Investor Presentation Jefferies 2013 Global Energy Conference Houston, TX November 12, 2013
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 costs 1 of $1.25 per Mcfe Low Cost Structure 2014 Marcellus per unit cash cost 1 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 Net debt to adjusted capitalization ratio of 33% as of 9/30/2013 Approximately 30% hedged at the midpoint of 2014 production guidance 1 Excludes DD&A, exploration expense, stock-based compensation and pension termination expenses
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 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 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) 2014E Drilling Activity: 130 140 net wells
PEER-LEADING PRODUCTION AND RESERVE GROWTH 42% Production Per Debt-Adjusted Share CAGR (2010 2012) 30% 26% 24% 22% 17% 16% 15% 8% 8% Peer median: 11% 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 18% 17% 15% 9% Reserves Per Debt-Adjusted Share CAGR (2010 2012) 5% 4% 2% Peer median: (2%) (1%) (2%) (4%) (10%) (12%) (18%) (21%) 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 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 (36%)
PROVEN TRACK RECORD OF PRODUCTION GROWTH 600 550 500 450 Bcfe 400 350 300 250 200 150 100 130.6 43.5% 187.5 42.8% 267.7 2013 Guidance: 44% - 54% (increased from 35%- 50%) 2014 Guidance: 30% - 50% Liquids (Net) Gas (Net) 50 0 2010 2011 2012 2013E 2014E
AND RESERVE GROWTH 4.5? 4.0 3.8 3.5 3.0 2.7 3.0 26.7% 2.5 12.3% Tcfe 2.0 2.1 31.1% Liquids (Net) Gas (Net) 1.5 1.0 0.5 0.0 2009 2010 2011 2012 2013E
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 5% Other 2% Eagle Ford / Marmaton / Pearsall 30% Eagle Ford 24% Marcellus 65% Marcellus 74% Production Equipment / Other 5% Land 5% Exploration 3% Production Equipment / Other 6% Land 6% Exploration 3% Drilling 87% Drilling 85%
INDUSTRY-LEADING COST STRUCTURE $2.50 $2.47 Operating Transportation¹ Taxes O/T Income G&A² Financing $2.12 $2.00 $ / Mcfe $1.50 $1.76 $1.67 Guidance Midpoint: $1.37 Guidance Midpoint: $1.21 $1.00 $0.80 $0.50 $0.00 2009 2010 2011 2012 2013E 2014E 2014E Marcellus Only 1 Includes all demand charges and gathering fees 2 Excludes stock-based compensation and pension termination expenses
50% PEER-LEADING CASH FLOW PER SHARE GROWTH WHILE GENERATING SUBSTANTIAL FREE CASH FLOW 2013E 2015E Cash Flow Per Share CAGR 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 $1,250 $1,000 $750 $500 $250 $0 ($250) ($500) ($750) ($1,000) ($1,250) 2014E 2015E Cumulative Free Cash Flow ($mm) COG Peer D Peer C Peer J Peer L Peer A Peer K Peer H Peer N Peer I Peer E Peer B Peer F Peer M Peer G 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
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
MARCELLUS SHALE
CABOT CONTINUES TO PRODUCE THE MOST PROLIFIC WELLS IN THE MARCELLUS SHALE Cumulative Production From January to June 2013 (Bcfe) 6.0 5.0 4.0 3.0 2.0 1.0 0.0 Top 20 Pennsylvania Marcellus Wells (January to June 2013) 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) Source: PA DEP Oil & Gas Reporting Website Note: Peers include Chief Oil & Gas and EQT Corporation
DERISKING OF CABOT S MARCELLUS POSITION 15 of Top 20 Marcellus Wells (Jan Jun 2013) SILVER LAKE Q2 FRIENDSVILLE / Q3 2013 Well Results MIDDLETOWN FOREST LAKE SILVER LAKE FRANKLIN BRIDGEWATER MONTROSE HALLSTEAD GREAT BEND NEW MILFORD SUSQUEHANNA DEPOT OAKLAND LANESBORO Recently Announced Q2 / Q3 2013 Well Results Number of Wells Total Frac Stages HARMONY THOMPSON Pad C 3 JACKSON 50 59.1 ARARAT Peak 24-Hour Rate (Mmcf/d) Pad A 4 109 109.5 Pad B 3 68 98.0 Pad D 3 45 55.8 Pad E 2 27 34.8 Pad F 1 23 32.8 JESSUP HARFORD RUSH BROOKLYN GIBSON HERRICK DIMOCK UNIONDALE AUBURN SPRINGVILLE LATHROP HOP BOTTOM LENOX CLIFFORD Cabot Acreage FOREST CITY Peer Acreage Conservation Areas
CONTINUED PERFORMANCE IMPROVEMENTS IN THE MARCELLUS Horizontal Length Average IP and 30-Day Rate Thousand Ft. 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 4.1 3.8 3.4 2.7 2.1 2008 2009 2010 2011 2012 Mmcfpd 20.0 15.0 10.0 5.0 0.0 16.8 17.4 15.1 14.0 14.5 11.9 8.7 7.4 7.2 5.9 2008 2009 2010 2011 2012 Average Number of Stages EUR Stages 20.0 15.0 10.0 5.0 4.6 8.5 13.4 15.6 17.7 Bcf 15.0 10.0 5.0 5.0 7.8 11.2 13.2 14.1 0.0 2008 2009 2010 2011 2012 0.0 2008 2009 2010 2011 2012 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
MARCELLUS RIG MOVE EFFICIENCIES 10 8.7 Move Days (Release to Spud) 8 6 4 2 7.4 4.8 4.0 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
CABOT IS DRILLING MARCELLUS WELLS FASTER DESPITE LONGER LATERAL LENGTHS 0 Drilling Days (Spud-to-Rig Release) 0 5 10 15 20 25 2,500 Measured Depth (Feet) 5,000 7,500 2011 2012 2013 YTD 10,000 12,500
MARCELLUS COMPLETION EFFICIENCIES FRAC EVOLUTION: 2010 Daylight Operations, single well pads 2011 24 Hour operations, multi well pads 2012 24 Hour operations, multi well pads, modified zipper operations 10 8 Average Frac Stages Per Crew Day Record of 9 frac stages per crew day (achieved five times) 9.0 2013 24 Hour operations, multi well pads, simultaneous zipper operations Days 6 EFFICIENCY RESULT: 4 100% increase in stages per day compared to 2010 Significant cost savings through the reduction in days on site 2 0 5.1 4.2 2.5 2.9 2010 2011 2012 2013 YTD
EVOLUTION OF CABOT S FRAC STAGE SPACING SHORTER STAGE LENGTHS AND REDUCED CLUSTER SPACING RESULTING IN HIGHER EURS PER 1,000 FEET OF LATERAL 4.0 3.7 EUR Per 1,000 of Lateral (Bcf) 3.0 2.0 1.0 2.4 2.9 3.3 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
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
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
CABOT S MARCELLUS GATHERING CAPACITY Cabot s Gross Marcellus Gathering Capacity (Mmcf/d) 4,000 3,650 3,800 Gross Takeaway Capacity (Mmcf/d) 3,000 2,000 1,000 0 2,380 1,580 650 255 20 95 Dec-08 Dec-09 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.
INTERSTATE PIPELINE MARKETS NY Canada Iroquois VT NH TGP 200 Line Constitution MA Boston Laser Millennium CT TGP 300 Line RI Hartford Springville Susquehanna County Long Island Transco PA New York City Charlotte NJ 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)
SCHEDULED APPALACHIA PIPELINE EXPANSIONS Over 13.3 Bcf/d of pipeline capacity expansions in Appalachia between now and 2017 with even more projects currently in the planning phases Cumulative Pipeline Capacity Additions (Bcf/d) 14 12 10 8 6 4 2 0 13.3 10.9 8.8 5.8 3.1 Q4 2013 2014 2015 2016 2017 Source: Bentek
CABOT S MARCELLUS ECONOMICS Typical Well IRR Sensitivity $6.5 million D&C $6.0 million D&C BTAX %IRR 200% 175% 150% 125% 100% 75% 50% 195% 150% 170% 115% 130% 80% 100% 70% $3.00 $3.50 $4.00 $4.50 Henry Hub ($ / Mmbtu) 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 Average Working Interest: 100% Average Revenue Interest: 85%
EAGLE FORD SHALE
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 Pad B 6-well pad Drilling Average lateral length over 8,000 Frio La Salle Atascosa McMullen ~20 miles
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
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.