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

KEY INVESTMENT HIGHLIGHTS

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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

ASSET OVERVIEW

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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

PROVEN TRACK RECORD OF PRODUCTION GROWTH…

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130.6

187.5

267.7

413.6

0

100

200

300

400

500

600

700

2010 2011 2012 2013 2014E 2015E

Bcfe

LiquidsGas

43.5%

42.8%

54.5%

2014 Guidance: 28% - 41%

2015 Guidance: 20% - 30%

…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

LiquidsGas

12.3%

26.7%

41.9%

INDUSTRY-LEADING CASH COST STRUCTURE

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$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

$ / M

cfe

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

CAPITAL EFFICIENT ASSETS CONTINUE TO RESULT IN SUPERIOR FINDING COSTS

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$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

$ / M

cfe

Total Company All-Sources F&D Marcellus-Only All-Sources F&D

2014E Capital Program: $1.375 - $1.475 billion

2014 CAPITAL PROGRAM

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Eagle Ford 30%

Marcellus 68%

Other 2% Land

6%

Drilling 84%

Production Equipment

/ Other 8%

Exploration 2%

9

Marcellus

0.0

1.0

2.0

3.0

4.0

5.0

Cum

ulat

ive P

rodu

ctio

n Fr

om Ju

ly to

De

cem

ber 2

013 (

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)

CABOT’S EUR PER FOOT IN THE MARCELLUS REMAINS BEST-IN-CLASS

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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

/ 1,00

0’ of

Lat

eral

(Bcf

e)

CABOT’S MARCELLUS ECONOMICS

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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

BTA

X %

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

ILLUSTRATIVE Q2 – Q4 2014 TOTAL COMPANY NATURAL GAS PRICE REALIZATIONS (INCLUDING THE IMPACT OF HEDGES)

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$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 –

Q4 20

14 C

OG To

tal C

ompa

ny N

atur

al Ga

s Rea

lizat

ions

($

/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)

Q2 – Q4 2014 TOTAL COMPANY NATURAL GAS PRODUCTION EXPOSURE BY INDEX

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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

ROAD MAP TO 2014 / 2015 PRODUCTION GROWTH

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0

500

1,000

1,500

2,000

2,500

3,000

Mmbt

u/d

Current Gross Marcellus Production Additional Firm Capacity on MillenniumNew Capacity on LDC System Q4 2015 Firm Capacity / Firm Sales Additions

Note: Assumes Constitution Pipeline in-service date of December 2015 (subject to change)

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Eagle Ford

EAGLE FORD SHALE SUMMARY

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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

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

48%

66%

86%

40%

50%

60%

70%

80%

90%

$80.00 $90.00 $100.00

BTA

X %

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.

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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