Antero Resources Finance 8-K Regulation FD Disclosure

Exhibit 99.1

Antero Resources September 2010

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 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. 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

Cautionary Note Regarding Hydrocarbon Quantities The U.S. Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in this presentation such as potential reserves, risked resource or other 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 reserves and accordingly are substantially less certain and no discount or other adjustment is included in the presentation of such numbers. In addition, estimates of probable or possible reserves may not meet the proposed definitions for such terms under the SEC’s proposed revised oil and gas disclosure rules. In this presentation: “Risked 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 or recovery techniques based on the unweighted first-day-of-the-month average pricing for the 12 months ended June 30, 2010 in each of our operating areas (“SEC pricing methodology”). Risked 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 risked resource may change significantly as development of our 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 new oil and natural gas disclosure rules. “Potential locations” or “drilling locations” represent the number of locations that Antero currently estimates could potentially be drilled in a particular area determined by the company’s reserve and resource analysis. Our actual drilling activities will depend on commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and transportation constraints, regulatory approvals and other factors. We may not be able to drill wells on a many of these locations. 2

Company Overview Paul M. Rady, Chairman & CEO Glen C. Warren, Jr., President & CFO 3

Executive Summary • Antero Resources is an oil and gas exploration and production (E&P) company focused on acquiring, developing and producing unconventional natural gas resources in the U.S. – Focused on fractured shales and tight sand reservoirs – Diversified asset base with critical mass in Appalachia, Arkoma, and Piceance resource plays – Proved reserves as of July 1, 2010 of 1.5 Tcfe(1),(2); Risked Resource of over 14 Tcfe(1) – Gross operated production of 150 MMcfe/d (145 MMcfe/d net including 38 MMcfe/d non-operated) (3) – 98% drilling success rate on over 500 operated wells since inception (February 2003) – Concentrated, low risk, low cost drilling inventory – 14,700 potential locations / 63% held by production (HBP) – Over 90 miles of gathering system infrastructure constructed and operating – Significant firm transportation portfolio – 235 MMcfe/d all expected in-service by end of 2011 – Highly experienced management team with proven track record in numerous resource plays: Powder River Basin CBM, Piceance Basin, Barnett Shale, Woodford Shale, Fayetteville Shale, Marcellus Shale • Top-quartile development costs – $1.23/Mcfe estimated development cost over latest twelve months(5) • Prudent financial management – Raised $1.4 billion of equity since 2004 to acquire and prove up leasehold – Large hedge position – 198 Bcf(4) hedged from July 1, 2010 through 2014 at approximately $6.47/MMBtu NYMEX-equivalent – Strong liquidity • Outstanding financial sponsorship from Warburg Pincus, Yorktown, Trilantic and others 1. Estimates per 7/1/2010 internal reserve analysis, using SEC reserve methodology. 2. SEC pricing as of 6/30/10, using SEC pricing methodology, was $4.00/MMBtu for Arkoma, $3.82/MMBtu for Piceance and $4.31/MMBtu for Appalachia 3. Includes 7 MMcfe/d of equity NGLs retained by Antero’s midstream business as compensation for processing third-party Woodford Shale gas. 4. Assumes 1,000 Btu average heat content. 5. Development costs are completed well costs.

Key Management Operating Accomplishments Antero management team has been a leader in unconventional resource identification, delineation and development for two decades with the following entities: • Barrett Resources (1990’s) - A leader in developing Piceance Basin tight sands play and the Powder River Basin CBM play • Pennaco Energy ( 1998 – 2001) – sold to Marathon Oil - Became the 2nd largest producer and 2nd most active driller in the Powder River Basin CBM play • Antero Barnett (2003 – 2005) – sold to XTO Energy - Became the 2nd largest producer and 2nd most active driller in the Barnett Shale play - Early user of horizontal drilling technology in Barnett - Executed 1st simo-frac (frac’d 3 horizontal wells at once) - Early user of microseismic imaging to monitor frac effectiveness and adjust frac in real time - Completed first horizontal re-frac - Antero drilled 4 of the top 20 best wells drilled in the Barnett to date • Antero Resources (2004 to present) - Became one of the largest producers and most active drillers in Woodford Shale play - Established a second core area in the Woodford Shale (East Rockpile) - Drilling longest laterals in Marcellus – averaging 6,200’ laterals - Drilled and delineated large, over-pressured Mancos shale resource in Piceance - Driving strong Williams Fork recoveries and capitalizing on rich gas in Piceance

Substantial Low Cost Resource Base • $1.20/Mcfe all-in finding cost since 2007 – including land costs • $1.23/Mcfe average development cost over the past 12 months (33 wells) – excluding land costs • Risked resource over 9x proved reserves Appalachia Proved Reserves(1) 1.5 Tcfe Risked Resource(2) 14.3 Tcfe Current Net Production(3) 145 MMcfe/d Net Acreage ~287,000 Total Rockies Mid-Continent Arkoma Woodford Midstream Processing Capacity 100 MMcfe/d CO2 Treating Capacity 42 MMcfe/d Gathering Pipeline 50 miles Ardmore/Fayetteville Shale Piceance–Mesaverde/Mancos Shale Net Production 65 MMcfe/d Arkoma–Woodford Shale Appalachia–Marcellus Shale Net Acreage ~18,000 Net Production 35 MMcfe/d Net Acreage ~67,000 Gathering Pipeline 20 miles Net Production 36 MMcfe/d Net Acreage ~124,000 Gathering Pipeline 20 miles Net Acreage ~78,000 1. SEC pricing as of 6/30/10, using SEC pricing methodology, was $4.00/MMBtu for Arkoma, $3.82/MMBtu for Piceance and $4.31/MMBtu for Appalachia. 2. Estimates per 7/1/2010 internal reserves analysis, using SEC reserve methodology. 3. Net production estimates as of September 2010. Net Production 36 MMcfe/d Net Production 9 MMcfe/d 6

Strong Track Record of Growth Average Net Daily Production (1) Proved Reserves (2) 500 1,000 1,500 2,000 50 100 150 31 85 6 105 87 235 680 1,141 135 1,513 0 2006 2007 2008 2009 6/30/2010 Arkoma Piceance Appalachia Fayetteville/Ardmore 0 2006 2007 2008 2009 2010E Arkoma Piceance Appalachia Fayetteville/Ardmore Antero Net Acreage (3) Operated Well 100 150 150,000 200,000 250,000 300,000 350,000 85 96 126 Completions 63 0 50 2006 2007 2008 2009 2010(4) Arkoma Piceance Appalachia 0 50,000 100,000 2004 2005 2006 2007 2008 2009 2010(4) Arkoma Piceance Appalachia Fayetteville/Ardmore 15 7 1. Production estimates per management. 2009 includes nominal amount of Fayetteville Shale non-operated production. 2. Proved reserves for 2006, 2007 and 2008 were determined using previously effective SEC methodology. 2009 and 7/1/10 reserves based on currently effective SEC methodology and pricing. 3. Excludes minimal holdings in other non-core areas. 4. As of September 2010. CAGR = ~103% CAGR = ~126%

Best-in-Class Finding Costs in 2009 Industry All-in Finding Costs 2009 (1) $ / Mcfe 2009 Antero traditional cost of $0.39/Mcfe(2) $6.00 $7.00 $8.00 • finding $0.39/• 1H 2010 Antero traditional finding cost of $0.47/Mcfe(2) • 98% drilling success rate since inception • Over 80% of the 350+ wells drilled and completed in the Arkoma, Piceance and were $3.00 $4.00 $5.00 Appalachian Basins unproved locations at spud date $1.00 $2.00 $0.39 $0.47 2009 Industry Median = $1.68 $0.00 CLR PVA STR EOG NFX WMB CHK XTO DVN PQ SD CRZO PXP Antero - 2009 SWN HK COG RRC KWK UPL XCO EQT Antero – 1H 2010 8 1. Source: JPM – North American Equity Research dated 3/2/2010. Includes all drilling and land acquisition costs for all companies. 2. Antero traditional finding costs calculated by the company.

And Low Finding Costs Over the Long-Term • Antero has successfully proven up over 1.5 Tcfe of reserves over the past 3 ½ years at low per unit cost including the $347 million Marcellus land acquisition from Dominion $7.00 $8.00 Industry 3-year All-in Finding Costs Through 2009 (1) • 3 ½-year Antero all-in finding costs of $1.20/Mcfe(2) $ / Mcfe $5.00 $6.00 $2.00 $3.00 $4.00 $1.20 3-year Industry Median = $2.54 $0.00 $1.00 CLR EOG PVA STR NFX DVN XTO WMB CHK PQ PXP SD Antero (2) UPL SWN RRC HK COG XCO EQT 9 1. Source: Barclays Capital. Includes all drilling and land acquisition costs for all companies including $347 million Dominion land acquisition for Antero. 2. Antero finding costs calculated over 3 ½ years using 7/1/2010 internally estimated reserves which were prepared consistent with SEC methodology.

Top-Quartile Development Costs • Per Mcfe development costs are an even better measure of capital efficiency and Antero is in the top-quartile Industry Development Costs 2009 $8.00 $9.00 • 2009 Antero development cost of $2.35/Mcfe(2) • 1H 2010 Antero development cost declined to $1.95/Mcfe(2) (includes $0.17/Mcfe of land expenditures $ / Mcfe $5.00 $6.00 $7.00 and $0.35/Mcfe of wells drilled but not yet completed) $2.00 $3.00 $4.00 $1.95 $2.35 2009 Industry Median = $3.63 $0.00 $1.00 WMB DVN XTO NFX STR CHK CRZO CLR PVA EOG SD PQ PXP - 2009 KWK UPL SWN RRC COG HK XCO EQT 1H 2010 10 1. Source: JPM – North American Equity Research dated 3/2/2010. Includes all drilling and land acquisition costs for all companies. 2. Antero development costs calculated by the company. Antero Antero – (1)

Impressive Well by Well Development Costs • Antero well by well development costs since September 2009 are $1.23/Mcfe • Antero LTM average development costs including land are only $1.40/Mcfe, well below the industry median development costs calculated by JPMorgan research for 2009 which were $3.63/Mcfe $3.50 $4.00 Antero Well by Well Development Costs - LTM(1) $/Mcfe 2009 Industry Median Development Costs: $3.63/Mcfe(2) $2.50 $3.00 Cost $1.00 $1.50 $2.00 LTM Antero Average Development Costs: $1.40/Mcfe(3) Development $0.00 $0.50 11 - Woodford Shale - Piceance Basin - Marcellus Shale 1. Latest twelve months through September 2010 - excludes land acquisition costs. 2. Source: JPM – North American Equity Research dated 3/2/2010. Includes all drilling and land acquisition costs for all companies. 3. Includes land acquisition costs of $0.17/Mcfe developed.

Low Break Even Natural Gas Prices • 50% of Antero 2010 capital budget is directed to the Marcellus NYMEX Break Even Price ($ per MMBtu)(1) $7.00 $8.00 6.18 $7.43 $7.52 $7.81 $4.00 $5.00 $6.00 $3.63 $3.96 $4.06 $4.08 $4.33 $4.36 $4.54 $4.60 $4.77 $4.85 $5.11 $5.21 $5.55 $5.74 $1.00 $2.00 $3.00 $0.35 $2.66 $2.75 $3.06 $0.00 1.00 $0.00 $0.3 12 1. Source: Credit Suisse report dated 9/17/2010 – Break even price is for 15% ATAX ROR. 2. Antero estimate assuming 1.2 Bcfe EUR, $1.8 million drilling and completion costs , 1160 BTU gas and $80 per Bbl crude oil. - Antero Projects

Marcellus Shale – The Place to Be 13 Source: Company presentations and websites

Antero Marcellus Shale • 124,000 net acres of leasehold in heart of the play, Resources Summary primarily acquired from Dominion – 84% HBP – 100% operated – 83% of acreage is 100% working interest – 80% NRI • 36 MMcfe/d net production (25% of total Company) • Antero operating 3 rigs • Only 1% of Antero potential drilling locations drilled • Surrounded by key Range, Atlas, XTO and Chesapeake Marcellus wells • Premium gas market – NYMEX-plus • Antero has completed 14 consistently strong horizontal wells – Demonstrated ability to drill wells with long laterals (6,000 ft +) in less than 30 days – $1.26/Mcfe development cost to date(1) 14 • Plenty of rich gas potential • Marcellus basin-wide production over 1 Bcfe/d 1. Development costs are based on completed well costs and preliminary EURs.

Piceance Basin – A Rich Gas Play • 67,000 net acres – 24% HBP and 55% 2013+ expiration • 35 MMcfe/d net production ( 24% of total Company) Summary Mesaverde Sand: • 10-acre well density throughout Mesaverde development • 81% NRI • Almost 100% operated • Antero operating 1 rig • Only 3% of Antero potential drilling locations drilled • completed over 170 wells with a 99% success - Rich, processable gas - 1,236 approved locations Mancos Shale: • Leader in Piceance Basin Mancos Shale delineation - Very encouraging well results Drilled and rate to date • Piceance basin-wide production over 2 Bcfe/d - Well positioned in highly over-pressured regime Areas of Operations Roan Plateau NOSR 1 1000 00 03 - - 4000 0001- Grand Hogback Parachute Rulison 1000 3 Gravel Trend Grand Mesa National Forest White River National Forest 1000 - 2000 2000 Battlement Mesa Grand Valley Mamm Creek Castle Springs Mesaverde “Valley Trend” Gas Fields 2000

Antero Mesaverde – A Liquids Play • Most of Antero and industry drilling to date has been Summary • In the Gravel Trend area, Antero has improved recoveries focused on the Mesaverde tight sands formation • Antero has completed 11 wells in its Battlement Mesa area where it has under $1.20/Mcfe development costs(1) and lowered costs - 1160 BTU gas - Expanding play through exploration step-outs Areas of Operation Antero Battlement Mesa Project Antero Gravel Trend Project W 16 1. Development costs are based on completed well costs and preliminary EURs.

Arkoma Woodford Shale Antero Acreage Position Summary • Antero operated 138 sections (63% of its net acreage) • 79,000 net acres – 71% HBP • Drilled and operated over 155 horizontal wells with a 97% success rate to date • 65 MMcfe/net production (45% of total Company)(1) East Rockpile Area d • Antero operating 1 rig • Have 3D seismic over most of acreage • Only 14% of Antero potential drilling locations drilled Torpedo Junction Area • Antero averaged 4.4 Bcf EUR per well for its last 10 operated wells in its East Rockpile area • $1.14/Mcfe development cost LTM(2) • Woodford Shale basin-wide production over 750 Northern Front Area MMcfe/d 17 1. Includes 7 MMcfe/d of equity NGLs retained by Antero’s midstream business as compensation for processing third-party gas. 2. Development costs are based on completed well costs and preliminary EURs.

Integrated Midstream Assets Overview Coalgate Processing Plant • Owns and operates 90 miles of gathering pipelines in Arkoma, Piceance and Appalachia combined • Operates 100 MMcfe/d of cryogenic processing plants in the Arkoma Basin • Backed by all Antero and Newfield wet gas reserves in Arkoma Woodford under long-term contracts • Formed 60 / 40 processing JV with MarkWest bringing Newfield wet gas to plants • Oneok NGL pipeline completed in September 2008 allowed the Antero plants to go to “deep cut”, more than doubling product yields to 4.0 GPM and over 9,500 gross Bbls/d of NGLs • Plants have run at full capacity for over two years • Capacity expansion currently under consideration 18

Financial Review Glen Warren, President & CFO 19

Conservative Financial Philosophy • Antero has historically employed a sound and disciplined financial philosophy – Equity capital used to fund acquisition of land, delineation drilling and initial infrastructure – Debt capital used primarily to execute the development plan and convert unproved reserves to proved reserves – During the building of Antero Barnett and Antero Resources LLC, management has maintained a moderate mix of debt and equity, reflecting the sponsor-backed nature of its equity sources • forward in the development phase Antero will maintain a more conservative sheet with the Going phase, balance following objectives: – Target net debt / EBITDAX of 2.0x to 3.0x – Target Mcfe net debt / proved reserves of $0.25 to $0.75 / • Invest well within cash flow plus liquidity while balancing capital efficiency and drilling economics • Continue our active/opportunistic hedging strategy to protect cash flow and returns, insulating our capital program – 198 Bcfe(1) MMBtu NYMEX hedged from July 1, 2010 through 2014 at approximately $6.47/– Strong counterparties – all collateralized, all in bank group • Maintain strong bank group – Led by JPMorgan with 12 other 20 banks • Continue to broaden sources of capital 1. Assumes 1,000 Btu average heat content.

Current Financial Summary 12/31/2007 12/31/2008 12/31/2009 6/30/2010 $ thousands 12 mos. 12 mos. 12 mos. LTM Financial Summary Summary Operating Results Production (Bcfe) 11 32 38 40 Revenue $91,494 $366,490 $207,990 $349,161 EBITDAX $59,980 $208,513 $201,270 $193,057 Summary Capital Structure Cash $11,114 $38,969 $10,669 $4,057 Credit facility $189,380 $396,580 $142,080 $85,994 Term Loan - 2nd Lien $225,000 $225,000 $0 $0 Senior notes $0 $0 $372,397 $528,190 Capital lease - non current $1,279 $1,154 $1,022 $1,259 Total debt $415,659 $622,734 $515,499 $615,443 Shareholder’s equity $394,302 $1,148,236 $1,269,386 $1,340,558 Non-controlling interest $0 $29,318 $29,721 $30,359 Total book capitalization $809,961 $1,800,288 $1,814,606 $1,986,360 Credit Statistics Total debt / book capitalization 51.3% 34.6% 28.4% 31.0% Total debt / EBTIDAX 6.9x 3.0x 2.6x 3.2x expense EBITDAX / interest 2.4x 5.5x 5.6x 4.1x Total debt / proved reserves ($/Mcfe) $1.77 $0.92 $0.45 $0.41 Total debt / PD reserves ($/Mcfe) $3.81 $2.61 $1.87 $1.77 (1) (1) 21 1. Calculated using Antero internally prepared 7/1/2010 SEC proved developed and producing and proved developed non-producing reserves. SEC pricing was $4.00 / MMBtu for Arkoma, $3.82 / MMBtu for Piceance and $4.31/ MMBtu for Appalachia.

2010 Capital Budget 2010 (1) (1) • 2010 budget funded by cash flow and revolver Capex Budget by Type 2010 Capex Budget by Basin Drilling 83% Midstream 5% Land 12% Appalachia 50% Arkoma 31% Piceance 19% 22 Budget = $394 Million 1. Latest management estimate.

Strong Hedge Portfolio • Antero is well hedged with 198 Bcf(1) at $6.47/MMBtu NYMEX-equivalent pricing • Represents four years of production at current production rates $9.00 $10.00 160.0 170.0 180.0 2H 2010 30,000 MMBtu/d @ $5.23 CIG 30,000 MMBtu/d @ $7.36 CP 10,000 MMBtu/d @ $6.39 NYMEX 35,000 MMBtu/d @ $6.09 TCO 105,000 MMBtu/d Total 2011 45,000 MMBtu/d @ $5.78 CIG 35,000 MMBtu/d @ $6.91 Transco 40,000 MMBtu/d @ $6.36 TCO 120,000 MMBtu/d Total 2012 35,000 MMBtu/d @ $6.06 CIG 35,000 MMBtu/d @ $7.05 Transco 50,000 MMBtu/d @ 6.18 TCO 120,000 MMBtu/d Total 2013 40,000 MMBtu/d @$5.96 CIG 40,000 MMBtu/d @$6.51Transco 40,000 MMBtu/d @ $6.36 TCO 120,000 MMBtu/d Total 2014 40,000 MMBtu/d @$6.07 CIG 20,000 MMBtu/d @$6.51 Transco 10,000 MMBtu/d @ $6.20 CP 60,000 MMBtu/d @ $6.39 TCO 130,000 MMBtu/d Total Antero Hedge Position $6.00 $7.00 $8.00 110.0 120.0 130.0 140.0 150.0 Avg NYMEX Hedged Price(2): $6.45 Avg NYMEX Hedged Price(2): $6.35 Avg NYMEX Hedged Price(2): $6.54 Avg NYMEX Hedged Price(2): $6.47 Current NYMEX Price: $4.12 Current NYMEX Price: $4.67 Current NYMEX Price: $5.31 Current NYMEX Price: $5.61 10 000 $6 32 TCO Avg NYMEX Hedged Price(2): $6.53 Current NYMEX Price: $5.79 10 000 $6 60 TCO 10 000 $6 24 TCO 10,000 $6.55 TCO 10,000 $5.63 TCO 10,000 $5.55 *** - Oct-10 - Dec-10 10 000 $5 53 TCO 10,000 $5.38 TCO 10,000 $5.55 TCO 10,000 $5.65 TCO $4.00 $5.00 60.0 70.0 80.0 90.0 100.0 10,000 $6.14 NYMEX 15,000 $7.01 Transco 10,000 $5.72 TCO 10,000 $6.66 TCO 10,000 $6.86 TCO 10,000 $6.84 TCO 10,000 $7.02 TCO 10,000 $7.00 TCO 10,000 $6.44 Transco 10,000 $6.75 TCO 10,000 $6.78 TCO 10,000 $6.12 TCO 10,000 $6.46 Transco 10,000 $6.67 TCO 10,000 $6.43 TCO 10,000 $6.43 TCO 10,000 $6.20 CP 10,000 $6.26 Transco 10,000 5.53 $1.00 $2.00 $3.00 10 0 20.0 30.0 40.0 50.0 10,000 $10.40 CP 10,000 $5.79 CP 10,000 $5.80 CP 20,000 $6.84 Transco 10,000 $5.14 CIG 25,000 $7.30 Transco 5,000 $5.98 CIG 5,000 $6.31 CIG 10,000 $5.13 CIG 10,000 $5.65 CIG 10,000 $5.85 CIG 10,000 $6.63 Transco 10,000 $5.77 CIG 10,000 $6.03 CIG 10,000 $6.16 CIG 10,000 $6.70 Transco 10,000 $5.99 CIG 10,000 $6.64 Transco 10,000 $6.38 Transco 10,000 $5.97 CIG 10,000 $6.00 CIG 10,000 $6.16 CIG 10,000 $5.73 CIG 10,000 $4.45 CIG 23 $- - 10.0 2010 2011 2012 2013 2014 Antero CIG Hedges Antero Transco Zone 4 Hedges Antero TCO Hedges Antero PDP Production Avg NYMEX Hedged Price Current NYMEX Strip (9/13/10) $10.23 CIG 10,000 $5.83 CIG 10,000 $6.18 CIG $4.93 CIG $5.36 CIG (1) Assumes 1,000 BTU gas (2) Using basis differentials per Wells Fargo as of 9/23/2010 $5.00 CIG , 10,000 $5.93 CIG 10,000 $6.15 CIG (Rockies) (Arkoma) (Appalachia)

Key Investment Highlights . Significant reserve potential diversified across three of the “big five” key U.S. onshore shale plays . Ability to allocate capital to most profitable projects based on commodity prices, basis differentials and local cost dynamics . No significant lease expirations; 63% of acreage HBP Diversified, stable asset base Top tier cost structure . $1.23/Mcfe estimated development cost over latest twelve months . Concentrated, low cost drilling inventory with estimated 8 Tcfe Risked Resource(1) < $1.60/Mcfe development cost . Significant infrastructure investments in Arkoma gathering, compression, processing and treating facilities in Piceance facilities . 1,783 proved drilling locations; 14,700 potential locations identified . 98% operated drilling success rate since inception . 103% compound annual growth in average net daily production since 2006 Large, low risk drilling inventory and and Marcellus gathering and water handling . Strong liquidity . Simple balance sheet . Large hedge position with 198 Bcf(2) hedged from July 1, 2010 through 2014 at approximately $6.47/Mcfe NYMEX-equivalent basin prices 60% 2011 Strong financial profile . of estimated production hedged at $6.35/MMBtu NYMEX-equivalent . Management with proven track record in tight sand and shale gas projects . Core management and technical team have worked together for many years Experienced management 24 team 1. See note on page 2 for Risked Resource definition. 2. Assumes 1,000 Btu average heat content.

Appendix 25

SEC Reserve Reconciliation SEC Reserve Reconciliation from 12/31/2009 to 6/30/2010 1,400.0 1,600.0 1,513 Bcfe Bcfe 1,141 Bcfe 600.0 800.0 1,000.0 1,200.0 865 1165 -200.0 0.0 200.0 400.0 YE 2009(1) Extensions, discoveries and additions Price and performance revisions Production MY 2010(2) 276 63 2 -21 348 298 30 Proved Developed Reserves PUDs 26 1. SEC pricing as of 12/31/09 was $3.25 / MMBtu in the Arkoma and $3.07 / MMBtu in the Piceance and $4.15 in Appalachia. Piceance reserves prepared by RS, Arkoma reserves prepared by D&M, Appalachia reserves prepared by Wright & Co. 2. Antero internally prepared 7/1/2010 SEC reserves using SEC pricing methodology. Pricing was $4.00 / MMBtu for Arkoma, $3.82 / MMBtu for Piceance and $4.31/ MMBtu for Appalachia.