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TRANSCRIPT
Investor Presentation
EnerCom's The Oil & Gas ConferenceDenver, COAugust 12, 2013
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 with rates of return that rival or exceed all of the top U.S. liquids plays at current commodity prices
– 25+ years of Marcellus inventory at current drilling levels– Oil-focused initiative in the Eagle Ford Shale
– Increased 2013 production guidance range from 35% - 50% to 44% - 54%
– Midpoint of 2013 guidance implies a three-year production CAGR of 45%
– 2012 proved reserve growth of 27% for a three-year reserve CAGR of 23%
– Q2 2013 per unit cash costs1 of $1.36 per Mcfe
– 2012 all sources finding costs of $0.87 per Mcfe
– 2012 all sources Marcellus finding costs of $0.49 per Mcfe
– $566 million of liquidity as of 6/30/2013
– Net debt to adjusted capitalization ratio of 32% as of 6/30/2013
– Approximately 65% hedged at the midpoint of 2013 production guidance
– 45 natural gas collar contracts for 2014 at a weighted average floor of $4.10 per Mcf1Excludes 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 wells
Marmaton – Penn Lime~70,000 net acres2013E Drilling Activity: ~10 net wells
Eagle Ford Shale / Pearsall Shale~62,000 net Eagle Ford acres~71,000 net Pearsall acresCurrent Rig Count: 22013E Drilling Activity: ~45 net wells
ASSET OVERVIEW
2012 Year-End Proved Reserves: 3.8 TcfeQ2 2013 Production: 1.046 Bcfe per day2013E Drilling Activity: 155 – 165 net wells
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…
?
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
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
$/Mcf
e
All-Sources F&D Costs
SUPERIOR RESERVE REPLACEMENT AND FINDING COSTS
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
2012 Capital Program: $979 million ($809 million net of JV and asset sales)
2013 Capital Program: $1.1 billion - $1.2 billion
Marcellus63%
Production Equipment /
Other 4%
Drilling83%
Land9%
Exploration4%
Other10%
Eagle Ford / Marmaton /
Pearsall30%
Marcellus65%
Land5%
Drilling87%
Production Equipment /
Other5%
Exploration3%
Other5%
DISCIPLINED CAPITAL SPENDING FOCUSED ON THE DRILL-BIT
Eagle Ford / Marmaton /
Pearsall27%
$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
$ / M
cfe
Operating Transportation Taxes O/T Income G&A¹ Financing
1 Excludes stock-based compensation and pension termination expenses
INDUSTRY LEADING COST STRUCTURE
$34mm $75mm
2014E Capital Expenditures¹ Current Regular Dividend (Recently increased by 100%
effective August 2013)
Estimated Capital Commitment for Constitution Pipeline
Implied 2014 Free Cash Flow
2014E Cash Flow¹
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
BrokerEstimate Range:
$1,190mm –
$1,548mm
Average:$1,342mm
USE OF PROCEEDS FOR POTENTIAL FREE CASH FLOW IN 2014
BrokerEstimate Range:
$1,477mm–
$1,981mm
Average:$1,729mm
Implied Free Cash
Flow:$278mm
Acceleration of Marcellus Drilling Program
Acceleration of Eagle Ford Drilling ProgramDividend Policy(Increase Regular Dividend / Share
Buybacks / Special Dividend)
Average 2014 Henry Hub / WTI Broker Estimates:
$4.01 per Mmbtu / $92.00 per Bbl
Pay Down Revolver Borrowings
MARCELLUS SHALE
Bare Earth LiDAR with Aerial photo, Township Lines, Cabot Wells and Acreage ~ 3 Miles
CABOT MARCELLUS SUMMARY
Reilly Pad
Zick 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
EVOLUTION OF CABOT’S MARCELLUS PROGRAM
0100200300400500600700800900
1,0001,100
Dec-09 Dec-10 Dec-11 Dec-12
Mmcf
pd
Gross Marcellus Daily Production
2010 2011 2012 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• De-risked eastern edge of
our acreage position• 185 producing Hz wells
• Expected to be 60% HBP by year-end 2013
• Transition into development mode (improved efficiencies / reduced costs)
• Additional testing of Upper Marcellus
• Additional downspacing testing
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
26
2016
14
0
10
20
30
2010 2011 2012 2013 YTD
Days
Drilling Days to TD
Record of8 days
$165$150
$105<$90
$0
$50
$100
$150
$200
2010 2011 2012 2013 YTD
$000
s Per
Sta
ge
Completion Cost Per Stage1
MARCELLUS OPERATING EFFICIENCIES
1 Pressure pumping costs only
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 Differential: 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 $4.50
BTAX
%IR
R
Henry Hub ($ / Mmbtu)
$6.5 million D&C $6.0 million D&C
Typical Well IRR Sensitivity
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
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)
Transco Gas PipelineMillennium Gas Pipeline
2015 Market AdditionsIroquois Pipeline
Tennessee Gas Pipeline (200)TransCanada Pipeline (via Iroquois)
FIRM TRANSPORTATION AND LONG-TERM SALES CONTRACTS
Firm Transportation Contracts2013 (current) 325 Mmcf per day2014 (current / target) 325 Mmcf per day / 450 Mmcf per day2015 (current / target)*** 875 Mmcf per day / 1 Bcf per day
Long-Term Sales Contracts (8-15 years in duration)2013 (current) 325 Mmcf per day2014 450 Mmcf per day2015 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 forward as new opportunities become available
***The increase from 2014 to 2015 includes 500 Mmcf/d of firm capacity associated with Constitution Pipeline
– Firm transportation contracts include volumes COG moves under its own firm capacity
– Targeted firm transportation volumes are subject to closing on agreements COG is currently negotiating
– 100% of COG’s volumes are gathered under a long-term firm agreement
INFRASTRUCTURE UPDATE
Maximum Interstate Delivery 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.
Compression, Dehydration & Measurement CapacityYear-end 2013 2.2 Bcf per dayYear-end 2014 3.4 Bcf per dayYear-end 2015 3.7 Bcf per day
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 pricing are hedged through 2013
COG Unhedged Realized Marcellus Pricing
PeriodDifferential to NYMEX
($/Mcf)Q1 2013 ($0.01)Q2 2013 $0.01July 2013 ($0.15)Estimated August – December 2013 ($0.10 - $0.15)
EAGLE FORD SHALE
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: 50
Operated wells currently drilling: 2
Operating wells completing: 2
Average completed well cost: ~$6.5mm
– Multi-well pad drilling expected to reduce well costs by $500,000 - $600,000 per well
400’ down-spacing results continue to reinforce the concept, resulting in ~500 identified undrilled locations remaining in COG’s 100% owned and operated Buckhorn area
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
15
109
0
5
10
15
2012 Q1 2013 Q2 2013
Days
Drilling Days to TD
650
900
450570
0
250
500
750
1,000
Program Average Last 6 Wells
Boep
d
Peak 24-Hour Rate and 30-Day Rate
3,000+ Locations in the Sweet Spot of the Marcellus Shale Implying 25+ Years of Inventory
at Current Drilling Levels
Currently Producing 1.2 Bcf/d of Gross Marcellus Production From Only 8% of
Our Identified Locations
Transitioning From Acreage Capture toEfficient Pad Development in 2014
Cash Flow Neutral Investment Program in 2013While Growing Production 44% to 54%
SIMPLE GROWTH STORY
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.