An updated PowerPoint from COG presented at the Barclays CEO Energy/Power Conference 2015 in New York City, September 2015. Cabot is one of (perhaps THE) most successful drillers in the Marcellus Shale.

1. BARCLAYS CEO ENERGY-POWER CONFERENCE
SEPTEMBER 8, 2015

2. 2
CABOT OIL & GAS ASSET OVERVIEW
2014 Year-End Proved Reserves: 7.4 Tcfe
2014 Production: 531.8 Bcfe
2015E Production Growth: 10% - 18%
2015E Drilling Activity: ~115 net wells
Eagle Ford Shale
~89,000 net acres
>1,300 locations
Current Rig Count: 1
2015E Drilling Activity: ~45 net wells
Marcellus Shale
~200,000 net acres
>3,000 locations
Current Rig Count: 3
2015E Drilling Activity: ~70 net wells

3. Best-in-class asset base provides competitive rates-of-return in the current market environment
• Peer-leading rates of return and EUR per lateral foot in the Marcellus Shale
• Marcellus: >50% IRR at $2.00 per Mcf realized price
• Eagle Ford: >50% IRR at $65.00 per Bbl realized price
Strategy is to provide returns-focused growth as opposed to “growth for the sake of growth”
• Cabot expects to generate 10% - 18% production growth in 2015 despite a 45% reduction in drilling
and completion spending
• Modest level of outspend anticipated under current commodity price realizations
Low-cost structure
• 2014 total company all-sources finding costs of $0.71 per Mcfe
• 2014 Marcellus-only all-sources finding costs of $0.43 per Mcf
• 2014 total company cash costs1 of $1.27 per Mcfe
• 2014 Marcellus-only cash costs1 of $0.80 per Mcf
Strong balance sheet provides financial flexibility in a low commodity price environment
• Conservative leverage position: Debt / LTM EBITDAX2 of 1.7x at Q2 2015
• Financial flexibility: Recently increased credit facility commitments to $1.8 billion, with only $383
million of borrowings outstanding as of June 30, 2015
• Hedge position provides downside protection: ~31% of 2015E natural gas production hedged
3
WELL POSITIONED TO NAVIGATE A CHALLENGING MARKET IN 2015
1 Excludes DD&A, exploration expense, and stock-based compensation
2 EBITDAX is a non-GAAP measure defined as net income plus interest expense, income tax expense, depreciation, depletion and amortization, exploration expense,
gains and losses resulting from the sale of assets, non-cash gains and losses on derivative instruments, and stock-based compensation expense and other

4. 4
2015 OPERATING PLAN AND CAPITAL PROGRAM
DOUBLE-DIGIT PRODUCTION GROWTH DESPITE A 45% DECLINE IN CAPITAL
SPENDING, HIGHLIGHTING COG’S CAPITAL EFFICIENCY
2015E Capital Program:
$900 million
Land
4%
Drilling &
Completion
80%
Production
Equipment /
Other
12%
Exploration
4%
FY 2014 FY 2015
Completed Frac Stages
177
~115
FY 2014 FY 2015
Net Wells Drilled
$1,315
~$720
FY 2014 FY 2015
Drilling and Completion Capital ($mm)
(~35%)
(~35%)
(~45%)
2015E D&C Capital:
$720 million
Marcellus
60%
Eagle Ford
40%

5. 5
PROVEN TRACK RECORD OF PRODUCTION AND RESERVE GROWTH…
130.6
187.5
267.7
413.6
531.8
0
100
200
300
400
500
600
700
2010 2011 2012 2013 2014 2015E
Bcfe
Liquids
Gas
43.5%
42.8%
54.5%
28.6%
2015
Guidance:
10% - 18%
Annual Production (Bcfe)
2.7 3.0
3.8
5.5
7.4
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
2010 2011 2012 2013 2014 2015E
Tcfe
Liquids
Gas
12.3%
26.7%
41.9%
35.7%
Year-End Proved Reserves (Tcfe)

6. 6
…WHILE MAINTAINING A CONSERVATIVE BALANCE SHEET
1 EBITDAX is a non-GAAP measure defined as net income plus interest expense, income tax expense, depreciation, depletion and amortization, exploration expense,
gains and losses resulting from the sale of assets, non-cash gains and losses on derivative instruments, and stock-based compensation expense and other
1.5x
1.4x 1.3x
0.9x
1.2x
1.7x
0.0x
0.5x
1.0x
1.5x
2.0x
2010 2011 2012 2013 2014 LTM Q2
2015
Net Debt to EBITDAX1

7. 7
INDUSTRY-LEADING COST STRUCTURE
1 Includes all demand charges and gathering fees
2 Excludes stock-based compensation
$1.76
$1.67
$1.28 $1.27 $1.26
$0.00
$0.50
$1.00
$1.50
$2.00
2011 2012 2013 2014 1H 2015
CashUnitCosts($/Mcfe)
Operating Transportation¹ Taxes O/T Income Cash G&A² Financing
3-Year F&D Costs:
Total Company
($/Mcfe)
3-Year F&D Costs:
Marcellus Only
($/Mcfe)
$1.30
$0.65
$1.02
$0.56
$0.76
$0.48
$0.68
$0.43

8. 8
CABOT’S LOW-COST STRUCTURE IS DESIGNED TO WEATHER ALL
COMMODITY CYCLES
Source: 2014 company filings
1 Excludes gathering, transport, processing and marketing costs
Peers include: Antero Resources, EQT, Range Resources and Southwestern Energy
$0.00
$0.25
$0.50
$0.75
$1.00
$1.25
COG Peer A Peer B Peer C Peer D
CashUnitCosts($/Mcfe)
Operating Costs G&A Interest
2014 Cash Costs Per Unit vs. Appalachia Peers ($/Mcfe)1
0
100
200
300
400
500
600
700
800
900
Peer B COG Peer D Peer A Peer C
ProductionPerEmployee(Mmcfe)
2014 Production Per Employee vs. Appalachia Peers (Mmcfe)

9. MARCELLUS SHALE

10. 10
CABOT’S MARCELLUS SHALE SUMMARY
 ~200,000 net acres
 Operated rig count: 3
 2015E drilling activity: ~70 net wells
 2015E average gross daily production: 1.7 – 1.8 Bcf/d
– Production levels from quarter to quarter will
ultimately be dictated by price realizations and
potential curtailments
– Flexibility to accelerate / decelerate completion
capital throughout the year
 Reduction in drilling and completion activity in 2015 is
predicated on lower anticipated natural gas price
realizations throughout Appalachia as we await the in-
service of new takeaway capacity
 COG plans to accelerate activity upon the in-service of
Constitution Pipeline in 2H 2016
 COG’s best-in-class Marcellus assets generate >50%
IRR at a realized price of $2.00 per Mcf
 Currently testing 500’ - 800’ downspacing between
laterals, which would increase inventory / resource
potential / NAV, if successful
1.54
1.7 – 1.8
FY 2014 FY 2015
Average Gross Daily Marcellus Production
(Bcf/d)
6.0
3.5
FY 2014 FY 2015
Average Marcellus Rig Count
$850
~$430
FY 2014 FY 2015
Marcellus Drilling and Completion Capital
($mm)

11. 11
CABOT OIL & GAS CONTINUES TO DRILL THE MOST PROLIFIC WELLS IN
THE MARCELLUS SHALE
Includes content supplied by IHS Global, Inc.; copyright IHS Global, Inc., 2015, All Rights Reserved. Includes all horizontal / directional Marcellus wells in Pennsylvania and West Virginia with a
production start date from January 2012 to December 2014
1 As measured by max 30-day rate
Note: Peers include Antero Resources, Chesapeake Energy, Chief Oil & Gas, EQT, Inflection Energy, PGE, Shell, Vantage Energy and Warren Resources
Cabot
70
Peer A
7
Peer B
7
Peer C
4
Peer D
3
Peer E
3
Peer F
3
Peer G
1
Peer H
1
Peer I
1
Top 100 Marcellus Wells By Operator1
1%
1%
1%
1%
2%
5%
5%
10%
20%
26%
Peer I
Peer E
Peer H
Peer A
Peer D
Peer B
Peer G
Peer F
Peer C
Cabot
Percentage of Operator’s Total Wells in Top 100

12. 12
CABOT’S EUR PER FOOT AND F&D COSTS REMAIN BEST-IN-CLASS IN
THE MARCELLUS AND UTICA
Source: Company presentations as of 08/03/15; peers include Antero Resources, EQT Corporation, Gulfport Energy, Noble Energy, Range Resources and
Rice Energy
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
ImpliedF&DCost($/Mcfe)
EURper1,000ft.oflateral(Bcfe)

13. 13
CABOT’S MARCELLUS SHALE ECONOMICS
Typical Marcellus Well Parameters
 EUR: 18 Bcf (3.6 Bcf per 1,000’)
 D&C Cost: $5.6MM
 Facilities Cost: $400K
 Lateral Length: 5,000’
17%
51%
96%
152%
8%
37%
65%
102%
0%
25%
50%
75%
100%
125%
150%
175%
$1.50 $2.00 $2.50 $3.00
BTAX%IRR
Realized Natural Gas Price Held Flat ($/Mmbtu)
2015 Program Well 2014 Program Well
Cabot’s YTD 2015
realized natural
gas price:
$2.32
 Number of Stages: 25
 Average Working Interest: 100%
 Average Net Revenue Interest: 85%
Even assuming wider differentials in Appalachia persist, the incremental Cabot Marcellus well produced
into the local market generates a rate of return of >55% based on the current NYMEX strip1
Note: Single well economics are all-in and include capital associated with road, pad and production facilities.
1 Assumes NYMEX strip as of August 5, 2015, held flat after year 9. Assumes regional differential of ($1.00) for the life of the well.

14. 14
CABOT’S MARCELLUS DRILLING AND COMPLETION COST SAVINGS
Marcellus AFE Well Costs By Component YTD Marcellus Well Cost Savings By Category
(40%)
(30%)
(20%)
(10%)
0%
FracServices
DrillingServices
CompletionServices
Facilities
DrillingRig
Tangibles
Completion
Services
31%
Drilling
Services
29%
Frac
Services
19%
Drilling Rig
7%
Facilities
7%
Tangibles
7%

15. 15
CABOT’S MARCELLUS DRILLING EFFICIENCIES
Marcellus Drilling Days (Spud to TD)1
16.9
14.3
13.6
12.8 12.4
10.5
6.9
Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Record
1 Normalized to a 5,000’ lateral length

16. 16
CABOT’S PRICE REALIZATION OUTLOOK IMPROVES SIGNIFICANTLY WITH THE
ADDITION OF NEW TAKEAWAY CAPACITY TO FAVORABLY PRICED MARKETS
15%
25%
49%
3%
24%
20%
43%
36%
19%
11%
9% 8%
8%
6% 4%
20%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Q3 2015E 2017E 2018E
%ofSalesbyIndex
Gulf Coast / Mid-Atlantic New England / NY / Canada NE PA DTI TCO Fixed Price
Illustrative
Differential
to NYMEX
($/Mcf)1
($0.95) –
($1.05)
($0.14) –
($0.45)
$0.18 –
($0.09)
Access to more favorably
priced markets in 2017 / 2018
results in a significant
improvement in differentials
1 Illustrative differential ranges are based on indicative quotes from trading counterparties and third-party research as of 8/5/2015. These projections involve risks and uncertainties that could
cause actual results to differ materially from projected results. Analysis assumes a 2H 2016 in-service for Constitution Pipeline and a Q3 2017 in-service for Atlantic Sunrise Pipeline. Differential
ranges are based on the following gross production ranges – Q3 2015E: 1.55 to 1.60 Bcf/d; 2017E: 2.1 to 2.4 Bcf/d; 2018E: 2.4 to 3.0 Bcf/d.

17. 17
SUPPLY GROWTH IS WANING…
DECREASED ACTIVITY AND FLATTENING PRODUCTION IN THE MARCELLUS
0
2
4
6
8
10
12
14
16
18
Bcf/d
Marcellus Region Natural Gas Production (Bcf/d)1
Source: 1 EIA Drilling Productivity Report as of July 13, 2015; 2 Baker Hughes North America Rotary Rig Count as of July 31, 2015
21 21 20 20 17 11 10
25 28 28 26 29 33 26
27 26 26 29 21 18
15
73 75 74 75
67
62
51
0
20
40
60
80
Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Current
Marcellus Horizontal Rig Count2
NE PA SW / Central PA WV

18. 18
…WHILE DEMAND GROWTH IS ON THE HORIZON
APPROXIMATELY 8 BCF PER DAY OF POTENTIAL NEW TAKEAWAY CAPACITY
FROM CABOT’S NORTHEAST PENNSYLVANIA SUPPLY AREA
Source: Public filings; internal estimates
0
1
2
3
4
5
6
7
8
Bcf/d
TCO East Side Expansion TGP Niagara NFG Northern Access 2015
NFG Tuscarora Lateral Leidy Southeast Expansion Constitution Pipeline
Algonquin AIM DTI New Market NFG Central Tioga
NFG Northern Access 2016 Millennium Valley Lateral Atlantic Sunrise
Millennium Expansion PennEast Atlantic Bridge
Virginia Southside Expansion Access Northeast TGP Northeast Energy Direct

19. EAGLE FORD SHALE

20. 20
CABOT’S EAGLE FORD SHALE SUMMARY
10,308
17,889
Q2 2014 Q2 2015
Net Eagle Ford Production (Boe/d)
Frio
La Salle
Atascosa
McMullen
COG Eagle Ford Shale Acreage Position
Buckhorn
~78K net acres
 ~89,000 net acres
– Buckhorn: ~78,000 net acres
– Presidio: ~11,000 net acres
 Operated rig count: 1
 2015E net liquids production growth: 50% - 60%
 Plan to drill ~45 wells and place 40 to 45 wells
on production during 2015
– Anticipate ~20 wells in backlog at year-end
– Flexibility to accelerate completion capital if
prices warrant
 Gross drilling inventory: >1,300 locations
(assuming 300’ spacing)
Presidio
~11K net acres

21. 21
CABOT’S EAGLE FORD SHALE ECONOMICS
18%
38%
61%
90%
7%
17%
27%
40%
0%
20%
40%
60%
80%
100%
$45.00 $55.00 $65.00 $75.00
BTAX%IRR
WTI Oil Price Held Flat ($/Bbl)
2015 Program Well 2014 Program Well
Typical Eagle Ford Well Parameters
 EUR: 565 MBoe
 D&C Cost: $6.0MM
 Facilities / Pumping Unit Cost: $600K
 Lateral Length: 7,700’
 Number of Stages: 30
 Average Working Interest: 100%
 Average Net Revenue Interest: 75%
Cabot’s YTD
2015 realized
oil price:
$50.00
Note: Single well economics are all-in and include capital associated with road, pad, production facilities and pumping units.

22. 22
CABOT’S EAGLE FORD DRILLING AND COMPLETION COST SAVINGS
Eagle Ford AFE Well Costs By Component YTD Eagle Ford Well Cost Savings By Category
(40%)
(30%)
(20%)
(10%)
0%
DrillingServices
DrillingRig
FracServices
CompletionServices
Facilities/ArtificialLift
Tangibles
% Reduction Due to Efficiency Gains % Reduction Due to Pricing
Frac
Services
42%
Completion
Services
20%
Drilling
Services
14%
Facilities /
Artificial Lift
10%
Tangibles
8%
Drilling Rig
6%

23. 23
CABOT’S EAGLE FORD DRILLING EFFICIENCIES
1 Normalized to a 7,700’ lateral length
Eagle Ford Drilling Days (Spud to TD)1
15.0
12.5 11.4
8.8 8.7 8.8
6.2
Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Record
Eagle Ford Drilling Costs ($ / Lateral Foot)
$419
$370 $400
$344
$296 $276
$201
Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Record

24. 24
CABOT’S EAGLE FORD LEASE OPERATING EXPENSE SAVINGS
Power & Fuel
25%
Treating
13%
Disposal
32%
Compression
5%
Surface
Equipment
7%
Subsurface
Maintenance
4%
Labor
6%
Misc.
8%
Eagle Ford Lease Operating Expense By Category YTD Eagle Ford Lease Operating Expense Savings
(80%)
(60%)
(40%)
(20%)
0%
Treating
SurfaceEquipment
Misc.
Power&Fuel
Labor
SubsurfaceMaintenance
Disposal

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.
25