Investor Presentation 

Howard Weil Energy ConferenceNew Orleans, LA

March 18, 2013March 18, 2013

Over 3 000 identified drilling locations in the sweet spot of the Marcellus Shale

KEY INVESTMENT HIGHLIGHTS

Extensive Inventory of Low-Risk, High-Return Drilling Opportunities

Extensive Inventory of Low-Risk, High-Return Drilling Opportunities

– 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

– Oil-focused initiatives in the Eagle Ford Shale, Marmaton oil play and Pearsall Shale g ppg pp

Industry Leading Production and Reserve

Industry Leading Production and Reserve

Shale

– Production growth of approximately 43% for the second consecutive year

– Midpoint of 2013 guidance implies a third consecutive year exceeding 40% Production and Reserve Growth

Production and Reserve Growth

p g p y gproduction growth

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

Low Cost StructureLow Cost Structure– 2012 all sources finding costs of $0.87 per Mcfe

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

– 2012 per unit cash costs1 of $1.67 per Mcfe

Strong Financial Position Strong Financial Position

p $ p

– $605 million of liquidity as of 12/31/2012

– Net debt to adjusted capitalization of 33% as of 12/31/2012Strong Financial Position and Financial Flexibility

Strong Financial Position and Financial Flexibility

Net debt to adjusted capitalization of 33% as of 12/31/2012

– Net debt to proved reserves of $0.27 per Mcfe as of 12/31/2012

– Approximately 53% hedged at the midpoint of 2013 production guidance1Excludes DD&A, exploration expense, stock-based compensation and pension termination expensesExcludes DD&A, exploration expense, stock based compensation and pension termination expenses

ASSET OVERVIEW

2012 Production: 267.7 Bcfe2012 Year-End Proved Reserves: 3.8 Tcfe

Marcellus Shale~200,000 net acres2012 Drilling Activity: 69.7 net wells 2012 Drilling Activity: 69.7 net wells Current Rig Count: 5

Marmaton – Penn Lime~70,000 net acres2012 Drilling Activity: 18.9 net wells Current Rig Count: 2Eagle Ford Shale / Pearsall Shale Current Rig Count: 2

~62,000 net Eagle Ford acres~71,000 net Pearsall acres2012 Drilling Activity: 25.8 net wellsCurrent Rig Count: 4

PROVEN TRACK RECORD OF PRODUCTION GROWTH…

350

400

267.7300

350

187.5200

250

Bcfe

Li id (N t)

2013 Guidance:35% - 50%

130.6150

Liquids (Net)Gas (Net)

43.5%

42.8%

50

10043.5%

02010 2011 2012 2013E

…AND RESERVE GROWTH

?4.5

3 0

3.8

3.5

4.0

2.7

3.0

2.5

3.0

cfe

12.3%

26.7%

2.1

1.5

2.0

Tc Liquids (Net)Gas (Net)31.1%

0.5

1.0

0.02009 2010 2011 2012 2013E

POSITIVE RESERVE REVISIONS DESPITE LOW NATURAL GAS PRICES

3,842927370

(115) (67) (38)(268)

3,033

(268)

cfe

Bc

Year-End 2011 Proved

Reserves

Additions Performance Revisions

Pricing Revisions

Deletions¹ Sales Production Year-End 2012 Proved

Reserves

1Deletions associated with the 5-year PUD rule, primarily in East Texas

96% Gas59% PD16.2 R/P

96% Gas60% PD14.4 R/P

e et o s assoc ated t t e 5 yea U u e, p a y ast e as

SUPERIOR RESERVE REPLACEMENT AND FINDING COSTS

443%

603%

390% 417%500%600%700%

Reserve Replacement Ratio

255%

390%

100%200%300%400%

0%100%

2008 2009 2010 2011 2012

$3.42

$3.00

$4.00All-Sources F&D Costs

$2.26

$1.05 $1.21$0.87$1.00

$2.00

$/Mcf

e

$0.002008 2009 2010 2011 2012

Production Per Debt-Adjusted Share CAGR (2010 – 2012)

PEER LEADING PRODUCTION AND RESERVE GROWTH

42%

30%26% 24% 22%

17% 16% 15%

Production Per Debt-Adjusted Share CAGR (2010 – 2012)

17% 16% 15%8% 8%

2%

(0%) (2%) (3%)

Peer median: 11%

(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

R P D bt Adj t d Sh CAGR (2010 2012)18% 17% 15%

9%5% 4% 2%

Reserves Per Debt-Adjusted Share CAGR (2010 – 2012)

Peer median: (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

Source: Cabot Oil & Gas, company filingsPeer group includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XECPeer group includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC

2012 Capital Program: $979 million 2013 Capital Program:

DISCIPLINED CAPITAL SPENDING FOCUSED ON THE DRILL-BIT2012 Capital Program: $979 million

($809 million net of JV and asset sales)2013 Capital Program:

$950 million - $1.025 billionOther10%

Eagle Ford /

Other5%

Eagle Ford / Marmaton /

Pearsall30%

Eagle Ford / Marmaton /

Pearsall27%

Marcellus63%

Marcellus65%

Production Equipment /

Other 4%

Land

Exploration4%

Land6%Production

Equipment / Other

Exploration3%

Land9%

Other6%

Drilling83%

Drilling85%

Operating Transportation Taxes O/T Income G&A¹ Financing

INDUSTRY LEADING COST STRUCTURE

$2.47$2.50

$0.57

$0.52

$2.12

$1.76$1 67

$2.00

$0 43

$0.42

$0.40

$0 27 $0.25$0 15

$0.38 $0.26$0.20 –$0.25

$1.67

$1.30 - $1.70$1.50

/ Mcf

e

$0.13

$0.15$0.39 $0 50

$0.43

$0.29 $0.15 $0.18 $0.10 –$0.20

$0.27 $0.15 –$0.20

$1.00

$

$0.91$0.76

$0.57$0 44 $0 35 –

$0 39$0.54 $0.50 –

$0.60

$0.50

$0.44 $0.35 –$0.45

$0.002009 2010 2011 2012 2013E

1 Excludes stock-based compensation and pension termination expensesp p p

USE OF PROCEEDS FOR POTENTIAL FREE CASH FLOW IN 2014

$17mm $75mm

BrokerEstimate

BrokerEstimate Range:

$1,361mm–

Implied Free Cash Estimate

Range:$900mm –$1,250mm

Median:

–$1,894mm

Median:$1 579mm

Flow Median:$376mm

2014E Capital Expenditures¹ Current Regular Dividend Estimated Capital Commitment for Constitution

Pipeline

Implied 2014 Free Cash Flow 2014E Cash Flow¹

Median:$1,111mm

$1,579mm

Median 2014 Henry Hub / WTI Broker Estimates:

$4 00 M bt / $92 02 Bblp

Acceleration of Marcellus Drilling Program

$4.00 per Mmbtu / $92.02 per Bbl

g g

P D R l B i P D R l B i Dividend Policy

(S i l Di id d / I R l Dividend Policy

(S i l Di id d / I R l

1Based on broker consensus estimates as of March 4, 2013; cash flow estimates based on consensus cash flow per share estimates multiplied by current outstanding share count

Pay Down Revolver Borrowings Pay Down Revolver Borrowings (Special Dividend / Increase Regular Dividend / Share Buybacks)

(Special Dividend / Increase Regular Dividend / Share Buybacks)

Based on broker consensus estimates as of March 4, 2013; cash flow estimates based on consensus cash flow per share estimates multiplied by current outstanding share count

Wells Producing: 197 H 39 V

CABOT MARCELLUS SUMMARY

Wells Producing: 197 H, 39 VWOPL: 14 wells (235 Stages)

Completing: 8 wells (179 Stages)Completing: 8 wells (179 Stages)WOC: 11 wells (204 Stages)

Horizontal Rigs: 5Horizontal Rigs: 5

Cumulative Production

7+ BCFReilly Pad

5-6 BCF

4 5 BCF

6-7 BCFZick Pad

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

4-5 BCF

3-4 BCF

2-3 BCF

EVOLUTION OF CABOT’S MARCELLUS PROGRAM

20102010 20112011 20122012 2013 and beyond

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

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

• Transition into development mode (improved efficiencies / • 44 producing Hz wells • 107 producing Hz wells • Tested downspacing

• De-risked eastern edge of our acreage position

• 185 producing Hz wells• Record gross production of

1 038 Bcf per day

(improved efficiencies / reduced costs)

• Additional testing of Upper Marcellus

• Additional downspacing testing

9001,0001,100 Gross Marcellus Daily Production

1.038 Bcf per day testing

300400500600700800

Mmcf

pd

0100200300

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

Horizontal Length Average IP and 30-Day Rate

CONTINUED PERFORMANCE IMPROVEMENTS IN THE MARCELLUS

2.73.4

3.8 4.1

3 03.54.04.5

d Ft

.

Horizontal Length

15.116.8 17.4

11 914.0 14.515.0

20.0

d

Average IP and 30 Day Rate

2.1

0 51.01.52.02.53.0

Thou

sand

7.4 8.75.9 7.2

11.9

5.0

10.0

Mmcf

pd

0.00.5

2008 2009 2010 2011 20120.0

2008 2009 2010 2011 2012

Average Number of Stages EUR

13.415.6

17.7

15.0

20.0

s

Average Number of Stages

11.213.2 14.1

10 0

15.0

EUR

4.6

8.5

5.0

10.0

Stag

es

5.0

7.8

5.0

10.0

Bcf

0.02008 2009 2010 2011 2012

0.02008 2009 2010 2011 2012

Number of wells: 2008 - 5, 2009 - 29, 2010 - 55, 2011 – 40, 2012 – 40Note: Data excludes wells drilled in the northern portion of our acreage positionNote: Data excludes wells drilled in the northern portion of our acreage position

Drilling Days to TD

MARCELLUS OPERATING EFFICIENCIES

322630

40

Drilling Days to TD

2016

10

20Days

Record of

02009 2010 2011 2012

Record of 10 days

$180$165

$150$150

$200

ge

Completion Cost Per Stage

$105

$50

$100

$150

00s P

er S

tag

$0

$50

2009 2010 2011 2012

$0

EVOLUTION OF MARCELLUS FRAC STAGE SPACING

50 ft125 ft.

Composite Bridge Plug

2 ft. perf cluster 6 SPF(Shots per foot)

50 ft.

Avg. Lateral Length 3,500 ft.Avg. Number Stages 10Avg. EUR 8.0 Bcf

(Shots per foot)

350 ft. Spacing

75 ft. 50 ft.

Avg. Lateral Length 3,500 ft.Avg. Number Stages 14Avg EUR 11 2 Bcf

250 ft. Spacing

Avg. EUR 11.2 Bcf

50 ft. 50 ft.

Avg. Lateral Length 3,500 ft.Avg. Number Stages 17-18A EUR 14 0 B f

200 ft. Spacing

Avg. EUR 14.0 Bcf

p g

CABOT HAD 15 OF THE TOP 20 PA MARCELLUS HORIZONTAL WELLS IN 2012

7.0

8.0 Cabot is the only publicly-traded company in the top 20!

5 0

6.0

n (B

cf)

4.0

5.0

ve P

rodu

ctio

n

2.0

3.0

Cum

ulat

iv

1.0

0

0.0PEER

#1PEER

#1COG COG COG COG COG COG COG PEER

#1PEER

#1COG COG COG COG COG COG COG COG PEER

#1

2013 Planned Activities2012 Program Highlights

MARCELLUS PROGRAM OVERVIEW AND ECONOMICS

2013 Planned Activities Operate 5 rigs for the majority of the year

Expect to spud ~85 wells

2013 program will average slightly longer lateral lengths

2012 Program Highlights 69.7 net wells drilled

6 wells turned in line with an EUR over 20 Bcf

Fastest well to 5 Bcf of cumulative production: 2013 program will average slightly longer lateral lengths than the 2012 program

Entire 2013 program will utilize 200’ frac stage spacing

Continue to focus on operational efficiencies to further

Fastest well to 5 Bcf of cumulative production: accomplished in 205 days

4 wells turned in line reached 1 Bcf of cumulative production in 40 days or less

improve well economics 5 wells turned in line in with a peak 24-hour production rate over 30 Mmcf per day

4 wells achieved spud to TD in 10 days

130%125%

150%

Typical Well Parameters (Based on 2012 Program) EUR: 14 Bcf

IP Rate: 17.3 Mmcfpd

Typical Well IRR Sensitivity

70%

100%

75%

100%

125%

BTAX

%IR

R Lateral Length: 4,100’

Number of Stages Per Well: 18

Total D&C: $6.5 million

50%

75%

$3.00 $3.50 $4.00 Henry Hub $ / Mmbtu

Average Working Interest: 100%

Average Revenue Interest: 85%

Gas Price Differential: NYMEX less $0.05 per Mmbtu

Current2 well pad

Hypothetical 10 well pad

HYPOTHETICAL 10-WELL PAD WITH 160+ POTENTIAL STAGES

2-well pad 10-well padLocation & road costs / well $200,000 $40,000Rig mobilization / well $175,000 $35,000Frac mobilization / well $110,000 $22,000

1,000 ft

Idle move day rig costs / well $225,000 $85,000Total $710,000 $182,000

Cost savings / well $(relative to 2-well pad) $528,000

500 ft

N 1,000 ft.

2013 Ri ht f d it ti ll l t

GROWING CAPACITY IN THE MARCELLUS

Compression and

Compression and

– 2013 program: Right-of-ways and permits essentially complete– 2014 program: Right-of-ways essentially complete and permitting on schedule– Exit rate gathering / dehydration capacity:

– 2012: 1.4 Bcf per dayDehydrationDehydration

2012: 1.4 Bcf per day– 2013E: 2.0 Bcf per day– 2014E: 2.9 Bcf per day

C t M k t

Takeaway and

Takeaway and

– Current Markets:– Tennessee Gas Pipeline – 300 Line: OH, PA, NY, NJ, CT– Transco Pipeline – Liedy System: PA, NY, NJ, DC, MD– Millennium Pipeline: NY, NJ, RI, CT

Markets Markets Millennium Pipeline: NY, NJ, RI, CT

– Planned Markets – March 2015:– Tennessee Gas Pipeline – 200 Line: MA– Iroquois Pipeline Zones 1 & 2: NY, CT, Canada

Firm Transportationand

Firm Transportationand

– Evaluate all opportunities for participation in expansion projects– Firm Transportation:

C t 300 M f dandFirm Sales

andFirm Sales

– Current: 300 Mmcf per day– March 2015: 850 Mmcf per day

– Firm Sales: 400 Mmcf per day

EAGLE FORD AND PEARSALL

S A t iAustin Chalk

PowderhornPresidio

targetSan Antonio

Eagle Ford

Buda

BuckhornGeorgetown Del Rio Shale

Edwards

Glen Rose

Upper Bexar Lower BexarCow Creek (James)Pearsall

targettarget Net acres

Rodessa

Pine Island ShaleCow Creek (James)

Sligo

Net acresEagle Ford: ~62,000Pearsall: ~71,000

target

EAGLE FORD - BUCKHORN

All W ll D i R ltAll Wells

Wells Drilled: 44Average 30-

Day RateEUR / Lateral

Foot

Down-spacing Results

Wells Drilled: 44

Current Drilling: 1

Wells Producing: 41 1 200’

Spacing

Day Rate FootStages (Boepd) (Boe)

Well A 23 766 79g

Completing / Waiting on Completion 3

Avg 24 Hour IP: (Plant yield of 90 Bbl Ngl / mmcf) ~650 Boepd

1,200Well B 25 492 60

Well C 20 790 80(Plant yield of 90 Bbl Ngl / mmcf) p

Avg 30 day rate: ~440 Boepd

Avg completed lateral length: ~5 000 Ft

400’Well D 20 493 56

Well E 16 410 76Avg completed lateral length: 5,000 Ft.

EUR Range all wells: 380-550 Mboe 400’

Well E 16 410 76

Well F 17 437 72

Down-spacing increases total mapped locations in our Buckhorn area to over 550 locations, doubling our

potential recoverable reserves in the area

Down-spacing increases total mapped locations in our Buckhorn area to over 550 locations, doubling our

potential recoverable reserves in the area

PEARSALL SHALE

30-day average production rate: 631 Boepd~56% oil

4 Pearsall wells with 30+ days of production Wells Drilled: 9

Current Drilling: 3~56% oilDrilling days: 40-45 days spud to spud Average CWC (including science): ~$10.0MM

Wells Producing / Flowing Back 5

Completing / WOC / WOPL 4

Estimated 2013 Gross Well Count 15Estimated 2013 Gross Well Count 15

20

N S

PearsallRodessa

~20 miles

Consistent Pearsall section across COG acreage position

Sligo

Pearsall

La SalleAtascosaFrioMcMullen

g p

~71,000 Net Acres

PENN LIME – MARMATON

Extended Reach Laterals

– 4 extended reach lateral wells drilled to date with 3 wells currently producing

– Average lateral length: ~9,300’

– Average frac stages per well: 30

– Average EUR: 230 Mboe BeaverTexas

BeaverN

g

– Average IP rate: 792 Boepd

– ~90% oil

$4 3MM $4 5MM ti t d CWCPerryton

.

TXOK

– $4.3MM - $4.5MM estimated CWC

COG Operated Wells

OchiltreeLipscomb

Hansford

0 4 8 mi

S

– 24 producing wells

– 4 wells drilling / waiting on completion ~70,000 Net Acres

U.S. NATURAL GAS DEMAND DRIVERS CONTINUE TO LOOK FAVORABLE…

O 45 i tt f l fi d ti it i ti t d t b ti d b t 2012 d 2016Over 45 gigawatts of coal-fired generating capacity is estimated to be retired between 2012 and 2016...

10 9

22.4

15.020.025.0

watts

8.2

1.4 2.7

10.9

0.05.0

10.0

2012 2013 2014 2015 2016

Giga

w

2012 2013 2014 2015 2016

…with a potential for over 48 gigawatts of capacity from gas-fired generation newbuilds coming online during the same time period

10 5 10.9 10 2

15.0 Under Construction Proposed

Source: EIA Annual Energy Outlook 2013 Early Release Reference case

8.5 8.810.5 10.2

0 0

5.0

10.0

Giga

watts

0.02012 2013 2014 2015 2016

Potential for incremental industrial demand of 3.3 Bcf/d by 2019 from new ethylene crackers, methanol and fertilizer plants, and gas-to-liquids projectsSource: BENTEK Energy, “Power Jump-Starts New Gas Market Cycle”

0 71.3

1.62.3

3.3

1 0

2.0

3.0

4.0

Bcf /

d

0.1 0.20.7

0.0

1.0

2013 2014 2015 2016 2017 2018 2019Source: Companies data, Morgan Stanley Commodities Research estimates

N i li t i M i ld t ti ll dd 5 1 B f/d f i t l t it b 2016

…RESULTING IN A POSITIVE OUTLOOK FOR LONG-TERM DEMAND

New pipeline systems in Mexico could potentially add 5.1 Bcf/d of incremental export capacity by 2016

2 73.7

5.1

4.0

6.0

d

0.9

2.7

0.0

2.0

2013 2014 2015 2016

Bcf /

d

2013 2014 2015 2016

Over 24 Bcf/d of proposed/potential U.S. LNG export facilities are currently approved or pending approval

2 8 2 63.4

3 0

4.0

Source: Company reports and presentations

2.8 2.6 2.4 2.1 1.8 1.7 1.5 1.4 1.3 1.3 1.10.8

0 0

1.0

2.0

3.0

Bcf /

d

0.0Gulf Coast Golden Pass Lake Charles Cheniere -

Corpus ChristiFreeport LNG Cameron LNG Gulf LNG Excelerate Oregon LNG Sabine Pass Pangea LNG Cove Point Others

Increased demand for natural gas in transportation could reach 3.6 Bcf/d by 2020 as natural gas vehicles penetrate heavy use end marketsSource: FERC Office of Energy Projects (as of March 11, 2013)

0.81.3

1.92.7

3.6

1 0

2.0

3.0

4.0

Bcf /

d

0.2 0.3 0.50.8

0.0

1.0

2013 2014 2015 2016 2017 2018 2019 2020Source: Credit Suisse Equity Research estimates

INVESTMENT SUMMARY

Simple Growth StorySimple Growth Story

3,000+ Remaining Locations in the 3,000+ Remaining Locations in the 3,000+ Remaining Locations in the Sweet Spot of the Marcellus Shale3,000+ Remaining Locations in the Sweet Spot of the Marcellus Shale

Transitioning from Acreage Capture toEfficient Pad Development by 2014

Transitioning from Acreage Capture toEfficient Pad Development by 2014p yp y

Cash Flow Positive Investment Program in 2013Cash Flow Positive Investment Program in 2013Cash Flow Positive Investment Program in 2013($3.50 per Mmbtu and $90 per barrel)

Cash Flow Positive Investment Program in 2013($3.50 per Mmbtu and $90 per barrel)

Thank youThank youThe statements regarding future financial performance and results and the otherThe 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 f d illi d k i i i f d i d d hfuture drilling and marketing activity, future production and costs, and other factors detailed in the Company’s Securities and Exchange Commission filings.