLs(1) • Estimated 1,430 gross horizontal drilling locations in the 1050 to 1250 BTU category(2) NGLs, 36% Natural Gas, 64% 769 MBbls NGLs 0% 20% 40% 60% 80% 100% 120% 140% 160% 180% 200% $3.00 $4.00 $5.00 $6.00 $7.00 BTAXROR NYMEX $/MMbtu $8.0 MM / 9.0 Bcf $8.0 MM / 10.0 Bcf $8.0 MM / 11.0 Bcf $8.0 MM / 10.0 Bcf - Spot NGL Pricing 4/1/13 ~57% ROR Antero Average for First 195 Horizontal Wells Marcellus Shale Well Economics Horizontal Rich Gas ___________________________ 1. No ethane takeaway available until Enterprise ethane pipeline is online (expected 1Q 2014). Well economics include fixed fee cost tariff on ATEX ethane pipeline. 2. Economics will vary considerably depending on Btu and other factors. 3. Volumes assume ethane recovery. NGL and oil volumes based on 10 Bcf well. 4. Defined as 10% before tax rate-of-return. 5. Fixed NYMEX gas prices with appropriate basis adjustment to the Marcellus area. 85% NRI assumed. NGL price of 36% WTI assumed except for SPOT NGL pricing case which assumes C2 rejection. 31 (5) (5) (5) (5) (5) 3 Yr Strip $4.25/MMBtu 45-70% ROR Well Cost ($MMs) EUR (Bcf) F&D ($/Mcf) NYMEX Breakeven(4) $8.00 9.0 $1.05 $1.26 $8.00 10.0 $0.94 $0.97 $8.00 11.0 $0.86 $0.73 Long-term $5.50/MMBtu 65-105% ROR Lateral Length Well Cost ($MM) EUR (Bcf) Net F&D ($/Mcf) 7,000 $8.7 9.8 $1.03 (3)
  • 33. 0% 50% 100% 150% 200% 250% 300% $3.00 $4.00 $5.00 $6.00 $7.00 BTAXROR NYMEX $/MMbtu $8.0 MM / 9.0 Bcf $8.0 MM / 10.0 Bcf $8.0 MM / 11.0 Bcf $8.0 MM / 10.0 Bcf - Spot NGL Pricing 4/1/13 • Assumes 1250 BTU gas and includes processing margin at $90.00/Bbl oil and 44% WTI NGLs(1) • Estimated 923 gross horizontal drilling locations in the 1250 to 1350 BTU category(2) Antero Average for First 195 Horizontal Wells Marcellus Shale Well Economics Horizontal Highly-Rich Gas 32 (5) (5) (5) (5) (5) Well Cost ($MMs) EUR (Bcf) F&D ($/Mcf) NYMEX Breakeven(4) $8.00 9.0 $1.05 $0 $8.00 10.0 $0.94 $0 $8.00 11.0 $0.86 $0 3 Yr Strip $4.25/MMBtu 100-155% ROR Long-term $5.50/MMBtu 130-200% ROR ~128% ROR % Oil, 2% NGLs, 47% Natural Gas, 51% (3) Lateral Length Well Cost ($ MM) EUR (Bcf) Net F&D ($/Mcf) 7,000 $8.7 9.8 $1.03 ___________________________ 1. No ethane takeaway available until Enterprise ethane pipeline is online (expected 1Q 2014). Well economics include fixed fee cost tariff on ATEX ethane pipeline. 2. Economics will vary considerably depending on Btu and other factors. 3. Volumes assume ethane recovery. NGL and oil volumes based on 10 Bcf well. 4. Defined as 10% before tax rate-of-return. 5. Fixed NYMEX gas prices with appropriate basis adjustment to the Marcellus area. 85% NRI assumed. NGL price of 44% WTI assumed except for SPOT NGL pricing case which assumes C2 rejection. 1,194 MBbls NGLs; 24 MBbls/Oil
  • 34. Marcellus Processing Barrels – 1150 BTU NGL Barrel - VolumeNGL Barrel - Volume Current NGL Value - $17.27/Bbl(1)Current NGL Value - $44.48/Bbl(1) C2 Recovery C2 Recovery C2 Rejection C2 Rejection ___________________________ 1. Assumes $90.00/Bbl WTI pricing and current spot NGL prices. 33 Propane, 57% Pentanes+, 16% Normal Butane, 13% Iso Butane, 9% Ethane, 5% Propane, $18.64 Pentanes+, $13.31 Normal Butane, $6.83 Iso Butane, $5.44 Ethane, $0.27 Ethane, 70% Propane, 18% Pentanes+, 5% Normal Butane, 4% Iso Butane, 3% Propane, $6.06 Ethane, $3.44 Pentanes+, $4.04 Normal Butane, $2.06 Iso Butane, $1.66
  • 35. Marcellus Processing Barrels – 1250 BTU NGL Barrel - VolumeNGL Barrel - Volume Current NGL Value - $23.44/Bbl(1)Current NGL Value - $48.44/Bbl(1) C2 Recovery C2 Recovery C2 Rejection C2 Rejection ___________________________ 1. Assumes $90.00/Bbl WTI pricing and current spot NGL prices. 34 Propane, 51%Pentanes+, 21% Normal Butane, 16% Iso Butane, 8% Ethane, 3% Pentanes+, $18.26 Propane, $16.80 Normal Butane, $8.20 Iso Butane, $5.02 Ethane, $0.16 Ethane, 58% Propane, 23% Pentanes+, 9% Normal Butane, 7% Iso Butane, 4% Propane, $7.52 Pentanes+, $7.55 Ethane, $2.86 Normal Butane, $3.40 Iso Butane, $2.11
  • 36. Gas $4.38 Gas $4.07 Gas $4.04 Gas $3.55 Gas $3.36 Condensate $0.45 Condensate $0.45 NGLs (C3+) $1.11 NGLs (C3+) $2.91 NGLs (C2+) $1.68 NGLs (C2+) $3.68 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 $10.00 1050 BTU 1150 BTU 1250 BTU 1150 BTU 1250 BTU Dry Gas Rich Gas Rich Gas Marcellus Rich Gas Provides Liquids and Processing Upgrade $4.38 $5.18 $7.40 $5.24 $7.49 • Marcellus rich gas and highly rich gas acreage provides a significant advantage in well economics – assuming $4.25/MMBtu NYMEX, $90.00/Bbl WTI and 40% WTI NGL pricing • Upgrade analysis demonstrates that ethane recovery is economic at higher ethane prices 35 Current – Ethane Rejection Projected – Ethane Recovery $/Mcf on Wellhead Gas Volumes (1) ($/Mcf) ___________________________ 1. Assumes $4.25/MMBtu NYMEX, $90.00/Bbl WTI and 40% WTI NGL pricing for 1200 BTU y-grade barrel for ethane recovery, C3+ spot prices for ethane rejection. 1.054 and 2.070 (ethane rejection) and 3.332 and 5.145 (ethane recovery) GPMs 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. +$0.80 Upgrade +$3.02 Upgrade Dry Gas Rich Gas Rich Gas +$0.86 Upgrade +$3.11 Upgrade (1085 BTU) 4% shrink (1100 BTU) 6% shrink (1006 BTU) 14% shrink (1008 BTU) 17% shrink
  • 37. Antero EBITDAX Reconciliation EBITDAX 36 ($ thousands) 6 Months Ended Antero Resources LLC 6/30/2012 6/30/2013 EBITDAX: Net income (loss) $254,318 $83,196 Unrealized loss (gain) on commodity derivative contracts (114,498) (61,265) Interest expense and other 48,593 63,396 Provision (benefit) for income taxes 183,969 53,325 Depreciation, depletion, amortization and accretion 38,477 93,484 Impairment of unproved properties 1,581 6,359 Exploration expense 4,756 11,662 (Gain) Loss on sale of assets (291,305) -- Other 1,996 1,200 EBITDAX from Continuing Operations $127,887 $251,357 EBITDAX from Discontinued Operations 100,692 -- EBITDAX $228,579 $251,357
  • 38. The U.S. Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates (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 reserves included in this presentation have been audited by Antero’s third-party engineers. Antero’s estimate of probable and possible reserves was prepared by Antero’s internal reserve engineers, has not been reviewed by third-party engineers, and is provided in this presentation because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies. Antero does not plan to include probable and possible reserve estimates in its filings with the SEC. We use certain other terms in this presentation relating to estimates of hydrocarbon volumes that the SEC’s guidelines prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, possible or probable reserves as defined by SEC regulations and accordingly are substantially less certain and no discount or other adjustment is included in the presentation of such numbers. 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 our 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. “Unrisked Resource” refers to Antero’s internal estimates of hydrocarbon quantities that Antero’s management believes may be potentially discovered through exploratory drilling or recovered with additional drilling. Unrisked resource may not constitute 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. Actual quantities that may be ultimately recovered from Antero’s interests will differ substantially. Factors affecting ultimate recovery include the scope of our 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. Estimates of unrisked resource may change significantly as development of Antero's resource plays provides additional data. “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. Cautionary Note Regarding Hydrocarbon Quantities 37
  • 39. Antero Resources 1625 17th Street Denver CO 80202 www.anteroresources.com