Morgan Stanley Marcellus-Utica Summit September 29, 2015 Pittsburgh, PA

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

Marcellus Shale

~89,000 net acres

~200,000 net acres

>1,300 locations

>3,000 locations

Current Rig Count: 1

Current Rig Count: 3

2015E Drilling Activity: ~45 net wells

2015E Drilling Activity: ~70 net wells 2

WELL POSITIONED TO NAVIGATE A CHALLENGING MARKET IN 2015

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

1 Excludes

DD&A, exploration expense, and stock-based compensation 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

2

3

2015 OPERATING PLAN AND CAPITAL PROGRAM DOUBLE-DIGIT PRODUCTION GROWTH DESPITE A 45% DECLINE IN CAPITAL SPENDING, HIGHLIGHTING COG’S CAPITAL EFFICIENCY Net Wells Drilled

2015E Capital Program: $900 million

177 (~35%)

FY 2014

~115

FY 2015

Land 4%

Exploration 4%

Production Equipment / Other 12%

Completed Frac Stages Drilling & Completion 80%

(~35%)

FY 2014

FY 2015

Drilling and Completion Capital ($mm)

2015E D&C Capital: $720 million Eagle Ford 40%

$1,315 (~45%)

FY 2014

~$720

FY 2015

Marcellus 60%

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PROVEN TRACK RECORD OF PRODUCTION AND RESERVE GROWTH…

Bcfe

Annual Production (Bcfe) 700 600 500 400 300 200 100 0

531.8 413.6 28.6%

267.7 187.5

130.6

2015 Guidance: 10% - 18%

Liquids

54.5%

Gas

42.8% 43.5%

2010

2011

2012

2013

2014

2015E

Tcfe

Year-End Proved Reserves (Tcfe) 9.0 8.0 7.0 6.0 5.0 4.0 3.0 2.0 1.0 0.0

7.4 5.5 3.8

35.7%

3.0

2.7

Liquids

41.9%

Gas

26.7% 12.3%

2010

2011

2012

2013

2014

2015E 5

…WHILE MAINTAINING A CONSERVATIVE BALANCE SHEET

Net Debt to EBITDAX1 2.0x 1.7x 1.5x 1.5x

1.4x

1.3x 1.2x

1.0x

0.9x

0.5x

0.0x 2010

1

2011

2012

2013

2014

LTM Q2 2015

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

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INDUSTRY-LEADING COST STRUCTURE

Operating

Transportation¹

Taxes O/T Income

Cash G&A²

Financing

$2.00 $1.76

Cash Unit Costs ($/Mcfe)

$1.67 $1.50 $1.28

$1.27

$1.26

1H 2015

$1.00

$0.50

$0.00 2011

2012

2013

2014

3-Year F&D Costs: Total Company ($/Mcfe)

$1.30

$1.02

$0.76

$0.68

3-Year F&D Costs: Marcellus Only ($/Mcfe)

$0.65

$0.56

$0.48

$0.43

1 Includes

all demand charges and gathering fees stock-based compensation

2 Excludes

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CABOT’S LOW-COST STRUCTURE IS DESIGNED TO WEATHER ALL COMMODITY CYCLES 2014 Cash Costs Per Unit vs. Appalachia Peers ($/Mcfe)1

Operating Costs

G&A

2014 Production Per Employee vs. Appalachia Peers (Mmcfe)

Interest

$1.25

900

Production Per Employee (Mmcfe)

800

Cash Unit Costs ($/Mcfe)

$1.00

$0.75

$0.50

$0.25

700 600 500 400 300 200 100

$0.00

0 COG

Peer A

Peer B

Peer C

Peer D

Source: 2014 company filings 1 Excludes gathering, transport, processing and marketing costs Peers include: Antero Resources, EQT, Range Resources and Southwestern Energy

Peer B

COG

Peer D

Peer A

Peer C

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MARCELLUS SHALE

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

FY 2014

FY 2015

Average Marcellus Rig Count 6.0 3.5

Reduction in drilling and completion activity in 2015 is predicated on lower anticipated natural gas price realizations throughout Appalachia as we await the inservice 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



Average Gross Daily Marcellus Production (Bcf/d) 1.7 – 1.8 1.54

Currently testing 500’ - 800’ downspacing between laterals, which would increase inventory / resource potential / NAV, if successful

FY 2014

FY 2015

Marcellus Drilling and Completion Capital ($mm) $850 ~$430

FY 2014

FY 2015 10

CABOT OIL & GAS CONTINUES TO DRILL THE MOST PROLIFIC WELLS IN THE MARCELLUS SHALE Top 100 Marcellus Wells By Operator1

Percentage of Operator’s Total Wells in Top 100

Peer G Peer H 1 Peer F 1 3 Peer E Peer I 3 1 Peer D 3

Cabot

26%

Peer C

20%

Peer F

Peer C 4 Peer B 7

Peer A 7

10%

Peer G

5%

Peer B

5%

Peer D

2%

Peer A

1%

Peer H

1%

Peer E

1%

Peer I

1%

Cabot 70

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

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CABOT’S EUR PER FOOT AND F&D COSTS REMAIN BEST-IN-CLASS IN THE MARCELLUS AND UTICA

$1.20

3.5 $1.00 3.0 2.5 2.0

$0.80

$0.60

1.5 $0.40 1.0 0.5

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

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Implied F&D Cost ($/Mcfe)

EUR per 1,000 ft. of lateral (Bcfe)

4.0

CABOT’S MARCELLUS SHALE ECONOMICS

2015 Program Well

2014 Program Well

175%

152%

BTAX %IRR

150%

Cabot’s YTD 2015 realized natural gas price: 96% $2.32

125% 100%

102% 75%

51%

50% 25% 0%

65% 17%

37%

8% $1.50

$2.00

$2.50

$3.00

Realized Natural Gas Price Held Flat ($/Mmbtu) Typical Marcellus Well Parameters  EUR: 18 Bcf (3.6 Bcf per 1,000’)

 Number of Stages: 25

 D&C Cost: $5.6MM

 Average Working Interest: 100%

 Facilities Cost: $400K

 Average Net Revenue Interest: 85%

 Lateral Length: 5,000’

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.

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CABOT’S MARCELLUS DRILLING AND COMPLETION COST SAVINGS

Tangibles

Drilling Rig

Drilling Rig 7%

Facilities

Completion Services 31%

Completion Services

Facilities 7%

Frac Services

Tangibles 7%

YTD Marcellus Well Cost Savings By Category

Drilling Services

Marcellus AFE Well Costs By Component

0%

(10%)

(20%) Frac Services 19% (30%)

Drilling Services 29%

(40%)

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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

1

Q2 2014

Normalized to a 5,000’ lateral length

Q3 2014

Q4 2014

Q1 2015

Q2 2015

Record

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CABOT’S PRICE REALIZATION OUTLOOK IMPROVES SIGNIFICANTLY WITH THE ADDITION OF NEW TAKEAWAY CAPACITY TO FAVORABLY PRICED MARKETS Gulf Coast / Mid-Atlantic

New England / NY / Canada

100%

% of Sales by Index

90% 80% 70%

6% 20%

9%

43%

TCO

Fixed Price 4% 8%

36%

11%

50%

DTI

19%

8%

60%

40%

NE PA

20%

Access to more favorably priced markets in 2017 / 2018 results in a significant improvement in differentials 24%

30% 49% 20% 10%

3%

25%

15%

0%

Illustrative Differential to NYMEX ($/Mcf)1

Q3 2015E

2017E

2018E

($0.95) – ($1.05)

($0.14) – ($0.45)

$0.18 – ($0.09)

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.

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Bcf/d

SUPPLY GROWTH IS WANING… DECREASED ACTIVITY AND FLATTENING PRODUCTION IN THE MARCELLUS Marcellus Region Natural Gas Production (Bcf/d)1

18 16 14 12 10 8 6 4 2 0

Marcellus Horizontal Rig Count2 NE PA

80 60 40

73

75

27

26

25

28

74 26

SW / Central PA 75 29

WV 67

62

21

18

15 28

26

29

20

33

26

21

21

20

20

17

11

10

Q1 2014

Q2 2014

Q3 2014

Q4 2014

Q1 2015

Q2 2015

Current

0

Source:

51

1 EIA

Drilling Productivity Report as of July 13, 2015; 2 Baker Hughes North America Rotary Rig Count as of July 31, 2015

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…WHILE DEMAND GROWTH IS ON THE HORIZON APPROXIMATELY 8 BCF PER DAY OF POTENTIAL NEW TAKEAWAY CAPACITY FROM CABOT’S NORTHEAST PENNSYLVANIA SUPPLY AREA 8 7 6

Bcf/d

5 4 3 2 1 0

TCO East Side Expansion NFG Tuscarora Lateral Algonquin AIM NFG Northern Access 2016 Millennium Expansion Virginia Southside Expansion Source: Public filings; internal estimates

TGP Niagara Leidy Southeast Expansion DTI New Market Millennium Valley Lateral PennEast Access Northeast

NFG Northern Access 2015 Constitution Pipeline NFG Central Tioga Atlantic Sunrise Atlantic Bridge TGP Northeast Energy Direct 18

EAGLE FORD SHALE

CABOT’S EAGLE FORD SHALE SUMMARY



~89,000 net acres

COG Eagle Ford Shale Acreage Position

–

Buckhorn: ~78,000 net acres

Buckhorn ~78K 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



Presidio ~11K net acres

Frio La Salle

Atascosa McMullen

Net Eagle Ford Production (Boe/d) 17,889

–

Anticipate ~20 wells in backlog at year-end

–

Flexibility to accelerate completion capital if prices warrant

10,308

Gross drilling inventory: >1,300 locations (assuming 300’ spacing)

Q2 2014

Q2 2015 20

CABOT’S EAGLE FORD SHALE ECONOMICS

2015 Program Well

2014 Program Well

100%

90%

BTAX %IRR

80% 61% Cabot’s YTD 2015 realized oil price: $50.00

60% 40% 20%

18%

40%

38% 27% 17%

7% 0% $45.00

$55.00

$65.00

$75.00

WTI Oil Price Held Flat ($/Bbl) Typical Eagle Ford Well Parameters  EUR: 565 MBoe

 Number of Stages: 30

 D&C Cost: $6.0MM

 Average Working Interest: 100%

 Facilities / Pumping Unit Cost: $600K

 Average Net Revenue Interest: 75%

 Lateral Length: 7,700’ Note: Single well economics are all-in and include capital associated with road, pad, production facilities and pumping units.

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CABOT’S EAGLE FORD DRILLING AND COMPLETION COST SAVINGS

YTD Eagle Ford Well Cost Savings By Category

Tangibles

% Reduction Due to Pricing Facilities / Artificial Lift

Facilities / Artificial Lift 10%

Frac Services

Frac Services 42%

Drilling Services

Tangibles 8%

Drilling Rig

% Reduction Due to Efficiency Gains Drilling Rig 6%

Completion Services

Eagle Ford AFE Well Costs By Component

0%

(10%)

(20%) Drilling Services 14% (30%)

Completion Services 20%

(40%)

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CABOT’S EAGLE FORD DRILLING EFFICIENCIES

Eagle Ford Drilling Days (Spud to TD)1

15.0 12.5

11.4 8.8

Q1 2014

Q2 2014

Q3 2014

Q4 2014

8.7

8.8

Q1 2015

Q2 2015

$296

$276

6.2

Record

Eagle Ford Drilling Costs ($ / Lateral Foot)

$419

$370

$400

$344

$201

Q1 2014

1

Q2 2014

Normalized to a 7,700’ lateral length

Q3 2014

Q4 2014

Q1 2015

Q2 2015

Record

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CABOT’S EAGLE FORD LEASE OPERATING EXPENSE SAVINGS

YTD Eagle Ford Lease Operating Expense Savings

Disposal

Surface Equipment 7%

Labor

Treating

Subsurface Maintenance 4%

Power & Fuel

Power & Fuel 25%

Misc.

Labor 6%

Surface Equipment

Misc. 8%

Subsurface Maintenance

Eagle Ford Lease Operating Expense By Category

0%

(20%)

Compression 5%

Treating 13%

(40%)

(60%) Disposal 32% (80%)

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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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