Second Quarter 2016 Earnings Call Presentation August 3, 2016

Transcription

1 Second Quarter 2016 Earnings Call Presentation August 3, 2016

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, 2015 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 our Annual Report on Form 10-K for the year ended December 31, 2015 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. Antero Resources Corporation is denoted as AR and Antero Midstream Partners LP is denoted as AM in the presentation, which are their respective New York Stock Exchange ticker symbols. 1

3 2Q 2016 PRICE REALIZATIONS & EBITDAX MARGIN NATURAL GAS PRICE REALIZATIONS (1) 2Q 2016 NYMEX: $1.95/MMbtu $/Mcf ($/Mcf) Realized Natural Gas Prices Before Hedges Realized Natural Gas Prices After Hedges NYMEX Strip Price 2Q 2016 $5.00 $4.50 $4.31 $4.00 $3.50 $3.00 $2.49 $2.52 $2.50 $2.03 $1.95 Average NYMEX Price 2Q 2016 $2.00 $1.93 $1.58 $1.50 $1.36 $1.55 $1.63 $1.50 $1.21 $1.32 $1.00 $0.50 $0.00 Antero Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 REALIZED GAS-EQUIVALENT PRICE & EBITDAX MARGINS (1)(3) ($/Mcfe) $/Mcfe $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 $3.97 EBITDAX $1.86/Mcfe $2.50 $2.50 EBITDAX $1.05/Mcfe EBITDAX $1.00/Mcfe Antero(2) Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 $2.11 EBITDAX $0.70/Mcfe $1.88 EBITDAX $0.84/Mcfe $1.55 EBITDAX $0.53/Mcfe Non-controlling Interest of Midstream MLP EBITDA LOE Production Taxes GPT G&A EBITDAX 1. Peers include CNX, COG, EQT, RRC & SWN. 2. AR realized price of $3.97/Mcfe includes $0.02/Mcfe of third party gathering, compression, and water distribution revenues. AR EBITDAX margin excludes EBITDA from midstream MLP associated with non-controlling interest. 3. Excludes EBITDA not attributable to E&P sponsor s ownership where applicable. 2

4 HIGHEST EBITDAX & MARGINS AMONG PEERS Antero has extended its lead among Appalachian Basin peers in both EBITDAX and EBITDAX margin Quarterly Appalachian Peer Group EBITDAX ($MM) (1) $500 $400 $300 $269 $291 Among Appalachian peers, AR has ranked in the top 2 for the highest EBITDAX for the fourth straight quarter and has ranked the highest in EBITDAX margin for the fifth straight quarter $308 $355 $332 Y-O-Y AR: $64MM Peer Avg: $76MM NYMEX Gas: 26% NYMEX Oil: 21% $200 $100 $0 $3.00 $2.50 $2.00 P5 P2 AR P3 P4 P1 2Q 2015 $1.90 P5 AR P2 P3 P4 P1 3Q 2015 $1.97 P2 AR P5 P3 P4 P1 AR P2 P5 P3 P1 P4 4Q Q 2016 Quarterly Appalachian Peer Group EBITDAX Margin ($/Mcfe) (1) $2.03 $2.03 AR P2 P3 P4 P5 P1 2Q 2016 AR Peer Group Ranking Improving Over Time #3 #2 #2 #1 #1 $1.86 Y-O-Y AR: 2% Peer Avg: 33% NYMEX Gas: 26% NYMEX Oil: 21% $1.50 $1.00 $0.50 $0.00 AR P3 P4 P2 P5 P1 2Q 2015 AR P3 P5 P4 P2 P1 3Q 2015 AR P3 P2 P1 P5 P4 AR P2 P1 P3 P4 P5 4Q Q 2016 AR Peer Group Ranking Top Tier #1 #1 #1 #1 #1 AR P1 P3 P4 P2 P5 2Q 2016 Note: AR and EQT EBITDAX margin excludes EBITDA from midstream MLP associated with noncontrolling interest. AR consolidated EBITDAX margin for 2Q 2016 was $2.06/Mcfe. CNX excludes EBITDAX contribution from coal operations. 1. Source: Public data from form 10-Qs and 10-Ks and Wall Street research. Peers include COG, CNX, EQT, RRC and SWN. 3

5 $/Mcfe INCREMENTAL COSTS DRIVE PRICE REALIZATIONS In a $60/Bbl WTI oil price and $3.09/MMBtu Nymex gas price scenario, $0.60/Mcfe in all-in processing and fractionation costs lead to a $0.95/Mcfe uptick in liquids price realizations, resulting in a pre-hedge net back of $4.18/Mcfe Excluding hedges as well as net marketing expense of $0.10 to $0.15/Mcfe, Antero s recycle ratio is 3.2x a high growth engine $5.00 $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $- Total Cash Costs $2.16/Mcfe Interest Expense $0.38 (5) G&A $0.23 LOE $0.10 Prod Tax$0.15 Processing $0.60 Firm Transport $0.40 G&C $0.30 $0.60/Mcfe of processing and fractionation costs deliver $0.70 to $1.20 per Mcfe price uptick in a $52 to $70 WTI environment Hedge Gain C3+ NGLs & Condensate Uptick $0.71 Hedge Gain C3+ NGLs & Condensate Uptick $0.95 Hedge Gain C3+ NGLs & Condensate Uptick $1.18 Cash 1Costs $52 WTI 2 3 $60 WTI 4 Case $70 WTI 5 Case (2016E Guidance) 3-Yr Strip (6/30/16) (6) 1. Excludes hedge gains and net marketing expense. 2. All three WTI sensitivity cases assume Henry Hub natural gas strip pricing through 2018, as of 6/30/ Assumes 2H weighted average C3+ NGL realization of 45% of WTI for each respective case. Unit Cash Cost vs. 3-Year Average Realized Pricing (1)(2)(3)(4) $0.40/Mcfe of FT cost delivers $0.14/Mcf premium gas price realization vs. Nymex 3-year strip pricing and a $0.92/Mcf premium to local Dominion South pricing Post-Hedge Price $4.58/Mcfe All-in Price: $3.94/Mcfe Post-Hedge Price $4.79/Mcfe All-in Price: $4.18/Mcfe Antero Realized Gas Price: $3.23/Mcf (+$0.14/Mcf to NYMEX) (+$0.92/Mcf to Dom South Strip) 4. Assumes 1250 BTU. 5. Based on 1H 2016 interest expense and actual production. 6. 6/30/16 strip through 2018 equates to $ Post-Hedge Price $4.99/Mcfe All-in Price: $4.41/Mcfe 6/30/16 NYMEX HH 3-year Strip Pricing: $3.09/MMBtu 6/30/16 Dom South 3-year Strip Pricing: $2.31/MMBtu 1H2016 Weighted Avg. F&D: $0.55/Mcfe 4

6 LARGEST CORE LIQUIDS RICH DRILLING INVENTORY AR is operating 24% of all rigs running and 58% of rigs running in liquids rich core areas in Appalachia Antero has over 3,080 undeveloped rich gas locations in its 3P reserves as of 12/31/2015, pro forma for the pending acreage acquisition Pro forma for the recent acreage acquisition, Antero controls an estimated 39% of the NGLs in the liquids-rich core of the two plays Antero has the largest core liquids-rich position in Appalachia with 420,000 net acres (> 1100 Btu) Represents over 24% of core liquidsrich acreage in Marcellus and Utica plays combined Core Liquids-Rich Net Acres(1) 500 (000s) 400 Marcellus Utica Basin Total Operated Rigs June 2015 Operated Rigs June 2016 Antero Antero Others Total Antero % 33% 9% 24% (4) (59) (63) 12% Y-O-Y Difference Others Total Antero % 11% 13% 12% Incremental core liquids-rich acreage included in pending acquisition Source: RigData Source: Core outlines and peer net acreage positions based on investor presentations, news releases and 10-K/10-Qs. Rig information per RigData as of 5/27/ Based on company filings and presentations. 5

7 NGL GROWTH AND ETHANE OPTIONALITY Antero continues to rapidly grow its liquids production, with 2015 year-over-year growth of 117% and 2016 NGL production growth guidance of 47% Developing significant ethane optionality with an estimated 85,000 Bbl/d of ethane in targeted production stream in 2017 (Bbl/d) NGL Production Growth by Purity Product (Bbl/d) Full C2 Recovery 90+ MBbl/d C2 100,000 Ethane (C2) 90,000 80,000 Propane (C3) Normal Butane (nc4) IsoButane (ic4) Sherwood deethanizer placed in service in late 4Q15 Ethane Optionality Ethane 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 Natural Gasoline (C5+) C3+ Production 13, ,000 Bbl/d of NGLs Produced 15,770 21,225 27, ,000 Bbl/d of NGLs Produced 36,006 39,725 45,072 49,140 Ethane 63,328 C2 Ethane 11,884 69,797 C2 Ethane 17,373 62,500 C2 Ethane 10,000 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q Guidance 1. Assumes 10,000 Bbl/d of ethane and 52,500 Bbl/d of C3+, respectively, per guidance release on 4/27/2016. C3+ barrel composition based on 2Q16 actual barrel composition. 2. Assumes 20 25% year-over-year equivalent production growth in For illustrative purposes C3+ production growth assumed at same rate. C3 nc4 ic4 C5+ (1) C3+ assuming 20% - 25% growth target 2017 Target (2) 6

8 ACQUISITION UPDATE Tag along option recently exercised on 11,500 net acres Strategic core inventory addition of 66,500 net acres and 5.0 Tcfe of Marcellus 3P reserves for $546 million purchase price (1) 40,000 net acre new footprint in Wetzel County 14,500 net infill acres in Tyler County 12,000 net infill acres primarily in Doddridge, Harrison and Ritchie Counties 48% HBP with additional 44% not expiring until MMcfe/d of net production >$1.5 billion estimated pre-tax PV-10 at 2015 year end assumptions Pro Forma Acreage Position Southern Rich 2.0 Bcf / 1,000 Wellhead EUR Industry - 17 Well Average Advanced Completions Wellhead: 2.2 Bcf/1,000 Processed: 2.6 Bcfe/1,000 C2 Recovery: 3.4 Bcfe/1,000 Dry Gas 2.2 Bcf / 1,000 Wellhead EUR Impacts 1,060 gross undeveloped locations 625 new locations averaging 9,300 lateral length 90 laterals extended from 4,700 to 10,100, on average Increasing average working interest in 345 planned laterals from 71% to 88% Broad consolidation and new development platform for AR in Wetzel County Adds new high-graded core county for Antero Attractive liquids-rich well economics consistent with recent Antero well results Latest completions averaging over 2.0 Bcf/1,000 at the wellhead Rates of return of 51% to 77% at 6/30/2016 strip pricing Significantly enhances dry gas optionality in the core, adding or enhancing 225 core Marcellus dry gas locations Includes dry Utica rights on 51,000 prospective net acres Value creation for Antero Midstream through dedication of ~106,000 gross acres, a 22% increase over existing dedication Provides significant organic growth opportunities for gathering, compression, processing and water segments AR has a 62% LP ownership in AM Expected to close 3Q 2016 Antero - 6 Well Average (Pierpoint Pad) Advanced 1200 Wellhead: 2.1 Bcf/1,000 Processed: 2.6 Bcfe/1,000 C2 Recovery: 3.2 Bcfe/1, Bcf/1000 Wellhead Type Curve (Not Inclusive of wells with Advanced Completions) Antero - 3 Well Average (Diane Davis Pad) Advanced 1500 Wellhead: 2.3 Bcf/1,000 Processed: 2.8 Bcfe/1,000 C2 Recovery: 3.5 Bcfe/1, Includes 11,500 net acres and 900 Bcfe of unaudited Marcellus 3P reserves associated with tag along sale rights exercised by a third party. Acquisition announced on 6/9/2016. Antero - 4 Well Average (RJ Smith Pad) Advanced 1200 Wellhead: 2.2 Bcf/1,000 Processed: 2.6 Bcfe/1,000 C2 Recovery: 3.2 Bcfe/1,000 Antero - 4 Well Average (Melody Pad) Advanced 1200 Wellhead: 2.1 Bcf/1,000 Processed: 2.5 Bcfe/1,000 C2 Recovery: 3.1 Bcfe/1,000 Antero Acquisition Acreage Districts with 3,000+ Antero Net Acres Antero Horizontal Marcellus Wells Industry Horizontal Marcellus Wells 7

9 PROVEN TRACK RECORD OF WELL COST REDUCTIONS Marcellus Well Cost Reductions for a 9,000 Lateral ($MM) (1) ($MM) $14 $12 $10 $8 $6 $4 $12.3 $8.3 $11.1 $7.3 $10.8 $7.4 $10.2 $10.2 $7.0 $7.0 COMPLETION COST $8.5 $5.4 $0.9 / 1,000 DRILLING COST $8.1 $5.3 34% Reduction in Marcellus well costs since Q % Reduction vs. well costs assumed in YE 2015 reserves $2 $4.0 $3.8 $3.4 $3.2 $3.2 $3.1 $2.8 $- Q Q Q Q Q Q Q Utica Well Cost Reductions for a 9,000 Lateral ($MM) (2) ($MM) $16 $14 $12 $10 $8 $6 $4 $14.0 $8.7 $12.4 $7.8 $12.9 $7.6 $7.1 $7.1 COMPLETION COST $5.6 $5.4 DRILLING COST $11.8 $11.8 $1.0 / 1,000 33% Reduction in Utica well costs since $10.3 Q $9.4 13% Reduction vs. well costs assumed in YE 2015 reserves $2 $0 $5.3 $4.6 $5.3 $4.7 $4.7 $4.7 $4.0 Q Q Q Q Q Q Q NOTE: Based on statistics for drilled wells within each respective period. 1. Based on 200 ft. stage spacing. 2. Based on 175 ft. stage spacing. 8

10 CONTINUOUS OPERATING IMPROVEMENT Operating Highlights Top 20 best drilling footage days in Marcellus since 2009 have all occurred in 2016, including 7,274 drilled in 24 hours in West Virginia on the Hunter 1H Recently drilled and cased longest lateral in company history at 14,024 feet Stayed within targeted zone for 95% of lateral length of all wells drilled in Q Increased sand placement during completions to 99% in Q Utilizing new floating casing procedure, reducing casing run time by over 12 hours Increased proppant and water loading by 25% in 2016 with encouraging results to date Utica Shale Ohio Marcellus Shale Acquired Acreage Utica Marcellus Q Q vs Q Q vs Activity Levels Average Rigs Running (75%) (57%) Average Completion Crews (50%) (36%) Operational Improvements Drilling Days % % Average Lateral Length (Ft) 8,543 8,575 9,000 5% 8,052 8,910 9,000 12% Stages per Well % % Stage Length % % Stages per Day % % Well Cost & Performance Improvements D&C per 1,000' of lateral ($MMs) $1.55 $1.36 $1.04 (33%) $1.34 $1.18 $0.90 (33%) Wellhead EUR per 1,000' of lateral (Bcf) (1) % % Processed EUR per 1,000' of lateral (Bcfe) (1)(2) % % Net development cost per processed Mcfe (2)(3) $1.28 $0.94 $0.72 (44%) $0.88 $0.73 $0.46 (47%) 1. Based on statistics for wells completed within each respective period. 2. Ethane rejection assumed. 3. Current D&C cost per 1,000 lateral divided by net EUR per 1,000 lateral assuming 81% NRI in Utica and 85% NRI in Marcellus. 9

11 ADVANCED COMPLETIONS DRIVE HIGHER EURS The initial performance of the 24 wells completed in 2016 using greater than 1,300 lb/ft has well exceeded our 1.7 Bcf/1,000 type curve through 120 days 2016 Marcellus Wells with Proppant Loading >1,300 pounds per foot (1) Bcf/1,000' Type Curve 2.0 Bcf/1,000' Type Curve 2016 Aggregated Production - Advanced Completions (1) 2016 Advanced Completion Well Population: - 24 wells with >1,300 lbs/foot of proppant - 1,500 lb/ft average proppant loading - 8,704' average lateral Wellhead Gas Production (MMcf/d) Bcf/1,000' 1.7 Bcf/1,000' Days From Peak Gas 1. All 24 Antero Marcellus wells with completions at >1,300 lb/ft of proppant normalized to time zero, production for each well normalized to 9,000 lateral length. 10

12 MARCELLUS UPSIDE POTENTIAL While we have not changed our 1.7 Bcf/1,000' Marcellus project-wide type curve, we are seeing stronger EURs per 1,000' in a significant portion of our Marcellus rich gas acreage for wells completed in the first half with at least 30 days of production history Assumptions Natural Gas 6/30/2016 strip Oil 6/30/2016 strip NGLs 37.5% of Oil Price 2016; ~50% of Oil Price NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL (2) ($/Bbl) 2016 $3.04 $50 $ $3.18 $52 $ $3.02 $54 $ $3.00 $55 $ $3.06 $55 $ $3.53 $58 $30 Pre-Tax PV-10 $20.0 $17.0 $14.0 $11.0 $8.0 $5.0 $2.0 -$1.0 Bcf/1,000 Bcfe/1,000 58% $ % $15.9 Pre-Tax PV-10 Classification (1) Highly-Rich Gas/Condensate Highly-Rich Gas BTU Regime EUR (Bcfe): EUR (MMBoe) : % Liquids: 33% 33% 33% 24% 24% 24% Well Cost ($MM): $8.1 $8.1 $8.1 $8.1 $8.1 $8.1 Bcf/1, Bcfe/1,000 : Net F&D ($/Mcfe): $0.46 $0.39 $0.34 $0.51 $0.43 $0.38 Pre-Tax NPV10 ($MM): $12.3 $15.9 $19.5 $8.2 $11.1 $13.9 Pre-Tax ROR: 58% 77% 99% 38% 51% 66% Payout (Years): Breakeven NYMEX Gas Price ($/MMBtu) (5) $1.22 $0.95 $0.76 $2.02 $1.77 $1.57 Gross 3P Locations (3) : 557 1,052 Pro Forma Gross 3P Locations (3) : 664 (19% Increase) 1,235 (17% Increase) 99% $19.5 Pre-Tax ROR 38% $8.2 51% $11.1 Highly-Rich Gas/Condensate Highly-Rich Gas 2.0(4) (4) Development Plan: Completions 1. 6/30/2016 pre-tax well economics based on a 9,000 lateral, 6/30/2016 natural gas and WTI strip pricing for , flat thereafter, NGLs at 37.5% of WTI for 2016 and ~50% of WTI thereafter, and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates include $1.2 million for road, pad and production facilities. Assumes ethane rejection. 2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 2016 and ~50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship. 3. Undeveloped Marcellus well locations as of 12/31/2015 adjusted for 6/30/2016 net acreage. 4. Represents actual results for 1Q Breakeven price for 15% pre-tax rate of return % $ % 80% 60% 40% 20% 0% Pre-Tax ROR 11

13 APPENDIX 12

14 ANTERO RESOURCES EBITDAX RECONCILIATION EBITDAX Reconciliation ($ in millions) Quarter Ended LTM Ended 6/30/2016 6/30/2016 EBITDAX: Net income (loss) including noncontrolling interest $(575.5) $155.5 Commodity derivative fair value (gains) (1,219.5) Net cash receipts on settled derivatives instruments ,092.7 Interest expense Income tax expense (benefit) (376.5) 41.0 Depreciation, depletion, amortization and accretion Impairment of unproved properties Exploration expense Equity-based compensation expense Equity in earnings of unconsolidated affiliate (0.5) (0.5) Contract termination and rig stacking Consolidated Adjusted EBITDAX $332.1 $1,