Company Overview March 2014

Transcription

1 Company Overview March 2014

2 FORWARD-LOOKING STATEMENTS This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Resources Corporation and its subsidiaries (collectively, the Company or Antero ) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words believe, expect, anticipate, plan, intend, estimate, project, foresee, should, would, could, or other similar expressions are intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forwardlooking statements contained in this presentation specifically include estimates of the Company s reserves, expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced under the heading Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2013 and in the Company s subsequent filings with the SEC. The Company cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading Risk Factors in the Registration Statement and in the Company s subsequent filings with the SEC. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. 1

3 ANTERO: A PURE PLAY ON THE MARCELLUS / UTICA Critical Mass In Two World Class Shale Plays Marcellus is the largest gas field in the U.S., 2 nd largest in the world Industry production approximately 14 Bcf/d today Antero has 35 Tcfe of fully engineered and audited 3P reserves in Marcellus and Utica Shales 678 MMcfe/d of average net production in 4Q 2013 including approximately 11,100 Bbl/d of liquids Market Leading Growth 159% Appalachian production CAGR for 2010 to 2013 Most active driller in Appalachia 20 rigs running Most active driller in Marcellus Shale 15 rigs running 3 rd most active driller in the Utica Shale 5 rigs running Industry Leading Capital Efficiency and Recycle Ratio Low development cost leader: $1.03/Mcfe (1) Industry leading growth-adjusted recycle ratio: 6.1x (1) Top quartile return on productive capital: 27% for 2013E Significant Emphasis on Takeaway and Liquids Processing 1.6 Bcf/d of processing capacity and 1.7 Bcf/d of gas takeaway Liquids expected to grow from 10% of fourth quarter 2013 production to ~ 16% in 2014 due to focus on liquids-rich development Liquidity and Hedge Position Support High Growth Story ~$1.2 billion pro forma available liquidity with current $1.5 billion bank commitment (2) 1.3 Tcfe hedged through 2019 at an average index price of $4.62/MMBtu and $96.54/Bbl Outstanding Management Team Over 30 years as a team (over 20 years in unconventional) Shale Pioneers early mover and driller of over 500 horizontal shale wells in the Barnett, Woodford, Marcellus and Utica Shales 1. Three year average through 2012; pro forma for Arkoma and Piceance divestitures. 2. See page 23 for the derivation of 12/31/2013 liquidity. 2

4 PREMIER UNCONVENTIONAL RESOURCE PLATFORM TOTAL 12/31/13 RESERVES (1) Assumes Ethane Rejection Net Proved Reserves (1) 7.6 Tcfe Net 3P Reserves (1) 35.0 Tcfe Pre-Tax 3P PV-10 (1) $20,362 MM Net 3P Liquids 902 MMBbls % Liquids Net 3P 15% 4Q 2013 Net Production (2) 678 MMcfe/d - 4Q 2013 Net Liquids (2) 11,190 Bbl/d Net Acres (3) 456,000 Undrilled 3P Locations 4,778 B D C A A B C MARCELLUS SHALE Net Proved Reserves (1) 7.2 Tcfe Net 3P Reserves (1) 25.0 Tcfe Pre-Tax 3P PV-10 (1) $15,729 MM % Liquids Net 3P 17% 4Q 2013 Net Production 621 MMcfe/d Undrilled 3P Locations 3,068 UTICA SHALE LIQUIDS RICH Net Proved Reserves (1) 362 Bcfe Net 3P Reserves (1) 5.8 Tcfe Pre-Tax 3P PV-10 (1) $4,666 MM % Liquids Net 3P 15% 4Q 2013 Net Production 54 MMcfe/d Undrilled 3P Locations 759 UPPER DEVONIAN SHALE Net Proved Reserves (1) 44 Bcfe Net 3P Reserves (1) 4.2 Tcfe Pre-Tax 3P PV-10 (1) NM % Liquids Net 3P 7% 4Q 2013 Net Production 3 MMcfe/d Undrilled 3P Locations 951 Pure-Play Appalachian-Focused Shale Company 100% operated Stable acreage base Marcellus Shale: 51% HBP, with additional 21% not expiring for 5+ years Utica Shale: 20% HBP, with additional 79% not expiring for 5+ years Portfolio flexibility across dry gas to liquids-rich and condensate windows Significant investment in midstream infrastructure and secured takeaway capacity Financial flexibility to pursue planned 2014 and 2015 development drilling activities Full scale development underway 20 rigs currently operating Additional Hedge Value 1.3 Tcfe hedged from 1/1/2014 through 12/31/2019 at an average index price of $4.62/MMBtu and $96.54/Bbl ~ $760 million mark-to-market hedge value as of 2/24/2014 D UTICA SHALE DRY GAS Net Acres (3) 128,000 Net Resource 5.0 Tcfe Undrilled Locations 950 ~ 50% hedged through NYMEX; 50% hedged through regional hubs 1. Proved, probable, and possible reserves as of December 31, 2013, assuming ethane rejection using SEC methodology and SEC pricing. Evaluations prepared by our internal reserve engineers and audited by DeGolyer & MacNaughton (D&M). Pre-Tax 3P PV-10 is a non-gaap financial measure. 2. Represents the average net daily production for the period October 1, 2013 through December 31, All net acres allocated to the Dry Gas Utica and Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as they are stacked pay formations attributable to the same leases. 3

5 STRONG TRACK RECORD OF GROWTH AVERAGE NET DAILY PRODUCTION (MMcfe/d) APPALACHIAN PRODUCTION (MMcfe/d) 1,000 Woodford Piceance Marcellus Utica 950 1,000 Marcellus Utica Sold Woodford and Piceance (4) E NET PROVED SEC RESERVES (Bcfe) (2) 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1, (3) Woodford Piceance Marcellus Utica 680 1,141 3,231 Sold Woodford and Piceance 5,017 4,283 7,632 (5) (5) (4) E OPERATED GROSS WELLS SPUD Woodford Piceance Marcellus Utica (4) E 1. CAGR = Compound Annual Growth Rate. 2. Proved reserves for 2006, 2007, and 2008 represent previously effective SEC methodology. 2009, 2010, 2011, 2012 and 2013 proved reserves based on current SEC reserve methodology and SEC pricing and are audited by independent third-party engineers. 3. Includes Upper Devonian Shale proved reserves (10 Bcfe in 2012 and 44 Bcfe in 2013). 4. Per Company press release dated January 29, 2014; production mid-point of MMcfe/d guidance and 2013 proved reserves are both in ethane rejection mode. Financial Crisis

6 OUTSTANDING RESERVE GROWTH (Tcfe) PROVED RESERVE GROWTH (1) Marcellus Utica 3P RESERVE GROWTH (1) Drivers Successful drilling Expanded proved footprint (HDA) 2013 RESERVE UPDATE Proved PV-10 increased 133% to $7.0 billion (including hedges) 3P PV-10 increased 82% to $21.4 billion (including hedges) Replaced 1,857% of 2013 production All-in finding cost of $0.58/Mcfe 2013 top-down development cost of $1.25/Mcfe 2013 bottoms-up development cost of $1.10/Mcfe Only 14% of 1P and 58% of 3P locations booked as SSL (1.73 Bcf/1,000 type curve) No Utica Shale WV/PA dry gas reserves booked FUTURE RESERVE GROWTH DRIVERS (Tcfe) Marcellus Utica Upper Devonian Drivers 80,000 net acres added in 2013 SSL results Utica results Driver Marcellus SSL completions Full scale Utica program Utica increased density drilling Utica dry gas drilling Core acreage acquisitions 2014 Action Complete transition to SSL type curve 41 wells to be completed; only 21 PUD locations booked as proved at YE 2013 Drilling 2 increased density pilots in Utica Drilling first Utica dry gas well in WV (126,000 net acres WV/PA) $200 million leasehold budget and 2013 reserves assume ethane rejection. 5

7 MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW-RISK, HIGH-RETURN GROWTH PROFILE MARCELLUS SSL WELL ECONOMICS (1)(2) UTICA WELL ECONOMICS (1) ROR 150% 100% 50% 0% % Highly-Rich Gas/ Condensate 65% Highly-Rich Gas Locations 890 1, % 21% 0 Rich Gas ROR Dry Gas 71% of Marcellus locations are processable (1100-plus Btu) Large Inventory of Low Breakeven Projects (3) Total 3P Locations ROR 200% 150% 100% 50% 0% % Highly-Rich Gas/ Condensate 169% Highly-Rich Gas Locations % Rich Gas ROR % Dry Gas 72% of Utica locations are processable (1100-plus Btu) Total 3P Locations $ / MMBtu NYMEX (Gas) $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 2,726 Antero Liquids-Rich Locations 366 Locations $0.00 $0.00 $0.00 $ Yr Strip - $4.38/MMBtu (4) $2.47 $2.50 $2.60 $2.94 $3.20 $3.51 $3.65 $3.66 $3.70 $ ,541 Locations Locations 637 Locations $0.89 $1.15 ` 890 Locations $3.75 $3.80 $3.81 $4.13 $4.25 $4.66 $5.05 $5.37 $ Well economics based on 12/31/2013 3P SSL reserves and strip pricing as of 12/31/ A portion of these locations do not assume SSL completions. 3. Source: Credit Suisse report dated January 2014 Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI year NYMEX STRIP as of 2/24/

8 LOW DEVELOPMENT COST DRIVES BEST-IN-CLASS RECYCLE RATIOS 3-Year All-in Development Costs ($/Mcfe) through 2012 $/Mcfe $4.00 $3.00 Antero Appalachia-Focused Peers $2.00 $1.00 $1.03 $1.14 $1.41 $1.57 $1.71 $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 x 6.0x 6.1x Antero Appalachia-Focused Peers 4.0x 3.5x 3.1x 2.7x 2.0x 0.0x Source: Wall Street research. Defined as average (Cash Operating Netback / PD F&D costs) x ( production CAGR). PD F&D Costs defined as total drilling and completion capital expenditures for the period divided by PDP and PDNP volumes added after adding back production for the period per JP Morgan analysis. Includes all drilling and completion costs but excludes land and acquisition costs for all companies. 1. Antero data pro forma for Woodford and Piceance divestitures; Antero production growth based on first half of 2013 only. 7

9 MARCELLUS/UTICA ADVANTAGED ECONOMICS Low-cost, liquids-rich Utica and Marcellus Shales will remain attractive in most commodity price environments U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE (1) Downside risks to breakeven costs for older shale plays once exploration resumes with higher natural gas prices?? Over 2,700 Antero Drilling Locations Needed to make up for base declines in conventional and GOM production Utica Shale SW (Rich) Marcellus Shale Permian NE (Dry) Marcellus Shale??? Eagle Ford Shale Granite Wash Niobrara Barnett Haynesville 1. Source: Credit Suisse report dated January 2014 Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI 8

10 INTEGRATED MIDSTREAM PROCESSING AND TAKEAWAY Infrastructure and commitments in place to handle strong natural gas, NGL and oil production growth Portfolio of firm transportation and sales and West Virginia location minimizes basis risk Producers located in northern West Virginia have seen much less basis widening and volatility than Pennsylvania producers Antero sold ~67% of its 2013 production at TCO index at NYMEX less $0.06/MMbtu prior to the Btu upgrade Leidy Basis to NYMEX Current $2.78 -$2.17 Dom South Basis to NYMEX Current $0.17 -$0.93 Antero Transport and Processing Firm Transport (FT) (MMBtu/d) 1,369,000 1,407,000 Firm Sales (MMBtu/d) (1) 330, ,000 Chicago Basis to NYMEX Current $3.23 -$0.07 Firm Processing Capacity (Mcf/d) 1,400,000 1,550,000 Ethane FT (Bbl/d) 20,000 20,000 1,600 Growing Processing Capacity Total Capacity 1,550 TCO Basis to NYMEX Current $0.13 -$0.43 (MMcf/d) 1,400 1,200 1, Seneca II Seneca I Sherwood III Sherwood II Sherwood I Marcellus Seneca III Sherwood IV Sherwood V Seneca IV Sherwood I Sherwood II Sherwood III Sherwood IV Sherwood V 2013 % of Production Sold TCO 67% Dom South 22% TETCO 5% NYMEX 6% CGTLA Basis to NYMEX Current $0.02 -$0.09 TCO Dom South TETCO M2 Leidy Appalachian Basis to NYMEX (2) $0.20 -$0.60 -$1.00 -$1.40 -$1.80 -$2.20 Utica Seneca I Seneca II Seneca III Seneca IV -$ ,000 MMBtu/d and 70,000 MMbtu/d also utilize firm transportation in 2014 and 2015, respectively. 2. Basis data from Wells Fargo daily indications and various private quotes as of 2/24/

11 LONG HAUL PIPELINE AND TRANSPORTATION NETWORK Antero has a leading firm transportation capacity position and is well-positioned in the southern portion of the Marcellus and Utica Shale from a gas takeaway perspective Chicago Basis to NYMEX Current $3.23 -$0.07 Leidy Basis to NYMEX Current $2.78 -$2.17 (1) Dom South Basis to NYMEX Current $0.17 -$0.93 TCO Basis to NYMEX Current $0.13 -$0.43 Appalachian Firm Transportation/Sales Commitment by Operator CGTLA Basis to NYMEX Current $0.02 -$0.09 Mcf/d 2,000,000 1,600,000 1,200, , ,000 Firm Sales Firm Transportation 0 (2) AR RRC EQT CNX COG CHK TLM STO SWN WPX RDS APC NFG Source: Tudor Pickering & Holt research report dated 9/3/2013 and company presentations, press releases. Note: Antero firm transportation and firm sales positions listed by pipeline in colored-coded boxes. 1. Firm transport as of year-end See Page 27 for timing of firm transportation graph. 2. Antero firm transportation as of 2/24/2014; includes 250 MMcf/d of firm sales. 10

12 SIGNIFICANT LONG-TERM COMMODITY HEDGE POSITION NATURAL GAS HEDGES 2/24/2014 BBtu/d Hedged Volume Average Index Price ($/MMBtu) (1) NYMEX Strip (2/24/2014) ($/MMBtu) $4.92 $4.91 $4.71 $4.34 $4.65 $4.46 $4.85 $4.20 $4.09 $4.10 $4.14 $ $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $ Reflects weighted average index price per annum based on volumes hedged and 6:1 gas to oil ratio. Antero has hedged ~3,000 Bbl/d for 2014, WTI hedges comprise ~1% of overall hedge book. ~$760 million mark-to-market unrealized gain as of February 24, Tcfe hedged from January 1, 2014 through year-end 2019 % HEDGE VOLUMES BY INDEX 2/24/2014 NYMEX 50% Chicago 2% 12% TCO 18% Dom South 18% CGTLA 11

13 ASSET OVERVIEW 12

14 WORLD-CLASS POSITION IN THE CORE OF THE MARCELLUS AND UTICA LIQUIDS-RICH FAIRWAYS Utica Shale Liquids-Rich Fairway ANTERO LIQUIDS-RICH UTICA SHALE 106,000 Net Acres 18 Horizontals Completed 5 Rigs Currently Running Marcellus Shale Southwestern & Northeastern Core Areas Utica Shale Core Area Marcellus Shale Liquids-Rich Fairway ANTERO MARCELLUS SHALE SW PA 25,000 Net Acres 2 Horizontals Completed Strong Results ANTERO MARCELLUS SHALE NW WV 325,000 Net Acres (Primarily Liquids-Rich Fairway) 234 Horizontals Completed 15 Rigs Currently Running Utica Shale Dry Gas Resource Underlies Marcellus Acreage Source: Company presentations and press releases. Upper Devonian Shale Resource Overlies Marcellus Acreage 13

15 WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT Antero Has Delineated And De-Risked Its Large Scale Acreage Position 100% operated 350,000 net acres in Southwestern Core 51% HBP with additional 21% not expiring for 5+ years 236 horizontal wells completed and online Laterals average 7, % drilling success rate Net production of 621 MMcfe/d in 4Q 2013, including 8,900 Bbl/d of liquids MHR WEESE UNIT 30-Day Rate 4-well average 9.3 MMcfe/d (31% liquids) CHK HADLEY UNIT 24-Hour IP 9.1 MMcfe/d (32% liquids) EQT PENN 15 UNIT 30-Day Rate 5-well average 9.3 MMcfe/d (29% liquids) BLANCHE UNIT 30-Day Rate 2H: 10.0 MMcfe/d (29% liquids) DOTSON UNIT 30-Day Rate 1H: 12.4 MMcfe/d 2H: 11.8 MMcfe/d (27% liquids) EQT 30-Day Rate 12 Recent Wells 9.2 MMcfe/d (20% Liquids) MOORE UNIT 30-Day Rate 1H: 9.9 MMcfe/d 2H: 10.0 MMcfe/d (17% liquids) Sherwood Processing Plant 142 Horizontals Completed 30-Day Rate 10.3 Bcf average EUR 8.1 MMcf/d 6,915 average lateral length 3,068 future drilling locations in the Marcellus (71% are processable) Operating 15 drilling rigs including 4 shallow rigs 25.0 Tcfe of net 3P (17% liquids), includes 7.2 Tcfe of proved reserves (assuming ethane rejection) CONSTABLE UNIT 30-Day Rate 1H: 15.2 MMcfe/d (30% liquids) PRUNTY UNIT 30-Day Rate 1H: 11.0 MMcfe/d (29% liquids) HINTERER UNIT 30-Day Rate 1H: 12.9 MMcfe/d (20% liquids) RUTH UNIT 30-Day Rate 1H: 19.3 MMcfe/d (14% liquids) Highly-Rich/Condensate 60,000 Net Acres 637 Gross Locations Highly-Rich Gas 100,000 Net Acres 834 Gross Locations Rich Gas 86,000 Net Acres 707 Gross Locations Dry Gas 104,000 Net Acres 890 Gross Locations Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned. Note: Rates assume ethane rejection. 14

16 MARCELLUS SIMPLE STRUCTURE Several regional anticlines in core area Predictable layer cake geology No faults at Marcellus level Over 1.7 million feet (315 miles) drilled horizontally without crossing a fault 3-D seismic not required to guide horizontal wells Regional East-West seismic line shows gentle structure at Marcellus level Allegheny Front and complex structure located many miles east of core area Favorable geology allows for longer laterals Regional Seismic Line Average Marcellus Lateral Lengths 8,000 7,300 Feet 6,000 4,000 2, ,800 4,500 4,100 Antero EQT RRC COG 100 Contours Top Marcellus W Profile along regional seismic line (time) Big Moses Arches Fork Wolf Summit No Data Benson Rhinestreet Tully Marcellus Onondaga E Source: Company presentations. 15

17 ANTERO S MARCELLUS SHALE TYPE CURVE SUPPORT Antero has over four years of production history to support its 1.5 Bcf/1,000 type curve (non-ssl) Antero s SSL type curve has been increased to 1.73 Bcf/1,000 with only 12% higher well costs Lack of faulting and contiguous acreage position allows for drilling of long laterals ~ 7,300 Drives down costs per 1,000 of lateral resulting in best-in-class development costs MMcf/d Marcellus Type Curve Normalized to 7,000 Lateral Antero Non-SSL Type Curve Non-SSL Type Curve Cumulative Production SSL Actual Production (2) 24-Hour Peak Rate 30-Day Avg. Rate 90-Day Avg. Rate 180-Day Avg. Rate Actual Non-SSL Production (1) 1.7 Bcf/1,000' SSL Type Curve One-Year Avg. Rate Two-Year Avg. Rate Three-Year Avg. Rate Wellhead (MMcf/d) # of wells Cumulative Bcf Production Year EURs Increase With Lateral Length Well Cost / 1,000 Decreases with Lateral Length Wellhead 24-hour Peak Rates (IPs) Wells EUR, BCF ,000 4,000 6,000 8,000 10,000 Lateral Length, ft Antero Marcellus wells normalized to time zero, production for each well normalized to 7,000 lateral length Antero Marcellus SSL wells normalized to time zero, production for each well normalized to 7,000 lateral length. $MM / 1,000' $1.8 $1.6 $1.4 $1.2 $1.0 $0.8 $0.6 2,000 4,000 6,000 8,000 10,000 Lateral length, ft MMcf/d Average IP 14.3 MMcf/d 1st Production from All Wells

18 MARCELLUS SINGLE WELL ECONOMICS ASSUMES ETHANE REJECTION Assumptions 12/31/2013 Strip Pricing & SEC Reserves NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL (2) ($/Bbl) 2014 $4.24 $95 $ $4.16 $88 $ $4.09 $83 $ $4.09 $80 $ $4.14 $79 $50 Marcellus SSL Well Economics and Total Locations (1) ROR 150% 100% 50% 0% % Highly-Rich Gas/ Condensate 65% % 890 Highly-Rich Gas Rich Gas Dry Gas Locations ROR 21% 0 1, Total 3P Locations Classification Highly-Rich/ Condensate Highly-Rich Gas Rich Gas Dry Gas BTU Range <1100 Modeled BTU EUR (Bcfe): EUR (MMBoe) : % Liquids: 34% 24% 12% 0% Lateral Length (ft): 7,000 7,000 7,000 7,000 Stage Length (ft): Well Cost ($MM): $9.5 $9.5 $9.5 $9.5 Bcf/1,000 : Bcfe/1,000 : HIGHLY RICH GAS Pre-Tax NPV10 DRY ($MM): GAS LOCATIONS RICH $20.5 GAS LOCATIONS $13.7 LOCATIONS $6.6 $3.7 Pre-Tax ROR: 117% 65% 32% 21% Net F&D ($/Mcfe): $0.68 $0.75 $0.84 $0.92 Payout (Years): Gross 3P Locations: Well economics are based on 12/31/2013 proved SSL reserves (P90) and strip pricing. Includes gathering, compression and processing fees. A portion of the locations do not include SSL completions. 2. Pricing for a 1225 BTU y-grade rejection barrel. 17

19 SHORTER STAGE LENGTHS ( SSL ) ENHANCING MARCELLUS RECOVERIES Enhancing Recoveries Shorter stage length (SSL) summary: 32 SSL wells completed 22 SSL wells have at least 30 days of production history 150 to 225 (SSL) vs. 350 stages previously 31% higher 30-day wellhead rate for first 22 SSL wells vs. the Antero type curve 27% higher 120-day rate vs. the Antero type curve Other Marcellus operators have indicated 20% to 30% improvement in IPs and EURs The 30-day processed rate for Antero s first 22 SSL wells has averaged 42% higher than the Antero type curve Estimated 12% increase in well costs for SSL completions as compared to non-ssl Gas Production (Mcfe/d) 10, day Rate Normalized production increase for 22 SSL wells vs. 1.5 Bcf/1,000' Type Curve 1.5 Bcf/1,000 Type Curve SSL vs Non-SSL Wellhead Average Rate Comparison 60-day 90-day 120-day Rate Rate Rate SSL Well Count SSL Avg Wellhead Rate MMcf/d(1) Wellhead Type Curve MMcf/d(2) SSL % Rate Improvement 31% 21% 24% 27% SSL Avg Processed Rate MMcfe/d(1) Processed Type Curve MMcfe/d(3) SSL % Rate Improvement 42% 32% 34% 38% (1) Wellhead condensate production is converted on a 6:1 basis (2) 1.5 Bcf/1,000 Type Curve. (3) 1.5 Bcf/1,000 Type Curve processed assuming 1225 BTU. 1, Days From Peak Gas Antero Type Curve SSL Average Wellhead SSL Average Processed 18

20 EXCITING CORE UTICA SHALE POSITION DELIVERS CONDENSATE AND NGLS 100% operated 106,000 net acres in the core rich gas / condensate window 20% HBP with additional 79% not expiring for 5+ years 75% of acreage has rich gas processing potential 18 Antero-operated horizontal wells completed and online 100% drilling success rate Net production of 54 MMcfe/d in 4Q 2013 including 2,200 Bbl/d of liquids First production in early August 2013 had access to Cadiz pipeline and processing Seneca I processing plant came online in November 2013 and Seneca II came online in January 2014 First 120 MMcf/d compressor station went into service in late January with an additional 120 MMcf/d compressor station expected by late 1Q future drilling locations Approximately 15% of EUR is liquids assuming ethane rejection Operating 5 rigs including 1 shallow rig 5.8 Tcfe of net 3P (15% liquids), includes 362 Bcfe of proved reserves (assuming ethane rejection) Utica Shale Industry Activity (1) REXX 24-Hour IP Guernsey 1H, 2H, Noble 1H Average 7.9 MMcf/d + 1,192 Bbl/d NGL Bbl/d Oil GULFPORT 24-Hour IP Boy Scout 1-33H, Ryser 1-25H, Groh 1-12H Average 5.3 MMcf/d Bbl/d NGL + 1,411 Bbl/d Oil WAYNE UNIT 30-Day Rate 3 wells average 5.4 MMcf/d Bbl/d NGL Bbl/d Oil MILEY UNIT 30-Day Rate 2 wells average 3.0 MMcf/d Bbl/d NGL Bbl/d Oil COAL UNIT 1H 24-Hour IP 11.8 MMcf/d + 2,063 Bbl/d NGL + 1,850 Bbl/d Oil Highly-Rich/Cond 30,000 Net Acres 205 Locations Seneca Processing Plant CHESAPEAKE 24-Hour IP Buell #8H 9.5 MMcf/d + 1,425 Bbl/d liquids MILLIGAN UNIT 24-Hour IP 3 wells average 11.3 MMcf/d + 1,971 Bbl/d NGL + 1,586 Bbl/d Oil Highly-Rich Gas 25,000 Net Acres 161 Locations Cadiz Processing Plant GULFPORT 24-Hour IP Wagner 1-28H, Shugert 1-1H, 1-12H Average 21.0 MMcf/d + 2,270 Bbl/d NGL Bbl/d Oil RUBEL UNIT 30-Day Rate 3 wells average 13.5 MMcf/d Bbl/d NGL + 45 Bbl/d Oil NORMAN UNIT 1H 30-Day Rate 13.6 MMcf/d Bbl/d NGL + 2 Bbl/d Oil GULFPORT 24-Hour IP McCort1-28H, 2-28H, Stutzman 1-14H Average 13.1 MMcf/d Bbl/d NGL + 21 Bbl/d Oil YONTZ UNIT 1H 30-Day Rate 14.6 MMcf/d Bbl/d NGL + 1 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. Note: Third party peak rates assume ethane recovery; Antero 24-hour peak rates assume ethane recovery; Antero 30-day rates assume ethane rejection. 1. For non-antero wells, Antero has converted rich gas rates where BTU has been disclosed to NGLs, assuming ethane recovery. Where BTU has not been disclosed, Antero has estimated BTU and gas composition. Utica Core Area Rich Gas 24,000 Net Acres 182 Locations GARY UNIT 1H 30-Day Rate 23.1 MMcf/d + 1,023 Bbl/d NGL + 65 Bbl/d Oil Dry Gas 27,000 Net Acres 211 Locations DOLLISON UNIT 1H 24-Hour IP 10.2 MMcf/d + 1,488 Bbl/d NGL + 1,397 Bbl/d Oil 19

21 ANTERO HAS MOST OF THE TOP UTICA 24-HOUR IPS STRONG SUPPORT FOR CORE POSITION Antero has 11 of the top 12 Utica 24-hour peak rates (IPs) announced to date Represent some of the best 24- hour peak rates of any shale play in North America 20 to 53 MMcfe/d per well 24- hour peak rate in the core area Excellent reservoir pressure with gradients in the 0.7 psi/ft range UTICA 24-HOUR IPs Core 12 to 53 MMcfe/d IPs Liquids content ranges from 40%-70% (assumes ethane recovery) in the liquids-rich window Antero recently announced 30- day rates on some of these wells (see page 29) MMcfe/d Tier 1 6 to 12 MMcfe/d IPs Source: Antero, press releases and company presentations. Note: Assumes ethane recovery. Antero Utica Wells 3rd Party Core Utica Wells 3rd Party Non-Core Utica Wells 20

22 UTICA SINGLE WELL ECONOMICS ASSUMES ETHANE REJECTION Assumptions Utica Well Economics and Locations (1) 12/31/2013 Strip Pricing & SEC Reserves 200% NYMEX ($/MMBtu) Classification WTI ($/Bbl) C3+ NGL (2) ($/Bbl) 2014 $4.24 $95 $ $4.16 $88 $ $4.09 $83 $ $4.09 $80 $ $4.14 $79 $49 ROR 150% 100% 50% 0% 137% Highly-Rich Gas/ Condensate Highly-Rich/ Condensate Highly-Rich Gas Rich Gas Dry Gas BTU Range <1100 Modeled BTU EUR (Bcfe): EUR (MMBoe) : % Liquids 32% 23% 15% 0% Lateral Length (ft): 7,000 7,000 7,000 7,000 Stage Length (ft): Well Cost ($MM): $11.0 $11.0 $11.0 $11.0 Bcf/1,000 : Bcfe/1,000 : HIGHLY RICH GAS LOCATIONS Pre-Tax NPV10 ($MM): $15.7 $26.6 $18.4 $11.7 DRY GAS LOCATIONS RICH GAS LOCATIONS Pre-Tax ROR: 137% 169% 95% 56% Net F&D ($/Mcfe): $1.21 $0.66 $0.72 $0.82 Payout (Years): Gross 3P Locations (3) : % 1. Well economics are based on 12/31/2013 proved (P90) reserves and strip pricing. Includes gathering, compression and processing fees. 2. Pricing for a 1225 BTU y-grade rejection barrel. 3. Gross 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content % % Highly-Rich Gas Rich Gas Dry Gas Locations ROR Total 3P Locations 21

23 LARGE MIDSTREAM FOOTPRINT Antero Midstream estimated cumulative YE 2014 total capital investment in midstream ~ $1,580 million Includes gathering lines, compressor stations and water distribution infrastructure Proprietary water sourcing and distribution system Improves operational efficiency and reduces water truck traffic Cost savings of $600,000 -$800,000 per well One of the benefits of a consolidated acreage position Utica Shale Marcellus Shale Projected Midstream Infrastructure (1) Marcellus Shale Utica Shale Total YE 2014E Cumulative Gathering / Compression Capex ($MM) $835 $295 $1,130 Gathering Pipelines (Miles) Compression Capacity (MMcf/d) 410 N/A 410 Ohio River Withdrawal System Completed YE 2014 Cumulative Water System Capex ($MM) $350 $100 $450 Water Pipeline (Miles) Water Storage Facilities YE 2014E Total Midstream ($MM) $1,185 $395 $1,580 Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned. 1. Represents inception to date actuals as of 9/30/2013 and remaining 2013 and 2014 budget. 22

24 PRO FORMA CAPITALIZATION CAPITALIZATION (PF Financing) ($ in millions) 12/31/ /31/2013 (2) Cash $17 $17 Senior Secured Revolving Credit Facility % Senior Notes Due % Senior Notes Due % Senior Notes Due ,000 1,000 Net Unamortized Premium 6 6 Total Debt $2,079 $2,079 Net Debt $2,062 $2,062 Shareholders' Equity $3,599 $3,599 Net Book Capitalization $5,660 $5,660 Net Market Capitalization (1) $17,328 $17,328 Financial & Operating Statistics LTM EBITDAX $649 $649 LTM Interest Expense (2) $137 $106 Proved Reserves (Bcfe) (12/31/2013) 7,632 7,632 Proved Developed Reserves (Bcfe) (12/31/2013) 2,023 2,023 Credit Statistics Net Debt / LTM EBITDAX 3.2x 3.2x LTM EBITDAX / Interest Expense 4.8x 6.1x Net Debt / Net Book Capitalization 36.4% 36.4% Net Debt / Net Market Capitalization 11.9% 11.9% Net Debt / Proved Developed Reserves ($/Mcfe) $1.02 $1.02 Net Debt / Proved Reserves ($/Mcfe) $0.27 $0.27 Liquidity Credit Facility Commitments (3) $1,500 $1,500 Less: Borrowings (288) (288) Less: Letters of Credit (32) (32) Plus: Cash Liquidity (Credit Facility + Cash) $1,197 $1, Equity valuation based on million shares outstanding and a share price of $58.27 as of 2/24/2014. Enterprise value includes net debt. 2. Pro forma interest expense adjusted for $1,578 million net proceeds from IPO priced on 10/14/2013 and $1,000 million 5.375% Senior Notes priced on 10/24/2013 net of fees; assumes $525 million 9.375% Senior Notes, $25 million 9.00% Senior Note and $140 million 7.25% Senior Notes repaid at beginning of year along with residual cash used to repay bank debt. 3. Lender commitments under the facility reduced to $1.5 billion from $1.75 billion on 10/21/2013; commitments can be expanded to the full $2.0 billion borrowing base upon bank approval. 23

25 HEALTH, SAFETY, ENVIRONMENT & COMMUNITY Protection Of Our People And The Environment Is An Antero Core Value Strong West Virginia Presence Over 75% of Antero Marcellus employees and contract workers are West Virginia residents Antero named Business of the Year for 2013 in Harrison County, West Virginia For outstanding corporate citizenship and community involvement 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 Keys to Execution Pad Impact Mitigation Green Completion Units Central Fresh Water System & Water Recycling Natural Gas Powered Drilling Rigs Natural Gas Vehicles (NGV) Safety & Environmental Local Presence LEED Gold Headquarters Building Closed loop mud system no mud pits Protective liners or mats on all well pads in addition to berms All Antero well completions use green completion units for completion flowback, essentially eliminating methane emissions (full compliance with EPA 2015 requirements) 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 Nine of Antero s contracted drilling rigs are currently running on natural gas 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 Five company safety representatives and 45 safety consultants cover all material field operations 24/7 including drilling, completion, construction and pipelining 23-person company environmental staff plus outside consultants monitor all operations and perform baseline water well testing Land office in Ellenboro, WV Recently moved into new 50,000 square foot district office in Bridgeport, WV 105 of Antero s 258 employees are located in West Virginia and Ohio Antero s new corporate headquarters in Denver has been LEED Gold Certified Completion expected by spring of

26 ANTERO KEY ATTRIBUTES 456,000 Net Acres in the Core Marcellus and Utica Shales Triple Digit Historical Production and Reserve Growth Low Cost Leader / High Return Projects Significant Takeaway and Processing Capacity Already in Place Clean Balance Sheet Supports High Growth Story Forward Thinking Management Team with a History of Success 25

27 APPENDIX 26

28 ANTERO FIRM TRANSPORTATION AND FIRM SALES Columbia Firm Sales #1 Firm Sales #2 Firm Sales #3 7/26/2009 9/30/ /1/ /31/ /1/2011 5/31/2017 1/1/2013 5/31/2022 Momentum III 9/1/ /31/2021 EQT 8/1/2012 8/31/2021 Chicago Direct 4/1/2013 9/30/2021 MMBtu/d 1,800,000 1,600,000 1,400,000 1,200,000 1,000, , , , ,000-27

29 ANTERO UTICA SHALE WELLS 24 HOUR IPS 24 hr Peak Rate Lateral Well Gas Equivalent Rate Wellhead Gas Shrunk Gas NGL Condensate % Total Length Name County (MMcfe/d) (MMcf/d) (MMcf/d) (Bbl/d) (Bbl/d) Liquids BTU (Feet) Yontz 1H Monroe , % ,115 Rubel 1H Monroe , % ,554 Gary 2H Monroe , % ,882 Rubel 3H Monroe , % ,424 Milligan 2H Noble ,361 2,087 68% ,989 Rubel 2H Monroe , % ,571 Norman 1H Monroe , % ,498 Coal 3H Noble ,063 1,850 67% ,768 Wayne 3HA Noble ,018 1,905 67% ,712 Wayne 4H Noble ,907 1,922 67% ,493 Milligan 3H Noble ,111 1,228 62% ,267 Dollison 1H Noble ,488 1,397 63% ,253 Milligan 1H Noble ,461 1,442 68% ,436 Wayne 2H Noble ,503 1,331 67% ,094 Miley 2H Noble ,172 1,450 70% ,153 Miley 5HA Noble ,090 1,285 70% ,296 Average Ethane Recovery (1) ,178 1,042 58% ,407 Average Ethane Rejection (2) ,042 40% , 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. 2. Average of Antero s first 16 core area wells, assuming ethane rejection. 28

30 ANTERO UTICA SHALE WELLS 30-DAY RATES Antero s wells have been producing against 1,100 psi line pressure due to lack of compression facilities First 120 MMcf/d compressor station started up in late January Day Rates Antero Core Area Lateral Well Gas Eq. Rate Wellhead Gas Shrunk Gas NGL Condensate % Total Estimated Length Name County (MMcfe/d) (MMcf/d) (MMcf/d) (Bbl/d) (Bbl/d) Liquids BTU (Feet) Gary 2H Monroe , % ,882 Rubel 2H Monroe % ,571 Rubel 3H Monroe % ,424 Yontz 1H Monroe % ,115 Norman 1H Monroe % ,498 Rubel 1H Monroe % ,554 Wayne 2H Noble % ,094 Wayne 3HA Noble % ,712 Wayne 4H Noble % ,493 Miley 2H Noble % ,153 Miley 5HA Noble % ,296 Average Ethane Rejection % ,436 Average Ethane Recovery (1) , % , Average of Antero s first 11 core area wells, assuming ethane recovery. 29

31 CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY 40 year proved reserve life based on 2013E production Reserve base provides significant exposure to liquids-rich projects 3P reserves of over 2.2 BBbl of NGLs and condensate in ethane recovery mode; 33% liquids ETHANE REJECTION (1) ETHANE RECOVERY (1) Marcellus 25.0 Tcfe Utica 5.8 Tcfe Upper Devonian 4.2 Tcfe 35.0 Tcfe Marcellus 29.5 Tcfe Utica 6.7 Tcfe Upper Devonian 4.7 Tcfe 40.8 Tcfe Gas 29.6 Tcf Oil 91 MMBbls NGLs 811 MMBbls 15% Liquids Gas 27.4 Tcf Oil 91 MMBbls NGLs 2,151 MMBbls 33% Liquids 1. Ethane rejection occurs when ethane is left in the wellhead gas stream as the gas is processed, rather than being separated out and sold as a liquid after fractionation. When ethane is left in the gas stream, the BTU content of the residue gas at the outlet of the processing plant is higher. Producers will elect to reject ethane when the price received for the higher BTU residue gas is greater than the price received for the ethane being sold as a liquid after fractionation. When ethane is recovered, the BTU content of the residue gas is lower, but a producer is then able to recover the value of the ethane sold as a separate NGL product. 30

32 MARCELLUS SHALE RICH GAS LIQUIDS AND PROCESSING UPGRADE Marcellus Shale rich gas and highly-rich gas acreage provides a significant advantage in well economics assuming $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current spot NGL pricing ($/Mcf) $/Wellhead Mcf (1)(2) +$4.13 Upgrade $9.00 +$2.79 Upgrade $8.28 $8.00 $7.00 $6.00 $5.00 $4.00 $4.15 +$1.04 Upgrade $5.19 NGLs (C3+) $1.30 $6.95 NGLs (C3+) $2.93 Condensate $0.16 NGLs (C3+) $3.92 Condensate $0.56 $3.00 $2.00 $1.00 $0.00 Gas $ BTU Gas $3.90 (1076 BTU) 8% shrink Gas $3.86 (1109 BTU) 12% shrink Gas $ BTU 1250 BTU 1300 BTU (1119 BTU) 14% shrink Dry Gas Dry Gas Highly Rich Gas Highly Rich/ Condensate Current Ethane Rejection 1. Assumes $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current NGL spot prices and (ethane rejection) and and (ethane recovery) GPM s used, all processing costs, shrink and fuel included. No ethane takeaway available until Enterprise ethane pipeline is online (expected 1Q 2014). Ethane recovery well economics include fixed fee cost tariff on ATEX ethane pipeline. 2. NGL prices as of 2/3/2014 from IntercontinentalExchange. 31

33 2013 REALIZATIONS 2013 NATURAL GAS REALIZATIONS ($/MCF) 2013 % Sales Average NYMEX Price Average Differential (2) Average BTU Upgrade Average 2013 Realized Price 2013 NGL Y-GRADE (C3+) REALIZATIONS Average Premium / (Discount) TCO 67% $3.65 $(0.06) $0.42 $4.02 $0.37 Dominion South 22% $3.65 $(0.41) $0.39 $3.64 $(0.01) NYMEX (1) 6% $3.65 $(0.40) $0.39 $3.65 TETCO 5% $3.65 $(0.26) $0.41 $3.80 $0.15 Total 100% $3.65 $(0.16) $0.42 $3.90 $ % 17% 2% 55% Ethane (C2) Propane (C3) Iso Butane (C4) Normal Butane Natural Gasoline $14.57 $0.72 $ % $7.55 $6.27 Antero Barrel 1. NYMEX differential represents contractual deduct to NYMEX-based sales. 2. Includes firm sales. 3. Based on monthly prices through 12/31/2013 WTI. Total $52.61 per Bbl 54% of WTI (4) 32

34 POSITIVE RATINGS MOMENTUM Moody s / S&P Historical Credit Ratings Moody s Upgrade Criteria An upgrade could be considered if debt / average daily production is sustained below $20,000 per boe and debt / proved-developed reserves is sustained below $8.00 per boe. An upgrade would also be contingent on Antero maintaining unleveraged cash margins greater than $25.00 per boe and retained cash flow to debt over 40% as it builds out infrastructure needs to support production growth. S&P Upgrade Criteria We would consider a positive rating action if the company continued to convert its PUD reserves to proved developed reserves and improved profitability, while maintaining leverage below 3x. - S&P Credit Research, October Moody s Credit Research, October 2013 Credit Rating (Moody s / S&P) Baa3 / BBB- Ba1 / BB+ Ba2 / BB Ba3 / BB- B1 / B+ B2 / B B3 / B- Caa1 / CCC+ 9/1/2010 2/24/2011 5/27/2011 8/27/2011 2/28/ /28/2011 5/31/ /21/2013 2/18//2014 Moody's (1) S&P 1. Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC. 33

35 ANTERO EBITDAX RECONCILIATION EBITDAX Reconciliation ($ in millions) (12 Months Ended) Antero Resources LLC 12/31/ /31/2013 EBITDAX: Net income (loss) from continuing operations $225.3 $(24.2) Commodity derivative fair value (gains) losses (179.5) (491.7) Net cash receipts on settled commodity derivatives instruments (Gain) loss on sale of assets (291.2) - Interest expense and other Loss on early extinguishment of debt Provision (benefit) for income taxes Depreciation, depletion, amortization and accretion Impairment of unproved properties Exploration expense Stock compensation expense Other EBITDAX from continuing operations $284.7 $649.4 EBITDAX: Net income (loss) from discontinued operations ($510.3) 5.3 Commodity derivative fair value (gains) losses (46.4) - Net cash receipts on settled commodity derivatives instruments (Gain) loss on sale of assets (8.5) Provision (benefit) for income taxes (272.6) 3.2 Depreciation, depletion, amortization and accretion Impairment of unproved properties Exploration expense EBITDAX from discontinued operations $ EBITDAX $434.3 $

36 CAUTIONARY NOTE Regarding Hydrocarbon Quantities The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates (collectively, 3P ). Antero has provided internally generated estimates for proved, probable and possible reserves in this presentation in accordance with SEC guidelines and definitions. The estimates of proved, probable and possible reserves as of December 31, 2013 included in this presentation have been audited by Antero s third-party engineers. Unless otherwise noted, reserve estimates are as of December 31, 2013, assuming ethane rejection and strip pricing. Actual quantities that may be ultimately recovered from Antero s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of Antero s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. In this presentation: 3P reserves refer to Antero s estimated aggregate proved, probable and possible reserves as of December 31, The SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. EUR, or Estimated Ultimate Recovery, refers to Antero s internal estimates of per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer s Petroleum Resource Management System or the SEC s oil and natural gas disclosure rules. Highly-rich/condensate refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1250 BTU and 1300 BTU in the Utica Shale. Highly-rich gas refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and 1250 BTU in the Utica Shale. Rich gas refers to gas having a heat content of between 1100 BTU to 1200 BTU. Dry gas refers to gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use. 35