The Cabot Oil & Gas PowerPoint presentation used during Cabot's address to the delegates at the Citi 2014 Global Energy and Utilities Conference in Boston, MA on May 14-15, 2014. The presentation has a number of interesting, inside bits of information useful to those who track the happenings in the Marcellus Shale.

1. INVESTOR PRESENTATION
Citi 2014 Global Energy and Utilities Conference
May 12 - 13, 2014

2. KEY INVESTMENT HIGHLIGHTS
2
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 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
– 2014 production growth guidance of 28% - 41%
– Initial 2015 production growth guidance of 20% - 30%
– 2013 proved reserve growth of 42% resulting in a three-year reserve CAGR of 26%
– 2013 total company all-sources finding costs of $0.55 per Mcfe
– 2013 Marcellus-only all-sources finding costs of $0.40 per Mcf
– 2014 total company per unit cash cost1 guidance of ~$1.25 per Mcfe
– 2014 Marcellus-only per unit cash cost1 guidance of ~$0.75 per Mcf
– Net debt to adjusted capitalization ratio of 34.5% as of 3/31/2014
– Over $900 million of liquidity as of 3/31/2014
1Excludes DD&A, exploration expense, stock-based compensation and pension termination expenses

3. ASSET OVERVIEW
3
Marcellus Shale
~200,000 net acres
Current Rig Count: 6
2014E Drilling Activity: ~110 net wells
Eagle Ford Shale
~66,000 net acres
Current Rig Count: 2 (increasing to 3 beginning in Q3 2014)
2014E Drilling Activity: 40 - 50 net wells
2013 Year-End Proved Reserves: 5.5 Tcfe
2013 Production: 413.6 Bcfe
2014E Production: 530 – 585 Bcfe
2014E Drilling Activity: 150 – 170 net wells

4. PROVEN TRACK RECORD OF PRODUCTION GROWTH…
4
130.6
187.5
267.7
413.6
0
100
200
300
400
500
600
700
2010 2011 2012 2013 2014E 2015E
Bcfe
Liquids
Gas
43.5%
42.8%
54.5%
2014
Guidance:
28% - 41%
2015
Guidance:
20% - 30%

5. …AND RESERVE GROWTH
5
2.7
3.0
3.8
5.5
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
2010 2011 2012 2013 2014E 2015E
Tcfe
Liquids
Gas
12.3%
26.7%
41.9%

6. INDUSTRY-LEADING CASH COST STRUCTURE
6
$2.12
$1.76
$1.67
$1.28
Guidance
Midpoint:
$1.25
~$0.75
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
2010 2011 2012 2013 2014E 2014E Marcellus Only
$/Mcfe
Operating Transportation¹ Taxes O/T Income G&A² Financing
1 Includes all demand charges and gathering fees
2 Excludes stock-based compensation and pension termination expenses

7. CAPITAL EFFICIENT ASSETS CONTINUE TO RESULT IN
SUPERIOR FINDING COSTS
7
$1.05
$1.21
$0.87
$0.55
$0.63 $0.65
$0.49
$0.40
$0.00
$0.25
$0.50
$0.75
$1.00
$1.25
2010 2011 2012 2013
$/Mcfe
Total Company All-Sources F&D Marcellus-Only All-Sources F&D

8. 2014E Capital Program: $1.375 - $1.475 billion
2014 CAPITAL PROGRAM
8
Eagle
Ford
30%
Marcellus
68%
Other
2% Land
6%
Drilling
84%
Production
Equipment
/ Other
8%
Exploration
2%

9. 9
Marcellus

10. 0.0
1.0
2.0
3.0
4.0
5.0
CumulativeProductionFromJulyto
December2013(Bcfe)
Top 20 Pennsylvania Marcellus Wells (July to December 2013)
COG HAD THE TOP 13 WELLS AND 17 OF THE TOP 20 WELLS IN
PENNSYLVANIA DURING THE SECOND HALF OF 2013
10
Source: PA DEP Oil & Gas Reporting Website
Note: Peers include EQT Corporation and Southwestern Energy
 17 of the top 20 (July to December 2013)
 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)

11. CABOT’S EUR PER FOOT IN THE MARCELLUS REMAINS
BEST-IN-CLASS
11
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Source: Company presentations; peers include Antero Resources, EQT Corporation, Noble Energy, Range Resources and Rice Energy
EUR/1,000’ofLateral(Bcfe)

12. CABOT’S MARCELLUS ECONOMICS
12
Typical Marcellus Well Parameters (Based on 2013 Program)
 EUR: 16.9 Bcf
 Well Cost: $7.0 million
 Lateral Length: 4,666’
 Number of Stages Per Well: 23
 Average Working Interest: 100%
 Average Revenue Interest: 85%
102%
150%
206%
50%
100%
150%
200%
250%
$3.00 $3.50 $4.00
BTAX%IRR
COG’s expected 2014 Marcellus realized natural gas price
Typical Marcellus Well IRR Sensitivity
Cabot plans to drill longer laterals in 2014 relative to the 2013 program

13. ILLUSTRATIVE Q2 – Q4 2014 TOTAL COMPANY NATURAL GAS
PRICE REALIZATIONS (INCLUDING THE IMPACT OF HEDGES)
13
$3.65
$3.55
$3.40
$3.30
$3.20
$3.10
$3.75
$3.65
$3.55
$3.45
$3.35
$3.25
$3.85
$3.75
$3.60
$3.50
$3.40
$3.30
$0.00
$1.00
$2.00
$3.00
$4.00
($1.00) ($1.25) ($1.50) ($1.75) ($2.00) ($2.25)
Q2–Q42014COGTotalCompanyNaturalGasRealizations
($/Mcf)
Basis Differential Sensitivities for TGP Zone 4 – 300 and Leidy Line Prices
$4.25 Strip $4.50 Strip $4.75 Strip
Note: Assumes the following regional basis based on futures curves and indicative quotes: TCO – ($0.16); DTI – ($0.78); MPL – ($1.00); TETCO M3 – ($0.41)

14. Q2 – Q4 2014 TOTAL COMPANY NATURAL GAS PRODUCTION
EXPOSURE BY INDEX
14
26%
23%
20%
13%
9%
4%
4% 1%
NYMEX
Leidy Line
Tennessee Zone 4 - 300 Leg
Millennium
Dominion
Columbia
TETCO M3
Houston Ship Channel
Average discount
of $0.10 to NYMEX

15. ROAD MAP TO 2014 / 2015 PRODUCTION GROWTH
15
0
500
1,000
1,500
2,000
2,500
3,000
Mmbtu/d
Current Gross Marcellus Production Additional Firm Capacity on Millennium
New Capacity on LDC System Q4 2015 Firm Capacity / Firm Sales Additions
Note: Assumes Constitution Pipeline in-service date of December 2015 (subject to change)

16. 16
Eagle Ford

17. EAGLE FORD SHALE SUMMARY
17
La Salle
Frio Atascosa
McMullen
~20
miles
Pad B
• 6-well pad
• Average IP rate of
1,045 Boe/d per well
(89% oil)
• Average 25-day rate of
946 Boe/d per well
 ~66,000 net acres (recently added ~4,000 net
acres)
 Current operated rig count: 2 (increasing to 3
beginning in Q3 2014)
 ~60% HBP
 ~50% of the 2014 program is expected to be on
pads with four wells or greater
 Cabot's first six-well pad realized cost savings of
~$600,000 per well
 Currently drilling a five-well pad with a planned
average lateral length over 8,500’
Pad A
• 4-well pad
• Average IP rate of 885
Boe/d per well (90%
oil)
• Average 30-day rate of
582 Boe/d per well
Pad C
• Single well pad
• Peak 24-hour rate of
1,344 Boe/d
(92% oil)
• Average 30-day rate of
966 Boe/d

18. EAGLE FORD DRILLING AND COMPLETION EFFICIENCIES
18
2011 2012 2013 Q1 2014
Drilling Days Per 1,000’ of Lateral
2011 2012 2013 Q1 2014
Average Lateral Length
2011 2012 2013 Q1 2014
Proppant Per Stage
2011 2012 2013 Q1 2014
Stage Spacing

19. 48%
66%
86%
40%
50%
60%
70%
80%
90%
$80.00 $90.00 $100.00
BTAX%IRR
WTI Oil Price ($/Bbl)
CABOT’S EAGLE FORD ECONOMICS
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Typical Eagle Ford Well Parameters
 EUR: 500 MBoe
 Well Cost: $7.0 million
 Lateral Length: 7,000’
 Number of Stages Per Well: 26
 Average Working Interest: 100%
 Average Revenue Interest: 75%
Typical Eagle Ford Well IRR Sensitivity
Note: Economics include facilities costs. Assumes Henry Hub price of $4.00 and NGL price of 40% of WTI.

20. 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.
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