Company website presentation march 2014v2

  • 909 views
Uploaded on

 

  • Full Name Full Name Comment goes here.
    Are you sure you want to
    Your message goes here
    Be the first to comment
    Be the first to like this
No Downloads

Views

Total Views
909
On Slideshare
0
From Embeds
0
Number of Embeds
2

Actions

Shares
Downloads
3
Comments
0
Likes
0

Embeds 0

No embeds

Report content

Flagged as inappropriate Flag as inappropriate
Flag as inappropriate

Select your reason for flagging this presentation as inappropriate.

Cancel
    No notes for slide

Transcript

  • 1. Company Overview March 2014
  • 2. FORWARD-LOOKING STATEMENTS This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Resources Corporation and its subsidiaries (collectively, the “Company” or “Antero”) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “estimate,” “project,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, 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 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 ● Marcellus is the largest gas field in the U.S., 2nd largest in the world – Industry production approximately 14 Bcf/d today ● Antero has 35 Tcfe of fully engineered and audited 3P reserves in Marcellus and Utica Shales ● 678 MMcfe/d of average net production in 4Q 2013 including approximately 11,100 Bbl/d of liquids Critical Mass In Two World Class Shale Plays ● 159% Appalachian production CAGR for 2010 to 2013 ● Most active driller in Appalachia – 20 rigs running − Most active driller in Marcellus Shale – 15 rigs running − 3rd most active driller in the Utica Shale – 5 rigs running Market Leading Growth ● Low development cost leader: $1.03/Mcfe(1) ● Industry leading growth-adjusted recycle ratio: 5.4x(1) ● Top quartile return on productive capital: 27% for 2013E Industry Leading Capital Efficiency and Recycle Ratio ● 1.6 Bcf/d of processing capacity and 2.1 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 Significant Emphasis on Takeaway and Liquids Processing ● ~$1.2 billion pro forma available liquidity with current $1.5 billion bank commitment(2) ● 1.5 Tcfe hedged through 2019 at an average index price of $4.58/MMBtu and $96.54/Bbl Liquidity and Hedge Position Support High Growth Story ● 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 Outstanding Management Team 21. Three year average through 2013; pro forma for Arkoma and Piceance divestitures. 2. See page 23 for the derivation of 12/31/2013 liquidity.
  • 4. 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 C PREMIER UNCONVENTIONAL RESOURCE PLATFORM 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. 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. 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 678 MMcfe/d - 4Q 2013 Net Liquids 11,190 Bbl/d Net Acres(2) 459,000 Undrilled 3P Locations 4,778 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 • 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 A 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 B 3 A C B “Pure-Play” Appalachian-Focused Shale Company UTICA SHALE – DRY GAS Net Acres(2) 128,000 Net Resource 7-11 Tcf Undrilled Locations 1,080 D D Additional Hedge Value • 1.5 Tcfe hedged from 1/1/2014 through 12/31/2019 at an average index price of $4.58/MMBtu and $96.54/Bbl • ~ $750 million mark-to-market hedge value as of 3/18/2014 • ~ 55% hedged through NYMEX; 45% hedged through regional hubs
  • 5. 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 2006 2007 2008 2009 2010 2011 2012 2013 Woodford Piceance Marcellus Utica(3) 87 235 680 1,141 3,231 5,017 4,283 7,632 (5) (5) Sold Woodford and Piceance 4 0 200 400 600 800 1,000 2006 2007 2008 2009 2010 2011 2012 2013 2014E Woodford Piceance Marcellus Utica 6 31 87 105 133 244 334 522 (4) 950 AVERAGE NET DAILY PRODUCTION (MMcfe/d) NET PROVED SEC RESERVES (Bcfe)(2) 193 0 25 50 75 100 125 150 175 200 2006 2007 2008 2009 2010 2011 2012 2013 2014E Woodford Piceance Marcellus Utica 85 96 126 18 66 91 119 162 (4) 1. CAGR = Compound Annual Growth Rate. 2. Proved reserves for 2006, 2007, and 2008 represent previously effective SEC methodology. 2009, 2010, 2011, 2012 and 2013 proved reserves based on current SEC reserve methodology and SEC pricing and are audited by independent third-party engineers. 3. Includes Upper Devonian Shale proved reserves (10 Bcfe in 2012 and 44 Bcfe in 2013). 4. Per Company press release dated January 29, 2014; production mid-point of 925-975 MMcfe/d guidance. 5. 2012 and 2013 proved reserves are both in ethane rejection mode. 6. Per First Call estimate as at 3/20/2014. Financial Crisis STRONG TRACK RECORD OF GROWTH OPERATED GROSS WELLS SPUD Sold Woodford and Piceance EBITDAX ($MM) $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 2006 2007 2008 2009 2010 2011 2012 2013 2014E Discontinued Operations Continuing Operations $0 $60 $209 $201 $198 $341 $434 $649 $1,272 (6)
  • 6. OUTSTANDING RESERVE GROWTH 1. 2012 and 2013 reserves assume ethane rejection. 5 PROVED RESERVE GROWTH(1) 3P RESERVE GROWTH(1) • 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 4.2 7.2 0.1 0.4 0 2 4 6 8 10 2012 2013 (Tcfe) Marcellus Utica 7.6 17.6 25.0 4.0 5.8 4.2 0 10 20 30 40 50 2012 2013 (Tcfe) Marcellus Utica Upper Devonian Drivers POTENTIAL RESERVE GROWTH DRIVERS 2013 RESERVE UPDATE • Marcellus SSL completions • Full scale Utica program • Utica increased density drilling • Utica dry gas drilling • Core acreage acquisitions Driver 2014 Action Complete transition to SSL type curve 4.3 21.6 35.0 • Successful drilling • Expanded proved footprint • 79,000 net acres added in 2013 • SSL results • Utica results 41 wells to be completed; only 21 PUD locations booked as proved at YE 2013 $200 million leasehold budget Drilling 2 increased density pilots in Utica Drilling first Utica dry gas well in WV (128,000 net acres WV/PA) Drivers
  • 7. $0.00 $0.00 $0.00 $0.00 $0.89 $1.15 $2.47 $2.50 $2.60 $2.94 $3.20 $3.27 $3.51 $3.65 $3.66 $3.70 $3.75 $3.80 $3.81 $4.13 $4.25 $4.66 $5.05 $5.37 $5.49 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 637 834 707 890 117% 65% 32% 21% 0 200 400 600 800 1000 0% 50% 100% 150% Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total3PLocations ROR Locations ROR MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW-RISK, HIGH-RETURN GROWTH PROFILE Large Inventory of Low Breakeven Projects(3) 1. Well economics based on 12/31/2013 3P SSL reserves and strip pricing as of 12/31/2013. 2. 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. 4. 3-year NYMEX STRIP as of 3/18/2014. 3 Yr Strip - $4.29/MMBtu(4) 637 Locations 1,541 Locations 366 Locations 890 Locations $/MMBtuNYMEX(Gas) 182 Locations 6 MARCELLUS SSL WELL ECONOMICS(1)(2) UTICA WELL ECONOMICS(1) 205 161 182 211 137% 169% 95% 56% 0 50 100 150 200 250 0% 50% 100% 150% 200% Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total3PLocations ROR Locations ROR 1,000  71% of Marcellus locations are processable (1100-plus Btu)  72% of Utica locations are processable (1100-plus Btu) ` >2,700 Antero Liquids-Rich Locations
  • 8. 0.0x 2.0x 4.0x 6.0x 8.0x 5.4x 2.7x2.9x 2.3x $0.00 $1.00 $2.00 $3.00 $4.00 $1.03 $1.14 $1.41 $1.57 $1.71 Other Peers LOW DEVELOPMENT COST DRIVES BEST-IN-CLASS RECYCLE RATIOS 7 Source: Proved developed F&D research prepared by JP Morgan Research report dated 07/22/2013. Defined as total drilling and completion capital expenditures for the period divided by PDP and PDNP volumes added after adding back production for the period. Includes all drilling and completion costs but excludes land and acquisition costs for all companies. 1. Antero internal estimate using JP Morgan development cost methodology; excludes Arkoma and Piceance operations. 2. Antero estimate based on public information; includes Arkoma and Piceance operations. 3-Year All-in Development Costs ($/Mcfe) through 2012 Antero Appalachia-Focused Peers Source: Wall Street research. Defined as 2011-2013 average (Cash Operating Netback / PD F&D costs) x (1 + 2013-2015 consensus 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 Appalachia-Focused Peers 3-Year Average Growth – Adjusted Recycle Ratio through 2013 $/Mcfe Other Peers
  • 9. Needed to make up for base declines in conventional and GOM production ? ?? Over 2,700 Antero Drilling Locations Permian Niobrara GraniteWash Barnett Haynesville U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE(1) 8  Low cost, liquids-rich Utica and Marcellus Shales will remain attractive in most commodity price environments Utica Shale SW (Rich) Marcellus Shale 1. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI NE (Dry) Marcellus Shale Eagle Ford Shale MARCELLUS & UTICA – ADVANTAGED ECONOMICS
  • 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 91. Antero firm transportation as of 3/18/2014. 0 200 400 600 800 1,000 1,200 1,400 1,600 (MMcf/d) Sherwood I Sherwood II Sherwood III Sherwood IV Sherwood V Seneca I Seneca II Seneca III Seneca IV Total Capacity 1,550 Marcellus Utica Sherwood I Sherwood II Sherwood III Seneca I Seneca II Seneca III Growing Processing Capacity Sherwood V Seneca IV Appalachian Firm Transportation/Sales Commitment by Operator Sherwood IV Source: Company presentations, press releases. 0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 RRC EQT COG CNX CHK TLM STO SWN WPX RDS APC NFG Mcf/d Firm Sales Firm Transportation (1) AR
  • 11. -$2.50 -$2.00 -$1.50 -$1.00 -$0.50 $0.00 $0.50 2014 2015 2016 2017 2018 2019 Appalachian Basis to NYMEX(2) LONG HAUL PIPELINE AND TRANSPORTATION NETWORK 10  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 Note: Antero firm transportation and firm sales positions listed by pipeline in color-coded boxes. 1. Firm transport as of year-end 2014. See Page 27 for timing of firm transportation graph. 2. Basis data from Wells Fargo daily indications and various private quotes as of 3/18/2014. (1) TCO Basis to NYMEX Current 2015 -$0.01 -$0.46 Dom South Basis to NYMEX Current 2015 -$0.31 -$0.89 Leidy Basis to NYMEX Current 2015 -$1.45 -$2.16 CGTLA Basis to NYMEX Current 2015 -$0.03 -$0.08 Chicago Basis to NYMEX Current 2015 +$0.22 -$0.04 TCO Dom South TETCO M2 Leidy Chicago 2013 % of Production Sold TCO 67% Dom South 22% TETCO M2 5% NYMEX 6% +
  • 12. 729 650 643 780 710 468 $4.92 $4.80 $4.71 $4.33 $4.60 $4.41 $4.49 $4.23 $4.16 $4.15 $4.29 $4.38 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 0 200 400 600 800 2014 2015 2016 2017 2018 2019 BBtu/d 11% 17% 16% 54% 2% NYMEX CGTLA Dom South TCO Chicago SIGNIFICANT LONG-TERM COMMODITY HEDGE POSITION 11 % HEDGE VOLUMES BY INDEX – 3/18/2014 Average Index Hedge Price ($/MMBtu)(1)Hedged Volume NYMEX Strip (3/18/2014) ($/MMBtu) NATURAL GAS HEDGES – 3/18/2014 1. Reflects weighted average index price per annum based on volumes hedged and 6:1 gas to oil ratio. Antero has hedged ~3,000 Bbl/d for 2014, WTI hedges comprise ~1% of overall hedge book.  ~$750 million mark-to-market unrealized gain as of March 18, 2014  1.5 Tcfe hedged from January 1, 2014 through year-end 2019
  • 13. ASSET OVERVIEW 12
  • 14. WORLD CLASS POSITION IN THE CORE OF THE MARCELLUS AND UTICA LIQUIDS-RICH FAIRWAYS Source: Company presentations and press releases. Utica Shale Core Area Marcellus Shale Southwestern & Northeastern Core Areas Upper Devonian Shale Resource Overlies Marcellus Acreage 13 ANTERO LIQUIDS-RICH UTICA SHALE 107,000 Net Acres 18 Horizontals Completed 5 Rigs Currently Running ANTERO MARCELLUS SHALE SW PA 25,000 Net Acres 2 Horizontals Completed Strong Results ANTERO MARCELLUS SHALE NW WV 327,000 Net Acres (Primarily Liquids-Rich Fairway) 234 Horizontals Completed 15 Rigs Currently Running Utica Shale Liquids-Rich Fairway Utica Shale Dry Gas Resource Underlies Marcellus Acreage Marcellus Shale Liquids-Rich Fairway
  • 15. WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT Antero Has Delineated And De-Risked Its Large Scale Acreage Position  100% operated  352,000 net acres in Southwestern Core – 51% HBP with additional 21% not expiring for 5+ years  236 horizontal wells completed and online – Laterals average 7,000’ – 100% drilling success rate  Net production of 621 MMcfe/d in 4Q 2013, including 8,900 Bbl/d of liquids  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) 14 Highly-Rich Gas 101,000 Net Acres 834 Gross Locations Rich Gas 86,000 Net Acres 707 Gross Locations Dry Gas 104,000 Net Acres 890 Gross Locations Highly-Rich/Condensate 61,000 Net Acres 637 Gross Locations MOORE UNIT 30-Day Rate 1H: 10.3 MMcfe/d 2H: 10.3 MMcfe/d (20% 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 (26% liquids) CONSTABLE UNIT 30-Day Rate 1H: 15.3 MMcfe/d (26% liquids) 142 Horizontals Completed 30-Day Rate 10.3 Bcf average EUR 8.1 MMcf/d 6,915’ average lateral length PRUNTY UNIT 30-Day Rate 1H: 12.2 MMcfe/d (27% liquids) HINTERER UNIT 30-Day Rate 1H: 12.9 MMcfe/d (20% liquids) RUTH UNIT 30-Day Rate 1H: 19.2 MMcfe/d (14% liquids) Sherwood Processing Plant EQT 30-Day Rate 12 Recent Wells 9.2 MMcfe/d (20% Liquids) Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held. Note: Rates assume ethane rejection. BLANCHE UNIT 30-Day Rate 2H: 10.2 MMcfe/d (30% liquids) DOTSON UNIT 30-Day Rate 1H: 12.4 MMcfe/d 2H: 11.8 MMcfe/d (26% liquids)
  • 16. MARCELLUS – SIMPLE STRUCTURE 15  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 Average Marcellus Lateral Lengths 7,300 4,800 4,500 4,100 0 2,000 4,000 6,000 8,000 Antero EQT RRC COG Feet Source: Company presentations. Wolf SummitArches ForkBig Moses Marcellus Onondaga Benson Rhinestreet Profile along regional seismic line (time)W E Regional Seismic Line No Data Tully 100’ Contours Top Marcellus
  • 17. 0 4 8 12 16 20 MMcf/d 30-Day Average Production Rates 0.0 3.0 6.0 9.0 12.0 15.0 0.0 3.0 6.0 9.0 12.0 15.0 0 1 2 3 4 5 6 7 8 9 10 CumulativeBcf MMcf/d Production Year Antero Non-SSL Type Curve Actual Non-SSL Production Non-SSL Type Curve Cumulative Production 1.7 Bcf/1,000' SSL Type Curve SSL Actual Production  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% to 15% 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 ANTERO’S MARCELLUS SHALE TYPE CURVE SUPPORT 1. 236 Antero Marcellus wells normalized to time zero, production for each well normalized to 7,000’ lateral length. 2. 32 Antero Marcellus SSL wells normalized to time zero, production for each well normalized to 7,000’ lateral length. Marcellus Type Curve – Normalized to 7,000’ Lateral (1) 16 24-Hour Peak Rate 30-Day Avg. Rate 90-Day Avg. Rate 180-Day Avg. Rate One-Year Avg. Rate Two-Year Avg. Rate Three-Year Avg. Rate Wellhead (MMcf/d) 14.3 8.1 6.3 5.3 4.2 3.1 2.3 # of wells 236 224 221 193 131 65 26 EURs Increase With Lateral Length Well Cost / 1,000’ Decreases with Lateral Length Wellhead 30-day Rates - 224 Wells Average 30-Day Rate – 8.1 MMcf/d (2) 0 4 8 12 16 20 2,000 4,000 6,000 8,000 10,000 EUR,BCF Lateral Length, ft $0.6 $0.8 $1.0 $1.2 $1.4 $1.6 $1.8 2,000 4,000 6,000 8,000 10,000 $MM/1,000' Lateral length, ft
  • 18. MARCELLUS SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION 17 DRY GAS LOCATIONS RICH GAS LOCATIONS HIGHLY RICH GAS LOCATIONS Assumptions  12/31/2013 Strip Pricing & SEC Reserves NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL(2) ($/Bbl) 2014 $4.24 $95 $54 2015 $4.16 $88 $50 2016 $4.09 $83 $50 2017 $4.09 $80 $50 2018+ $4.14 $79 $50 Marcellus SSL Well Economics and Total Locations(1) Classification Highly-Rich/ Condensate Highly-Rich Gas Rich Gas Dry Gas BTU Range 1275-1350 1200-1275 1100-1200 <1100 Modeled BTU 1313 1250 1150 1050 EUR (Bcfe): 16.5 14.9 13.3 12.1 EUR (MMBoe): 2.8 2.5 2.2 2.0 % Liquids: 34% 24% 12% 0% Lateral Length (ft): 7,000 7,000 7,000 7,000 Stage Length (ft): 225 225 225 225 Well Cost ($MM): $9.5 $9.5 $9.5 $9.5 Bcf/1,000’: 1.7 1.7 1.7 1.7 Bcfe/1,000’: 2.4 2.1 1.9 1.7 Pre-Tax NPV10 ($MM): $20.5 $13.7 $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): 0.9 1.3 2.4 3.6 Gross 3P Locations: 637 834 707 890 1. Well economics are based on 12/31/2013 proved SSL reserves (P90) and strip pricing. Includes gathering, compression and processing fees. 2. Pricing for a 1225 BTU y-grade rejection barrel. 637 834 707 890 117% 65% 32% 21% 0 200 400 600 800 1,000 0% 50% 100% 150% Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total3PLocations ROR Locations ROR
  • 19. 1,000 10,000 0 30 60 90 120 150 180 210 240 GasProduction(Mcfe/d) Days From Peak Gas Antero Type Curve SSL Average Wellhead SSL Average Processed Enhancing Recoveries  Shorter stage length (SSL) summary: – 36 SSL wells completed – 32 SSL wells have at least 30 days of production history – 150’ to 225’ (SSL) vs. 350’ stages previously  28% higher 30-day wellhead rate for first 32 SSL wells vs. the Antero type curve – 29% higher 180-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 32 SSL wells has averaged 38% higher than the Antero type curve  Estimated 12% to 15% increase in well costs for SSL completions as compared to non-SSL 18 SHORTER STAGE LENGTHS (“SSL”) – ENHANCING MARCELLUS RECOVERIES 1.5 Bcf/1,000’ Type Curve Normalized production increase for 36 SSL wells vs. 1.5 Bcf/1,000' Type Curve SSL vs Non-SSL Wellhead Average Rate Comparison 30-day Rate 90-day Rate 120-day Rate 180-day Rate SSL Well Count 32 19 18 10 SSL Avg. Wellhead Rate – MMcf/d(1) 9.8 8.0 7.7 7.3 Wellhead Type Curve – MMcf/d(2) 7.6 6.6 6.2 5.7 SSL % Rate Improvement 28% 22% 24% 29% SSL Avg. Processed Rate – MMcfe/d(1) 11.2 9.2 8.7 8.3 Processed Type Curve – MMcfe/d(3) 8.1 7.0 6.6 6.0 SSL % Rate Improvement 38% 31% 33% 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
  • 20. Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held. 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.  100% operated  107,000 net acres in the core rich gas / condensate window – 20% HBP with additional 79% not expiring for 5+ years – 75% of acreage has rich gas processing potential  18 Antero-operated horizontal wells completed and online − 100% drilling success rate  Net production of 54 MMcfe/d in 4Q 2013 including 2,200 Bbl/d of liquids − First production in early August 2013 had access to Cadiz pipeline and processing − Seneca I processing plant came online in November 2013 and Seneca II came online in January 2014 − First 120 MMcf/d compressor station went into service in late January with an additional 120 MMcf/d compressor station expected by late 1Q 2014  759 future drilling locations – Approximately 15% of EUR is liquids assuming ethane rejection  Operating 5 rigs including 1 shallow rig  5.8 Tcfe of net 3P (15% liquids), includes 362 Bcfe of proved reserves (assuming ethane rejection) EXCITING CORE UTICA SHALE POSITION DELIVERS CONDENSATE AND NGLS 19 Utica Shale Industry Activity(1) Seneca Processing Plant Cadiz Processing Plant CHESAPEAKE 24-Hour IP Buell #8H 9.5 MMcf/d + 1,425 Bbl/d liquids GULFPORT 24-Hour IP Boy Scout 1-33H, Ryser 1-25H, Groh 1-12H Average 5.3 MMcf/d + 675 Bbl/d NGL + 1,411 Bbl/d Oil REXX 24-Hour IP Guernsey 1H, 2H, Noble 1H Average 7.9 MMcf/d + 1,192 Bbl/d NGL + 502 Bbl/d Oil MILEY UNIT 30-Day Rate 2 wells average 7.5 MMcfe/d (60% liquids) NORMAN UNIT 1H 30-Day Rate 16.4 MMcfe/d (17% liquids) YONTZ UNIT 1H 30-Day Rate 17.0 MMcfe/d (14% liquids) RUBEL UNIT 30-Day Rate 3 wells average 17.3 MMcfe/d (22% liquids) GULFPORT 24-Hour IP McCort1-28H, 2-28H, Stutzman 1-14H Average 13.1 MMcf/d + 922 Bbl/d NGL + 21 Bbl/d Oil GULFPORT 24-Hour IP Wagner 1-28H, Shugert 1-1H, 1-12H Average 21.0 MMcf/d + 2,270 Bbl/d NGL + 292 Bbl/d Oil Utica Core Area WAYNE UNIT 30-Day Rate 3 wells average 10.8 MMcfe/d (49% liquids) GARY UNIT 1H 30-Day Rate 29.7 MMcfe/d (22% liquids) Highly-Rich/Cond 30,000 Net Acres 205 Locations Highly-Rich Gas 26,000 Net Acres 161 Locations Rich Gas 24,000 Net Acres 182 Locations Dry Gas 27,000 Net Acres 211 Locations
  • 21. 0.0 10.0 20.0 30.0 40.0 50.0 60.0 MMcfe/d Source: Antero, press releases and company presentations. Note: Assumes ethane recovery. ANTERO HAS MOST OF THE TOP UTICA 24-HOUR IPS – STRONG SUPPORT FOR CORE POSITION  Antero has 12 of the top 13 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  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) 20 UTICA 24-HOUR IPs Core 12 to 53 MMcfe/d IPs Tier 1 6 to 12 MMcfe/d IPs Antero Utica Wells 3rd Party Core Utica Wells 3rd Party Non-Core Utica Wells
  • 22. UTICA SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION 21 DRY GAS LOCATIONS RICH GAS LOCATIONS HIGHLY RICH GAS LOCATIONS Assumptions  12/31/2013 Strip Pricing & SEC Reserves Utica Well Economics and Locations(1) Classification Highly-Rich/ Condensate Highly-Rich Gas Rich Gas Dry Gas BTU Range 1250-1300 1200-1250 1100-1200 <1100 Modeled BTU 1275 1225 1175 EUR (Bcfe): 11.3 20.5 18.8 16.6 EUR (MMBoe): 1.9 3.4 3.1 2.8 % Liquids 32% 23% 15% 0% Lateral Length (ft): 7,000 7,000 7,000 7,000 Stage Length (ft): 240 240 240 240 Well Cost ($MM): $11.0 $11.0 $11.0 $11.0 Bcf/1,000’: 1.2 2.4 2.4 2.4 Bcfe/1,000’: 1.6 2.9 2.7 2.4 Pre-Tax NPV10 ($MM): $15.7 $26.6 $18.4 $11.7 Pre-Tax ROR: 137% 169% 95% 56% Net F&D ($/Mcfe): $1.21 $0.66 $0.72 $0.82 Payout (Years): 0.5 0.5 0.8 1.3 Gross 3P Locations(3): 205 161 182 211 1. Well economics are based on 12/31/2013 proved (P90) reserves and strip pricing. Includes gathering, compression and processing fees. 2. Pricing for a 1225 BTU y-grade rejection barrel. 3. Gross 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content. NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL(2) ($/Bbl) 2014 $4.24 $95 $54 2015 $4.16 $88 $50 2016 $4.09 $83 $49 2017 $4.09 $80 $49 2018+ $4.14 $79 $49 205 161 182 211 137% 169% 95% 56% 0 50 100 150 200 250 0% 50% 100% 150% 200% Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total3PLocations ROR Locations ROR
  • 23. LARGE MIDSTREAM FOOTPRINT 22 Ohio River Withdrawal System Completed Antero Midstream estimated cumulative YE 2014 total capital investment in midstream ~ $1.5 billion – 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 to $800,000 per well − One of the benefits of a consolidated acreage position Utica Shale Marcellus Shale Projected Midstream Infrastructure(1) Marcellus Shale Utica Shale Total YE 2014E Cumulative Gathering / Compression Capex ($MM) $750 $350 $1,100 Gathering Pipelines (Miles) 192 92 284 Compression Capacity (MMcf/d) 410 120 530 YE 2014 Cumulative Water System Capex ($MM) $300 $100 $400 Water Pipeline (Miles) 122 48 170 Water Storage Facilities 31 16 47 YE 2014E Total Midstream ($MM) $1,050 $450 $1,500 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 12/31/2013 and 2014 guidance.
  • 24. CAPITALIZATION 1. Equity valuation based on 262.0 million shares outstanding and a share price of $63.95 as of 3/20/2014. 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 $2.0 billion borrowing base upon bank approval. PRO FORMA CAPITALIZATION ($ in millions) 12/31/2013 (PF Financing) 12/31/2013 (2) Cash $17 $17 Senior Secured Revolving Credit Facility 288 288 7.25% Senior Notes Due 2019 260 260 6.00% Senior Notes Due 2020 525 525 5.375% Senior Notes Due 2021 1,000 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) $18,816 $18,816 Financial & Operating Statistics LTM EBITDAX $649 $649 LTM Interest Expense(2) $137 $106 Proved Reserves (Bcfe) (12/31/2013) 7,632 7,632 Proved Developed Reserves (Bcfe) (12/31/2013) 2,023 2,023 Credit Statistics Net Debt / LTM EBITDAX 3.2x 3.2x LTM EBITDAX / Interest Expense 4.8x 6.1x Net Debt / Net Book Capitalization 36.4% 36.4% Net Debt / Net Market Capitalization 11.0% 11.0% Net Debt / Proved Developed Reserves ($/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 17 17 Liquidity (Credit Facility + Cash) $1,197 $1,197 23
  • 25. Keys to Execution Pad Impact Mitigation  Closed loop mud system – no mud pits  Protective liners or mats on all well pads in addition to berms Green Completion Units  All Antero well completions use green completion units for completion flowback, essentially eliminating methane emissions (full compliance with EPA 2015 requirements) Central Fresh Water System & Water Recycling  Numerous sources of water – building central water system to source water for completion  Antero recycles over 95% of its flowback water with the remainder injected into disposal wells – no discharge to water treatment plants in West Virginia Natural Gas Powered Drilling Rigs  Nine of Antero’s contracted drilling rigs are currently running on natural gas Natural Gas Vehicles (NGV)  Antero supported the first natural gas fueling station in West Virginia which recently opened  Antero has a dozen NGV trucks and plans to continue to convert its truck fleet to NGV Safety & Environmental  Five company safety representatives and 45 safety consultants cover all material field operations 24/7 including drilling, completion, construction and pipelining  23-person company environmental staff plus outside consultants monitor all operations and perform baseline water well testing Local Presence  Land office in Ellenboro, WV  Recently moved into new 50,000 square foot district office in Bridgeport, WV  109 of Antero’s 264 employees are located in West Virginia and Ohio LEED Gold Headquarters Building  Antero’s new corporate headquarters in Denver has been LEED Gold Certified  Completion expected by spring of 2014 HEALTH, SAFETY, ENVIRONMENT & COMMUNITY Antero Core Values: Protect Our People and the Environment 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 24
  • 26. ANTERO KEY ATTRIBUTES 25 459,000 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
  • 27. 26 APPENDIX 26
  • 28. ANTERO FIRM TRANSPORTATION AND FIRM SALES 27 MMBtu/d Columbia 7/26/2009 – 9/30/2025 Firm Sales #1 10/1/2011– 10/31/2019 Firm Sales #2 10/1/2011 – 5/31/2017 Firm Sales #3 1/1/2013 – 5/31/2022 Momentum III 9/1/2012 – 12/31/2023 EQT 8/1/2012 – 12/31/2023 REX/MGT/ANR 4/1/2013 – 9/30/2025 - 500,000 1,000,000 1,500,000 2,000,000 2,500,000
  • 29. 1. 24-hour peak rates assume full ethane recovery (assuming typical ethane plant product recoveries of 85% to 90%) however Antero is currently rejecting ethane due to current market prices. 2. Average of Antero’s first 15 core area wells, assuming ethane rejection. ANTERO UTICA SHALE WELLS – 24 HOUR IPS 28 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 53.3 38.9 33.9 3,177 52 36% 1161 5,115 Rubel 1H Monroe 47.5 31.1 25.9 3,391 214 46% 1231 6,554 Gary 2H Monroe 43.5 28.9 24.2 3,053 162 44% 1224 8,882 Rubel 3H Monroe 42.6 28.4 23.7 3,003 142 44% 1220 6,424 Milligan 2H Noble 40.2 17.2 13.5 2,361 2,087 68% 1276 5,989 Rubel 2H Monroe 37.4 24.8 20.7 2,635 156 45% 1217 6,571 Norman 1H Monroe 37.1 26.1 22.3 2,419 45 40% 1186 5,498 Coal 3H Noble 35.3 15.1 11.8 2,063 1,850 67% 1278 7,768 Wayne 3HA Noble 35.1 14.7 11.6 2,018 1,905 67% 1272 6,712 Wayne 4H Noble 34.2 14.2 11.2 1,907 1,922 67% 1265 6,493 Milligan 3H Noble 32.1 15.4 12.1 2,111 1,228 62% 1276 5,267 Milligan 1H Noble 25.8 10.6 8.3 1,461 1,442 68% 1276 6,436 Wayne 2H Noble 25.5 10.9 8.5 1,503 1,331 67% 1281 6,094 Miley 2H Noble 22.4 8.6 6.7 1,172 1,450 70% 1278 6,153 Miley 5HA Noble 20.2 7.7 6.0 1,090 1,285 70% 1291 6,296 35.5 19.5 16.0 2,224 1,018 57% 1249 6,417 28.7 18.8 17.6 844 1,018 42% 1251 6,518 Average ‐ Ethane Recovery(1) Average ‐ Ethane Rejection(2) 24‐hr Peak Rate
  • 30. 1. Average of Antero’s first 11 core area wells, assuming ethane rejection. ANTERO UTICA SHALE WELLS – 30-DAY RATES 29 Antero’s wells produced against 1,100 psi line pressure until late January 2014 due to lack of compression facilities − First 120 MMcf/d compressor station started up in late January 2014 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 29.7 24.6 23.1 1,023 65 22% 1224 8,882 Rubel 2H Monroe 19.2 15.9 15.0 625 64 22% 1217 6,571 Rubel 3H Monroe 18.7 15.6 14.7 623 43 21% 1220 6,424 Yontz 1H Monroe 17.0 15.2 14.6 392 1 14% 1161 5,115 Norman 1H Monroe 16.4 14.3 13.6 461 2 17% 1186 5,498 Rubel 1H Monroe 14.0 11.5 10.8 501 28 23% 1231 6,554 Wayne 2H Noble 12.1 6.5 6.0 367 653 51% 1281 6,094 Wayne 3HA Noble 11.0 6.1 5.6 354 540 49% 1272 6,712 Wayne 4H Noble 9.2 5.2 4.7 284 452 48% 1265 6,493 Miley 2H Noble 9.0 3.8 3.5 213 700 61% 1278 6,153 Miley 5HA Noble 5.9 2.7 2.5 161 418 59% 1291 6,296 14.7 11.0 10.4 455 270 35% 1239 6,436 17.9 11.0 9.2 1,189 270 53% 1239 6,436 30‐Day Rates ‐ Antero Core Area Average ‐ Ethane Rejection Average ‐ Ethane Recovery(1)
  • 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 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. ETHANE REJECTION(1) ETHANE RECOVERY(1) 30 Marcellus – 25.0 Tcfe Utica – 5.8 Tcfe Upper Devonian – 4.2 Tcfe 35.0 Tcfe Gas – 29.6 Tcf Oil – 91 MMBbls NGLs – 811 MMBbls Marcellus – 29.5 Tcfe Utica – 6.7 Tcfe Upper Devonian – 4.7 Tcfe 40.8 Tcfe Gas – 27.4 Tcf Oil – 91 MMBbls NGLs – 2,151 MMBbls 15% Liquids 33% Liquids
  • 32. Gas $4.46 Gas $4.19 Gas $4.15 Gas $4.08 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 1050 BTU $5.15 $6.55 $7.68 $4.46 1150 BTU 1250 BTU 1300 BTU MARCELLUS SHALE RICH GAS – LIQUIDS AND PROCESSING UPGRADE 1. NGL prices as of 3/18/2014 from IntercontinentalExchange. 2. Assumes $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current NGL spot prices. 0.886, 1.972 and 2.632 (ethane rejection) GPMs used, all processing costs, shrink and fuel included. No NYMEX basis differential assumed. Current – Ethane Rejection (1076 BTU) 8% shrink (1109 BTU) 12% shrink (1119 BTU) 14% shrink $/Wellhead Mcf(1)(2) ($/Mcf)  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(1) 31 +$0.69 Upgrade +$2.08 Upgrade +$3.22 Upgrade Highly-Rich GasDry Gas NGLs (C3+) $0.96 NGLs (C3+) $2.24 NGLs (C3+) $3.03 Condensate $0.16 Condensate $0.56 Highly-Rich/ Condensate Dry Gas
  • 33. 2013 REALIZATIONS Ethane (C2) Propane (C3) Iso Butane (C4) Normal Butane Natural Gasoline Total $52.61 per Bbl 54% of WTI(4) 2013 NGL Y-GRADE (C3+) REALIZATIONS 2013 NATURAL GAS REALIZATIONS ($/MCF) 55% 2% 11% 15% 17% $23.49 $6.27 $7.55 $14.57 $0.72 32 1. NYMEX differential represents contractual deduct to NYMEX-based sales. 2. Includes firm sales. 3. Price excludes hedges. 4. Based on monthly prices through 12/31/2013 WTI. Antero Barrel 2013 % Sales Average NYMEX Price Average Differential(2) Average BTU Upgrade Average 2013 Realized Price(3) 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 $0.25
  • 34. POSITIVE RATINGS MOMENTUM Moody’s / S&P Historical Credit Ratings “We would consider a positive rating action if the company continued to convert its PUD reserves to proved developed reserves and improved profitability, while maintaining leverage below 3x.” - S&P Credit Research, October 2013 “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 $25.00 per boe and retained cash flow to debt over 40% as it builds out infrastructure needs to support production growth.” - Moody’s Credit Research, October 2013 Moody's S&P Credit Rating (Moody’s / S&P) Ba3 / BB- B1 / B+ B2 / B B3 / B- 9/1/2010 2/24/2011 5/31/2012 10/21/2013 2/18//20142/28/2012 11/28/20118/27/20115/27/2011 Ba2 / BB Ba1 / BB+ Caa1 / CCC+ (1) ___________________________ 1. Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC. Baa3 / BBB- Moody’s Upgrade Criteria S&P Upgrade Criteria 33
  • 35. ANTERO EBITDAX RECONCILIATION 34 EBITDAX Reconciliation ($ in millions) (12 Months Ended) Antero Resources LLC 12/31/2012 12/31/2013 EBITDAX: Net income (loss) from continuing operations $225.3 $(24.2) Commodity derivative fair value (gains) losses (179.5) (491.7) Net cash receipts on settled commodity derivatives instruments 178.5 163.6 (Gain) loss on sale of assets (291.2) - Interest expense and other 97.5 136.6 Loss on early extinguishment of debt - 42.6 Provision (benefit) for income taxes 121.2 186.2 Depreciation, depletion, amortization and accretion 102.1 234.9 Impairment of unproved properties 12.1 10.9 Exploration expense 14.7 22.3 Stock compensation expense - 365.3 Other 4.1 2.9 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 92.2 - (Gain) loss on sale of assets 795.9 (8.5) Provision (benefit) for income taxes (272.6) 3.2 Depreciation, depletion, amortization and accretion 89.1 - Impairment of unproved properties 1.0 - Exploration expense 1.0 - EBITDAX from discontinued operations $149.6 - EBITDAX $434.3 $649.4
  • 36. CAUTIONARY NOTE The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates (collectively, “3P”). Antero has provided internally generated estimates for proved, probable and possible reserves in this presentation in accordance with SEC guidelines and definitions. The estimates of proved, probable and possible reserves as of December 31, 2013 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates are as of December 31, 2013, assuming ethane rejection and strip pricing. Actual quantities that may be ultimately recovered from Antero’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of Antero’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. In this presentation:  “3P reserves” refer to Antero’s estimated aggregate proved, probable and possible reserves as of December 31, 2013. The SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.  “EUR,” or “Estimated Ultimate Recovery,” refers to Antero’s internal estimates of per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules.  “Highly-rich/condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1250 BTU and 1300 BTU in the Utica Shale.  “Highly-rich gas” refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and 1250 BTU in the Utica Shale.  “Rich gas” refers to gas having a heat content of between 1100 BTU to 1200 BTU.  “Dry gas” refers to gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use. Regarding Hydrocarbon Quantities 35