howard weil energy conference presentation - 3 18 2013...
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Investor Presentation
Howard Weil Energy ConferenceNew Orleans, LA
March 18, 2013March 18, 2013
Over 3 000 identified drilling locations in the sweet spot of the Marcellus Shale
KEY INVESTMENT HIGHLIGHTS
Extensive Inventory of Low-Risk, High-Return Drilling Opportunities
Extensive Inventory of Low-Risk, High-Return Drilling Opportunities
– Over 3,000 identified drilling locations in the sweet spot of the Marcellus Shale with rates of return that rival or exceed all of the top U.S. liquids plays at current commodity prices
– Oil-focused initiatives in the Eagle Ford Shale, Marmaton oil play and Pearsall Shale g ppg pp
Industry Leading Production and Reserve
Industry Leading Production and Reserve
Shale
– Production growth of approximately 43% for the second consecutive year
– Midpoint of 2013 guidance implies a third consecutive year exceeding 40% Production and Reserve Growth
Production and Reserve Growth
p g p y gproduction growth
– 2012 proved reserve growth of 27% for a three-year reserve CAGR of 23%
Low Cost StructureLow Cost Structure– 2012 all sources finding costs of $0.87 per Mcfe
– 2012 all sources Marcellus finding costs of $0.49 per Mcfe
– 2012 per unit cash costs1 of $1.67 per Mcfe
Strong Financial Position Strong Financial Position
p $ p
– $605 million of liquidity as of 12/31/2012
– Net debt to adjusted capitalization of 33% as of 12/31/2012Strong Financial Position and Financial Flexibility
Strong Financial Position and Financial Flexibility
Net debt to adjusted capitalization of 33% as of 12/31/2012
– 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 expensesExcludes DD&A, exploration expense, stock based compensation and pension termination expenses
ASSET OVERVIEW
2012 Production: 267.7 Bcfe2012 Year-End Proved Reserves: 3.8 Tcfe
Marcellus Shale~200,000 net acres2012 Drilling Activity: 69.7 net wells 2012 Drilling Activity: 69.7 net wells Current Rig Count: 5
Marmaton – Penn Lime~70,000 net acres2012 Drilling Activity: 18.9 net wells Current Rig Count: 2Eagle Ford Shale / Pearsall Shale Current Rig Count: 2
~62,000 net Eagle Ford acres~71,000 net Pearsall acres2012 Drilling Activity: 25.8 net wellsCurrent Rig Count: 4
PROVEN TRACK RECORD OF PRODUCTION GROWTH…
350
400
267.7300
350
187.5200
250
Bcfe
Li id (N t)
2013 Guidance:35% - 50%
130.6150
Liquids (Net)Gas (Net)
43.5%
42.8%
50
10043.5%
02010 2011 2012 2013E
…AND RESERVE GROWTH
?4.5
3 0
3.8
3.5
4.0
2.7
3.0
2.5
3.0
cfe
12.3%
26.7%
2.1
1.5
2.0
Tc Liquids (Net)Gas (Net)31.1%
0.5
1.0
0.02009 2010 2011 2012 2013E
POSITIVE RESERVE REVISIONS DESPITE LOW NATURAL GAS PRICES
3,842927370
(115) (67) (38)(268)
3,033
(268)
cfe
Bc
Year-End 2011 Proved
Reserves
Additions Performance Revisions
Pricing Revisions
Deletions¹ Sales Production Year-End 2012 Proved
Reserves
1Deletions associated with the 5-year PUD rule, primarily in East Texas
96% Gas59% PD16.2 R/P
96% Gas60% PD14.4 R/P
e et o s assoc ated t t e 5 yea U u e, p a y ast e as
SUPERIOR RESERVE REPLACEMENT AND FINDING COSTS
443%
603%
390% 417%500%600%700%
Reserve Replacement Ratio
255%
390%
100%200%300%400%
0%100%
2008 2009 2010 2011 2012
$3.42
$3.00
$4.00All-Sources F&D Costs
$2.26
$1.05 $1.21$0.87$1.00
$2.00
$/Mcf
e
$0.002008 2009 2010 2011 2012
Production Per Debt-Adjusted Share CAGR (2010 – 2012)
PEER LEADING PRODUCTION AND RESERVE GROWTH
42%
30%26% 24% 22%
17% 16% 15%
Production Per Debt-Adjusted Share CAGR (2010 – 2012)
17% 16% 15%8% 8%
2%
(0%) (2%) (3%)
Peer median: 11%
(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
R P D bt Adj t d Sh CAGR (2010 2012)18% 17% 15%
9%5% 4% 2%
Reserves Per Debt-Adjusted Share CAGR (2010 – 2012)
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 N
Source: Cabot Oil & Gas, company filingsPeer group includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XECPeer group includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC
2012 Capital Program: $979 million 2013 Capital Program:
DISCIPLINED CAPITAL SPENDING FOCUSED ON THE DRILL-BIT2012 Capital Program: $979 million
($809 million net of JV and asset sales)2013 Capital Program:
$950 million - $1.025 billionOther10%
Eagle Ford /
Other5%
Eagle Ford / Marmaton /
Pearsall30%
Eagle Ford / Marmaton /
Pearsall27%
Marcellus63%
Marcellus65%
Production Equipment /
Other 4%
Land
Exploration4%
Land6%Production
Equipment / Other
Exploration3%
Land9%
Other6%
Drilling83%
Drilling85%
Operating Transportation Taxes O/T Income G&A¹ Financing
INDUSTRY LEADING COST STRUCTURE
$2.47$2.50
$0.57
$0.52
$2.12
$1.76$1 67
$2.00
$0 43
$0.42
$0.40
$0 27 $0.25$0 15
$0.38 $0.26$0.20 –$0.25
$1.67
$1.30 - $1.70$1.50
/ Mcf
e
$0.13
$0.15$0.39 $0 50
$0.43
$0.29 $0.15 $0.18 $0.10 –$0.20
$0.27 $0.15 –$0.20
$1.00
$
$0.91$0.76
$0.57$0 44 $0 35 –
$0 39$0.54 $0.50 –
$0.60
$0.50
$0.44 $0.35 –$0.45
$0.002009 2010 2011 2012 2013E
1 Excludes stock-based compensation and pension termination expensesp p p
USE OF PROCEEDS FOR POTENTIAL FREE CASH FLOW IN 2014
$17mm $75mm
BrokerEstimate
BrokerEstimate Range:
$1,361mm–
Implied Free Cash Estimate
Range:$900mm –$1,250mm
Median:
–$1,894mm
Median:$1 579mm
Flow Median:$376mm
2014E Capital Expenditures¹ Current Regular Dividend Estimated Capital Commitment for Constitution
Pipeline
Implied 2014 Free Cash Flow 2014E Cash Flow¹
Median:$1,111mm
$1,579mm
Median 2014 Henry Hub / WTI Broker Estimates:
$4 00 M bt / $92 02 Bblp
Acceleration of Marcellus Drilling Program
$4.00 per Mmbtu / $92.02 per Bbl
g g
P D R l B i P D R l B i Dividend Policy
(S i l Di id d / I R l Dividend Policy
(S i l Di id d / I R l
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
Pay Down Revolver Borrowings Pay Down Revolver Borrowings (Special Dividend / Increase Regular Dividend / Share Buybacks)
(Special Dividend / Increase Regular Dividend / Share Buybacks)
Based 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
Wells Producing: 197 H 39 V
CABOT MARCELLUS SUMMARY
Wells Producing: 197 H, 39 VWOPL: 14 wells (235 Stages)
Completing: 8 wells (179 Stages)Completing: 8 wells (179 Stages)WOC: 11 wells (204 Stages)
Horizontal Rigs: 5Horizontal Rigs: 5
Cumulative Production
7+ BCFReilly Pad
5-6 BCF
4 5 BCF
6-7 BCFZick Pad
Bare Earth LiDAR with Aerial photo, Township Lines, Cabot Wells and Acreage ~ 3 Miles
4-5 BCF
3-4 BCF
2-3 BCF
EVOLUTION OF CABOT’S MARCELLUS PROGRAM
20102010 20112011 20122012 2013 and beyond
2013 and beyond
• 13% HBP• Reduced stage spacing from
300 ft. to 250 ft.• Divested midstream assets• 44 producing Hz wells
• 29% HBP• Drilling days reduced• Reduced completion cost
per stage• 107 producing Hz wells
• 43% HBP• Implemented 200 ft. stage
spacing• Tested Upper Marcellus• Tested downspacing
• Expected to be 60% HBP by year-end 2013
• Transition into development mode (improved efficiencies / • 44 producing Hz wells • 107 producing Hz wells • Tested downspacing
• De-risked eastern edge of our acreage position
• 185 producing Hz wells• Record gross production of
1 038 Bcf per day
(improved efficiencies / reduced costs)
• Additional testing of Upper Marcellus
• Additional downspacing testing
9001,0001,100 Gross Marcellus Daily Production
1.038 Bcf per day testing
300400500600700800
Mmcf
pd
0100200300
Dec-09 Dec-10 Dec-11 Dec-12
Horizontal Length Average IP and 30-Day Rate
CONTINUED PERFORMANCE IMPROVEMENTS IN THE MARCELLUS
2.73.4
3.8 4.1
3 03.54.04.5
d Ft
.
Horizontal Length
15.116.8 17.4
11 914.0 14.515.0
20.0
d
Average IP and 30 Day Rate
2.1
0 51.01.52.02.53.0
Thou
sand
7.4 8.75.9 7.2
11.9
5.0
10.0
Mmcf
pd
0.00.5
2008 2009 2010 2011 20120.0
2008 2009 2010 2011 2012
Average Number of Stages EUR
13.415.6
17.7
15.0
20.0
s
Average Number of Stages
11.213.2 14.1
10 0
15.0
EUR
4.6
8.5
5.0
10.0
Stag
es
5.0
7.8
5.0
10.0
Bcf
0.02008 2009 2010 2011 2012
0.02008 2009 2010 2011 2012
Number of wells: 2008 - 5, 2009 - 29, 2010 - 55, 2011 – 40, 2012 – 40Note: Data excludes wells drilled in the northern portion of our acreage positionNote: Data excludes wells drilled in the northern portion of our acreage position
Drilling Days to TD
MARCELLUS OPERATING EFFICIENCIES
322630
40
Drilling Days to TD
2016
10
20Days
Record of
02009 2010 2011 2012
Record of 10 days
$180$165
$150$150
$200
ge
Completion Cost Per Stage
$105
$50
$100
$150
00s P
er S
tag
$0
$50
2009 2010 2011 2012
$0
EVOLUTION OF MARCELLUS FRAC STAGE SPACING
50 ft125 ft.
Composite Bridge Plug
2 ft. perf cluster 6 SPF(Shots per foot)
50 ft.
Avg. Lateral Length 3,500 ft.Avg. Number Stages 10Avg. EUR 8.0 Bcf
(Shots per foot)
350 ft. Spacing
75 ft. 50 ft.
Avg. Lateral Length 3,500 ft.Avg. Number Stages 14Avg EUR 11 2 Bcf
250 ft. Spacing
Avg. EUR 11.2 Bcf
50 ft. 50 ft.
Avg. Lateral Length 3,500 ft.Avg. Number Stages 17-18A EUR 14 0 B f
200 ft. Spacing
Avg. EUR 14.0 Bcf
p g
CABOT HAD 15 OF THE TOP 20 PA MARCELLUS HORIZONTAL WELLS IN 2012
7.0
8.0 Cabot is the only publicly-traded company in the top 20!
5 0
6.0
n (B
cf)
4.0
5.0
ve P
rodu
ctio
n
2.0
3.0
Cum
ulat
iv
1.0
0
0.0PEER
#1PEER
#1COG COG COG COG COG COG COG PEER
#1PEER
#1COG COG COG COG COG COG COG COG PEER
#1
2013 Planned Activities2012 Program Highlights
MARCELLUS PROGRAM OVERVIEW AND ECONOMICS
2013 Planned Activities Operate 5 rigs for the majority of the year
Expect to spud ~85 wells
2013 program will average slightly longer lateral lengths
2012 Program Highlights 69.7 net wells drilled
6 wells turned in line with an EUR over 20 Bcf
Fastest well to 5 Bcf of cumulative production: 2013 program will average slightly longer lateral lengths than the 2012 program
Entire 2013 program will utilize 200’ frac stage spacing
Continue to focus on operational efficiencies to further
Fastest well to 5 Bcf of cumulative production: accomplished in 205 days
4 wells turned in line reached 1 Bcf of cumulative production in 40 days or less
improve well economics 5 wells turned in line in with a peak 24-hour production rate over 30 Mmcf per day
4 wells achieved spud to TD in 10 days
130%125%
150%
Typical Well Parameters (Based on 2012 Program) EUR: 14 Bcf
IP Rate: 17.3 Mmcfpd
Typical Well IRR Sensitivity
70%
100%
75%
100%
125%
BTAX
%IR
R Lateral Length: 4,100’
Number of Stages Per Well: 18
Total D&C: $6.5 million
50%
75%
$3.00 $3.50 $4.00 Henry Hub $ / Mmbtu
Average Working Interest: 100%
Average Revenue Interest: 85%
Gas Price Differential: NYMEX less $0.05 per Mmbtu
Current2 well pad
Hypothetical 10 well pad
HYPOTHETICAL 10-WELL PAD WITH 160+ POTENTIAL STAGES
2-well pad 10-well padLocation & road costs / well $200,000 $40,000Rig mobilization / well $175,000 $35,000Frac mobilization / well $110,000 $22,000
1,000 ft
Idle move day rig costs / well $225,000 $85,000Total $710,000 $182,000
Cost savings / well $(relative to 2-well pad) $528,000
500 ft
N 1,000 ft.
2013 Ri ht f d it ti ll l t
GROWING CAPACITY IN THE MARCELLUS
Compression and
Compression and
– 2013 program: Right-of-ways and permits essentially complete– 2014 program: Right-of-ways essentially complete and permitting on schedule– Exit rate gathering / dehydration capacity:
– 2012: 1.4 Bcf per dayDehydrationDehydration
2012: 1.4 Bcf per day– 2013E: 2.0 Bcf per day– 2014E: 2.9 Bcf per day
C t M k t
Takeaway and
Takeaway and
– Current Markets:– Tennessee Gas Pipeline – 300 Line: OH, PA, NY, NJ, CT– Transco Pipeline – Liedy System: PA, NY, NJ, DC, MD– Millennium Pipeline: NY, NJ, RI, CT
Markets Markets Millennium Pipeline: NY, NJ, RI, CT
– Planned Markets – March 2015:– Tennessee Gas Pipeline – 200 Line: MA– Iroquois Pipeline Zones 1 & 2: NY, CT, Canada
Firm Transportationand
Firm Transportationand
– Evaluate all opportunities for participation in expansion projects– Firm Transportation:
C t 300 M f dandFirm Sales
andFirm Sales
– Current: 300 Mmcf per day– March 2015: 850 Mmcf per day
– Firm Sales: 400 Mmcf per day
EAGLE FORD AND PEARSALL
S A t iAustin Chalk
PowderhornPresidio
targetSan Antonio
Eagle Ford
Buda
BuckhornGeorgetown Del Rio Shale
Edwards
Glen Rose
Upper Bexar Lower BexarCow Creek (James)Pearsall
targettarget Net acres
Rodessa
Pine Island ShaleCow Creek (James)
Sligo
Net acresEagle Ford: ~62,000Pearsall: ~71,000
target
EAGLE FORD - BUCKHORN
All W ll D i R ltAll Wells
Wells Drilled: 44Average 30-
Day RateEUR / Lateral
Foot
Down-spacing Results
Wells Drilled: 44
Current Drilling: 1
Wells Producing: 41 1 200’
Spacing
Day Rate FootStages (Boepd) (Boe)
Well A 23 766 79g
Completing / Waiting on Completion 3
Avg 24 Hour IP: (Plant yield of 90 Bbl Ngl / mmcf) ~650 Boepd
1,200Well B 25 492 60
Well C 20 790 80(Plant yield of 90 Bbl Ngl / mmcf) p
Avg 30 day rate: ~440 Boepd
Avg completed lateral length: ~5 000 Ft
400’Well D 20 493 56
Well E 16 410 76Avg completed lateral length: 5,000 Ft.
EUR Range all wells: 380-550 Mboe 400’
Well E 16 410 76
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
Down-spacing increases total mapped locations in our Buckhorn area to over 550 locations, doubling our
potential recoverable reserves in the area
PEARSALL SHALE
30-day average production rate: 631 Boepd~56% oil
4 Pearsall wells with 30+ days of production Wells Drilled: 9
Current Drilling: 3~56% oilDrilling days: 40-45 days spud to spud Average CWC (including science): ~$10.0MM
Wells Producing / Flowing Back 5
Completing / WOC / WOPL 4
Estimated 2013 Gross Well Count 15Estimated 2013 Gross Well Count 15
20
N S
PearsallRodessa
~20 miles
Consistent Pearsall section across COG acreage position
Sligo
Pearsall
La SalleAtascosaFrioMcMullen
g p
~71,000 Net Acres
PENN LIME – MARMATON
Extended Reach Laterals
– 4 extended reach lateral wells drilled to date with 3 wells currently producing
– Average lateral length: ~9,300’
– Average frac stages per well: 30
– Average EUR: 230 Mboe BeaverTexas
BeaverN
g
– Average IP rate: 792 Boepd
– ~90% oil
$4 3MM $4 5MM ti t d CWCPerryton
.
TXOK
– $4.3MM - $4.5MM estimated CWC
COG Operated Wells
OchiltreeLipscomb
Hansford
0 4 8 mi
S
– 24 producing wells
– 4 wells drilling / waiting on completion ~70,000 Net Acres
U.S. NATURAL GAS DEMAND DRIVERS CONTINUE TO LOOK FAVORABLE…
O 45 i tt f l fi d ti it i ti t d t b ti d b t 2012 d 2016Over 45 gigawatts of coal-fired generating capacity is estimated to be retired between 2012 and 2016...
10 9
22.4
15.020.025.0
watts
8.2
1.4 2.7
10.9
0.05.0
10.0
2012 2013 2014 2015 2016
Giga
w
2012 2013 2014 2015 2016
…with a potential for over 48 gigawatts of capacity from gas-fired generation newbuilds coming online during the same time period
10 5 10.9 10 2
15.0 Under Construction Proposed
Source: EIA Annual Energy Outlook 2013 Early Release Reference case
8.5 8.810.5 10.2
0 0
5.0
10.0
Giga
watts
0.02012 2013 2014 2015 2016
Potential for incremental industrial demand of 3.3 Bcf/d by 2019 from new ethylene crackers, methanol and fertilizer plants, and gas-to-liquids projectsSource: BENTEK Energy, “Power Jump-Starts New Gas Market Cycle”
0 71.3
1.62.3
3.3
1 0
2.0
3.0
4.0
Bcf /
d
0.1 0.20.7
0.0
1.0
2013 2014 2015 2016 2017 2018 2019Source: Companies data, Morgan Stanley Commodities Research estimates
N i li t i M i ld t ti ll dd 5 1 B f/d f i t l t it b 2016
…RESULTING IN A POSITIVE OUTLOOK FOR LONG-TERM DEMAND
New pipeline systems in Mexico could potentially add 5.1 Bcf/d of incremental export capacity by 2016
2 73.7
5.1
4.0
6.0
d
0.9
2.7
0.0
2.0
2013 2014 2015 2016
Bcf /
d
2013 2014 2015 2016
Over 24 Bcf/d of proposed/potential U.S. LNG export facilities are currently approved or pending approval
2 8 2 63.4
3 0
4.0
Source: Company reports and presentations
2.8 2.6 2.4 2.1 1.8 1.7 1.5 1.4 1.3 1.3 1.10.8
0 0
1.0
2.0
3.0
Bcf /
d
0.0Gulf Coast Golden Pass Lake Charles Cheniere -
Corpus ChristiFreeport LNG Cameron LNG Gulf LNG Excelerate Oregon LNG Sabine Pass Pangea LNG Cove Point Others
Increased demand for natural gas in transportation could reach 3.6 Bcf/d by 2020 as natural gas vehicles penetrate heavy use end marketsSource: FERC Office of Energy Projects (as of March 11, 2013)
0.81.3
1.92.7
3.6
1 0
2.0
3.0
4.0
Bcf /
d
0.2 0.3 0.50.8
0.0
1.0
2013 2014 2015 2016 2017 2018 2019 2020Source: Credit Suisse Equity Research estimates
INVESTMENT SUMMARY
Simple Growth StorySimple Growth Story
3,000+ Remaining Locations in the 3,000+ Remaining Locations in the 3,000+ Remaining Locations in the Sweet Spot of the Marcellus Shale3,000+ Remaining Locations in the Sweet Spot of the Marcellus Shale
Transitioning from Acreage Capture toEfficient Pad Development by 2014
Transitioning from Acreage Capture toEfficient Pad Development by 2014p yp y
Cash Flow Positive Investment Program in 2013Cash Flow Positive Investment Program in 2013Cash Flow Positive Investment Program in 2013($3.50 per Mmbtu and $90 per barrel)
Cash Flow Positive Investment Program in 2013($3.50 per Mmbtu and $90 per barrel)
Thank youThank youThe statements regarding future financial performance and results and the otherThe 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 f d illi d k i i i f d i d d hfuture drilling and marketing activity, future production and costs, and other factors detailed in the Company’s Securities and Exchange Commission filings.
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