Cabot Oil & Gas' latest Investor Presentation, prepared for the EnerCom Oil & Gas Conference held in Denver (August 12, 2013). The presentation contains a number of interesting slides, including a map of their well locations and a map of interstate pipelines detailing how they get all that gas (now over 1 Bcf/d) to market.

1. Investor Presentation
EnerCom's
The Oil & Gas Conference
Denver, CO
August 12, 2013

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 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 Mcf
1Excludes DD&A, exploration expense, stock-based compensation and pension termination expenses
KEY INVESTMENT HIGHLIGHTS

3. Marcellus Shale
~200,000 net acres
Current Rig Count: 6 (as of August 21, 2013)
2013E Drilling Activity: ~100 net wells
Marmaton – Penn Lime
~70,000 net acres
2013E Drilling Activity: ~10 net wells
Eagle Ford Shale / Pearsall Shale
~62,000 net Eagle Ford acres
~71,000 net Pearsall acres
Current Rig Count: 2
2013E Drilling Activity: ~45 net wells
ASSET OVERVIEW
2012 Year-End Proved Reserves: 3.8 Tcfe
Q2 2013 Production: 1.046 Bcfe per day
2013E Drilling Activity: 155 – 165 net wells

4. 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…

5. ?
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

6. 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
$/Mcfe
All-Sources F&D Costs
SUPERIOR RESERVE REPLACEMENT AND FINDING COSTS

7. 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 filings
Peer group includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC

8. 2012 Capital Program: $979 million
($809 million net of JV and asset sales)
2013 Capital Program:
$1.1 billion - $1.2 billion
Marcellus
63%
Production
Equipment /
Other
4%
Drilling
83%
Land
9%
Exploration
4%
Other
10%
Eagle Ford /
Marmaton /
Pearsall
30%
Marcellus
65%
Land
5%
Drilling
87%
Production
Equipment /
Other
5%
Exploration
3%
Other
5%
DISCIPLINED CAPITAL SPENDING FOCUSED ON THE DRILL-BIT
Eagle Ford /
Marmaton /
Pearsall
27%

9. $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&A¹ Financing
1 Excludes stock-based compensation and pension termination expenses
INDUSTRY LEADING COST STRUCTURE

10. $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
Broker
Estimate
Range:
$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 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

11. MARCELLUS SHALE

12. 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

13. EVOLUTION OF CABOT’S MARCELLUS PROGRAM
0
100
200
300
400
500
600
700
800
900
1,000
1,100
Dec-09 Dec-10 Dec-11 Dec-12
Mmcfpd
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

14. 2.1
2.7
3.4
3.8
4.1
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
2008 2009 2010 2011 2012
ThousandFt.
Horizontal Length
7.4
8.7
15.1
16.8 17.4
5.9
7.2
11.9
14.0 14.5
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
13.4
15.6
17.7
0.0
5.0
10.0
15.0
20.0
2008 2009 2010 2011 2012
Stages
Average Number of Stages
5.0
7.8
11.2
13.2
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 – 40
Note: Data excludes wells drilled in the northern portion of our acreage position
CONTINUED PERFORMANCE IMPROVEMENTS IN THE MARCELLUS

15. 26
20
16
14
0
10
20
30
2010 2011 2012 2013 YTD
Days
Drilling Days to TD
Record of
8 days
$165
$150
$105
<$90
$0
$50
$100
$150
$200
2010 2011 2012 2013 YTD
$000sPerStage
Completion Cost Per Stage1
MARCELLUS OPERATING EFFICIENCIES
1 Pressure pumping costs only

16. 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 $4.50
BTAX%IRR
Henry Hub ($ / Mmbtu)
$6.5 million D&C $6.0 million D&C
Typical Well IRR Sensitivity

17. 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

18. NY
VT NH
PA
NJ
CT
MA
RI
Iroquois
Millennium
Springville
TGP 200 Line
Canada
Boston
Hartford
Long
Island
Laser
TGP 300 Line
Transco
Constitution
New York
City
Charlotte
INTERSTATE PIPELINE MARKETS
Susquehanna
County
Current Markets
Tennessee Gas Pipeline (300)
Transco Gas Pipeline
Millennium Gas Pipeline
2015 Market Additions
Iroquois Pipeline
Tennessee Gas Pipeline (200)
TransCanada Pipeline (via Iroquois)

19. 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 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

20. 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 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

21. 2013 MARCELLUS SALES BY INDEX AND UNHEDGED REALIZED PRICING
COG 2013 Marcellus Sales By Index
Index
% of COG 2013
Marcellus Sales
NYMEX 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
Period
Differential to NYMEX
($/Mcf)
Q1 2013 ($0.01)
Q2 2013 $0.01
July 2013 ($0.15)
Estimated August – December 2013 ($0.10 - $0.15)

22. EAGLE FORD SHALE

23. 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
10
9
0
5
10
15
2012 Q1 2013 Q2 2013
Days
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

24. 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 to
Efficient Pad Development in 2014
Cash Flow Neutral Investment Program in 2013
While Growing Production 44% to 54%
SIMPLE GROWTH STORY

25. 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.