Morgan Stanley Marcellus-Utica Summit September 29, 2015 Pittsburgh, PA

Transcription

1 Morgan Stanley Marcellus-Utica Summit September 29, 2015 Pittsburgh, PA

2 CABOT OIL & GAS ASSET OVERVIEW 2014 Year-End Proved Reserves: 7.4 Tcfe 2014 Production: Bcfe 2015E Production Growth: 10% - 18% 2015E Drilling Activity: ~115 net wells Eagle Ford Shale ~89,000 net acres >1,300 locations Current Rig Count: E Drilling Activity: ~45 net wells Marcellus Shale ~200,000 net acres >3,000 locations Current Rig Count: E Drilling Activity: ~70 net wells 2

3 WELL POSITIONED TO NAVIGATE A CHALLENGING MARKET IN 2015 Best-in-class asset base provides competitive rates-of-return in the current market environment Peer-leading rates of return and EUR per lateral foot in the Marcellus Shale Marcellus: >50% IRR at $2.00 per Mcf realized price Eagle Ford: >50% IRR at $65.00 per Bbl realized price Strategy is to provide returns-focused growth as opposed to growth for the sake of growth Cabot expects to generate 10% - 18% production growth in 2015 despite a 45% reduction in drilling and completion spending Modest level of outspend anticipated under current commodity price realizations Low-cost structure 2014 total company all-sources finding costs of $0.71 per Mcfe 2014 Marcellus-only all-sources finding costs of $0.43 per Mcf 2014 total company cash costs 1 of $1.27 per Mcfe 2014 Marcellus-only cash costs 1 of $0.80 per Mcf Strong balance sheet provides financial flexibility in a low commodity price environment Conservative leverage position: Debt / LTM EBITDAX 2 of 1.7x at Q Financial flexibility: Recently increased credit facility commitments to $1.8 billion, with only $383 million of borrowings outstanding as of June 30, 2015 Hedge position provides downside protection: ~31% of 2015E natural gas production hedged 1 Excludes DD&A, exploration expense, and stock-based compensation 2 EBITDAX is a non-gaap measure defined as net income plus interest expense, income tax expense, depreciation, depletion and amortization, exploration expense, gains and losses resulting from the sale of assets, non-cash gains and losses on derivative instruments, and stock-based compensation expense and other 3

4 2015 OPERATING PLAN AND CAPITAL PROGRAM DOUBLE-DIGIT PRODUCTION GROWTH DESPITE A 45% DECLINE IN CAPITAL SPENDING, HIGHLIGHTING COG S CAPITAL EFFICIENCY Net Wells Drilled 177 (~35%) ~115 FY 2014 FY 2015 Completed Frac Stages (~35%) FY 2014 FY 2015 Drilling and Completion Capital ($mm) $1,315 (~45%) ~$ E Capital Program: $900 million Land 4% Production Equipment / Other 12% Eagle Ford 40% Exploration 4% 2015E D&C Capital: $720 million Drilling & Completion 80% FY 2014 FY 2015 Marcellus 60% 4

5 PROVEN TRACK RECORD OF PRODUCTION AND RESERVE GROWTH Annual Production (Bcfe) Bcfe % % % % 2015 Guidance: 10% - 18% E Liquids Gas Year-End Proved Reserves (Tcfe) Tcfe % 41.9% 26.7% 12.3% E Liquids Gas 5

6 WHILE MAINTAINING A CONSERVATIVE BALANCE SHEET Net Debt to EBITDAX 1 2.0x 1.7x 1.5x 1.5x 1.4x 1.3x 1.2x 1.0x 0.9x 0.5x 0.0x LTM Q EBITDAX is a non-gaap measure defined as net income plus interest expense, income tax expense, depreciation, depletion and amortization, exploration expense, gains and losses resulting from the sale of assets, non-cash gains and losses on derivative instruments, and stock-based compensation expense and other 6

7 INDUSTRY-LEADING COST STRUCTURE $2.00 Operating Transportation¹ Taxes O/T Income Cash G&A² Financing $1.76 $1.67 Cash Unit Costs ($/Mcfe) $1.50 $1.00 $0.50 $1.28 $1.27 $1.26 $ H Year F&D Costs: Total Company ($/Mcfe) $1.30 $1.02 $0.76 $ Year F&D Costs: Marcellus Only ($/Mcfe) $0.65 $0.56 $0.48 $ Includes all demand charges and gathering fees 2 Excludes stock-based compensation 7

8 CABOT S LOW-COST STRUCTURE IS DESIGNED TO WEATHER ALL COMMODITY CYCLES 2014 Cash Costs Per Unit vs. Appalachia Peers ($/Mcfe) Production Per Employee vs. Appalachia Peers (Mmcfe) Operating Costs G&A Interest $ Cash Unit Costs ($/Mcfe) $1.00 $0.75 $0.50 $0.25 Production Per Employee (Mmcfe) $0.00 COG Peer A Peer B Peer C Peer D 0 Peer B COG Peer D Peer A Peer C Source: 2014 company filings 1 Excludes gathering, transport, processing and marketing costs Peers include: Antero Resources, EQT, Range Resources and Southwestern Energy 8

9 MARCELLUS SHALE

10 CABOT S MARCELLUS SHALE SUMMARY ~200,000 net acres Operated rig count: E drilling activity: ~70 net wells Average Gross Daily Marcellus Production (Bcf/d) E average gross daily production: Bcf/d Production levels from quarter to quarter will ultimately be dictated by price realizations and potential curtailments Flexibility to accelerate / decelerate completion capital throughout the year Reduction in drilling and completion activity in 2015 is predicated on lower anticipated natural gas price realizations throughout Appalachia as we await the inservice of new takeaway capacity COG plans to accelerate activity upon the in-service of Constitution Pipeline in 2H 2016 COG s best-in-class Marcellus assets generate >50% IRR at a realized price of $2.00 per Mcf Currently testing downspacing between laterals, which would increase inventory / resource potential / NAV, if successful FY 2014 FY 2015 Average Marcellus Rig Count FY 2014 FY 2015 Marcellus Drilling and Completion Capital ($mm) $850 ~$430 FY 2014 FY

11 CABOT OIL & GAS CONTINUES TO DRILL THE MOST PROLIFIC WELLS IN THE MARCELLUS SHALE Top 100 Marcellus Wells By Operator 1 Percentage of Operator s Total Wells in Top 100 Peer E 3 Peer D 3 Peer C 4 Peer F 3 Peer G 1 Peer H 1 Peer I 1 Cabot Peer C Peer F Peer G 5% 10% 20% 26% Peer B 7 Peer B 5% Peer A 7 Peer D Peer A 2% 1% Cabot 70 Peer H Peer E 1% 1% Peer I 1% Includes content supplied by IHS Global, Inc.; copyright IHS Global, Inc., 2015, All Rights Reserved. Includes all horizontal / directional Marcellus wells in Pennsylvania and West Virginia with a production start date from January 2012 to December As measured by max 30-day rate Note: Peers include Antero Resources, Chesapeake Energy, Chief Oil & Gas, EQT, Inflection Energy, PGE, Shell, Vantage Energy and Warren Resources 11

12 CABOT S EUR PER FOOT AND F&D COSTS REMAIN BEST-IN-CLASS IN THE MARCELLUS AND UTICA 4.0 $1.20 EUR per 1,000 ft. of lateral (Bcfe) $1.00 $0.80 $0.60 $0.40 $0.20 Implied F&D Cost ($/Mcfe) Source: Company presentations as of 08/03/15; peers include Antero Resources, EQT Corporation, Gulfport Energy, Noble Energy, Range Resources and Rice Energy 12

13 CABOT S MARCELLUS SHALE ECONOMICS BTAX %IRR 175% 150% 125% 100% 75% 50% 25% 0% 8% 17% 2015 Program Well 2014 Program Well 51% 37% Cabot s YTD 2015 realized natural gas price: $ % 65% 152% 102% $1.50 $2.00 $2.50 $3.00 Realized Natural Gas Price Held Flat ($/Mmbtu) Typical Marcellus Well Parameters EUR: 18 Bcf (3.6 Bcf per 1,000 ) D&C Cost: $5.6MM Facilities Cost: $400K Lateral Length: 5,000 Number of Stages: 25 Average Working Interest: 100% Average Net Revenue Interest: 85% Even assuming wider differentials in Appalachia persist, the incremental Cabot Marcellus well produced into the local market generates a rate of return of >55% based on the current NYMEX strip 1 Note: Single well economics are all-in and include capital associated with road, pad and production facilities. 1 Assumes NYMEX strip as of August 5, 2015, held flat after year 9. Assumes regional differential of ($1.00) for the life of the well. 13

14 CABOT S MARCELLUS DRILLING AND COMPLETION COST SAVINGS Marcellus AFE Well Costs By Component YTD Marcellus Well Cost Savings By Category Drilling Rig 7% Facilities 7% Tangibles 7% Completion Services 31% 0% Frac Services Drilling Services Completion Services Facilities Drilling Rig Tangibles (10%) (20%) Frac Services 19% (30%) Drilling Services 29% (40%) 14

15 CABOT S MARCELLUS DRILLING EFFICIENCIES Marcellus Drilling Days (Spud to TD) Q Q Q Q Q Q Record 1 Normalized to a 5,000 lateral length 15

16 CABOT S PRICE REALIZATION OUTLOOK IMPROVES SIGNIFICANTLY WITH THE ADDITION OF NEW TAKEAWAY CAPACITY TO FAVORABLY PRICED MARKETS Gulf Coast / Mid-Atlantic New England / NY / Canada NE PA DTI TCO Fixed Price 100% 90% 20% 6% 4% 9% 8% % of Sales by Index 80% 70% 60% 50% 40% 30% 20% 10% 0% 8% 11% 43% 3% 15% Illustrative Differential to NYMEX ($/Mcf) 1 ($0.95) ($1.05) Access to more favorably priced markets in 2017 / 2018 results in a significant improvement in differentials Q3 2015E 2017E 2018E 36% 24% 25% ($0.14) ($0.45) 19% 20% 49% $0.18 ($0.09) 1 Illustrative differential ranges are based on indicative quotes from trading counterparties and third-party research as of 8/5/2015. These projections involve risks and uncertainties that could cause actual results to differ materially from projected results. Analysis assumes a 2H 2016 in-service for Constitution Pipeline and a Q in-service for Atlantic Sunrise Pipeline. Differential ranges are based on the following gross production ranges Q3 2015E: 1.55 to 1.60 Bcf/d; 2017E: 2.1 to 2.4 Bcf/d; 2018E: 2.4 to 3.0 Bcf/d. 16

17 SUPPLY GROWTH IS WANING DECREASED ACTIVITY AND FLATTENING PRODUCTION IN THE MARCELLUS Bcf/d Marcellus Region Natural Gas Production (Bcf/d) Marcellus Horizontal Rig Count 2 NE PA SW / Central PA WV Q Q Q Q Q Q Current Source: 1 EIA Drilling Productivity Report as of July 13, 2015; 2 Baker Hughes North America Rotary Rig Count as of July 31,

18 WHILE DEMAND GROWTH IS ON THE HORIZON APPROXIMATELY 8 BCF PER DAY OF POTENTIAL NEW TAKEAWAY CAPACITY FROM CABOT S NORTHEAST PENNSYLVANIA SUPPLY AREA Bcf/d TCO East Side Expansion TGP Niagara NFG Northern Access 2015 NFG Tuscarora Lateral Leidy Southeast Expansion Constitution Pipeline Algonquin AIM DTI New Market NFG Central Tioga NFG Northern Access 2016 Millennium Valley Lateral Atlantic Sunrise Millennium Expansion PennEast Atlantic Bridge Virginia Southside Expansion Access Northeast TGP Northeast Energy Direct Source: Public filings; internal estimates 18

19 EAGLE FORD SHALE

20 CABOT S EAGLE FORD SHALE SUMMARY ~89,000 net acres Buckhorn: ~78,000 net acres COG Eagle Ford Shale Acreage Position Buckhorn ~78K net acres Presidio: ~11,000 net acres Operated rig count: 1 Presidio ~11K net acres 2015E net liquids production growth: 50% - 60% Frio La Salle Atascosa McMullen Plan to drill ~45 wells and place 40 to 45 wells on production during 2015 Anticipate ~20 wells in backlog at year-end Net Eagle Ford Production (Boe/d) 17,889 Flexibility to accelerate completion capital if prices warrant 10,308 Gross drilling inventory: >1,300 locations (assuming 300 spacing) Q Q

21 CABOT S EAGLE FORD SHALE ECONOMICS 2015 Program Well 2014 Program Well 100% 90% 80% BTAX %IRR 60% 40% 20% 18% Cabot s YTD 2015 realized oil price: $ % 17% 61% 27% 40% 0% 7% $45.00 $55.00 $65.00 $75.00 WTI Oil Price Held Flat ($/Bbl) Typical Eagle Ford Well Parameters EUR: 565 MBoe D&C Cost: $6.0MM Facilities / Pumping Unit Cost: $600K Lateral Length: 7,700 Number of Stages: 30 Average Working Interest: 100% Average Net Revenue Interest: 75% Note: Single well economics are all-in and include capital associated with road, pad, production facilities and pumping units. 21

22 CABOT S EAGLE FORD DRILLING AND COMPLETION COST SAVINGS Eagle Ford AFE Well Costs By Component YTD Eagle Ford Well Cost Savings By Category Facilities / Artificial Lift 10% Tangibles 8% Drilling Rig 6% Frac Services 42% % Reduction Due to Efficiency Gains % Reduction Due to Pricing 0% Drilling Services Drilling Rig Frac Services Completion Services Facilities / Artificial Lift Tangibles (10%) Drilling Services 14% (20%) (30%) Completion Services 20% (40%) 22

23 CABOT S EAGLE FORD DRILLING EFFICIENCIES Eagle Ford Drilling Days (Spud to TD) Q Q Q Q Q Q Record Eagle Ford Drilling Costs ($ / Lateral Foot) $419 $370 $400 $344 $296 $276 $201 Q Q Q Q Q Q Record 1 Normalized to a 7,700 lateral length 23

24 CABOT S EAGLE FORD LEASE OPERATING EXPENSE SAVINGS Eagle Ford Lease Operating Expense By Category YTD Eagle Ford Lease Operating Expense Savings Subsurface Maintenance 4% Surface Equipment 7% Labor 6% Misc. 8% Power & Fuel 25% 0% Treating Surface Equipment Misc. Power & Fuel Labor Subsurface Maintenance Disposal (20%) Compression 5% Treating 13% (40%) (60%) Disposal 32% (80%) 24

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. 25