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Cabot Oil & Gas Marcellus & Eagle Ford Presentation at BOA Merrill Lynch Global Energy Event, Nov 2013
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Cabot Oil & Gas Marcellus & Eagle Ford Presentation at BOA Merrill Lynch Global Energy Event, Nov 2013

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PowerPoint presentation with loads of useful maps and charts that details Cabot's shale drilling program in the northeast Marcellus--in Susquehanna County, PA. Cabot is the lowest price producer MDN …

PowerPoint presentation with loads of useful maps and charts that details Cabot's shale drilling program in the northeast Marcellus--in Susquehanna County, PA. Cabot is the lowest price producer MDN is aware of. They estimate in 2014 their breakeven cost to drill--the cost at which they will start turning a profit--is a low, low 80 cents per thousand cubic feet of natural gas ($0.80 Mcf). It is an astonishing number.

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  • 1. Investor Presentation Bank of America Merrill Lynch 2013 Global Energy Conference November 21, 2013
  • 2. KEY INVESTMENT HIGHLIGHTS Extensive Inventory of Low-Risk, High-Return Drilling Opportunities Industry-Leading Production and Reserve Growth – Over 3,000 identified drilling locations in the sweet spot of the Marcellus Shale implying 25+ years of inventory at current drilling levels – Peer-leading rates of return and EUR per lateral foot in the Marcellus Shale – Oil-focused initiative in the Eagle Ford Shale – Initiated 2014 production growth guidance of 30% - 50% – Reaffirmed 2013 production growth guidance of 44% - 54% – 2012 proved reserve growth of 27% resulting in a three-year reserve CAGR of 23% – Q3 2013 total company per unit cash costs1 of $1.25 per Mcfe Low Cost Structure – 2014 Marcellus per unit cash cost1 guidance of ~$0.80 per Mcf – 2012 total company all-sources finding costs of $0.87 per Mcfe – 2012 Marcellus all-sources finding costs of $0.49 per Mcf Strong Financial Position and Financial Flexibility 1Excludes – Net debt to adjusted capitalization ratio of 33% as of 9/30/2013 – Approximately 30% hedged at the midpoint of 2014 production guidance DD&A, exploration expense, stock-based compensation and pension termination expenses
  • 3. ASSET OVERVIEW 2012 Year-End Proved Reserves: 3.8 Tcfe Q3 2013 Production: 1.164 Bcfe per day 2013E Drilling Activity: 155 – 165 net wells 2014E Drilling Activity: 170 – 190 net wells Marcellus Shale ~200,000 net acres Current Rig Count: 6 (as of August 21, 2013) 2013E Drilling Activity: ~100 net wells 2014E Rig Count: 7 (beginning January 2014) Eagle Ford Shale ~62,000 net acres Current Rig Count: 2 2013E Drilling Activity: 30 – 35 net wells 2014E Rig Count: 2 2014E Drilling Activity: 40 – 50 net wells 2014E Drilling Activity: 130 – 140 net wells
  • 4. PEER-LEADING PRODUCTION AND RESERVE GROWTH Production Per Debt-Adjusted Share CAGR (2010 – 2012) 42% 30% 26% 24% 22% 17% 16% 15% 8% Peer median: 11% 8% 2% (0%) COG 18% Peer A 17% Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K (2%) Peer L (3%) Peer M (9%) Peer N Reserves Per Debt-Adjusted Share CAGR (2010 – 2012) 15% 9% 5% 4% 2% Peer median: (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 Source: Cabot Oil & Gas, company filings Peer group from 2013 proxy statement includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC Peer M Peer G Peer I Peer B Peer N
  • 5. TRANSFORMATION TO A MARCELLUS AND EAGLE FORD FOCUSED STORY IN 2014 2013E Capital Program: $1.1 billion - $1.2 billion 2014E Capital Program: $1.375 billion - $1.475 billion Other 2% Other 5% Eagle Ford 24% Eagle Ford / Marmaton / Pearsall 30% Marcellus 74% Marcellus 65% Production Equipment / Other 5% Land 5% Exploration 3% Production Equipment / Other 6% Drilling 87% Land 6% Exploration 3% Drilling 85%
  • 6. PROVEN TRACK RECORD OF PRODUCTION GROWTH… 600 550 500 Bcfe 450 400 2014 Guidance: 30% - 50% 350 300 267.7 250 150 2013 Guidance: 44% - 54% (increased from 35%50%) 187.5 200 42.8% 130.6 43.5% 100 Liquids (Net) Gas (Net) 50 0 2010 2011 2012 2013E 2014E
  • 7. …AND RESERVE GROWTH ? 4.5 4.0 3.8 3.5 3.0 Tcfe 3.0 12.3% 2.5 2.0 26.7% 2.7 2.1 Liquids (Net) 31.1% Gas (Net) 1.5 1.0 0.5 0.0 2009 2010 2011 2012 2013E
  • 8. INDUSTRY-LEADING COST STRUCTURE Operating $2.50 Transportation¹ Taxes O/T Income G&A² Financing $2.47 $2.12 $2.00 $ / Mcfe $1.76 $1.67 $1.50 Guidance Midpoint: $1.37 Guidance Midpoint: $1.21 $1.00 $0.80 $0.50 $0.00 2009 1 Includes 2010 2011 all demand charges and gathering fees stock-based compensation and pension termination expenses 2 Excludes 2012 2013E 2014E 2014E Marcellus Only
  • 9. PEER-LEADING CASH FLOW PER SHARE GROWTH WHILE GENERATING SUBSTANTIAL FREE CASH FLOW 2013E – 2015E Cash Flow Per Share CAGR 50% 40% 30% 20% 10% 0% (10%) COG Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N Peer B Peer F Peer M Peer G 2014E – 2015E Cumulative Free Cash Flow ($mm) $1,250 $1,000 $750 $500 $250 $0 ($250) ($500) ($750) ($1,000) ($1,250) COG Peer D Peer C Peer J Peer L Peer A Peer K Peer H Peer N Peer I Peer E Source: First Call consensus median as of 11/11/2013; cumulative free cash flow defined as cash flow per share times shares outstanding less capital expenditures; consensus 2014 pricing of $3.85 per Mmbtu and $93.92 per Bbl Peer group from 2013 proxy statement includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC
  • 10. POTENTIAL USES FOR FREE CASH FLOW Expand Core Acreage Positions in the Marcellus and Eagle Ford Accelerate Development of our Marcellus and Eagle Ford Programs Organically Build Positions in New Venture Opportunities Return Cash to Shareholders Via Share Buybacks and Increased Regular Dividends
  • 11. MARCELLUS SHALE
  • 12. Cumulative Production From January to June 2013 (Bcfe) CABOT CONTINUES TO PRODUCE THE MOST PROLIFIC WELLS IN THE MARCELLUS SHALE Top 20 Pennsylvania Marcellus Wells (January to June 2013) 6.0 5.0     15 of the top 20 (January to June 2013) 10 of the top 20 (July to December 2012) 14 of the top 20 (January to June 2012) 15 of the top 20 (July to December 2011) 4.0 3.0 2.0 1.0 0.0 Source: PA DEP Oil & Gas Reporting Website Note: Peers include Chief Oil & Gas and EQT Corporation
  • 13. DERISKING OF CABOT’S MARCELLUS POSITION 15 of Top 20 Marcellus Wells (Jan – Jun 2013) SILVER LAKE LANESBORO HALLSTEAD SILVER LAKE GREAT BEND Recently Announced Q2 / Q3 2013 Well Results HARMONY SUSQUEHANNA Total Frac Number of Peak 24-Hour DEPOT Wells Stages Rate (Mmcf/d) Pad A OAKLAND MIDDLETOWN 3 68 98.0 3 JACKSON 50 59.1 Pad D 3 45 55.8 Pad E 2 27 34.8 Pad F FOREST LAKE 109.5 Pad B FRANKLIN 109 Pad C FRIENDSVILLE Q2 / Q3 2013 Well Results 4 1 23 NEW MILFORD BRIDGEWATER MONTROSE THOMPSON 32.8 ARARAT JESSUP HARFORD RUSH GIBSON BROOKLYN HERRICK DIMOCK UNIONDALE HOP BOTTOM AUBURN LATHROP SPRINGVILLE LENOX CLIFFORD Cabot Acreage FOREST CITY Peer Acreage Conservation Areas
  • 14. CONTINUED PERFORMANCE IMPROVEMENTS IN THE MARCELLUS 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 3.4 3.8 Average IP and 30-Day Rate 20.0 4.1 2.7 2.1 10.0 5.0 2008 2009 2010 15.1 15.0 Mmcfpd Thousand Ft. Horizontal Length 2011 0.0 2012 11.9 7.4 8.7 5.9 2008 13.4 2009 5.0 0.0 2010 13.2 10.0 5.0 2009 2011 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 2011 2012 14.1 11.2 4.6 2008 2010 15.0 17.7 8.5 10.0 14.5 EUR Bcf Stages 15.0 15.6 14.0 17.4 7.2 Average Number of Stages 20.0 16.8 2012 0.0 7.8 5.0 2008 2009 2010 2011 2012
  • 15. MARCELLUS RIG MOVE EFFICIENCIES 10 Move Days (Release to Spud) 8.7 8 7.4 6 4.8 4.0 4 2 0 2011/2012 (25 Moves) Implementation of New Move Process (4 Moves) Average For Last 19 Moves Target  Implemented a new rig move process in 2013 including 24-hour operations for rig up and rig down  The new process has reduced average rig moves by ~4 days  4-day reduction in move time yields $250K in savings per move including rig time, trucking, rentals, and labor charges
  • 16. CABOT IS DRILLING MARCELLUS WELLS FASTER DESPITE LONGER LATERAL LENGTHS Drilling Days (Spud-to-Rig Release) 0 5 10 15 20 25 0 Measured Depth (Feet) 2,500 5,000 2011 2012 2013 YTD 7,500 10,000 12,500
  • 17. MARCELLUS COMPLETION EFFICIENCIES FRAC EVOLUTION: Average Frac Stages Per Crew Day 2010 – Daylight Operations, single well pads 10 Record of 9 frac stages per crew day (achieved five times) 2011 – 24 Hour operations, multi well pads 8 2013 – 24 Hour operations, multi well pads, simultaneous zipper operations EFFICIENCY RESULT: Days 2012 – 24 Hour operations, multi well pads, modified zipper operations 6 4  100% increase in stages per day compared to 2010  Significant cost savings through the reduction in days on site 9.0 4.2 2 2.5 0 2.9 2010 2011 5.1 2012 2013 YTD
  • 18. EVOLUTION OF CABOT’S FRAC STAGE SPACING SHORTER STAGE LENGTHS AND REDUCED CLUSTER SPACING RESULTING IN HIGHER EURS PER 1,000 FEET OF LATERAL EUR Per 1,000’ of Lateral (Bcf) 4.0 3.7 3.3 2.9 3.0 2.4 2.0 1.0 0.0 2008 2009 2010 - Q2 2012 Q3 - Q4 2012 Packer Systems Completion 400’ spacing Packer Systems Completion 300’ spacing Plug/Perf 250’ spacing Plug/Perf 200’ spacing
  • 19. COMPRESSED NATURAL GAS (CNG) AND LINE GAS USAGE IN CABOT’S MARCELLUS OPERATIONS CNG Usage in Cabot’s Vehicles - Estimated displacement of ~110,000 gasoline gallon equivalents (GGE) in 2014 CNG / Line Gas Usage in Cabot’s Drilling Operations - Estimated displacement of ~1.1 million diesel gallon equivalents (DGE) in 2014 - Plan to utilize CNG / Line Gas in 100% of Cabot’s future drilling operations for estimated displacement of 2.5+ million DGE Line Gas Usage in Cabot’s Completion Operations - Estimated displacement of ~1.5 million DGE in 2014 - Plan to utilize Line Gas in 100% of Cabot’s future completion operations for estimated displacement of 2.6+ million DGE
  • 20. COG MARCELLUS MARKETING STRATEGY Diversifying on Multiple Pipelines to Multiple Geographic Locations Firm Transportation Arrangements Long-Term Sales Agreements (Firm Sales) Investing in New Pipeline Projects Opportunistic Hedging Program
  • 21. CABOT’S MARCELLUS GATHERING CAPACITY Cabot’s Gross Marcellus Gathering Capacity (Mmcf/d) Gross Takeaway Capacity (Mmcf/d) 4,000 3,650 3,800 3,000 2,380 2,000 1,580 1,000 0 650 20 95 Dec-08 Dec-09 255 Dec-10 Dec-11 Dec-12 Dec-13 Dec-14 Dec-15 Note: Capacity volumes above are indicative deliverability estimates for facilities that are in place or planned for those periods; these are not production estimates. Facilities include compression, dehydration and measurement.
  • 22. INTERSTATE PIPELINE MARKETS Canada Iroquois NY NH VT TGP 200 Line Constitution Laser Boston MA CT Millennium RI TGP 300 Line Hartford Springville Transco Susquehanna County Long Island New York City PA NJ Charlotte Current Markets Tennessee Gas Pipeline – 300 (CT, NJ, OH, PA, WV) Transco Gas Pipeline (DC, MD, NC, NJ, NY, PA, VA) Millennium Gas Pipeline (CT, NJ, NY, RI) 2015 Market Additions Iroquois Pipeline (CT, Long Island) Tennessee Gas Pipeline – 200 (CT, MA, NH) TransCanada Pipeline (via Iroquois)
  • 23. SCHEDULED APPALACHIA PIPELINE EXPANSIONS Cumulative Pipeline Capacity Additions (Bcf/d) Over 13.3 Bcf/d of pipeline capacity expansions in Appalachia between now and 2017 with even more projects currently in the planning phases 14 13.3 12 10.9 10 8.8 8 5.8 6 4 3.1 2 0 Q4 2013 Source: Bentek 2014 2015 2016 2017
  • 24. CABOT’S MARCELLUS ECONOMICS Typical Well IRR Sensitivity $6.5 million D&C $6.0 million D&C 195% 200% BTAX %IRR 175% 150% 150% 115% 125% 100% 80% 75% 50% 170% 130% 100% 70% $3.00 $3.50 $4.00 Henry Hub ($ / Mmbtu) Typical Well Parameters (Based on 2012 Program)  EUR: 14.1 Bcf  Number of Stages Per Well: 18  IP Rate: 17.4 Mmcfpd  Average Working Interest: 100%  Lateral Length: 4,100’  Average Revenue Interest: 85% $4.50
  • 25. EAGLE FORD SHALE
  • 26. 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: 56 Pad A • 4-well pad • Completing • Lateral lengths ranging from 5,200’ to 8,000’  Operated wells currently drilling / suspended: 6  Operated wells completing: 5  Average completed well cost: ~$6.5mm – Multi-well pad drilling expected to reduce well costs by $500,000 - $600,000 per well  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 ~20 miles Pad B • 6-well pad • Drilling • Average lateral length over 8,000’ Frio Atascosa La Salle McMullen
  • 27. SIMPLE GROWTH STORY 3,000+ Locations in the Sweet Spot of the Marcellus Shale Implying 25+ Years of Inventory at Current Drilling Levels Currently Producing 1.3 Bcf/d of Gross Marcellus Production From Only 8% of Our Identified Locations Peer-Leading Rates of Return and EUR Per Lateral Foot in the Marcellus Shale Industry-Leading Cost Structure Continuing to Improve Due to Efficiency Gains Best-In-Class Production and Cash Flow Per Share Growth While Generating Free Cash Flow
  • 28. 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.