Cabot Oil & Gas Investor Presentation - March 18, 2013

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A presentation made at the Howard Weil Energy Conference in New Orleans, LA on March 18, 2013 by Cabot Oil & Gas. The presentation contains important information about their drilling cost …

A presentation made at the Howard Weil Energy Conference in New Orleans, LA on March 18, 2013 by Cabot Oil & Gas. The presentation contains important information about their drilling cost structure--showing they have some of the lowest shale drilling costs in the industry.

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  • 1. Investor Presentation  Howard Weil Energy Conference New Orleans, LA March 18, 2013
  • 2. KEY INVESTMENT HIGHLIGHTS – Over 3 000 identified drilling locations in the sweet spot of the Marcellus Shale 3,000 Extensive Inventory of with rates of return that rival or exceed all of the top U.S. liquids plays at current commodity prices Low-Risk, High-Return – Oil-focused initiatives in the Eagle Ford Shale, Marmaton oil play and Pearsall Drilling Opportunities g pp Shale – Production growth of approximately 43% for the second consecutive year Industry Leading – Midpoint of 2013 guidance implies a third consecutive year exceeding 40% p g p y g Production and Reserve production growth Growth – 2012 proved reserve growth of 27% for a three-year reserve CAGR of 23% – 2012 all sources finding costs of $0.87 per Mcfe Low Cost Structure – 2012 all sources Marcellus finding costs of $0.49 per Mcfe – 2012 per unit cash costs1 of $1.67 p Mcfe p $ per – $605 million of liquidity as of 12/31/2012 Strong Financial Position – Net debt to adjusted capitalization of 33% as of 12/31/2012 and Financial Flexibility – Net debt to proved reserves of $0.27 per Mcfe as of 12/31/2012 – Approximately 53% hedged at the midpoint of 2013 production guidance1Excludes DD&A, exploration expense, stock-based compensation and pension termination expenses stock based
  • 3. ASSET OVERVIEW2012 Production: 267.7 Bcfe2012 Year-End Proved Reserves: 3.8 Tcfe Marcellus Shale ~200,000 net acres 2012 Drilling Activity: 69.7 net wells Current Rig Count: 5 Marmaton – Penn Lime ~70,000 net acres 2012 Drilling Activity: 18.9 net wells Eagle Ford Shale / Pearsall Shale Current Rig Count: 2 ~62,000 net Eagle Ford acres ~71,000 net Pearsall acres 2012 Drilling Activity: 25.8 net wells Current Rig Count: 4
  • 4. PROVEN TRACK RECORD OF PRODUCTION GROWTH… 400 350 300 267.7 2013Bcfe 250 Guidance: 35% - 50% 200 187.5 Liquids (N t) Li id (Net) 42.8% Gas (Net) 150 130.6 43.5% 100 50 0 2010 2011 2012 2013E
  • 5. …AND RESERVE GROWTH ? 4.5 4.0 3.8 3.5 3.0 30 3.0 2.7 26.7% 2.5 12.3% cfe 2.1 Liquids (Net)Tc 2.0 31.1% Gas (Net) 1.5 1.0 0.5 0.0 2009 2010 2011 2012 2013E
  • 6. POSITIVE RESERVE REVISIONS DESPITE LOW NATURAL GAS PRICES 370 927 (115) (67) (38) 3,842 (268) 3,033 cfeBc Year-End 2011 Additions Performance Pricing Deletions¹ Sales Production Year-End 2012 Proved Revisions Revisions Proved Reserves Reserves 96% Gas 96% Gas 59% PD 60% PD 16.2 R/P 14.4 R/P 1Deletions e et o s assoc ated with t e 5 yea PUD rule, p a y in East Texas associated t the 5-year U u e, primarily ast e as
  • 7. SUPERIOR RESERVE REPLACEMENT AND FINDING COSTS Reserve Replacement Ratio 700% 603% 600% 500% 443% 417% 390% 400% 300% 255% 200% 100% 0% 2008 2009 2010 2011 2012 All-Sources F&D Costs $4.00 $3.42 $3.00 $2.26$/Mcfe $2.00 $1.05 $1.21 $0.87 $1.00 $0.00 2008 2009 2010 2011 2012
  • 8. PEER LEADING PRODUCTION AND RESERVE GROWTH Production Per Debt-Adjusted Share CAGR (2010 – 2012)42% 30% 26% 24% 22% 17% 16% 15% Peer median: 11% 8% 8% 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 Reserves Per Debt-Adjusted Sh CAGR (2010 – 2012) R P D bt Adj t d Share18% 17% 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 Peer M Peer G Peer I Peer B Peer NSource: Cabot Oil & Gas, company filingsPeer group includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC
  • 9. DISCIPLINED CAPITAL SPENDING FOCUSED ON THE DRILL-BIT 2012 Capital Program: $979 million 2013 Capital Program: ($809 million net of JV and asset sales) $950 million - $1.025 billion Other Other 10% 5% Eagle Ford / Marmaton /Eagle Ford / PearsallMarmaton / 30% Pearsall 27% Marcellus Marcellus 63% 65% Production Equipment / Exploration Land Exploration Other 4% Production 6% 3% 4% Equipment / Land Other 9% 6% Drilling Drilling 83% 85%
  • 10. INDUSTRY LEADING COST STRUCTURE Operating Transportation Taxes O/T Income G&A¹ Financing $2.47 $2.50 $0.57 $2.12 $2.00 $0.52 $1.76 $1.67 $1 67 $0.42 $0.38 $0.26 $1.30 - $1.70 $1.50$ / Mcfe $0.40 $0.20 – $0.25 $0.43 $0 43 $0.25 $0.27 $0 27 $0.15 $0 15 – $0.20 $0.29 $0.15 $0.18 $0.10 – $1.00 $0.13 $0.20 $0.15 $0 39 $0.39 $0.54 $0.50 $0 50 – $0.60 $0.50 $0.91 $0.76 $0.57 $0.44 $0 44 $0.35 $0 35 – $0.45 $0.00 2009 2010 2011 2012 2013E 1 Excludes stock-based compensation and p p pension termination expenses p
  • 11. USE OF PROCEEDS FOR POTENTIAL FREE CASH FLOW IN 2014 Broker $75mm Estimate $17mm Range: Broker Implied $1,361mm Estimate Free Cash – Range: Flow $1,894mm $900mm – Median: $1,250mm $376mm Median: Median: $1,579mm $1 579mm $1,111mm 2014E Capital Expenditures¹ Current Regular Dividend Estimated Capital Implied 2014 Free Cash Flow 2014E Cash Flow¹ Commitment for Constitution Median 2014 Henry Hub / WTI Broker Estimates: p Pipeline $4.00 $4 00 per Mmbtu / $92.02 per Bbl M bt $92 02 Acceleration of Marcellus Drilling Program g g Dividend Policy (Special Di id d I (S i l Dividend / Increase Regular R l Pay D P Down Revolver Borrowings R l B i Dividend / Share Buybacks)1Based on broker consensus estimates as of March 4, 2013; cash flow estimates based on consensus cash flow per share estimates multiplied by current outstanding share count
  • 12. CABOT MARCELLUS SUMMARY Wells Producing: 197 H 39 V H, WOPL: 14 wells (235 Stages) Completing: 8 wells (179 Stages) WOC: 11 wells (204 Stages) Horizontal Rigs: 5CumulativeProduction 7+ BCF Reilly Pad 6-7 BCF Zick Pad 5-6 BCF 4-5 4 5 BCF 3-4 BCF 2-3 BCF ~ 3 Miles Bare Earth LiDAR with Aerial photo, Township Lines, Cabot Wells and Acreage
  • 13. EVOLUTION OF CABOT’S MARCELLUS PROGRAM 2013 and 2010 2011 2012 beyond• 13% HBP • 29% HBP • 43% HBP • Expected to be 60% HBP• Reduced stage spacing from • Drilling days reduced • Implemented 200 ft. stage by year-end 2013 300 ft. to 250 ft. • Reduced completion cost spacing • Transition into• Divested midstream assets per stage • Tested Upper Marcellus development mode• 44 producing Hz wells • 107 producing Hz wells • Tested downspacing (improved efficiencies / • De-risked eastern edge of reduced costs) our acreage position • Additional testing of Upper • 185 producing Hz wells Marcellus • Record gross production of • Additional downspacing 1.038 1 038 Bcf per day testing 1,100 Gross Marcellus Daily Production 1,000 900 800Mmcfpd 700 600 500 400 300 200 100 0 Dec-09 Dec-10 Dec-11 Dec-12
  • 14. CONTINUED PERFORMANCE IMPROVEMENTS IN THE MARCELLUS Horizontal Length Average IP and 30-Day Rate 30 Day 4.5 4.1 20.0 3.8 16.8 17.4 4.0 3.4 15.1 14.5 3.5 15.0 14.0Thousand Ft. 3.0 30 2.7 11.9 11 9 Mmcfpd d d 2.5 2.1 8.7 10.0 2.0 7.4 7.2 1.5 5.9 1.0 5.0 0.5 05 0.0 0.0 2008 2009 2010 2011 2012 2008 2009 2010 2011 2012 Average Number of Stages EUR 20.0 15.0 14.1 17.7 13.2 15.6 11.2 15.0 13.4 10.0 10 0Stages s 7.8 Bcf 10.0 8.5 5.0 4.6 5.0 5.0 0.0 0.0 2008 2009 2010 2011 2012 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
  • 15. MARCELLUS OPERATING EFFICIENCIES Drilling Days to TD 40 32 30 26Days 20 20 16 10 Record of 10 days 0 2009 2010 2011 2012 Completion Cost Per Stage $200 $180 $165 $150 ge $150$000s Per Stag $105 $100 $50 $0 2009 2010 2011 2012
  • 16. EVOLUTION OF MARCELLUS FRAC STAGE SPACING 125 ft. 50 ft ft. Composite Bridge Plug Avg. Lateral Length 3,500 ft. Avg. Number Stages 10 2 ft. perf cluster 6 SPF Avg. EUR 8.0 Bcf (Shots per foot) 350 ft. Spacing 75 ft. 50 ft. Avg. Lateral Length 3,500 ft. Avg. Number Stages 14 Avg. Avg EUR 11.2 11 2 Bcf 250 ft. Spacing 50 ft. 50 ft. Avg. Lateral Length 3,500 ft. Avg. Number Stages 17-18 Avg. A EUR 14.0 Bcf 14 0 B f 200 ft. Spacing p g
  • 17. CABOT HAD 15 OF THE TOP 20 PA MARCELLUS HORIZONTAL WELLS IN 2012 8.0 Cabot is the only publicly-traded company in the top 20! 7.0 6.0Cumulativ Production (Bcf) 5.0 50 n 4.0 ve 3.0 2.0 0 1.0 0.0 PEER PEER COG COG COG COG COG COG COG PEER PEER COG COG COG COG COG COG COG COG PEER #1 #1 #1 #1 #1
  • 18. MARCELLUS PROGRAM OVERVIEW AND ECONOMICS2012 Program Highlights 2013 Planned Activities 69.7 net wells drilled  Operate 5 rigs for the majority of the year 6 wells turned in line with an EUR over 20 Bcf  Expect to spud ~85 wells Fastest well to 5 Bcf of cumulative production:  2013 program will average slightly longer lateral lengths accomplished in 205 days than the 2012 program 4 wells turned in line reached 1 Bcf of cumulative  Entire 2013 program will utilize 200’ frac stage spacing production in 40 days or less  Continue to focus on operational efficiencies to further 5 wells turned in line in with a peak 24-hour production improve well economics rate over 30 Mmcf per day 4 wells achieved spud to TD in 10 daysTypical Well Parameters (Based on 2012 Program) Typical Well IRR Sensitivity EUR: 14 Bcf 150% 130% IP Rate: 17.3 Mmcfpd 125% Lateral Length: 4,100’ BTAX %IRR 100% Number of Stages Per Well: 18 100% Total D&C: $6.5 million 70% 75% Average Working Interest: 100% Average Revenue Interest: 85% 50% $3.00 $3.50 $4.00 Gas Price Differential: NYMEX less $0.05 per Mmbtu Henry Hub $ / Mmbtu
  • 19. HYPOTHETICAL 10-WELL PAD WITH 160+ POTENTIAL STAGES Current Hypothetical 2-well 2 well pad 10 well pad 10-well Location & road costs / well $200,000 $40,000 Rig mobilization / well $175,000 $35,000 Frac mobilization / well $110,000 $22,000 Idle move day rig costs / well $225,000 $85,000 Total $710,000 $182,000 1,000 ft Cost savings / well (relative to 2-well pad) $528,000 $ 500 ftN 1,000 ft.
  • 20. GROWING CAPACITY IN THE MARCELLUS – 2013 program: Right-of-ways and permits essentially complete Ri ht f d it ti ll l t Compression – 2014 program: Right-of-ways essentially complete and permitting on schedule – Exit rate gathering / dehydration capacity: and – 2012: 1.4 Bcf per day Dehydration – 2013E: 2.0 Bcf per day – 2014E: 2.9 Bcf per day – C Current Markets: tM k t – Tennessee Gas Pipeline – 300 Line: OH, PA, NY, NJ, CT Takeaway – Transco Pipeline – Liedy System: PA, NY, NJ, DC, MD and – Millennium Pipeline: NY, NJ, RI, CT Markets – Planned Markets – March 2015: – Tennessee Gas Pipeline – 200 Line: MA – Iroquois Pipeline Zones 1 & 2: NY, CT, Canada – Evaluate all opportunities for participation in expansion projectsFirm Transportation – Firm Transportation: and – C Current: 300 Mmcf per d t M f day Firm Sales – March 2015: 850 Mmcf per day – Firm Sales: 400 Mmcf per day
  • 21. EAGLE FORD AND PEARSALL Austin Chalk San A t i S Antonio target Eagle Ford Powderhorn Presidio Buda Del Rio Shale Buckhorn Georgetown Edwards Glen Rose Rodessa Upper Bexar Lower Bexar targetPearsall target Cow Creek (James) Net acres Pine Island Shale target Eagle Ford: ~62,000 Sligo Pearsall: ~71,000
  • 22. EAGLE FORD - BUCKHORN All W ll Wells Down-spacing R lt D i Results Average 30- EUR / LateralWells Drilled: 44 Day Rate Foot Stages (Boepd) (Boe)Current Drilling: 1 Spacing Well A 23 766 79 gWells Producing: 41 1,200 1 200’Completing / Waiting on Well B 25 492 60 3CompletionAvg 24 Hour IP: ~650 Boepd p Well C 20 790 80(Plant yield of 90 Bbl Ngl / mmcf) 400’Avg 30 day rate: ~440 Boepd Well D 20 493 56Avg completed lateral length: ~5 000 Ft 5,000 Ft. Well E 16 410 76 400’EUR Range all wells: 380-550 Mboe Well F 17 437 72 Down-spacing increases total mapped locations in our Buckhorn area to over 550 locations, doubling our potential recoverable reserves in the area
  • 23. PEARSALL SHALE 4 Pearsall wells with 30+ days of production Wells Drilled: 9 30-day average production rate: 631 Boepd Current Drilling: 3 ~56% oil Wells Producing / Flowing Back 5 Drilling days: 40-45 days spud to spud Average CWC (including science): ~$10.0MM Completing / WOC / WOPL 4 Estimated 2013 Gross Well Count 15 N S Rodessa ~20 20 Pearsall miles Sligo Consistent Pearsall section across COG acreage position g p Frio AtascosaLa Salle McMullen ~71,000 Net Acres
  • 24. PENN LIME – MARMATON Extended Reach Laterals – 4 extended reach lateral wells drilled to date with 3 wells currently producing – Average lateral length: ~9,300’ N Beaver – Average frac stages per well: 30 – Average EUR: 230 Mboe g Texas Beaver – Average IP rate: 792 Boepd . OK TX – ~90% oil Perryton – $4 3MM - $4 5MM estimated CWC $4.3MM $4.5MM ti t d Hansf ord S Lipscomb Ochiltree 0 4 8 mi COG Operated Wells – 24 producing wells – 4 wells drilling / waiting on completion ~70,000 Net Acres
  • 25. U.S. NATURAL GAS DEMAND DRIVERS CONTINUE TO LOOK FAVORABLE… Over O 45 gigawatts of coal-fired generating capacity is estimated to be retired between 2012 and 2016... i tt f l fi d ti it i ti t d t b ti d b t d 2016 25.0 22.4 20.0 watts 15.0 10.9 10 9Gigaw 10.0 8.2 5.0 1.4 2.7 0.0 2012 2013 2014 2015 2016 Source: EIA Annual Energy Outlook 2013 Early Release Reference case …with a potential for over 48 gigawatts of capacity from gas-fired generation newbuilds coming online during the same time period 15.0 Under Construction Proposed 10.5 10 5 10.9 10.2 10 2 10.0 8.5 8.8Gigawatts 5.0 0.0 00 2012 2013 2014 2015 2016 Source: BENTEK Energy, “Power Jump-Starts New Gas Market Cycle” Potential for incremental industrial demand of 3.3 Bcf/d by 2019 from new ethylene crackers, methanol and fertilizer plants, and gas-to-liquids projects 4.0 3.3 3.0 2.3Bcf /d 2.0 1.6 1.3 1.0 10 0.7 07 0.1 0.2 0.0 2013 2014 2015 2016 2017 2018 2019 Source: Companies data, Morgan Stanley Commodities Research estimates
  • 26. …RESULTING IN A POSITIVE OUTLOOK FOR LONG-TERM DEMAND New i li N pipeline systems in Mexico could potentially add 5 1 B f/d of incremental export capacity b 2016 t i M i ld t ti ll dd 5.1 Bcf/d f i t l t it by 6.0 5.1 3.7 4.0 2.7 27Bcf /d d 2.0 0.9 0.0 2013 2014 2015 2016 Source: Company reports and presentations Over 24 Bcf/d of proposed/potential U.S. LNG export facilities are currently approved or pending approval 4.0 3.4 3.0 30 2.8 28 2.6 26 2.4 2.1 1.8 1.7Bcf /d 2.0 1.5 1.4 1.3 1.3 1.1 1.0 0.8 0.0 00 Gulf Coast Golden Pass Lake Charles Cheniere - Freeport LNG Cameron LNG Gulf LNG Excelerate Oregon LNG Sabine Pass Pangea LNG Cove Point Others Corpus Christi Source: FERC Office of Energy Projects (as of March 11, 2013) Increased demand for natural gas in transportation could reach 3.6 Bcf/d by 2020 as natural gas vehicles penetrate heavy use end markets 4.0 3.6 3.0 2.7Bcf /d 1.9 2.0 1.3 0.8 1.0 10 0.5 0.2 0.3 0.0 2013 2014 2015 2016 2017 2018 2019 2020 Source: Credit Suisse Equity Research estimates
  • 27. INVESTMENT SUMMARY Simple Growth Story 3,000+ Remaining Locations in the Sweet Spot of the Marcellus Shale Transitioning from Acreage Capture to Efficient Pad Development by 2014 p y Cash Flow Positive Investment Program in 2013 ($3.50 per Mmbtu and $90 per barrel)
  • 28. Thank youThank youThe statements regarding future financial performance and results and the other The statements regarding future financial performance and results and the otherstatements 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 f d illi d k i i i f d i d d hfactors detailed in the Company’s Securities and Exchange Commission filings.