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7/27/2019 Cabot Oil & Gas
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Investor PresentationEnerCom's
The Oil & Gas ConferenceDenver, CO
August 12, 2013
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Extensive Inventory ofLow-Risk, High-Return
Drilling Opportunities
Industry LeadingProduction and Reserve
Growth
Low Cost Structure
Strong Financial Positionand Financial Flexibili ty
Over 3,000 identified dri lling locations in the sweet spot o f the Marcellus Shale withrates of return that rival or exceed all of the top U.S. liquids plays at currentcommodity prices
25+ years of Marcellus inventory at current drilling levels Oil-focused initiative in the Eagle Ford Shale
Increased 2013 produ ction gu idance range from 35% - 50% to 44% - 54%
Midpoin t of 2013 guidance impl ies a three-year production CAGR of 45%
2012 proved reserve g rowth of 27% for a three-year reserve CAGR of 23%
Q2 2013 per unit cash cos ts1 of $1.36 per Mcfe
2012 all sources fin ding co sts o f $0.87 per Mcfe
2012 all sources Marcellus fi nding costs of $0.49 per Mcfe
$566 million of l iquid ity as o f 6/30/2013
Net debt t o adjus ted capitalization ratio of 32% as of 6/30/2013
Approximately 65% hedged at the midpoint o f 2013 production guidance
45 natural gas collar contracts fo r 2014 at a weighted average floor of $4.10 per Mcf
1Excludes DD&A, exploration expense, stock-based compensation and pension termination expenses
KEY INVESTMENT HIGHLIGHTS
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Marcellus Shale~200,000 net acresCurrent Rig Count: 6 (as of August 21, 2013)2013E Drilling Act ivity: ~100 net wells
Marmaton Penn Lime~70,000 net acres2013E Drilling Activi ty: ~10 net wells
Eagle Ford Shale / Pearsall Shale~62,000 net Eagle Ford acres~71,000 net Pearsall acresCurrent Rig Count: 22013E Drilli ng Activ ity: ~45 net wells
ASSET OVERVIEW
2012 Year-End Proved Reserves: 3.8 Tcfe
Q2 2013 Production: 1.046 Bcfe per day
2013E Drilling Activ ity: 155 165 net wells
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130.6
187.5
267.7
0
50
100
150
200
250
300
350
400
2010 2011 2012 2013E
Bcfe
Liquids (Net)
Gas (Net)
43.5%
42.8%
2013
Guidance:
44% - 54%(increased
from 35%-
50%)
PROVEN TRACK RECORD OF PRODUCTION GROWTH
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?
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
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255%
603%
390% 417%
0%
100%
200%
300%
400%
500%
600%
700%
2009 2010 2011 2012
Reserve Replacement Ratio
$2.26
$1.05 $1.21$0.87
$0.00
$1.00
$2.00
$3.00
2009 2010 2011 2012
$/M
cfe
Al l-Sources F&D Costs
SUPERIOR RESERVE REPLACEMENT AND FINDING COSTS
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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 includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC
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2012 Capital Program: $979 million($809 milli on net of JV and asset sales)
2013 Capital Program:$1.1 billion - $1.2 billion
Marcellus
63%
ProductionEquipment /
Other4%
Drilling83%
Land9%
Exploration4%
Other10%
Eagle Ford /Marmaton /
Pearsall30%
Marcellus
65%
Land5%
Drilling87%
ProductionEquipment /
Other5%
Exploration3%
Other5%
DISCIPLINED CAPITAL SPENDING FOCUSED ON THE DRILL-BIT
Eagle Ford /Marmaton /
Pearsall27%
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$0.91$0.76
$0.57$0.44 $0.30
$0.40
$0.13
$0.15$0.39
$0.54$0.50 $0.60
$0.43
$0.29 $0.15 $0.18 $0.10 $0.20
$0.42
$0.40
$0.27$0.25
$0.15 $0.20
$0.57
$0.52
$0.38 $0.26
$0.15 $0.20
$2.47
$2.12
$1.76$1.67
$1.20 - $1.60
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
2009 2010 2011 2012 2013E
$/Mcfe
Operating Transportation Taxes O/T Income G&A Financing
1Excludes stock-based compensation and pension termination expenses
INDUSTRY LEADING COST STRUCTURE
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$34mm$75mm
2014E Capital Expenditures Current Regular Dividend(Recently i ncreased by 100%
effective August 2013)
Estimated Capital Commitmentfor Constitution Pipeline
Implied 2014Free Cash Flow
2014E Cash Flow
1Based on broker consensus estimates as of August 7, 2013; cash flow estimates based on consensus cash flow per share estimates multiplied by current outstanding share count
Broker
EstimateRange:
$1,190mm
$1,548mm
Average:
$1,342mm
USE OF PROCEEDS FOR POTENTIAL FREE CASH FLOW IN 2014
Broker
Estimate
Range:
$1,477mm
$1,981mm
Average:
$1,729mm
Implied
Free Cash
Flow:$278mm
Acceleration of Marcellus Dri ll ing Program
Accelerat ion of Eagle Ford Dri ll ing ProgramDividend Policy(Increase Regular Dividend / Share
Buybacks / Special Dividend)
Average 2014 Henry Hu b /WTI Broker Estimates:
$4.01 per Mmbt u / $92.00 per Bbl
Pay Down Revolver Borrowings
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MARCELLUS SHALE
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12/25Bare Earth LiDAR with Aerial photo , Townsh ip Lines, Cabot Wells and Acreage ~ 3 Miles
CABOT MARCELLUS SUMMARY
Reilly
PadZick Pad
Completing: 14 wells (266 Stages)
Wells Producing: 226 H, 39 V
WOPL: 10 wells (245 Stages)
WOC: 15 wells (347 Stages)
Rig Count: 6 (as of August 21, 2013)
Cumulative
Production
5-6 BCF
4-5 BCF
3-4 BCF
2-3 BCF
7-8 BCF
6-7 BCF
8+ BCF
2 wells (27 stages)IP rate: 34.8 Mmcf/d2 wells (37 stages)
IP rate: 51.2 Mmcf/d
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EVOLUTION OF CABOTS MARCELLUS PROGRAM
0100200300400500600
700800900
1,0001,100
Dec-09 Dec-10 Dec-11 Dec-12
Mm
cfpd
Gross Marcellus Daily Produc tion
2010 2011 20122013 andbeyond
13% HBP Reduced stage spacing f rom
300 ft. to 250 ft. Divested midstream assets 44 produc ing Hz wells
29% HBP Drilling days reduced Reduced completion cost
per stage 107 produc ing Hz wells
43% HBP Implemented 200 ft. stage
spacing Tested Upper Marcellus Tested downspacing De-risked eastern edge of
our acreage position
185 producing Hz wells
Expected to be 60% HBPby year-end 2013
Transition intodevelopment mode(improved efficiencies /reduced costs)
Addi tional test ing of Upper
Marcellus Addi tional downspac ing
testing
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2.1
2.7
3.43.8
4.1
0.00.51.01.52.02.53.03.5
4.04.5
2008 2009 2010 2011 2012
ThousandFt.
Horizontal Length
7.48.7
15.116.8 17.4
5.97.2
11.9 14.014.5
0.0
5.0
10.0
15.0
20.0
2008 2009 2010 2011 2012
Mmcfpd
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
S
tages
Average Number of Stages
5.0
7.8
11.2
13.214.1
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 40
Note: Data excludes wells drilled in the northern portion of our acreage position
CONTINUED PERFORMANCE IMPROVEMENTS IN THE MARCELLUS
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26
20
1614
0
10
20
30
2010 2011 2012 2013 YTD
Days
Drilling Days to TD
Record of8 days
$165$150
$105
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Typical Well Parameters (Based on 2012 Program)
EUR: 14.1 Bcf
IP Rate: 17.4 Mmcfpd
Lateral Length : 4,100
Number of Stages Per Well: 18
CABOT MARCELLUS ECONOMICS
Average Working Interest: 100%
Average Revenue Interest: 85%
Gas Price Different ial: NYMEX less $0.05 per Mmbtu
70%
100%
130%
170%
80%
115%
150%
195%
50%
75%
100%
125%
150%
175%
200%
$3.00 $3.50 $4.00 $4.50
BTAX%IRR
Henry Hub ($ / Mmbtu)
$6.5 million D&C $6.0 million D&C
Typical Well IRR Sensitiv ity
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Diversifying on Multiple Pipelines
Firm Transportation Arrangements
Long-Term Sales Agreements(Firm Sales)
Investing in New Pipeline Projects
COG MARCELLUS MARKETING STRATEGY
Opportunistic Hedging Program
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NY
VT NH
PA
NJ
CT
MA
RI
Iroquois
Millennium
Springville
TGP 200 Line
Canada
Boston
Hartford
LongIsland
Laser
TGP 300 Line
Transco
Constitution
New YorkCity
Charlotte
INTERSTATE PIPELINE MARKETS
SusquehannaCounty
Current MarketsTennessee Gas Pipel ine (300)
Transco Gas PipelineMillennium Gas Pipeline
2015 Market Addit ionsIroquois Pipeline
Tennessee Gas Pipel ine (200)TransCanada Pipeline (via Iroquois)
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FIRM TRANSPORTATION AND LONG-TERM SALES CONTRACTS
Firm Transportation Contracts
2013 (current) 325 Mmcf per day
2014 (current / target) 325 Mmcf per day / 450 Mmcf per day
2015 (current / target)*** 875 Mmcf per day / 1 Bcf per day
Long-Term Sales Contracts (8-15 years in duration)
2013 (current) 325 Mmcf per day
2014 450 Mmcf per day
2015 615 Mmcf per day
Long-term sales contracts include volumes COG moves under its customers firm capacity
Long-term sales contract volumes will change going fo rward as new opportun ities become available
***The increase from 2014 to 2015 includes 500 Mmcf/d of firm c apacity associated with Constitu tion Pipeline
Firm transportation contracts include volumes COG moves under its own firm capacity
Targeted firm transportation volumes are subject to clos ing on agreements COG is currently negotiating
100% of COGs volumes are gathered under a long-term fi rm agreement
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INFRASTRUCTURE UPDATE
Maximum Interstate Delivery Capacity
Note: Capacity volumes above are indicative deliverability estimates for facilities thatare in place or planned for those periods; these are not product ion estimates.
Compression, Dehydration & Measurement Capacity
Year-end 2013 2.2 Bcf per day
Year-end 2014 3.4 Bcf per day
Year-end 2015 3.7 Bcf per day
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2013 MARCELLUS SALES BY INDEX AND UNHEDGED REALIZED PRICING
COG 2013 Marcellus Sales By Index
Index
% of COG 2013
Marcellus SalesNYMEX 65%
Dominion Transmission*** 19%
Columbia Gas Transmission 11%
Other 5%***Approximately 70% of the volumes sold at Dominion Transmission pr icing are hedged through 2013
COG Unhedged Realized Marcellus Pricing
PeriodDifferential to NYMEX
($/Mcf)
Q1 2013 ($0.01)Q2 2013 $0.01
July 2013 ($0.15)
Estimated August December 2013 ($0.10 - $0.15)
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EAGLE FORD SHALE
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EAGLE FORD SHALE SUMMARY
~62,000 net acres
Current operated rig count: 2
Added a second r ig in late July that wil lfocus solely on multi-well pad development(3 6 wells per pad)
Operated wells producing: 50
Operated wells currently drilling: 2
Operating wells completing: 2
Average completed well cost : ~$6.5mm
Multi-well pad dril ling expected to reducewell costs by $500,000 - $600,000 per well
400 down-spacing results continue to reinforcethe concept, resulting in ~500 identifiedundrilled locations remaining in COGs 100%owned and operated Buckhorn area
Recently completed an extended lateral well(8,000+) with a 24-hour peak rate of ~1,130Boepd and a 120-day rate of ~1,100 Boepd
15
109
0
5
10
15
2012 Q1 2013 Q2 2013
Day
s
Drilling Days to TD
650
900
450
570
0
250
500
750
1,000
Program Average Last 6 Wells
Boepd
Peak 24-Hour Rate and 30-Day Rate
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3,000+ Locations in the Sweet Spot of theMarcellus Shale Implying 25+ Years of Inventory
at Current Drilling Levels
Currently Producing 1.2 Bcf/d of GrossMarcellus Production From Only 8% of
Our Identified Locations
Transit ioning From Acreage Capture toEfficient Pad Development in 2014
Cash Flow Neutral Investment Program in 2013While Growing Production 44% to 54%
SIMPLE GROWTH STORY
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Thank youThe 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, butnot limited to, market factors, the market price of natural gas and oil, results of
future drilling and marketing activity, future production and costs, and otherfactors detailed in the Companys Securities and Exchange Commission filings.