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Scotia Howard Weil Energy Conference
March 21, 2016
2
CABOT OIL & GAS OVERVIEW
2015 Production: 602.5 Bcfe (13% growth)
2015 Year-End Proved Reserves: 8.2 Tcfe (11% growth)
2...
3
KEY INVESTMENT HIGHLIGHTS
1 Excludes DD&A, exploration expense, and stock-based compensation
2 EBITDAX is a non-GAAP mea...
4
133
~30
FY 2015 FY 2016E
Net Wells Drilled
2016 CAPITAL BUDGET AND OPERATING PLAN
CONTINUED FOCUS ON CAPITAL EFFICIENCY
...
5
PROVEN TRACK RECORD OF PRODUCTION AND RESERVE GROWTH…
413.6
531.8
602.5
0
100
200
300
400
500
600
700
2013 2014 2015 201...
6
…WHILE MAINTAINING A CONSERVATIVE BALANCE SHEET
1 EBITDAX is a non-GAAP measure defined as net income plus interest expe...
7
INDUSTRY-LEADING COST STRUCTURE
1 Includes all demand charges and gathering fees
2 Excludes stock-based compensation
3 M...
MARCELLUS SHALE
9
CABOT’S MARCELLUS SHALE SUMMARY
 ~200,000 net acres
 Operated rig count: 1
 2015 activity: 83 net wells drilled / 58 ...
10
SUCCESSFUL RESULTS FROM CABOT’S DOWNSPACING TESTS HAVE RESULTED
IN A 15% INCREASE IN MARCELLUS LOCATIONS
Comparison of ...
11
CABOT OIL & GAS CONTINUES TO DRILL THE MOST PROLIFIC WELLS IN
THE MARCELLUS SHALE
Includes content supplied by IHS Glob...
12
CABOT HAS 18 OF THE TOP 20 WELLS DRILLED IN PENNSYLVANIA SINCE 2012
Cumulative Natural Gas Production (Bcf)
16.3
13.2 1...
13
CABOT’S MARCELLUS DRILLING AND COMPLETION COST SAVINGS
Marcellus AFE Well Costs By Component Marcellus Well Cost Saving...
14
CABOT’S MARCELLUS DRILLING EFFICIENCIES
Marcellus Drilling Days (Spud to TD)1
16.9
14.3
13.6
12.8 12.4
10.5
9.4 9.4
6.0...
15
ACTIVITY LEVELS IN NORTHEAST PENNSYLVANIA ARE DECLINING RAPIDLY…
Source: 1 Baker Hughes North America Rotary Rig Count ...
0
1
2
3
4
5
6
7
8
Dec-16 Mar-17 Jun-17 Sep-17 Dec-17 Mar-18 Jun-18 Sep-18 Dec-18
Bcf/d
Algonquin AIM DTI New Market NFG Ce...
17
CABOT’S CASH MARGINS IN THE MARCELLUS ARE EXPECTED TO IMPROVE SIGNIFICANTLY
WITH THE ADDITION OF NEW TAKEAWAY CAPACITY ...
EAGLE FORD SHALE
19
CABOT’S EAGLE FORD SHALE SUMMARY
 ~85,500 net acres
– Buckhorn: ~75,000 net acres
– Presidio: ~10,500 net acres
 No r...
20
CABOT’S EAGLE FORD DRILLING AND COMPLETION COST SAVINGS
Eagle Ford AFE Well Costs By Component Eagle Ford Well Cost Sav...
21
CABOT’S EAGLE FORD DRILLING EFFICIENCIES
1 Normalized to a 7,700’ lateral length
Eagle Ford Drilling Days (Spud to TD)1...
Thank you
The statements regarding future financial performance and results
and the other statements which are not histori...
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Cabot Oil & Gas Presentation - March 21, 2016

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A presentation delivered by Cabot Oil & Gas at the Scotia Howard Weil Energy Conference in New Orleans in March 2016. During the presentation we learn Cabot plans to complete 40 wells in the Marcellus in 2016 and grow production slightly--up to 7% in 2016 over 2015.

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Cabot Oil & Gas Presentation - March 21, 2016

  1. 1. Scotia Howard Weil Energy Conference March 21, 2016
  2. 2. 2 CABOT OIL & GAS OVERVIEW 2015 Production: 602.5 Bcfe (13% growth) 2015 Year-End Proved Reserves: 8.2 Tcfe (11% growth) 2016E Drilling Activity: ~30 net wells 2016E Production Growth: 2% - 7% Eagle Ford Shale ~85,500 net acres ~1,300 locations No Rigs Currently Running 2015 Drilling Activity: 49 net wells 2016E Drilling Activity: ~5 net wells Marcellus Shale ~200,000 net acres ~3,450 locations Current Rig Count: 1 2015 Drilling Activity: 83 net wells 2016E Drilling Activity: ~25 net wells
  3. 3. 3 KEY INVESTMENT HIGHLIGHTS 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 Extensive Inventory of Low-Risk, High-Quality Drilling Opportunities Disciplined Capital Spending Driving Production and Reserve Growth Low Cost Structure Focused on Maintaining a Strong Financial Position – Peer-leading EUR per lateral foot in the Marcellus Shale – Recently increased Marcellus EUR per 1,000 feet guidance from 3.6 Bcf to 3.8 Bcf – Recent downspacing tests resulted in a 15% increase in Marcellus location count to ~3,450 locations – 2016 capital spending guidance of $325 million, a 58% reduction year-over-year – 2016 production growth guidance of 2% - 7% despite the significant reduction in spending – 2015 reserve growth of 11% despite reduced activity levels and lower price realizations – 2015 total company all-sources finding costs of $0.57 per Mcfe – 2015 Marcellus-only all-sources finding costs of $0.31 per Mcf – 2015 total company cash costs1 of $1.27 per Mcfe – 2015 Marcellus-only cash costs1 of $0.82 per Mcf (direct LOE of $0.04 per Mcf) – Conservative leverage position: Net debt / LTM EBITDAX2 of 1.3x as of 12/31/2015 (pro forma for recent equity offering) – Financial flexibility: Undrawn $1.8 billion credit facility and >$580 million of cash as of 12/31/2015 (pro forma for recent equity offering)
  4. 4. 4 133 ~30 FY 2015 FY 2016E Net Wells Drilled 2016 CAPITAL BUDGET AND OPERATING PLAN CONTINUED FOCUS ON CAPITAL EFFICIENCY 1 Includes facilities and pumping units 2016E Capital Program: $325 mm (excludes $80 - $150 mm of equity method investments) Land 5% Drilling, Completion and Facilities 92% Other 3% 2016E D&C Capital1: $300 mm Eagle Ford 30% Marcellus 70% 102 ~55 FY 2015 FY 2016E Net Wells Completed ~5,900’ ~7,400’~7,000’ ~9,500’ Marcellus Eagle Ford Average Lateral Lengths (Ft.) FY 2015 FY 2016E
  5. 5. 5 PROVEN TRACK RECORD OF PRODUCTION AND RESERVE GROWTH… 413.6 531.8 602.5 0 100 200 300 400 500 600 700 2013 2014 2015 2016E Bcfe Liquids Gas 28.6% 2016 Guidance: 2% - 7% 13.3% Annual Production (Bcfe) 5.5 7.4 8.2 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 2013 2014 2015 Tcfe Liquids Gas 35.7% Year-End Proved Reserves (Tcfe) 10.7%
  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 1.3x 0.9x 1.2x 1.3x YE 2012 YE 2013 YE 2014 YE 2015 (Pro forma for recent equity offering) Net Debt to LTM EBITDAX1
  7. 7. 7 INDUSTRY-LEADING COST STRUCTURE 1 Includes all demand charges and gathering fees 2 Excludes stock-based compensation 3 Mid-point of 2016 guidance $1.76 $1.67 $1.28 $1.27 $1.27 $1.25 $0.00 $0.50 $1.00 $1.50 $2.00 2011 2012 2013 2014 2015 2016E³ CashUnitCosts($/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 $0.62 $0.39
  8. 8. MARCELLUS SHALE
  9. 9. 9 CABOT’S MARCELLUS SHALE SUMMARY  ~200,000 net acres  Operated rig count: 1  2015 activity: 83 net wells drilled / 58 net wells completed  2016E activity: ~25 net wells drilled / ~40 net wells completed  Cabot’s reduction in drilling and completion activity in 2016 is predicated on lower anticipated natural gas price realizations throughout Appalachia as we await the in-service of new takeaway capacity  Cabot’s year-end backlog of uncompleted wells allows for reduced capital spending in 2016, while providing flexibility into 2017  Marcellus well costs have declined over 30% year-over-year to $6.7 million for a 7,000’ lateral, driven by continued efficiency gains and lower service costs  Recently increased EUR per 1,000’ guidance from 3.6 Bcf to 3.8 Bcf, further solidifying Cabot’s productivity per well as best-in- class across the Marcellus  Success of recent downspacing tests between 700 and 800 feet (down from 1,000 feet) has resulted in a 15% increase in location count to ~3,450 net locations ~5,300’ ~5,900’ ~7,000’ FY 2014 FY 2015 FY 2016E Marcellus Planned Lateral Lengths (Ft.) 63 48 Year-End 2015 Year-End 2016E Year-End Drilled Uncompleted Net Wells
  10. 10. 10 SUCCESSFUL RESULTS FROM CABOT’S DOWNSPACING TESTS HAVE RESULTED IN A 15% INCREASE IN MARCELLUS LOCATIONS Comparison of Cabot’s 700- to 800-foot spaced wells vs. 1,000-foot spaced type curve 0 200 400 600 800 1,000 0 200 400 600 800 1,000 1,200 DailyProductionperStage(Mcf/d) Days Cabot’s 1,000-foot spaced Lower Marcellus type curve Average of Cabot’s 700 to 800-foot downspaced wells
  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., 2016, All Rights Reserved. Includes all horizontal / directional Marcellus wells in Pennsylvania and West Virginia with a production start date from January 2012 to December 2015 1 As measured by max 30-day rate Note: Peers include Antero Resources, Chesapeake Energy, Chief Oil & Gas, EQT, PGE, Range Resources, Rice Energy, Vantage Energy and Warren Resources Cabot 68 Peer A 7 Peer B 6 Peer C 6 Peer D 4 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% 1% 3% 4% 4% 6% 21% Peer G Peer B Peer C Peer F Peer H Peer A Peer I Peer D Peer E Cabot Percentage of Operator’s Total Wells in Top 100
  12. 12. 12 CABOT HAS 18 OF THE TOP 20 WELLS DRILLED IN PENNSYLVANIA SINCE 2012 Cumulative Natural Gas Production (Bcf) 16.3 13.2 13.0 12.9 11.8 11.7 11.4 11.4 10.7 10.1 9.9 9.7 9.7 9.6 9.6 9.6 9.6 9.6 9.4 9.3 Source: PA DEP Oil & Gas Reporting Website; production data through December 2015. Includes all wells drilled on or after 1/1/2012
  13. 13. 13 CABOT’S MARCELLUS DRILLING AND COMPLETION COST SAVINGS Marcellus AFE Well Costs By Component Marcellus Well Cost Savings By Category (60%) (50%) (40%) (30%) (20%) (10%) 0% Frac Services Drilling Services Completion Services DrillingRig Facilities Tangibles % Reduction Due to Efficiency Gains % Reduction Due to Pricing Completion Services 31% Drilling Services 28% Frac Services 18% Drilling Rig 8% Facilities 9% Tangibles 6%
  14. 14. 14 CABOT’S MARCELLUS DRILLING EFFICIENCIES Marcellus Drilling Days (Spud to TD)1 16.9 14.3 13.6 12.8 12.4 10.5 9.4 9.4 6.0 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Record 1 Normalized to a 5,000’ lateral length
  15. 15. 15 ACTIVITY LEVELS IN NORTHEAST PENNSYLVANIA ARE DECLINING RAPIDLY… Source: 1 Baker Hughes North America Rotary Rig Count as of March 11, 2016; 2 FracFocus Chemical Disclosure Registry (activity through February 2016 as of March 15, 2016) Note: Northeast Pennsylvania includes Bradford, Lycoming, Sullivan, Susquehanna, Tioga and Wyoming counties 17 11 10 9 4 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Current Northeast Pennsylvania Horizontal Rig Count1 107 68 67 31 11 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Northeast Pennsylvania Wells Completed2
  16. 16. 0 1 2 3 4 5 6 7 8 Dec-16 Mar-17 Jun-17 Sep-17 Dec-17 Mar-18 Jun-18 Sep-18 Dec-18 Bcf/d Algonquin AIM DTI New Market NFG Central Tioga NFG Northern Access 2016 UGI Sunberry Millennium Valley Lateral Atlantic Sunrise Constitution Pipeline DTI Leidy South PennEast Atlantic Bridge Virginia Southside Expansion TGP Orion Caithness Moxie Freedom Millennium Expansion Access Northeast TGP Northeast Energy Direct 16 Source: Public filings; internal estimates Note: October 2017 in-service date assumed for Constitution and Atlantic Sunrise based on the mid-point of the current disclosure of the second half of 2017 …WHILE DEMAND GROWTH IS ON THE HORIZON Cabot's Incremental Firm Transport / Firm Sales Additions Project Name Mmcf/d Constitution Pipeline 500 Atlantic Sunrise 850 PennEast 150 TGP Orion Project 135 Caithness Moxie Freedom Power Plant 165 Other Pending Projects TBD Total Incremental FT / FS Additions 1,800+
  17. 17. 17 CABOT’S CASH MARGINS IN THE MARCELLUS ARE EXPECTED TO IMPROVE SIGNIFICANTLY WITH THE ADDITION OF NEW TAKEAWAY CAPACITY TO FAVORABLY PRICED MARKETS 16% 22% 52% 3% 8% 21% 53% 51% 16% 8% 11% 7% 6% 7% 2% 14% 2% 2% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2016E 2017E 2018E %ofSalesbyIndex Gulf Coast/Mid-Atlantic NY/New England/Canada NE PA DTI TCO Fixed Price/Other NYMEX prices and illustrative differentials are based on indicative quotes from the CME Group and trading counterparties as of 3/16/2016. These projections involve risks and uncertainties that could cause actual results to differ materially from projected results. Analysis assumes an October 2017 in-service for Constitution and Atlantic Sunrise Pipelines based on the mid-point of the current disclosure of the second half of 2017. Illustrative Improvement in Pre-Hedge Cash Margins ($/Mcf) (Based on Current Market Indications) 2016E 2017E 2018E NYMEX $2.18 $2.73 $2.79 Basis Differential + Gathering & Transportation ~($1.40) ~($1.30) ~($1.00) Direct LOE ($0.05) ($0.05) ($0.05) Regional G&A ($0.03) ($0.03) ($0.03) Production Taxes ($0.02) ($0.02) ($0.02) Illustrative Cash Margin ($/Mcf) $0.68 $1.33 $1.69 ~150% increase in cash margins based on illustrative analysis
  18. 18. EAGLE FORD SHALE
  19. 19. 19 CABOT’S EAGLE FORD SHALE SUMMARY  ~85,500 net acres – Buckhorn: ~75,000 net acres – Presidio: ~10,500 net acres  No rigs currently operating  2015 activity: 49 net wells drilled / 44 net wells completed  2016E activity: ~5 net wells drilled / ~15 net wells completed  2016 activity levels are predicated on meeting all mandatory near-term drilling / operating commitments necessary to maintain current leasehold position  Anticipate 13 wells in backlog at year-end 2016 – Flexibility to accelerate completion capital if prices warrant in 2016  Gross Eagle Ford locations: ~1,300 locations ~7,300’ ~7,400’ ~9,500’ FY 2014 FY 2015 FY 2016E Eagle Ford Lateral Lengths (Ft.) 23 13 Year-End 2015 Year-End 2016E Year-End Drilled Uncompleted Net Wells
  20. 20. 20 CABOT’S EAGLE FORD DRILLING AND COMPLETION COST SAVINGS Eagle Ford AFE Well Costs By Component Eagle Ford Well Cost Savings By Category (70%) (60%) (50%) (40%) (30%) (20%) (10%) 0% FracServices DrillingServices DrillingRig CompletionServices Facilities/ArtificialLift Tangibles % Reduction Due to Efficiency Gains % Reduction Due to Pricing Frac Services 31% Completion Services 25% Drilling Services 16% Facilities / Artificial Lift 13% Tangibles 8% Drilling Rig 7%
  21. 21. 21 CABOT’S EAGLE FORD DRILLING EFFICIENCIES 1 Normalized to a 7,700’ lateral length Eagle Ford Drilling Days (Spud to TD)1 15.0 12.5 11.4 8.8 8.7 8.8 8.2 8.0 6.2 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Record Eagle Ford Drilling Costs ($ / Lateral Foot) $419 $370 $400 $344 $296 $280 $232 $205 $181 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Record
  22. 22. 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. 22

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