A presentation delivered by Cabot Oil & Gas at the Scotia Howard Weil Energy Conference in New Orleans in March 2016. During the presentation we learn Cabot plans to complete 40 wells in the Marcellus in 2016 and grow production slightly--up to 7% in 2016 over 2015.

1. Scotia Howard Weil Energy Conference
March 21, 2016

2. 2
CABOT OIL & GAS OVERVIEW
2015 Production: 602.5 Bcfe (13% growth)
2015 Year-End Proved Reserves: 8.2 Tcfe (11% growth)
2016E Drilling Activity: ~30 net wells
2016E Production Growth: 2% - 7%
Eagle Ford Shale
~85,500 net acres
~1,300 locations
No Rigs Currently Running
2015 Drilling Activity: 49 net wells
2016E Drilling Activity: ~5 net wells
Marcellus Shale
~200,000 net acres
~3,450 locations
Current Rig Count: 1
2015 Drilling Activity: 83 net wells
2016E Drilling Activity: ~25 net wells

3. 3
KEY INVESTMENT HIGHLIGHTS
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
Extensive Inventory of
Low-Risk, High-Quality
Drilling Opportunities
Disciplined Capital
Spending Driving
Production and
Reserve Growth
Low Cost Structure
Focused on
Maintaining a Strong
Financial Position
– Peer-leading EUR per lateral foot in the Marcellus Shale
– Recently increased Marcellus EUR per 1,000 feet guidance from 3.6 Bcf to 3.8 Bcf
– Recent downspacing tests resulted in a 15% increase in Marcellus location count to
~3,450 locations
– 2016 capital spending guidance of $325 million, a 58% reduction year-over-year
– 2016 production growth guidance of 2% - 7% despite the significant reduction in spending
– 2015 reserve growth of 11% despite reduced activity levels and lower price realizations
– 2015 total company all-sources finding costs of $0.57 per Mcfe
– 2015 Marcellus-only all-sources finding costs of $0.31 per Mcf
– 2015 total company cash costs1 of $1.27 per Mcfe
– 2015 Marcellus-only cash costs1 of $0.82 per Mcf (direct LOE of $0.04 per Mcf)
– Conservative leverage position: Net debt / LTM EBITDAX2 of 1.3x as of 12/31/2015
(pro forma for recent equity offering)
– Financial flexibility: Undrawn $1.8 billion credit facility and >$580 million of cash as of
12/31/2015 (pro forma for recent equity offering)

4. 4
133
~30
FY 2015 FY 2016E
Net Wells Drilled
2016 CAPITAL BUDGET AND OPERATING PLAN
CONTINUED FOCUS ON CAPITAL EFFICIENCY
1 Includes facilities and pumping units
2016E Capital Program:
$325 mm (excludes $80 - $150 mm
of equity method investments)
Land
5%
Drilling, Completion
and Facilities
92%
Other
3%
2016E D&C Capital1:
$300 mm
Eagle Ford
30%
Marcellus
70%
102
~55
FY 2015 FY 2016E
Net Wells Completed
~5,900’
~7,400’~7,000’
~9,500’
Marcellus Eagle Ford
Average Lateral Lengths (Ft.)
FY 2015 FY 2016E

5. 5
PROVEN TRACK RECORD OF PRODUCTION AND RESERVE GROWTH…
413.6
531.8
602.5
0
100
200
300
400
500
600
700
2013 2014 2015 2016E
Bcfe
Liquids
Gas
28.6%
2016
Guidance:
2% - 7%
13.3%
Annual Production (Bcfe)
5.5
7.4 8.2
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
2013 2014 2015
Tcfe
Liquids
Gas
35.7%
Year-End Proved Reserves (Tcfe)
10.7%

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
1.3x
0.9x
1.2x
1.3x
YE 2012 YE 2013 YE 2014 YE 2015
(Pro forma for recent
equity offering)
Net Debt to LTM EBITDAX1

7. 7
INDUSTRY-LEADING COST STRUCTURE
1 Includes all demand charges and gathering fees
2 Excludes stock-based compensation
3 Mid-point of 2016 guidance
$1.76
$1.67
$1.28 $1.27 $1.27 $1.25
$0.00
$0.50
$1.00
$1.50
$2.00
2011 2012 2013 2014 2015 2016E³
CashUnitCosts($/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
$0.62
$0.39

8. MARCELLUS SHALE

9. 9
CABOT’S MARCELLUS SHALE SUMMARY
 ~200,000 net acres
 Operated rig count: 1
 2015 activity: 83 net wells drilled / 58 net wells completed
 2016E activity: ~25 net wells drilled / ~40 net wells completed
 Cabot’s reduction in drilling and completion activity in 2016 is
predicated on lower anticipated natural gas price realizations
throughout Appalachia as we await the in-service of new takeaway
capacity
 Cabot’s year-end backlog of uncompleted wells allows for reduced
capital spending in 2016, while providing flexibility into 2017
 Marcellus well costs have declined over 30% year-over-year to $6.7
million for a 7,000’ lateral, driven by continued efficiency gains and
lower service costs
 Recently increased EUR per 1,000’ guidance from 3.6 Bcf to 3.8
Bcf, further solidifying Cabot’s productivity per well as best-in-
class across the Marcellus
 Success of recent downspacing tests between 700 and 800 feet
(down from 1,000 feet) has resulted in a 15% increase in location
count to ~3,450 net locations
~5,300’
~5,900’
~7,000’
FY 2014 FY 2015 FY 2016E
Marcellus Planned Lateral Lengths (Ft.)
63
48
Year-End 2015 Year-End 2016E
Year-End Drilled Uncompleted Net Wells

10. 10
SUCCESSFUL RESULTS FROM CABOT’S DOWNSPACING TESTS HAVE RESULTED
IN A 15% INCREASE IN MARCELLUS LOCATIONS
Comparison of Cabot’s 700- to 800-foot spaced wells vs. 1,000-foot spaced type curve
0
200
400
600
800
1,000
0 200 400 600 800 1,000 1,200
DailyProductionperStage(Mcf/d)
Days
Cabot’s 1,000-foot spaced Lower Marcellus type curve
Average of Cabot’s 700 to 800-foot downspaced wells

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., 2016, All Rights Reserved. Includes all horizontal / directional Marcellus wells in Pennsylvania and West Virginia with a
production start date from January 2012 to December 2015
1 As measured by max 30-day rate
Note: Peers include Antero Resources, Chesapeake Energy, Chief Oil & Gas, EQT, PGE, Range Resources, Rice Energy, Vantage Energy and Warren Resources
Cabot
68
Peer A
7
Peer B
6
Peer C
6
Peer D
4
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%
1%
3%
4%
4%
6%
21%
Peer G
Peer B
Peer C
Peer F
Peer H
Peer A
Peer I
Peer D
Peer E
Cabot
Percentage of Operator’s Total Wells in Top 100

12. 12
CABOT HAS 18 OF THE TOP 20 WELLS DRILLED IN PENNSYLVANIA SINCE 2012
Cumulative Natural Gas Production (Bcf)
16.3
13.2 13.0 12.9
11.8 11.7 11.4 11.4
10.7
10.1 9.9 9.7 9.7 9.6 9.6 9.6 9.6 9.6 9.4 9.3
Source: PA DEP Oil & Gas Reporting Website; production data through December 2015. Includes all wells drilled on or after 1/1/2012

13. 13
CABOT’S MARCELLUS DRILLING AND COMPLETION COST SAVINGS
Marcellus AFE Well Costs By Component Marcellus Well Cost Savings By Category
(60%)
(50%)
(40%)
(30%)
(20%)
(10%)
0%
Frac
Services
Drilling
Services
Completion
Services
DrillingRig
Facilities
Tangibles
% Reduction Due to Efficiency Gains % Reduction Due to Pricing
Completion
Services
31%
Drilling
Services
28%
Frac
Services
18%
Drilling Rig
8%
Facilities
9%
Tangibles
6%

14. 14
CABOT’S MARCELLUS DRILLING EFFICIENCIES
Marcellus Drilling Days (Spud to TD)1
16.9
14.3
13.6
12.8 12.4
10.5
9.4 9.4
6.0
Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Record
1 Normalized to a 5,000’ lateral length

15. 15
ACTIVITY LEVELS IN NORTHEAST PENNSYLVANIA ARE DECLINING RAPIDLY…
Source: 1 Baker Hughes North America Rotary Rig Count as of March 11, 2016; 2 FracFocus Chemical Disclosure Registry (activity through February 2016 as of
March 15, 2016)
Note: Northeast Pennsylvania includes Bradford, Lycoming, Sullivan, Susquehanna, Tioga and Wyoming counties
17
11
10
9
4
Q1 2015 Q2 2015 Q3 2015 Q4 2015 Current
Northeast Pennsylvania
Horizontal Rig Count1
107
68 67
31
11
Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016
Northeast Pennsylvania
Wells Completed2

16. 0
1
2
3
4
5
6
7
8
Dec-16 Mar-17 Jun-17 Sep-17 Dec-17 Mar-18 Jun-18 Sep-18 Dec-18
Bcf/d
Algonquin AIM DTI New Market NFG Central Tioga
NFG Northern Access 2016 UGI Sunberry Millennium Valley Lateral
Atlantic Sunrise Constitution Pipeline DTI Leidy South
PennEast Atlantic Bridge Virginia Southside Expansion
TGP Orion Caithness Moxie Freedom Millennium Expansion
Access Northeast TGP Northeast Energy Direct
16
Source: Public filings; internal estimates
Note: October 2017 in-service date assumed for Constitution and Atlantic Sunrise based on the mid-point of the current disclosure of the second half of 2017
…WHILE DEMAND GROWTH IS ON THE HORIZON
Cabot's Incremental Firm Transport / Firm Sales Additions
Project Name Mmcf/d
Constitution Pipeline 500
Atlantic Sunrise 850
PennEast 150
TGP Orion Project 135
Caithness Moxie Freedom Power Plant 165
Other Pending Projects TBD
Total Incremental FT / FS Additions 1,800+

17. 17
CABOT’S CASH MARGINS IN THE MARCELLUS ARE EXPECTED TO IMPROVE SIGNIFICANTLY
WITH THE ADDITION OF NEW TAKEAWAY CAPACITY TO FAVORABLY PRICED MARKETS
16%
22%
52%
3%
8%
21%
53%
51%
16%
8%
11%
7%
6%
7%
2%
14%
2% 2%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2016E 2017E 2018E
%ofSalesbyIndex
Gulf Coast/Mid-Atlantic NY/New England/Canada
NE PA DTI
TCO Fixed Price/Other
NYMEX prices and illustrative differentials are based on indicative quotes from the CME Group and trading counterparties as of 3/16/2016. These projections involve risks and uncertainties that
could cause actual results to differ materially from projected results. Analysis assumes an October 2017 in-service for Constitution and Atlantic Sunrise Pipelines based on the mid-point of the
current disclosure of the second half of 2017.
Illustrative Improvement in Pre-Hedge Cash Margins ($/Mcf)
(Based on Current Market Indications)
2016E 2017E 2018E
NYMEX $2.18 $2.73 $2.79
Basis Differential +
Gathering & Transportation
~($1.40) ~($1.30) ~($1.00)
Direct LOE ($0.05) ($0.05) ($0.05)
Regional G&A ($0.03) ($0.03) ($0.03)
Production Taxes ($0.02) ($0.02) ($0.02)
Illustrative
Cash Margin ($/Mcf)
$0.68 $1.33 $1.69
~150% increase in cash margins
based on illustrative analysis

18. EAGLE FORD SHALE

19. 19
CABOT’S EAGLE FORD SHALE SUMMARY
 ~85,500 net acres
– Buckhorn: ~75,000 net acres
– Presidio: ~10,500 net acres
 No rigs currently operating
 2015 activity: 49 net wells drilled / 44 net wells completed
 2016E activity: ~5 net wells drilled / ~15 net wells completed
 2016 activity levels are predicated on meeting all mandatory
near-term drilling / operating commitments necessary to
maintain current leasehold position
 Anticipate 13 wells in backlog at year-end 2016
– Flexibility to accelerate completion capital if prices
warrant in 2016
 Gross Eagle Ford locations: ~1,300 locations
~7,300’ ~7,400’
~9,500’
FY 2014 FY 2015 FY 2016E
Eagle Ford Lateral Lengths (Ft.)
23
13
Year-End 2015 Year-End 2016E
Year-End Drilled Uncompleted Net Wells

20. 20
CABOT’S EAGLE FORD DRILLING AND COMPLETION COST SAVINGS
Eagle Ford AFE Well Costs By Component Eagle Ford Well Cost Savings By Category
(70%)
(60%)
(50%)
(40%)
(30%)
(20%)
(10%)
0%
FracServices
DrillingServices
DrillingRig
CompletionServices
Facilities/ArtificialLift
Tangibles
% Reduction Due to Efficiency Gains % Reduction Due to Pricing
Frac
Services
31%
Completion
Services
25%
Drilling
Services
16%
Facilities /
Artificial Lift
13%
Tangibles
8%
Drilling Rig
7%

21. 21
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 8.2 8.0
6.2
Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Record
Eagle Ford Drilling Costs ($ / Lateral Foot)
$419
$370 $400
$344
$296 $280
$232 $205 $181
Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Record

22. 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.
22