Investor Presentation

EnerCom's The Oil & Gas ConferenceDenver, COAugust 12, 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 with rates of return that rival or exceed all of the top U.S. liquids plays at current commodity prices

– 25+ years of Marcellus inventory at current drilling levels– Oil-focused initiative in the Eagle Ford Shale

– Increased 2013 production guidance range from 35% - 50% to 44% - 54%

– Midpoint of 2013 guidance implies a three-year production CAGR of 45%

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

– Q2 2013 per unit cash costs1 of $1.36 per Mcfe

– 2012 all sources finding costs of $0.87 per Mcfe

– 2012 all sources Marcellus finding costs of $0.49 per Mcfe

– $566 million of liquidity as of 6/30/2013

– Net debt to adjusted capitalization ratio of 32% as of 6/30/2013

– Approximately 65% hedged at the midpoint of 2013 production guidance

– 45 natural gas collar contracts for 2014 at a weighted average floor of $4.10 per Mcf1Excludes 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 wells

Marmaton – Penn Lime~70,000 net acres2013E Drilling Activity: ~10 net wells

Eagle Ford Shale / Pearsall Shale~62,000 net Eagle Ford acres~71,000 net Pearsall acresCurrent Rig Count: 22013E Drilling Activity: ~45 net wells

ASSET OVERVIEW

2012 Year-End Proved Reserves: 3.8 TcfeQ2 2013 Production: 1.046 Bcfe per day2013E Drilling Activity: 155 – 165 net wells

130.6

187.5

267.7

0

50

100

150

200

250

300

350

400

2010 2011 2012 2013E

Bcfe

Liquids (Net)Gas (Net)

43.5%

42.8%

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

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

255%

603%

390% 417%

0%100%200%300%400%500%600%700%

2009 2010 2011 2012

Reserve Replacement Ratio

$2.26

$1.05 $1.21$0.87

$0.00

$1.00

$2.00

$3.00

2009 2010 2011 2012

$/Mcf

e

All-Sources F&D Costs

SUPERIOR RESERVE REPLACEMENT AND FINDING COSTS

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 includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC

2012 Capital Program: $979 million ($809 million net of JV and asset sales)

2013 Capital Program: $1.1 billion - $1.2 billion

Marcellus63%

Production Equipment /

Other 4%

Drilling83%

Land9%

Exploration4%

Other10%

Eagle Ford / Marmaton /

Pearsall30%

Marcellus65%

Land5%

Drilling87%

Production Equipment /

Other5%

Exploration3%

Other5%

DISCIPLINED CAPITAL SPENDING FOCUSED ON THE DRILL-BIT

Eagle Ford / Marmaton /

Pearsall27%

$0.91$0.76

$0.57$0.44 $0.30 –

$0.40

$0.13

$0.15$0.39

$0.54 $0.50 –$0.60

$0.43

$0.29 $0.15 $0.18 $0.10 –$0.20

$0.42

$0.40

$0.27 $0.25$0.15 –$0.20

$0.57

$0.52

$0.38 $0.26

$0.15 –$0.20

$2.47

$2.12

$1.76$1.67

$1.20 - $1.60

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

2009 2010 2011 2012 2013E

$ / M

cfe

Operating Transportation Taxes O/T Income G&A¹ Financing

1 Excludes stock-based compensation and pension termination expenses

INDUSTRY LEADING COST STRUCTURE

$34mm $75mm

2014E Capital Expenditures¹ Current Regular Dividend (Recently increased by 100%

effective August 2013)

Estimated Capital Commitment for Constitution Pipeline

Implied 2014 Free Cash Flow

2014E Cash Flow¹

1Based on broker consensus estimates as of August 7, 2013; cash flow estimates based on consensus cash flow per share estimates multiplied by current outstanding share count

BrokerEstimate Range:

$1,190mm –

$1,548mm

Average:$1,342mm

USE OF PROCEEDS FOR POTENTIAL FREE CASH FLOW IN 2014

BrokerEstimate Range:

$1,477mm–

$1,981mm

Average:$1,729mm

Implied Free Cash

Flow:$278mm

Acceleration of Marcellus Drilling Program

Acceleration of Eagle Ford Drilling ProgramDividend Policy(Increase Regular Dividend / Share

Buybacks / Special Dividend)

Average 2014 Henry Hub / WTI Broker Estimates:

$4.01 per Mmbtu / $92.00 per Bbl

Pay Down Revolver Borrowings

MARCELLUS SHALE

Bare Earth LiDAR with Aerial photo, Township Lines, Cabot Wells and Acreage ~ 3 Miles

CABOT MARCELLUS SUMMARY

Reilly Pad

Zick Pad

Completing: 14 wells (266 Stages)

Wells Producing: 226 H, 39 V

WOPL: 10 wells (245 Stages)

WOC: 15 wells (347 Stages)

Rig Count: 6 (as of August 21, 2013)

Cumulative Production

5-6 BCF

4-5 BCF

3-4 BCF

2-3 BCF

7-8 BCF

6-7 BCF

8+ BCF

2 wells (27 stages)IP rate: 34.8 Mmcf/d2 wells (37 stages)

IP rate: 51.2 Mmcf/d

EVOLUTION OF CABOT’S MARCELLUS PROGRAM

0100200300400500600700800900

1,0001,100

Dec-09 Dec-10 Dec-11 Dec-12

Mmcf

pd

Gross Marcellus Daily Production

2010 2011 2012 2013 and beyond

• 13% HBP• Reduced stage spacing from

300 ft. to 250 ft.• Divested midstream assets• 44 producing Hz wells

• 29% HBP• Drilling days reduced• Reduced completion cost

per stage• 107 producing Hz wells

• 43% HBP• Implemented 200 ft. stage

spacing• Tested Upper Marcellus• Tested downspacing• De-risked eastern edge of

our acreage position• 185 producing Hz wells

• Expected to be 60% HBP by year-end 2013

• Transition into development mode (improved efficiencies / reduced costs)

• Additional testing of Upper Marcellus

• Additional downspacing testing

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

26

2016

14

0

10

20

30

2010 2011 2012 2013 YTD

Days

Drilling Days to TD

Record of8 days

$165$150

$105<$90

$0

$50

$100

$150

$200

2010 2011 2012 2013 YTD

$000

s Per

Sta

ge

Completion Cost Per Stage1

MARCELLUS OPERATING EFFICIENCIES

1 Pressure pumping costs only

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

IP Rate: 17.4 Mmcfpd

Lateral Length: 4,100’

Number of Stages Per Well: 18

CABOT MARCELLUS ECONOMICS

Average Working Interest: 100%

Average Revenue Interest: 85%

Gas Price Differential: NYMEX less $0.05 per Mmbtu

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

Diversifying on Multiple Pipelines

Firm Transportation Arrangements

Long-Term Sales Agreements (Firm Sales)

Investing in New Pipeline Projects

COG MARCELLUS MARKETING STRATEGY

Opportunistic Hedging Program

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)

Transco Gas PipelineMillennium Gas Pipeline

2015 Market AdditionsIroquois Pipeline

Tennessee Gas Pipeline (200)TransCanada Pipeline (via Iroquois)

FIRM TRANSPORTATION AND LONG-TERM SALES CONTRACTS

Firm Transportation Contracts2013 (current) 325 Mmcf per day2014 (current / target) 325 Mmcf per day / 450 Mmcf per day2015 (current / target)*** 875 Mmcf per day / 1 Bcf per day

Long-Term Sales Contracts (8-15 years in duration)2013 (current) 325 Mmcf per day2014 450 Mmcf per day2015 615 Mmcf per day

– Long-term sales contracts include volumes COG moves under its customers’ firm capacity

– Long-term sales contract volumes will change going forward as new opportunities become available

***The increase from 2014 to 2015 includes 500 Mmcf/d of firm capacity associated with Constitution Pipeline

– Firm transportation contracts include volumes COG moves under its own firm capacity

– Targeted firm transportation volumes are subject to closing on agreements COG is currently negotiating

– 100% of COG’s volumes are gathered under a long-term firm agreement

INFRASTRUCTURE UPDATE

Maximum Interstate Delivery 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.

Compression, Dehydration & Measurement CapacityYear-end 2013 2.2 Bcf per dayYear-end 2014 3.4 Bcf per dayYear-end 2015 3.7 Bcf per day

2013 MARCELLUS SALES BY INDEX AND UNHEDGED REALIZED PRICING

COG 2013 Marcellus Sales By Index

Index% of COG 2013

Marcellus SalesNYMEX 65%Dominion Transmission*** 19%Columbia Gas Transmission 11%Other 5%***Approximately 70% of the volumes sold at Dominion Transmission pricing are hedged through 2013

COG Unhedged Realized Marcellus Pricing

PeriodDifferential to NYMEX

($/Mcf)Q1 2013 ($0.01)Q2 2013 $0.01July 2013 ($0.15)Estimated August – December 2013 ($0.10 - $0.15)

EAGLE FORD SHALE

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: 50

Operated wells currently drilling: 2

Operating wells completing: 2

Average completed well cost: ~$6.5mm

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

400’ down-spacing results continue to reinforce the concept, resulting in ~500 identified undrilled locations remaining in COG’s 100% owned and operated Buckhorn area

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

15

109

0

5

10

15

2012 Q1 2013 Q2 2013

Days

Drilling Days to TD

650

900

450570

0

250

500

750

1,000

Program Average Last 6 Wells

Boep

d

Peak 24-Hour Rate and 30-Day Rate

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

at Current Drilling Levels

Currently Producing 1.2 Bcf/d of Gross Marcellus Production From Only 8% of

Our Identified Locations

Transitioning From Acreage Capture toEfficient Pad Development in 2014

Cash Flow Neutral Investment Program in 2013While Growing Production 44% to 54%

SIMPLE GROWTH STORY

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.