Cabot Oil & Gas Investor Presentation/Update December 2013
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Transcript of Cabot Oil & Gas Investor Presentation/Update December 2013
Investor Presentation
December 2013 Company Update
HIGHLIGHTS FROM CABOT’S FIRST 10-WELL MARCELLUS PAD
170 Stages with a Combined Peak Production Rate of 201 Mmcf/d and a Combined Average 30-Day
Production Rate of 168 Mmcf/d
10-Well Pad Included Two Upper Marcellus Wells and a 500’ Downspacing Pilot Program in the Lower Marcellus
Realized Cost Savings of $6 Million for the 10-Well Pad Implying a Reduction in Well Costs from $6.4 Million for a
2-Well Pad to $5.8 Million for a 10-Well Pad
Cabot’s First Location Hydraulically Fractured by an Entirely Bi-Fuel Frac Fleet
OVERVIEW OF CABOT’S 10-WELL PAD OPERATIONS
Bi-fuel metering of natural gas to frac
pumps
Water storage tanks
Additional sand storage
Bi-fuel frac pumps
Simultaneous Zipper Ops / Pumpdown Wireline
Plug-Perf
Lower Marcellus Well
Upper Marcellus Well
Fault
Upper Marcellus Interval
Lower Marcellus Interval
1,000’
4 Lower Marcellus wells to the North
UPPER MARCELLUS DE-RISKING AND LOWER MARCELLUS 500’ DOWNSPACING PILOT
2 Upper / 4 Lower Marcellus wells to the South
1,000’ 1,000’
500’ 500’
1,000’
1,000’
DRILLING AND COMPLETION EFFICIENCIES ON THE 10-WELL PAD
$325
$258$228
2012 1H 2013 10-Well Pad
Drilling Cost Per Foot ($)
4.25.1
6.3
2012 1H 2013 10-Well Pad
Frac Stages Per Crew Day
PAD DRILLING EFFICIENCIES RESULTING IN LOWER WELL COSTS
$6.4
$5.8
($0.2)
($0.2)
($0.2)
Single Well Cost for 2-Well Pad
Location and Road Savings
Drilling Efficiencies Completion Efficiencies
Single Well Cost for 10-Well Pad
Marcellus Well Cost For Typical 14 Bcf (18-Stage) Well ($mm)
TRANSITIONING FROM ACREAGE CAPTURE TO PAD DRILLING
23%
60%
2013E 2014E
Percentage of Marcellus Wells Drilled on Pads with 5 or More Wells
COMPANY OVERVIEW
Extensive Inventory of Low-Risk, High-Return Drilling Opportunities
Industry-Leading Production and Reserve
Growth
Low Cost Structure
Strong Financial Position and Financial
Flexibility
– Over 3,000 identified drilling locations in the sweet spot of the Marcellus Shale implying 25+ years of inventory at current drilling levels
– Peer-leading rates of return and EUR per lateral foot in the Marcellus Shale
– Oil-focused initiative in the Eagle Ford Shale
– Initiated 2014 production growth guidance of 30% - 50%
– Reaffirmed 2013 production growth guidance of 44% - 54%
– 2012 proved reserve growth of 27% resulting in a three-year reserve CAGR of 23%
– Q3 2013 total company per unit cash costs1 of $1.25 per Mcfe
– 2014 Marcellus per unit cash cost1 guidance of ~$0.80 per Mcf
– 2012 total company all-sources finding costs of $0.87 per Mcfe
– 2012 Marcellus all-sources finding costs of $0.49 per Mcf
– Net debt to adjusted capitalization ratio of 33% as of 9/30/2013
– Approximately 30% hedged at the midpoint of 2014 production guidance
1Excludes DD&A, exploration expense, stock-based compensation and pension termination expenses
KEY INVESTMENT HIGHLIGHTS
Marcellus Shale~200,000 net acresCurrent Rig Count: 6 (as of August 21, 2013)2013E Drilling Activity: ~100 net wells2014E Rig Count: 7 (beginning January 2014)2014E Drilling Activity: 130 – 140 net wells
Eagle Ford Shale~62,000 net acresCurrent Rig Count: 22013E Drilling Activity: 30 – 35 net wells2014E Rig Count: 22014E Drilling Activity: 40 – 50 net wells
ASSET OVERVIEW
2012 Year-End Proved Reserves: 3.8 TcfeQ3 2013 Production: 1.164 Bcfe per day2013E Drilling Activity: 155 – 165 net wells2014E Drilling Activity: 170 – 190 net wells
42%
30%26% 24% 22%
17% 16% 15%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
Production Per Debt-Adjusted Share CAGR (2010 – 2012)
PEER-LEADING PRODUCTION AND RESERVE GROWTH
18% 17% 15%9%
5% 4% 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 N
Reserves Per Debt-Adjusted Share CAGR (2010 – 2012)
Peer median: 11%
Peer median: (2%)
Source: Cabot Oil & Gas, company filingsPeer group from 2013 proxy statement includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC
2013E Capital Program: $1.1 billion - $1.2 billion
2014E Capital Program: $1.375 billion - $1.475 billion
Marcellus65%
Production Equipment /
Other 5%
Drilling87%
Land5%
Exploration3%
Other5%
Eagle Ford 24%
Marcellus74%
Land6%
Drilling85%
Production Equipment /
Other6%
Exploration3%
Other2%
TRANSFORMATION TO A MARCELLUS AND EAGLE FORD FOCUSED STORY IN 2014
Eagle Ford / Marmaton /
Pearsall30%
130.6
187.5
267.7
0
50
100
150
200
250
300
350
400
450
500
550
600
2010 2011 2012 2013E 2014E
Bcfe
Liquids (Net)Gas (Net)
43.5%
42.8%
2013 Guidance:44% - 54%(increased from 35%-
50%)
2014 Guidance:30% - 50%
PROVEN TRACK RECORD OF PRODUCTION GROWTH…
?
2.1
2.7
3.0
3.8
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
2009 2010 2011 2012 2013E
Tcfe
Liquids (Net)Gas (Net)31.1%
12.3%
26.7%
…AND RESERVE GROWTH
$2.47
$2.12
$1.76$1.67
Guidance Midpoint:
$1.37GuidanceMidpoint:
$1.21
$0.80
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
2009 2010 2011 2012 2013E 2014E 2014E Marcellus Only
$ / M
cfe
Operating Transportation¹ Taxes O/T Income G&A² Financing
1 Includes all demand charges and gathering fees2 Excludes stock-based compensation and pension termination expenses
INDUSTRY-LEADING COST STRUCTURE
PEER-LEADING CASH FLOW PER SHARE GROWTH WHILE GENERATING SUBSTANTIAL FREE CASH FLOW
(10%)
0%
10%
20%
30%
40%
50%
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
2013E – 2015E Cash Flow Per Share CAGR
Source: First Call consensus median as of 11/11/2013; cumulative free cash flow defined as cash flow per share times shares outstanding less capital expenditures; consensus 2014 pricing of $3.85 per Mmbtu and $93.92 per BblPeer group from 2013 proxy statement includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC
($1,250)($1,000)
($750)($500)($250)
$0 $250 $500 $750
$1,000 $1,250
COG Peer D Peer C Peer J Peer L Peer A Peer K Peer H Peer N Peer I Peer E Peer B Peer F Peer M Peer G
2014E – 2015E Cumulative Free Cash Flow ($mm)
POTENTIAL USES FOR FREE CASH FLOW
Expand Core Acreage
Positions in the Marcellus
and Eagle Ford
Accelerate Development
of our Marcellus and
Eagle Ford Programs
Organically Build
Positions in New Venture
Opportunities
Return Cash to Shareholders
Via Share Buybacks and
Increased Regular
Dividends
MARCELLUS SHALE
CABOT CONTINUES TO PRODUCE THE MOST PROLIFIC WELLS IN THE MARCELLUS SHALE
0.0
1.0
2.0
3.0
4.0
5.0
6.0
Cum
ulat
ive P
rodu
ctio
n Fr
om Ja
nuar
y to
June
2013
(Bcf
e) Top 20 Pennsylvania Marcellus Wells (January to June 2013)
Source: PA DEP Oil & Gas Reporting WebsiteNote: Peers include Chief Oil & Gas and EQT Corporation
15 of the top 20 (January to June 2013) 10 of the top 20 (July to December 2012) 14 of the top 20 (January to June 2012) 15 of the top 20 (July to December 2011)
FRIENDSVILLE
MIDDLETOWN
RUSH
AUBURN
FOREST LAKE
JESSUP
DIMOCK
SPRINGVILLE
SILVER LAKESILVER LAKE
GREAT BEND
HALLSTEADSUSQUEHANNA
DEPOT
OAKLAND
HARMONY
LANESBORO
FRANKLIN
NEW MILFORD
JACKSONTHOMPSON
ARARAT
BRIDGEWATER
MONTROSE
BROOKLYN
HARFORD
GIBSONHERRICK
UNIONDALE
LATHROPLENOX CLIFFORD
HOP BOTTOM
FOREST CITY
DERISKING OF CABOT’S MARCELLUS POSITION
15 of Top 20 Marcellus Wells (Jan – Jun 2013)
Cabot Acreage
Peer Acreage
Conservation Areas
Recently Announced Q2 / Q3 2013 Well ResultsNumber of
WellsTotal Frac
StagesPeak 24-Hour Rate (Mmcf/d)
Pad A 4 109 109.5Pad B 3 68 98.0Pad C 3 50 59.1Pad D 3 45 55.8Pad E 2 27 34.8Pad F 1 23 32.8
Q2 / Q3 2013 Well Results
2.12.7
3.43.8 4.1
0.00.51.01.52.02.53.03.54.04.5
2008 2009 2010 2011 2012
Thou
sand
Ft.
Horizontal Length
7.4 8.7
15.116.8 17.4
5.9 7.2
11.914.0 14.5
0.0
5.0
10.0
15.0
20.0
2008 2009 2010 2011 2012
Mmcf
pd
Average IP and 30-Day Rate
4.6
8.5
13.415.6
17.7
0.0
5.0
10.0
15.0
20.0
2008 2009 2010 2011 2012
Stag
es
Average Number of Stages
5.0
7.8
11.213.2 14.1
0.0
5.0
10.0
15.0
2008 2009 2010 2011 2012
Bcf
EUR
Number of wells: 2008 - 5, 2009 - 29, 2010 - 55, 2011 – 40, 2012 – 40Note: Data excludes wells drilled in the northern portion of our acreage position
CONTINUED PERFORMANCE IMPROVEMENTS IN THE MARCELLUS
8.7
7.4
4.84.0
0
2
4
6
8
10
2011/2012 (25 Moves) Implementation of New Move Process (4 Moves)
Average For Last 19 Moves Target
Move
Day
s (Re
lease
to S
pud)
MARCELLUS RIG MOVE EFFICIENCIES
Implemented a new rig move process in 2013 including 24-hour operations for rig up and rig down
The new process has reduced average rig moves by ~4 days
4-day reduction in move time yields $250K in savings per move including rig time, trucking, rentals, and labor charges
CABOT IS DRILLING MARCELLUS WELLS FASTER DESPITE LONGER LATERAL LENGTHS
0
2,500
5,000
7,500
10,000
12,500
0 5 10 15 20 25
Meas
ured
Dep
th (F
eet)
Drilling Days (Spud-to-Rig Release)
201120122013 YTD
MARCELLUS COMPLETION EFFICIENCIES
EFFICIENCY RESULT:
100% increase in stages per day compared to 2010
Significant cost savings through the reduction in days on site
2010 – Daylight Operations, single well pads
2011 – 24 Hour operations, multi well pads
2012 – 24 Hour operations, multi well pads, modified zipper operations
2013 – 24 Hour operations, multi well pads, simultaneous zipper operations
FRAC EVOLUTION:
2.5 2.94.2
5.1
9.0
0
2
4
6
8
10
2010 2011 2012 2013 YTD
Days
Average Frac Stages Per Crew Day
Record of 9 frac stages per crew day
(achieved five times)
EVOLUTION OF CABOT’S FRAC STAGE SPACING
Packer Systems
Completion400’ spacing
Packer Systems
Completion300’ spacing
Plug/Perf250’ spacing
Plug/Perf200’ spacing
2.4
2.93.3
3.7
0.0
1.0
2.0
3.0
4.0
2008 2009 2010 - Q2 2012 Q3 - Q4 2012
EUR
Per 1
,000’
of L
ater
al (B
cf)
SHORTER STAGE LENGTHS AND REDUCED CLUSTER SPACING RESULTING IN HIGHER EURS PER 1,000 FEET OF LATERAL
COMPRESSED NATURAL GAS (CNG) AND LINE GAS USAGE IN CABOT’S MARCELLUS OPERATIONS
CNG Usage in Cabot’s Vehicles- Estimated displacement of ~110,000 gasoline gallon
equivalents (GGE) in 2014
CNG / Line Gas Usage in Cabot’s Drilling Operations- Estimated displacement of ~1.1 million diesel gallon
equivalents (DGE) in 2014- Plan to utilize CNG / Line Gas in 100% of Cabot’s future
drilling operations for estimated displacement of 2.5+ million DGE
Line Gas Usage in Cabot’s Completion Operations- Estimated displacement of ~1.5 million DGE in 2014- Plan to utilize Line Gas in 100% of Cabot’s future
completion operations for estimated displacement of 2.6+ million DGE
Diversifying on Multiple Pipelines to Multiple Geographic Locations
Firm Transportation Arrangements
Long-Term Sales Agreements (Firm Sales)
Investing in New Pipeline Projects
COG MARCELLUS MARKETING STRATEGY
Opportunistic Hedging Program
20 95255
650
1,580
2,380
3,6503,800
0
1,000
2,000
3,000
4,000
Dec-08 Dec-09 Dec-10 Dec-11 Dec-12 Dec-13 Dec-14 Dec-15
Gros
s Tak
eawa
y Cap
acity
(Mm
cf/d
)
Cabot’s Gross Marcellus Gathering Capacity (Mmcf/d)
CABOT’S MARCELLUS GATHERING CAPACITY
Note: Capacity volumes above are indicative deliverability estimates for facilities that are in place or planned for those periods; these are not production estimates. Facilities include compression, dehydration and measurement.
NYVT NH
PA
NJ
CT
MA
RI
Iroquois
Millennium
Springville
TGP 200 Line
Canada
Boston
Hartford
Long Island
LaserTGP 300 Line
Transco
Constitution
New York City
Charlotte
INTERSTATE PIPELINE MARKETS
Susquehanna County
Current MarketsTennessee Gas Pipeline – 300 (CT, NJ, OH, PA, WV)Transco Gas Pipeline (DC, MD, NC, NJ, NY, PA, VA)
Millennium Gas Pipeline (CT, NJ, NY, RI)
2015 Market AdditionsIroquois Pipeline (CT, Long Island)
Tennessee Gas Pipeline – 200 (CT, MA, NH)TransCanada Pipeline (via Iroquois)
SCHEDULED APPALACHIA PIPELINE EXPANSIONS
3.1
5.8
8.8
10.9
13.3
0
2
4
6
8
10
12
14
Q4 2013 2014 2015 2016 2017
Cum
ulat
ive P
ipeli
ne C
apac
ity A
dditi
ons
(Bcf
/d)
Source: Bentek
Over 13.3 Bcf/d of pipeline capacity expansions in Appalachia between now and 2017 with even more projects currently in the planning phases
Typical Well Parameters (Based on 2012 Program) EUR: 14.1 Bcf
IP Rate: 17.4 Mmcfpd
Lateral Length: 4,100’
CABOT’S MARCELLUS ECONOMICS
Number of Stages Per Well: 18
Average Working Interest: 100%
Average Revenue Interest: 85%
70%
100%
130%
170%
80%
115%
150%
195%
50%
75%
100%
125%
150%
175%
200%
$3.00 $3.50 $4.00 $4.50
BTAX
%IR
R
Henry Hub ($ / Mmbtu)
$6.5 million D&C $6.0 million D&C
Typical Well IRR Sensitivity
EAGLE FORD SHALE
La SalleFrio Atascosa
McMullen
~20 milesPad B
• 6-well pad• Drilling• Average lateral
length over 8,000’
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: 56
Operated wells currently drilling / suspended: 6
Operated wells completing: 5
Average completed well cost: ~$6.5mm
– Multi-well pad drilling expected to reduce well costs by $500,000 - $600,000 per well
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
Pad A• 4-well pad• Completing• Lateral lengths
ranging from 5,200’ to 8,000’
3,000+ Locations in the Sweet Spot of the Marcellus Shale Implying 25+ Years of Inventory at Current Drilling Levels
Currently Producing 1.3 Bcf/d of Gross Marcellus Production From Only 8% of Our Identified Locations
Peer-Leading Rates of Return and EUR Per Lateral Foot in the Marcellus Shale
Industry-Leading Cost Structure Continuing to Improve Due to Efficiency Gains
SIMPLE GROWTH STORY
Best-In-Class Production and Cash Flow Per Share Growth While Generating Free Cash Flow
Thank youThe 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.