Investor Presentation

Bank of America Merrill Lynch 2013 Global Energy Conference

November 21, 2013

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 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

– Initiated 2014 production growth guidance of 30% - 50%

– Reaffirmed 2013 production growth guidance of 44% - 54%

– 2012 proved reserve growth of 27% resulting in a three-year reserve CAGR of 23%

– Q3 2013 total company per unit cash costs1 of $1.25 per Mcfe

– 2014 Marcellus per unit cash cost1 guidance of ~$0.80 per Mcf

– 2012 total company all-sources finding costs of $0.87 per Mcfe

– 2012 Marcellus all-sources finding costs of $0.49 per Mcf

– Net debt to adjusted capitalization ratio of 33% as of 9/30/2013

– Approximately 30% hedged at the midpoint of 2014 production guidance

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

KEY INVESTMENT HIGHLIGHTS

Marcellus Shale~200,000 net acresCurrent Rig Count: 6 (as of August 21, 2013)2013E Drilling Activity: ~100 net wells2014E Rig Count: 7 (beginning January 2014)2014E Drilling Activity: 130 – 140 net wells

Eagle Ford Shale~62,000 net acresCurrent Rig Count: 22013E Drilling Activity: 30 – 35 net wells2014E Rig Count: 22014E Drilling Activity: 40 – 50 net wells

ASSET OVERVIEW

2012 Year-End Proved Reserves: 3.8 TcfeQ3 2013 Production: 1.164 Bcfe per day2013E Drilling Activity: 155 – 165 net wells2014E Drilling Activity: 170 – 190 net wells

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 filingsPeer group from 2013 proxy statement includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC

2013E Capital Program: $1.1 billion - $1.2 billion

2014E Capital Program: $1.375 billion - $1.475 billion

Marcellus65%

Production Equipment /

Other 5%

Drilling87%

Land5%

Exploration3%

Other5%

Eagle Ford 24%

Marcellus74%

Land6%

Drilling85%

Production Equipment /

Other6%

Exploration3%

Other2%

TRANSFORMATION TO A MARCELLUS AND EAGLE FORD FOCUSED STORY IN 2014

Eagle Ford / Marmaton /

Pearsall30%

130.6

187.5

267.7

0

50

100

150

200

250

300

350

400

450

500

550

600

2010 2011 2012 2013E 2014E

Bcfe

Liquids (Net)Gas (Net)

43.5%

42.8%

2013 Guidance:44% - 54%(increased from 35%-

50%)

2014 Guidance:30% - 50%

PROVEN TRACK RECORD OF PRODUCTION GROWTH…

?

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

$2.47

$2.12

$1.76$1.67

Guidance Midpoint:

$1.37GuidanceMidpoint:

$1.21

$0.80

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

2009 2010 2011 2012 2013E 2014E 2014E Marcellus Only

$ / M

cfe

Operating Transportation¹ Taxes O/T Income G&A² Financing

1 Includes all demand charges and gathering fees2 Excludes stock-based compensation and pension termination expenses

INDUSTRY-LEADING COST STRUCTURE

PEER-LEADING CASH FLOW PER SHARE GROWTH WHILE GENERATING SUBSTANTIAL FREE CASH FLOW

(10%)

0%

10%

20%

30%

40%

50%

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

2013E – 2015E Cash Flow Per Share CAGR

Source: First Call consensus median as of 11/11/2013; cumulative free cash flow defined as cash flow per share times shares outstanding less capital expenditures; consensus 2014 pricing of $3.85 per Mmbtu and $93.92 per BblPeer group from 2013 proxy statement includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC

($1,250)($1,000)

($750)($500)($250)

$0 $250 $500 $750

$1,000 $1,250

COG Peer D Peer C Peer J Peer L Peer A Peer K Peer H Peer N Peer I Peer E Peer B Peer F Peer M Peer G

2014E – 2015E Cumulative Free Cash Flow ($mm)

POTENTIAL USES FOR FREE CASH FLOW

Expand Core Acreage

Positions in the Marcellus

and Eagle Ford

Accelerate Development

of our Marcellus and

Eagle Ford Programs

Organically Build

Positions in New Venture

Opportunities

Return Cash to Shareholders

Via Share Buybacks and

Increased Regular

Dividends

MARCELLUS SHALE

CABOT CONTINUES TO PRODUCE THE MOST PROLIFIC WELLS IN THE MARCELLUS SHALE

0.0

1.0

2.0

3.0

4.0

5.0

6.0

Cum

ulat

ive P

rodu

ctio

n Fr

om Ja

nuar

y to

June

2013

(Bcf

e) Top 20 Pennsylvania Marcellus Wells (January to June 2013)

Source: PA DEP Oil & Gas Reporting WebsiteNote: Peers include Chief Oil & Gas and EQT Corporation

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)

FRIENDSVILLE

MIDDLETOWN

RUSH

AUBURN

FOREST LAKE

JESSUP

DIMOCK

SPRINGVILLE

SILVER LAKESILVER LAKE

GREAT BEND

HALLSTEADSUSQUEHANNA

DEPOT

OAKLAND

HARMONY

LANESBORO

FRANKLIN

NEW MILFORD

JACKSONTHOMPSON

ARARAT

BRIDGEWATER

MONTROSE

BROOKLYN

HARFORD

GIBSONHERRICK

UNIONDALE

LATHROP LENOX CLIFFORDHOP BOTTOM

FOREST CITY

DERISKING OF CABOT’S MARCELLUS POSITION

15 of Top 20 Marcellus Wells (Jan – Jun 2013)

Cabot Acreage

Peer Acreage

Conservation Areas

Recently Announced Q2 / Q3 2013 Well ResultsNumber of

WellsTotal Frac

StagesPeak 24-Hour Rate (Mmcf/d)

Pad A 4 109 109.5Pad B 3 68 98.0Pad C 3 50 59.1Pad D 3 45 55.8Pad E 2 27 34.8Pad F 1 23 32.8

Q2 / Q3 2013 Well Results

2.12.7

3.43.8 4.1

0.00.51.01.52.02.53.03.54.04.5

2008 2009 2010 2011 2012

Thou

sand

Ft.

Horizontal Length

7.4 8.7

15.116.8 17.4

5.9 7.2

11.914.0 14.5

0.0

5.0

10.0

15.0

20.0

2008 2009 2010 2011 2012

Mmcf

pd

Average IP and 30-Day Rate

4.6

8.5

13.415.6

17.7

0.0

5.0

10.0

15.0

20.0

2008 2009 2010 2011 2012

Stag

es

Average Number of Stages

5.0

7.8

11.213.2 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 – 40Note: Data excludes wells drilled in the northern portion of our acreage position

CONTINUED PERFORMANCE IMPROVEMENTS IN THE MARCELLUS

8.7

7.4

4.84.0

0

2

4

6

8

10

2011/2012 (25 Moves) Implementation of New Move Process (4 Moves)

Average For Last 19 Moves Target

Move

Day

s (Re

lease

to S

pud)

MARCELLUS RIG MOVE EFFICIENCIES

Implemented a new rig move process in 2013 including 24-hour operations for rig up and rig down

The new process has reduced average rig moves by ~4 days

4-day reduction in move time yields $250K in savings per move including rig time, trucking, rentals, and labor charges

CABOT IS DRILLING MARCELLUS WELLS FASTER DESPITE LONGER LATERAL LENGTHS

0

2,500

5,000

7,500

10,000

12,500

0 5 10 15 20 25

Meas

ured

Dep

th (F

eet)

Drilling Days (Spud-to-Rig Release)

201120122013 YTD

MARCELLUS COMPLETION EFFICIENCIES

EFFICIENCY RESULT:

100% increase in stages per day compared to 2010

Significant cost savings through the reduction in days on site

2010 – Daylight Operations, single well pads

2011 – 24 Hour operations, multi well pads

2012 – 24 Hour operations, multi well pads, modified zipper operations

2013 – 24 Hour operations, multi well pads, simultaneous zipper operations

FRAC EVOLUTION:

2.5 2.94.2

5.1

9.0

0

2

4

6

8

10

2010 2011 2012 2013 YTD

Days

Average Frac Stages Per Crew Day

Record of 9 frac stages per crew day

(achieved five times)

EVOLUTION OF CABOT’S FRAC STAGE SPACING

Packer Systems

Completion400’ spacing

Packer Systems

Completion300’ spacing

Plug/Perf250’ spacing

Plug/Perf200’ spacing

2.4

2.93.3

3.7

0.0

1.0

2.0

3.0

4.0

2008 2009 2010 - Q2 2012 Q3 - Q4 2012

EUR

Per 1

,000’

of L

ater

al (B

cf)

SHORTER STAGE LENGTHS AND REDUCED CLUSTER SPACING RESULTING IN HIGHER EURS PER 1,000 FEET OF LATERAL

COMPRESSED NATURAL GAS (CNG) AND LINE GAS USAGE IN CABOT’S MARCELLUS OPERATIONS

CNG Usage in Cabot’s Vehicles- Estimated displacement of ~110,000 gasoline gallon

equivalents (GGE) in 2014

CNG / Line Gas Usage in Cabot’s Drilling Operations- Estimated displacement of ~1.1 million diesel gallon

equivalents (DGE) in 2014- Plan to utilize CNG / Line Gas in 100% of Cabot’s future

drilling operations for estimated displacement of 2.5+ million DGE

Line Gas Usage in Cabot’s Completion Operations- Estimated displacement of ~1.5 million DGE in 2014- Plan to utilize Line Gas in 100% of Cabot’s future

completion operations for estimated displacement of 2.6+ million DGE

Diversifying on Multiple Pipelines to Multiple Geographic Locations

Firm Transportation Arrangements

Long-Term Sales Agreements (Firm Sales)

Investing in New Pipeline Projects

COG MARCELLUS MARKETING STRATEGY

Opportunistic Hedging Program

20 95255

650

1,580

2,380

3,6503,800

0

1,000

2,000

3,000

4,000

Dec-08 Dec-09 Dec-10 Dec-11 Dec-12 Dec-13 Dec-14 Dec-15

Gros

s Tak

eawa

y Cap

acity

(Mm

cf/d

)

Cabot’s Gross Marcellus Gathering Capacity (Mmcf/d)

CABOT’S MARCELLUS GATHERING 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. Facilities include compression, dehydration and measurement.

NYVT NH

PA

NJ

CT

MA

RI

Iroquois

Millennium

Springville

TGP 200 Line

Canada

Boston

Hartford

Long Island

LaserTGP 300 Line

Transco

Constitution

New York City

Charlotte

INTERSTATE PIPELINE MARKETS

Susquehanna County

Current MarketsTennessee Gas Pipeline – 300 (CT, NJ, OH, PA, WV)Transco Gas Pipeline (DC, MD, NC, NJ, NY, PA, VA)

Millennium Gas Pipeline (CT, NJ, NY, RI)

2015 Market AdditionsIroquois Pipeline (CT, Long Island)

Tennessee Gas Pipeline – 200 (CT, MA, NH)TransCanada Pipeline (via Iroquois)

SCHEDULED APPALACHIA PIPELINE EXPANSIONS

3.1

5.8

8.8

10.9

13.3

0

2

4

6

8

10

12

14

Q4 2013 2014 2015 2016 2017

Cum

ulat

ive P

ipeli

ne C

apac

ity A

dditi

ons

(Bcf

/d)

Source: Bentek

Over 13.3 Bcf/d of pipeline capacity expansions in Appalachia between now and 2017 with even more projects currently in the planning phases

Typical Well Parameters (Based on 2012 Program) EUR: 14.1 Bcf

IP Rate: 17.4 Mmcfpd

Lateral Length: 4,100’

CABOT’S MARCELLUS ECONOMICS

Number of Stages Per Well: 18

Average Working Interest: 100%

Average Revenue Interest: 85%

70%

100%

130%

170%

80%

115%

150%

195%

50%

75%

100%

125%

150%

175%

200%

$3.00 $3.50 $4.00 $4.50

BTAX

%IR

R

Henry Hub ($ / Mmbtu)

$6.5 million D&C $6.0 million D&C

Typical Well IRR Sensitivity

EAGLE FORD SHALE

La SalleFrio Atascosa

McMullen

~20 milesPad B

• 6-well pad• Drilling• Average lateral

length over 8,000’

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: 56

Operated wells currently drilling / suspended: 6

Operated wells completing: 5

Average completed well cost: ~$6.5mm

– Multi-well pad drilling expected to reduce well costs by $500,000 - $600,000 per well

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

Pad A• 4-well pad• Completing• Lateral lengths

ranging from 5,200’ to 8,000’

3,000+ Locations in the Sweet Spot of the Marcellus Shale Implying 25+ Years of Inventory at Current Drilling Levels

Currently Producing 1.3 Bcf/d of Gross Marcellus Production From Only 8% of Our Identified Locations

Peer-Leading Rates of Return and EUR Per Lateral Foot in the Marcellus Shale

Industry-Leading Cost Structure Continuing to Improve Due to Efficiency Gains

SIMPLE GROWTH STORY

Best-In-Class Production and Cash Flow Per Share Growth While Generating Free Cash Flow

Thank youThe 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.