Investor Presentation. EnerCom's The Oil & Gas Conference Denver, CO August 12, 2013

Transcription

1 Investor Presentation EnerCom's The Oil & Gas Conference Denver, CO August 12, 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 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% Low Cost Structure Q per unit cash costs 1 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 Strong Financial Position and Financial Flexibility $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 1 Excludes DD&A, exploration expense, stock-based compensation and pension termination expenses

3 ASSET OVERVIEW 2012 Year-End Proved Reserves: 3.8 Tcfe Q Production: Bcfe per day 2013E Drilling Activity: net wells Marcellus Shale ~200,000 net acres Current Rig Count: 6 (as of August 21, 2013) 2013E Drilling Activity: ~100 net wells Eagle Ford Shale / Pearsall Shale ~62,000 net Eagle Ford acres ~71,000 net Pearsall acres Current Rig Count: E Drilling Activity: ~45 net wells Marmaton Penn Lime ~70,000 net acres 2013E Drilling Activity: ~10 net wells

4 PROVEN TRACK RECORD OF PRODUCTION GROWTH Bcfe % 2013 Guidance: 44% - 54% (increased from 35%- 50%) Liquids (Net) Gas (Net) % E

5 AND RESERVE GROWTH 4.5? % % Tcfe % Liquids (Net) Gas (Net) E

6 SUPERIOR RESERVE REPLACEMENT AND FINDING COSTS 700% 600% 500% 400% 300% 200% 100% 0% Reserve Replacement Ratio 603% 390% 417% 255% $3.00 $2.26 All-Sources F&D Costs $2.00 $/Mcfe $1.00 $1.05 $1.21 $0.87 $

7 PEER LEADING PRODUCTION AND RESERVE GROWTH 42% Production Per Debt-Adjusted Share CAGR ( ) 30% 26% 24% 22% 17% 16% 15% 8% 8% 2% Peer median: 11% (0%) (2%) (3%) 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 (9%) 18% 17% 15% 9% Reserves Per Debt-Adjusted Share CAGR ( ) 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 includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC (36%)

8 DISCIPLINED CAPITAL SPENDING FOCUSED ON THE DRILL-BIT 2012 Capital Program: $979 million ($809 million net of JV and asset sales) Other 10% 2013 Capital Program: $1.1 billion - $1.2 billion Other 5% Eagle Ford / Marmaton / Pearsall 27% Eagle Ford / Marmaton / Pearsall 30% Marcellus 63% Marcellus 65% Production Equipment / Other 4% Land 9% Exploration 4% Production Equipment / Other 5% Land 5% Exploration 3% Drilling 83% Drilling 87%

9 INDUSTRY LEADING COST STRUCTURE Operating Transportation Taxes O/T Income G&A¹ Financing $2.50 $2.47 $0.57 $2.12 $ / Mcfe $2.00 $1.50 $1.00 $0.50 $0.00 $0.42 $0.43 $0.13 $0.91 $0.52 $0.40 $0.29 $0.15 $0.15 $0.76 $1.76 $0.38 $0.27 $0.39 $0.57 $1.67 $0.26 $0.25 $0.18 $0.54 $ $1.60 $0.15 $0.20 $0.15 $0.20 $0.10 $0.20 $0.50 $0.60 $0.44 $0.30 $ E 1 Excludes stock-based compensation and pension termination expenses

10 USE OF PROCEEDS FOR POTENTIAL FREE CASH FLOW IN 2014 Broker Estimate Range: $1,190mm $1,548mm Average: $1,342mm $34mm $75mm Implied Free Cash Flow: $278mm Broker Estimate Range: $1,477mm $1,981mm Average: $1,729mm 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 Average 2014 Henry Hub / WTI Broker Estimates: $4.01 per Mmbtu / $92.00 per Bbl Acceleration of Marcellus Drilling Program Dividend Policy (Increase Regular Dividend / Share Buybacks / Special Dividend) Acceleration of Eagle Ford Drilling Program Pay Down Revolver Borrowings 1 Based 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

11 MARCELLUS SHALE

12 CABOT MARCELLUS SUMMARY Rig Count: 6 (as of August 21, 2013) Wells Producing: 226 H, 39 V WOPL: 10 wells (245 Stages) Completing: 14 wells (266 Stages) WOC: 15 wells (347 Stages) 2 wells (37 stages) IP rate: 51.2 Mmcf/d 2 wells (27 stages) IP rate: 34.8 Mmcf/d Cumulative Production 8+ BCF 7-8 BCF 6-7 BCF 5-6 BCF 4-5 BCF 3-4 BCF Zick Pad Reilly Pad 2-3 BCF Bare Earth LiDAR with Aerial photo, Township Lines, Cabot Wells and Acreage ~ 3 Miles

13 EVOLUTION OF CABOT S MARCELLUS PROGRAM 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 Mmcfpd Gross Marcellus Daily Production 1,100 1, Dec-09 Dec-10 Dec-11 Dec-12

14 CONTINUED PERFORMANCE IMPROVEMENTS IN THE MARCELLUS Horizontal Length Average IP and 30-Day Rate Thousand Ft Mmcfpd Average Number of Stages EUR Stages Bcf Number of wells: , , , , Note: Data excludes wells drilled in the northern portion of our acreage position

15 MARCELLUS OPERATING EFFICIENCIES Drilling Days to TD Days Record of 8 days YTD Completion Cost Per Stage 1 $000s Per Stage $200 $150 $100 $50 $165 $150 $105 <$90 $ YTD 1 Pressure pumping costs only

16 CABOT 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 Average Working Interest: 100% Average Revenue Interest: 85% Gas Price Differential: NYMEX less $0.05 per Mmbtu Number of Stages Per Well: 18

17 COG MARCELLUS MARKETING STRATEGY Diversifying on Multiple Pipelines Firm Transportation Arrangements Long-Term Sales Agreements (Firm Sales) Investing in New Pipeline Projects Opportunistic Hedging Program

18 INTERSTATE PIPELINE MARKETS NY Canada Iroquois VT NH TGP 200 Line Constitution MA Boston Laser Millennium CT RI TGP 300 Line Hartford Springville Susquehanna County Long Island Transco Charlotte PA NJ New York City 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 ***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 Long-Term Sales Contracts (8-15 years in duration) 2013 (current) 325 Mmcf per day Mmcf per day 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

20 INFRASTRUCTURE UPDATE Maximum Interstate Delivery Capacity Compression, Dehydration & Measurement Capacity Year-end 2013 Year-end 2014 Year-end Bcf per day 3.4 Bcf per day 3.7 Bcf per day Note: Capacity volumes above are indicative deliverability estimates for facilities that are in place or planned for those periods; these are not production estimates.

21 Index 2013 MARCELLUS SALES BY INDEX AND UNHEDGED REALIZED PRICING COG 2013 Marcellus Sales By 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 Period COG Unhedged Realized Marcellus Pricing Differential to NYMEX ($/Mcf) Q ($0.01) Q $0.01 July 2013 ($0.15) Estimated August December 2013 ($ $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 Days Boepd 1, Peak 24-Hour Rate and 30-Day Rate Program Average Last 6 Wells Drilling Days to TD Q Q2 2013

24 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 1.2 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%

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.