1.
Investor Presentation
Bank of America Merrill Lynch
2013 Global Energy Conference
November 21, 2013

2.
KEY INVESTMENT HIGHLIGHTS
Extensive Inventory of
Low-Risk, High-Return
Drilling Opportunities
Industry-Leading
Production and Reserve
Growth
– 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
Low Cost Structure
– 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
Strong Financial
Position and Financial
Flexibility
1Excludes
– Net debt to adjusted capitalization ratio of 33% as of 9/30/2013
– Approximately 30% hedged at the midpoint of 2014 production guidance
DD&A, exploration expense, stock-based compensation and pension termination expenses

3.
ASSET OVERVIEW
2012 Year-End Proved Reserves: 3.8 Tcfe
Q3 2013 Production: 1.164 Bcfe per day
2013E Drilling Activity: 155 – 165 net wells
2014E Drilling Activity: 170 – 190 net wells
Marcellus Shale
~200,000 net acres
Current Rig Count: 6 (as of August 21, 2013)
2013E Drilling Activity: ~100 net wells
2014E Rig Count: 7 (beginning January 2014)
Eagle Ford Shale
~62,000 net acres
Current Rig Count: 2
2013E Drilling Activity: 30 – 35 net wells
2014E Rig Count: 2
2014E Drilling Activity: 40 – 50 net wells
2014E Drilling Activity: 130 – 140 net wells

4.
PEER-LEADING PRODUCTION AND RESERVE GROWTH
Production Per Debt-Adjusted Share CAGR (2010 – 2012)
42%
30%
26%
24%
22%
17%
16%
15%
8%
Peer median: 11%
8%
2%
(0%)
COG
18%
Peer A
17%
Peer B
Peer C
Peer D
Peer E
Peer F
Peer G
Peer H
Peer I
Peer J
Peer K
(2%)
Peer L
(3%)
Peer M
(9%)
Peer N
Reserves Per Debt-Adjusted Share CAGR (2010 – 2012)
15%
9%
5%
4%
2%
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
Source: Cabot Oil & Gas, company filings
Peer group from 2013 proxy statement includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC
Peer M
Peer G
Peer I
Peer B
Peer N

5.
TRANSFORMATION TO A MARCELLUS AND EAGLE FORD
FOCUSED STORY IN 2014
2013E Capital Program:
$1.1 billion - $1.2 billion
2014E Capital Program:
$1.375 billion - $1.475 billion
Other
2%
Other
5%
Eagle Ford
24%
Eagle Ford /
Marmaton /
Pearsall
30%
Marcellus
74%
Marcellus
65%
Production
Equipment /
Other
5%
Land
5%
Exploration
3%
Production
Equipment /
Other
6%
Drilling
87%
Land
6%
Exploration
3%
Drilling
85%

6.
PROVEN TRACK RECORD OF PRODUCTION GROWTH…
600
550
500
Bcfe
450
400
2014
Guidance:
30% - 50%
350
300
267.7
250
150
2013
Guidance:
44% - 54%
(increased
from 35%50%)
187.5
200
42.8%
130.6
43.5%
100
Liquids (Net)
Gas (Net)
50
0
2010
2011
2012
2013E
2014E

7.
…AND RESERVE GROWTH
?
4.5
4.0
3.8
3.5
3.0
Tcfe
3.0
12.3%
2.5
2.0
26.7%
2.7
2.1
Liquids (Net)
31.1%
Gas (Net)
1.5
1.0
0.5
0.0
2009
2010
2011
2012
2013E

8.
INDUSTRY-LEADING COST STRUCTURE
Operating
$2.50
Transportation¹
Taxes O/T Income
G&A²
Financing
$2.47
$2.12
$2.00
$ / Mcfe
$1.76
$1.67
$1.50
Guidance
Midpoint:
$1.37
Guidance
Midpoint:
$1.21
$1.00
$0.80
$0.50
$0.00
2009
1 Includes
2010
2011
all demand charges and gathering fees
stock-based compensation and pension termination expenses
2 Excludes
2012
2013E
2014E
2014E Marcellus Only

9.
PEER-LEADING CASH FLOW PER SHARE GROWTH WHILE GENERATING
SUBSTANTIAL FREE CASH FLOW
2013E – 2015E Cash Flow Per Share CAGR
50%
40%
30%
20%
10%
0%
(10%)
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
Peer B
Peer F
Peer M
Peer G
2014E – 2015E Cumulative Free Cash Flow ($mm)
$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
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 Bbl
Peer group from 2013 proxy statement includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC

10.
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

11.
MARCELLUS SHALE

12.
Cumulative Production From January to June 2013 (Bcfe)
CABOT CONTINUES TO PRODUCE THE MOST PROLIFIC WELLS IN THE
MARCELLUS SHALE
Top 20 Pennsylvania Marcellus Wells (January to June 2013)
6.0
5.0




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)
4.0
3.0
2.0
1.0
0.0
Source: PA DEP Oil & Gas Reporting Website
Note: Peers include Chief Oil & Gas and EQT Corporation

13.
DERISKING OF CABOT’S MARCELLUS POSITION
15 of Top 20 Marcellus Wells
(Jan – Jun 2013) SILVER LAKE
LANESBORO
HALLSTEAD
SILVER LAKE
GREAT BEND
Recently Announced Q2 / Q3 2013 Well Results
HARMONY
SUSQUEHANNA Total Frac
Number of
Peak 24-Hour
DEPOT
Wells
Stages
Rate (Mmcf/d)
Pad A
OAKLAND
MIDDLETOWN
3
68
98.0
3 JACKSON
50
59.1
Pad D
3
45
55.8
Pad E
2
27
34.8
Pad F
FOREST LAKE
109.5
Pad B
FRANKLIN
109
Pad C
FRIENDSVILLE
Q2 / Q3 2013 Well Results
4
1
23
NEW MILFORD
BRIDGEWATER
MONTROSE
THOMPSON
32.8
ARARAT
JESSUP
HARFORD
RUSH
GIBSON
BROOKLYN
HERRICK
DIMOCK
UNIONDALE
HOP BOTTOM
AUBURN
LATHROP
SPRINGVILLE
LENOX
CLIFFORD
Cabot Acreage
FOREST
CITY
Peer Acreage
Conservation Areas

14.
CONTINUED PERFORMANCE IMPROVEMENTS IN THE MARCELLUS
4.5
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
0.0
3.4
3.8
Average IP and 30-Day Rate
20.0
4.1
2.7
2.1
10.0
5.0
2008
2009
2010
15.1
15.0
Mmcfpd
Thousand Ft.
Horizontal Length
2011
0.0
2012
11.9
7.4
8.7
5.9
2008
13.4
2009
5.0
0.0
2010
13.2
10.0
5.0
2009
2011
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
2011
2012
14.1
11.2
4.6
2008
2010
15.0
17.7
8.5
10.0
14.5
EUR
Bcf
Stages
15.0
15.6
14.0
17.4
7.2
Average Number of Stages
20.0
16.8
2012
0.0
7.8
5.0
2008
2009
2010
2011
2012

15.
MARCELLUS RIG MOVE EFFICIENCIES
10
Move Days (Release to Spud)
8.7
8
7.4
6
4.8
4.0
4
2
0
2011/2012 (25 Moves)
Implementation of New Move
Process (4 Moves)
Average For Last 19 Moves
Target
 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

16.
CABOT IS DRILLING MARCELLUS WELLS FASTER DESPITE
LONGER LATERAL LENGTHS
Drilling Days (Spud-to-Rig Release)
0
5
10
15
20
25
0
Measured Depth (Feet)
2,500
5,000
2011
2012
2013 YTD
7,500
10,000
12,500

17.
MARCELLUS COMPLETION EFFICIENCIES
FRAC EVOLUTION:
Average Frac Stages Per Crew Day
2010 – Daylight Operations, single well pads
10
Record of 9 frac stages
per crew day
(achieved five times)
2011 – 24 Hour operations, multi well pads
8
2013 – 24 Hour operations, multi well pads,
simultaneous zipper operations
EFFICIENCY RESULT:
Days
2012 – 24 Hour operations, multi well pads,
modified zipper operations
6
4
 100% increase in stages per day compared to 2010
 Significant cost savings through the reduction in days
on site
9.0
4.2
2
2.5
0
2.9
2010
2011
5.1
2012
2013 YTD

18.
EVOLUTION OF CABOT’S FRAC STAGE SPACING
SHORTER STAGE LENGTHS AND REDUCED CLUSTER SPACING
RESULTING IN HIGHER EURS PER 1,000 FEET OF LATERAL
EUR Per 1,000’ of Lateral (Bcf)
4.0
3.7
3.3
2.9
3.0
2.4
2.0
1.0
0.0
2008
2009
2010 - Q2 2012
Q3 - Q4 2012
Packer
Systems
Completion
400’ spacing
Packer
Systems
Completion
300’ spacing
Plug/Perf
250’ spacing
Plug/Perf
200’ spacing

19.
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

20.
COG MARCELLUS MARKETING STRATEGY
Diversifying on Multiple Pipelines to
Multiple Geographic Locations
Firm Transportation Arrangements
Long-Term Sales Agreements
(Firm Sales)
Investing in New Pipeline Projects
Opportunistic Hedging Program

21.
CABOT’S MARCELLUS GATHERING CAPACITY
Cabot’s Gross Marcellus Gathering Capacity (Mmcf/d)
Gross Takeaway Capacity (Mmcf/d)
4,000
3,650
3,800
3,000
2,380
2,000
1,580
1,000
0
650
20
95
Dec-08
Dec-09
255
Dec-10
Dec-11
Dec-12
Dec-13
Dec-14
Dec-15
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.

22.
INTERSTATE PIPELINE MARKETS
Canada
Iroquois
NY
NH
VT
TGP 200 Line
Constitution
Laser
Boston
MA
CT
Millennium
RI
TGP 300 Line
Hartford
Springville
Transco
Susquehanna
County
Long
Island
New York
City
PA
NJ
Charlotte
Current Markets
Tennessee 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 Additions
Iroquois Pipeline (CT, Long Island)
Tennessee Gas Pipeline – 200 (CT, MA, NH)
TransCanada Pipeline (via Iroquois)

23.
SCHEDULED APPALACHIA PIPELINE EXPANSIONS
Cumulative Pipeline Capacity Additions
(Bcf/d)
Over 13.3 Bcf/d of pipeline capacity expansions in Appalachia between now and 2017
with even more projects currently in the planning phases
14
13.3
12
10.9
10
8.8
8
5.8
6
4
3.1
2
0
Q4 2013
Source: Bentek
2014
2015
2016
2017

24.
CABOT’S MARCELLUS ECONOMICS
Typical Well IRR Sensitivity
$6.5 million D&C
$6.0 million D&C
195%
200%
BTAX %IRR
175%
150%
150%
115%
125%
100%
80%
75%
50%
170%
130%
100%
70%
$3.00
$3.50
$4.00
Henry Hub ($ / Mmbtu)
Typical Well Parameters (Based on 2012 Program)
 EUR: 14.1 Bcf
 Number of Stages Per Well: 18
 IP Rate: 17.4 Mmcfpd
 Average Working Interest: 100%
 Lateral Length: 4,100’
 Average Revenue Interest: 85%
$4.50

25.
EAGLE FORD SHALE

26.
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
Pad A
• 4-well pad
• Completing
• Lateral lengths
ranging from
5,200’ to 8,000’
 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
~20
miles
Pad B
• 6-well pad
• Drilling
• Average lateral
length over
8,000’
Frio
Atascosa
La Salle
McMullen

27.
SIMPLE GROWTH STORY
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
Best-In-Class Production and Cash Flow Per Share Growth
While Generating Free Cash Flow

28.
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.