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Cabot Oil & Gas Presentation: September 2015

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An updated PowerPoint from COG presented at the Barclays CEO Energy/Power Conference 2015 in New York City, September 2015. Cabot is one of (perhaps THE) most successful drillers in the Marcellus Shale.

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Cabot Oil & Gas Presentation: September 2015

  1. 1. BARCLAYS CEO ENERGY-POWER CONFERENCE SEPTEMBER 8, 2015
  2. 2. 2 CABOT OIL & GAS ASSET OVERVIEW 2014 Year-End Proved Reserves: 7.4 Tcfe 2014 Production: 531.8 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: 1 2015E Drilling Activity: ~45 net wells Marcellus Shale ~200,000 net acres >3,000 locations Current Rig Count: 3 2015E Drilling Activity: ~70 net wells
  3. 3. 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 costs1 of $1.27 per Mcfe • 2014 Marcellus-only cash costs1 of $0.80 per Mcf Strong balance sheet provides financial flexibility in a low commodity price environment • Conservative leverage position: Debt / LTM EBITDAX2 of 1.7x at Q2 2015 • 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 3 WELL POSITIONED TO NAVIGATE A CHALLENGING MARKET IN 2015 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
  4. 4. 4 2015 OPERATING PLAN AND CAPITAL PROGRAM DOUBLE-DIGIT PRODUCTION GROWTH DESPITE A 45% DECLINE IN CAPITAL SPENDING, HIGHLIGHTING COG’S CAPITAL EFFICIENCY 2015E Capital Program: $900 million Land 4% Drilling & Completion 80% Production Equipment / Other 12% Exploration 4% FY 2014 FY 2015 Completed Frac Stages 177 ~115 FY 2014 FY 2015 Net Wells Drilled $1,315 ~$720 FY 2014 FY 2015 Drilling and Completion Capital ($mm) (~35%) (~35%) (~45%) 2015E D&C Capital: $720 million Marcellus 60% Eagle Ford 40%
  5. 5. 5 PROVEN TRACK RECORD OF PRODUCTION AND RESERVE GROWTH… 130.6 187.5 267.7 413.6 531.8 0 100 200 300 400 500 600 700 2010 2011 2012 2013 2014 2015E Bcfe Liquids Gas 43.5% 42.8% 54.5% 28.6% 2015 Guidance: 10% - 18% Annual Production (Bcfe) 2.7 3.0 3.8 5.5 7.4 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 2010 2011 2012 2013 2014 2015E Tcfe Liquids Gas 12.3% 26.7% 41.9% 35.7% Year-End Proved Reserves (Tcfe)
  6. 6. 6 …WHILE MAINTAINING A CONSERVATIVE BALANCE SHEET 1 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 1.5x 1.4x 1.3x 0.9x 1.2x 1.7x 0.0x 0.5x 1.0x 1.5x 2.0x 2010 2011 2012 2013 2014 LTM Q2 2015 Net Debt to EBITDAX1
  7. 7. 7 INDUSTRY-LEADING COST STRUCTURE 1 Includes all demand charges and gathering fees 2 Excludes stock-based compensation $1.76 $1.67 $1.28 $1.27 $1.26 $0.00 $0.50 $1.00 $1.50 $2.00 2011 2012 2013 2014 1H 2015 CashUnitCosts($/Mcfe) Operating Transportation¹ Taxes O/T Income Cash G&A² Financing 3-Year F&D Costs: Total Company ($/Mcfe) 3-Year F&D Costs: Marcellus Only ($/Mcfe) $1.30 $0.65 $1.02 $0.56 $0.76 $0.48 $0.68 $0.43
  8. 8. 8 CABOT’S LOW-COST STRUCTURE IS DESIGNED TO WEATHER ALL COMMODITY CYCLES Source: 2014 company filings 1 Excludes gathering, transport, processing and marketing costs Peers include: Antero Resources, EQT, Range Resources and Southwestern Energy $0.00 $0.25 $0.50 $0.75 $1.00 $1.25 COG Peer A Peer B Peer C Peer D CashUnitCosts($/Mcfe) Operating Costs G&A Interest 2014 Cash Costs Per Unit vs. Appalachia Peers ($/Mcfe)1 0 100 200 300 400 500 600 700 800 900 Peer B COG Peer D Peer A Peer C ProductionPerEmployee(Mmcfe) 2014 Production Per Employee vs. Appalachia Peers (Mmcfe)
  9. 9. MARCELLUS SHALE
  10. 10. 10 CABOT’S MARCELLUS SHALE SUMMARY  ~200,000 net acres  Operated rig count: 3  2015E drilling activity: ~70 net wells  2015E average gross daily production: 1.7 – 1.8 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 in- service 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 500’ - 800’ downspacing between laterals, which would increase inventory / resource potential / NAV, if successful 1.54 1.7 – 1.8 FY 2014 FY 2015 Average Gross Daily Marcellus Production (Bcf/d) 6.0 3.5 FY 2014 FY 2015 Average Marcellus Rig Count $850 ~$430 FY 2014 FY 2015 Marcellus Drilling and Completion Capital ($mm)
  11. 11. 11 CABOT OIL & GAS CONTINUES TO DRILL THE MOST PROLIFIC WELLS IN THE MARCELLUS SHALE 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 2014 1 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 Cabot 70 Peer A 7 Peer B 7 Peer C 4 Peer D 3 Peer E 3 Peer F 3 Peer G 1 Peer H 1 Peer I 1 Top 100 Marcellus Wells By Operator1 1% 1% 1% 1% 2% 5% 5% 10% 20% 26% Peer I Peer E Peer H Peer A Peer D Peer B Peer G Peer F Peer C Cabot Percentage of Operator’s Total Wells in Top 100
  12. 12. 12 CABOT’S EUR PER FOOT AND F&D COSTS REMAIN BEST-IN-CLASS IN THE MARCELLUS AND UTICA Source: Company presentations as of 08/03/15; peers include Antero Resources, EQT Corporation, Gulfport Energy, Noble Energy, Range Resources and Rice Energy $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 ImpliedF&DCost($/Mcfe) EURper1,000ft.oflateral(Bcfe)
  13. 13. 13 CABOT’S MARCELLUS SHALE ECONOMICS 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’ 17% 51% 96% 152% 8% 37% 65% 102% 0% 25% 50% 75% 100% 125% 150% 175% $1.50 $2.00 $2.50 $3.00 BTAX%IRR Realized Natural Gas Price Held Flat ($/Mmbtu) 2015 Program Well 2014 Program Well Cabot’s YTD 2015 realized natural gas price: $2.32  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 strip1 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 ($1.00) for the life of the well.
  14. 14. 14 CABOT’S MARCELLUS DRILLING AND COMPLETION COST SAVINGS Marcellus AFE Well Costs By Component YTD Marcellus Well Cost Savings By Category (40%) (30%) (20%) (10%) 0% FracServices DrillingServices CompletionServices Facilities DrillingRig Tangibles Completion Services 31% Drilling Services 29% Frac Services 19% Drilling Rig 7% Facilities 7% Tangibles 7%
  15. 15. 15 CABOT’S MARCELLUS DRILLING EFFICIENCIES Marcellus Drilling Days (Spud to TD)1 16.9 14.3 13.6 12.8 12.4 10.5 6.9 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Record 1 Normalized to a 5,000’ lateral length
  16. 16. 16 CABOT’S PRICE REALIZATION OUTLOOK IMPROVES SIGNIFICANTLY WITH THE ADDITION OF NEW TAKEAWAY CAPACITY TO FAVORABLY PRICED MARKETS 15% 25% 49% 3% 24% 20% 43% 36% 19% 11% 9% 8% 8% 6% 4% 20% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Q3 2015E 2017E 2018E %ofSalesbyIndex Gulf Coast / Mid-Atlantic New England / NY / Canada NE PA DTI TCO Fixed Price Illustrative Differential to NYMEX ($/Mcf)1 ($0.95) – ($1.05) ($0.14) – ($0.45) $0.18 – ($0.09) Access to more favorably priced markets in 2017 / 2018 results in a significant improvement in differentials 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 Q3 2017 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.
  17. 17. 17 SUPPLY GROWTH IS WANING… DECREASED ACTIVITY AND FLATTENING PRODUCTION IN THE MARCELLUS 0 2 4 6 8 10 12 14 16 18 Bcf/d Marcellus Region Natural Gas Production (Bcf/d)1 Source: 1 EIA Drilling Productivity Report as of July 13, 2015; 2 Baker Hughes North America Rotary Rig Count as of July 31, 2015 21 21 20 20 17 11 10 25 28 28 26 29 33 26 27 26 26 29 21 18 15 73 75 74 75 67 62 51 0 20 40 60 80 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Current Marcellus Horizontal Rig Count2 NE PA SW / Central PA WV
  18. 18. 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 Source: Public filings; internal estimates 0 1 2 3 4 5 6 7 8 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
  19. 19. EAGLE FORD SHALE
  20. 20. 20 CABOT’S EAGLE FORD SHALE SUMMARY 10,308 17,889 Q2 2014 Q2 2015 Net Eagle Ford Production (Boe/d) Frio La Salle Atascosa McMullen COG Eagle Ford Shale Acreage Position Buckhorn ~78K net acres  ~89,000 net acres – Buckhorn: ~78,000 net acres – Presidio: ~11,000 net acres  Operated rig count: 1  2015E net liquids production growth: 50% - 60%  Plan to drill ~45 wells and place 40 to 45 wells on production during 2015 – Anticipate ~20 wells in backlog at year-end – Flexibility to accelerate completion capital if prices warrant  Gross drilling inventory: >1,300 locations (assuming 300’ spacing) Presidio ~11K net acres
  21. 21. 21 CABOT’S EAGLE FORD SHALE ECONOMICS 18% 38% 61% 90% 7% 17% 27% 40% 0% 20% 40% 60% 80% 100% $45.00 $55.00 $65.00 $75.00 BTAX%IRR WTI Oil Price Held Flat ($/Bbl) 2015 Program Well 2014 Program Well 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% Cabot’s YTD 2015 realized oil price: $50.00 Note: Single well economics are all-in and include capital associated with road, pad, production facilities and pumping units.
  22. 22. 22 CABOT’S EAGLE FORD DRILLING AND COMPLETION COST SAVINGS Eagle Ford AFE Well Costs By Component YTD Eagle Ford Well Cost Savings By Category (40%) (30%) (20%) (10%) 0% DrillingServices DrillingRig FracServices CompletionServices Facilities/ArtificialLift Tangibles % Reduction Due to Efficiency Gains % Reduction Due to Pricing Frac Services 42% Completion Services 20% Drilling Services 14% Facilities / Artificial Lift 10% Tangibles 8% Drilling Rig 6%
  23. 23. 23 CABOT’S EAGLE FORD DRILLING EFFICIENCIES 1 Normalized to a 7,700’ lateral length Eagle Ford Drilling Days (Spud to TD)1 15.0 12.5 11.4 8.8 8.7 8.8 6.2 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Record Eagle Ford Drilling Costs ($ / Lateral Foot) $419 $370 $400 $344 $296 $276 $201 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Record
  24. 24. 24 CABOT’S EAGLE FORD LEASE OPERATING EXPENSE SAVINGS Power & Fuel 25% Treating 13% Disposal 32% Compression 5% Surface Equipment 7% Subsurface Maintenance 4% Labor 6% Misc. 8% Eagle Ford Lease Operating Expense By Category YTD Eagle Ford Lease Operating Expense Savings (80%) (60%) (40%) (20%) 0% Treating SurfaceEquipment Misc. Power&Fuel Labor SubsurfaceMaintenance Disposal
  25. 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

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