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Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
Cabot Investor Presentation Aug 12, 2013
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Cabot Investor Presentation Aug 12, 2013

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Cabot Oil & Gas' latest Investor Presentation, prepared for the EnerCom Oil & Gas Conference held in Denver (August 12, 2013). The presentation contains a number of interesting slides, including a map …

Cabot Oil & Gas' latest Investor Presentation, prepared for the EnerCom Oil & Gas Conference held in Denver (August 12, 2013). The presentation contains a number of interesting slides, including a map of their well locations and a map of interstate pipelines detailing how they get all that gas (now over 1 Bcf/d) to market.

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  • 1. Investor Presentation EnerCom's The Oil & Gas Conference Denver, CO August 12, 2013
  • 2. Extensive Inventory of Low-Risk, High-Return Drilling Opportunities Industry Leading Production and Reserve Growth Low Cost Structure Strong Financial Position and Financial Flexibility – Over 3,000 identified drilling locations in the sweet spot of the Marcellus Shale with rates of return that rival or exceed all of the top U.S. liquids plays at current commodity prices – 25+ years of Marcellus inventory at current drilling levels – Oil-focused initiative in the Eagle Ford Shale – Increased 2013 production guidance range from 35% - 50% to 44% - 54% – Midpoint of 2013 guidance implies a three-year production CAGR of 45% – 2012 proved reserve growth of 27% for a three-year reserve CAGR of 23% – Q2 2013 per unit cash costs1 of $1.36 per Mcfe – 2012 all sources finding costs of $0.87 per Mcfe – 2012 all sources Marcellus finding costs of $0.49 per Mcfe – $566 million of liquidity as of 6/30/2013 – Net debt to adjusted capitalization ratio of 32% as of 6/30/2013 – Approximately 65% hedged at the midpoint of 2013 production guidance – 45 natural gas collar contracts for 2014 at a weighted average floor of $4.10 per Mcf 1Excludes DD&A, exploration expense, stock-based compensation and pension termination expenses KEY INVESTMENT HIGHLIGHTS
  • 3. Marcellus Shale ~200,000 net acres Current Rig Count: 6 (as of August 21, 2013) 2013E Drilling Activity: ~100 net wells Marmaton – Penn Lime ~70,000 net acres 2013E Drilling Activity: ~10 net wells Eagle Ford Shale / Pearsall Shale ~62,000 net Eagle Ford acres ~71,000 net Pearsall acres Current Rig Count: 2 2013E Drilling Activity: ~45 net wells ASSET OVERVIEW 2012 Year-End Proved Reserves: 3.8 Tcfe Q2 2013 Production: 1.046 Bcfe per day 2013E Drilling Activity: 155 – 165 net wells
  • 4. 130.6 187.5 267.7 0 50 100 150 200 250 300 350 400 2010 2011 2012 2013E Bcfe Liquids (Net) Gas (Net) 43.5% 42.8% 2013 Guidance: 44% - 54% (increased from 35%- 50%) PROVEN TRACK RECORD OF PRODUCTION GROWTH…
  • 5. ? 2.1 2.7 3.0 3.8 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 2009 2010 2011 2012 2013E Tcfe Liquids (Net) Gas (Net)31.1% 12.3% 26.7% …AND RESERVE GROWTH
  • 6. 255% 603% 390% 417% 0% 100% 200% 300% 400% 500% 600% 700% 2009 2010 2011 2012 Reserve Replacement Ratio $2.26 $1.05 $1.21 $0.87 $0.00 $1.00 $2.00 $3.00 2009 2010 2011 2012 $/Mcfe All-Sources F&D Costs SUPERIOR RESERVE REPLACEMENT AND FINDING COSTS
  • 7. 42% 30% 26% 24% 22% 17% 16% 15% 8% 8% 2% (0%) (2%) (3%) (9%) COG Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N Production Per Debt-Adjusted Share CAGR (2010 – 2012) PEER LEADING PRODUCTION AND RESERVE GROWTH 18% 17% 15% 9% 5% 4% 2% (1%) (2%) (4%) (10%) (12%) (18%) (21%) (36%) COG Peer C Peer E Peer F Peer L Peer D Peer A Peer J Peer K Peer H Peer M Peer G Peer I Peer B Peer N Reserves Per Debt-Adjusted Share CAGR (2010 – 2012) Peer median: 11% Peer median: (2%) Source: Cabot Oil & Gas, company filings Peer group includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC
  • 8. 2012 Capital Program: $979 million ($809 million net of JV and asset sales) 2013 Capital Program: $1.1 billion - $1.2 billion Marcellus 63% Production Equipment / Other 4% Drilling 83% Land 9% Exploration 4% Other 10% Eagle Ford / Marmaton / Pearsall 30% Marcellus 65% Land 5% Drilling 87% Production Equipment / Other 5% Exploration 3% Other 5% DISCIPLINED CAPITAL SPENDING FOCUSED ON THE DRILL-BIT Eagle Ford / Marmaton / Pearsall 27%
  • 9. $0.91 $0.76 $0.57 $0.44 $0.30 – $0.40 $0.13 $0.15 $0.39 $0.54 $0.50 – $0.60 $0.43 $0.29 $0.15 $0.18 $0.10 – $0.20 $0.42 $0.40 $0.27 $0.25 $0.15 – $0.20 $0.57 $0.52 $0.38 $0.26 $0.15 – $0.20 $2.47 $2.12 $1.76 $1.67 $1.20 - $1.60 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 2009 2010 2011 2012 2013E $/Mcfe Operating Transportation Taxes O/T Income G&A¹ Financing 1 Excludes stock-based compensation and pension termination expenses INDUSTRY LEADING COST STRUCTURE
  • 10. $34mm $75mm 2014E Capital Expenditures¹ Current Regular Dividend (Recently increased by 100% effective August 2013) Estimated Capital Commitment for Constitution Pipeline Implied 2014 Free Cash Flow 2014E Cash Flow¹ 1Based on broker consensus estimates as of August 7, 2013; cash flow estimates based on consensus cash flow per share estimates multiplied by current outstanding share count Broker Estimate Range: $1,190mm – $1,548mm Average: $1,342mm USE OF PROCEEDS FOR POTENTIAL FREE CASH FLOW IN 2014 Broker Estimate Range: $1,477mm – $1,981mm Average: $1,729mm Implied Free Cash Flow: $278mm Acceleration of Marcellus Drilling Program Acceleration of Eagle Ford Drilling ProgramDividend Policy (Increase Regular Dividend / Share Buybacks / Special Dividend) Average 2014 Henry Hub / WTI Broker Estimates: $4.01 per Mmbtu / $92.00 per Bbl Pay Down Revolver Borrowings
  • 11. MARCELLUS SHALE
  • 12. Bare Earth LiDAR with Aerial photo, Township Lines, Cabot Wells and Acreage ~ 3 Miles CABOT MARCELLUS SUMMARY Reilly Pad Zick Pad Completing: 14 wells (266 Stages) Wells Producing: 226 H, 39 V WOPL: 10 wells (245 Stages) WOC: 15 wells (347 Stages) Rig Count: 6 (as of August 21, 2013) Cumulative Production 5-6 BCF 4-5 BCF 3-4 BCF 2-3 BCF 7-8 BCF 6-7 BCF 8+ BCF 2 wells (27 stages) IP rate: 34.8 Mmcf/d2 wells (37 stages) IP rate: 51.2 Mmcf/d
  • 13. EVOLUTION OF CABOT’S MARCELLUS PROGRAM 0 100 200 300 400 500 600 700 800 900 1,000 1,100 Dec-09 Dec-10 Dec-11 Dec-12 Mmcfpd Gross Marcellus Daily Production 2010 2011 2012 2013 and beyond • 13% HBP • Reduced stage spacing from 300 ft. to 250 ft. • Divested midstream assets • 44 producing Hz wells • 29% HBP • Drilling days reduced • Reduced completion cost per stage • 107 producing Hz wells • 43% HBP • Implemented 200 ft. stage spacing • Tested Upper Marcellus • Tested downspacing • De-risked eastern edge of our acreage position • 185 producing Hz wells • Expected to be 60% HBP by year-end 2013 • Transition into development mode (improved efficiencies / reduced costs) • Additional testing of Upper Marcellus • Additional downspacing testing
  • 14. 2.1 2.7 3.4 3.8 4.1 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 2008 2009 2010 2011 2012 ThousandFt. Horizontal Length 7.4 8.7 15.1 16.8 17.4 5.9 7.2 11.9 14.0 14.5 0.0 5.0 10.0 15.0 20.0 2008 2009 2010 2011 2012 Mmcfpd Average IP and 30-Day Rate 4.6 8.5 13.4 15.6 17.7 0.0 5.0 10.0 15.0 20.0 2008 2009 2010 2011 2012 Stages Average Number of Stages 5.0 7.8 11.2 13.2 14.1 0.0 5.0 10.0 15.0 2008 2009 2010 2011 2012 Bcf EUR Number of wells: 2008 - 5, 2009 - 29, 2010 - 55, 2011 – 40, 2012 – 40 Note: Data excludes wells drilled in the northern portion of our acreage position CONTINUED PERFORMANCE IMPROVEMENTS IN THE MARCELLUS
  • 15. 26 20 16 14 0 10 20 30 2010 2011 2012 2013 YTD Days Drilling Days to TD Record of 8 days $165 $150 $105 <$90 $0 $50 $100 $150 $200 2010 2011 2012 2013 YTD $000sPerStage Completion Cost Per Stage1 MARCELLUS OPERATING EFFICIENCIES 1 Pressure pumping costs only
  • 16. Typical Well Parameters (Based on 2012 Program)  EUR: 14.1 Bcf  IP Rate: 17.4 Mmcfpd  Lateral Length: 4,100’  Number of Stages Per Well: 18 CABOT MARCELLUS ECONOMICS  Average Working Interest: 100%  Average Revenue Interest: 85%  Gas Price Differential: NYMEX less $0.05 per Mmbtu 70% 100% 130% 170% 80% 115% 150% 195% 50% 75% 100% 125% 150% 175% 200% $3.00 $3.50 $4.00 $4.50 BTAX%IRR Henry Hub ($ / Mmbtu) $6.5 million D&C $6.0 million D&C Typical Well IRR Sensitivity
  • 17. Diversifying on Multiple Pipelines Firm Transportation Arrangements Long-Term Sales Agreements (Firm Sales) Investing in New Pipeline Projects COG MARCELLUS MARKETING STRATEGY Opportunistic Hedging Program
  • 18. NY VT NH PA NJ CT MA RI Iroquois Millennium Springville TGP 200 Line Canada Boston Hartford Long Island Laser TGP 300 Line Transco Constitution New York City Charlotte INTERSTATE PIPELINE MARKETS Susquehanna County Current Markets Tennessee Gas Pipeline (300) Transco Gas Pipeline Millennium Gas Pipeline 2015 Market Additions Iroquois Pipeline Tennessee Gas Pipeline (200) TransCanada Pipeline (via Iroquois)
  • 19. FIRM TRANSPORTATION AND LONG-TERM SALES CONTRACTS Firm Transportation Contracts 2013 (current) 325 Mmcf per day 2014 (current / target) 325 Mmcf per day / 450 Mmcf per day 2015 (current / target)*** 875 Mmcf per day / 1 Bcf per day Long-Term Sales Contracts (8-15 years in duration) 2013 (current) 325 Mmcf per day 2014 450 Mmcf per day 2015 615 Mmcf per day – Long-term sales contracts include volumes COG moves under its customers’ firm capacity – Long-term sales contract volumes will change going forward as new opportunities become available ***The increase from 2014 to 2015 includes 500 Mmcf/d of firm capacity associated with Constitution Pipeline – Firm transportation contracts include volumes COG moves under its own firm capacity – Targeted firm transportation volumes are subject to closing on agreements COG is currently negotiating – 100% of COG’s volumes are gathered under a long-term firm agreement
  • 20. INFRASTRUCTURE UPDATE Maximum Interstate Delivery Capacity Note: Capacity volumes above are indicative deliverability estimates for facilities that are in place or planned for those periods; these are not production estimates. Compression, Dehydration & Measurement Capacity Year-end 2013 2.2 Bcf per day Year-end 2014 3.4 Bcf per day Year-end 2015 3.7 Bcf per day
  • 21. 2013 MARCELLUS SALES BY INDEX AND UNHEDGED REALIZED PRICING COG 2013 Marcellus Sales By Index Index % of COG 2013 Marcellus Sales NYMEX 65% Dominion Transmission*** 19% Columbia Gas Transmission 11% Other 5% ***Approximately 70% of the volumes sold at Dominion Transmission pricing are hedged through 2013 COG Unhedged Realized Marcellus Pricing Period Differential to NYMEX ($/Mcf) Q1 2013 ($0.01) Q2 2013 $0.01 July 2013 ($0.15) Estimated August – December 2013 ($0.10 - $0.15)
  • 22. EAGLE FORD SHALE
  • 23. EAGLE FORD SHALE SUMMARY  ~62,000 net acres  Current operated rig count: 2 – Added a second rig in late July that will focus solely on multi-well pad development (3 – 6 wells per pad)  Operated wells producing: 50  Operated wells currently drilling: 2  Operating wells completing: 2  Average completed well cost: ~$6.5mm – Multi-well pad drilling expected to reduce well costs by $500,000 - $600,000 per well  400’ down-spacing results continue to reinforce the concept, resulting in ~500 identified undrilled locations remaining in COG’s 100% owned and operated Buckhorn area  Recently completed an extended lateral well (8,000’+) with a 24-hour peak rate of ~1,130 Boepd and a 120-day rate of ~1,100 Boepd 15 10 9 0 5 10 15 2012 Q1 2013 Q2 2013 Days Drilling Days to TD 650 900 450 570 0 250 500 750 1,000 Program Average Last 6 Wells Boepd Peak 24-Hour Rate and 30-Day Rate
  • 24. 3,000+ Locations in the Sweet Spot of the Marcellus Shale Implying 25+ Years of Inventory at Current Drilling Levels Currently Producing 1.2 Bcf/d of Gross Marcellus Production From Only 8% of Our Identified Locations Transitioning From Acreage Capture to Efficient Pad Development in 2014 Cash Flow Neutral Investment Program in 2013 While Growing Production 44% to 54% SIMPLE GROWTH STORY
  • 25. Thank you The statements regarding future financial performance and results and the other statements which are not historical facts contained in this presentation are forward-looking statements that involve risks and uncertainties, including, but not limited to, market factors, the market price of natural gas and oil, results of future drilling and marketing activity, future production and costs, and other factors detailed in the Company’s Securities and Exchange Commission filings.

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