Cabot Oil & Gas

7/27/2019 Cabot Oil & Gas

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Investor PresentationEnerCom's

The Oil & Gas ConferenceDenver, CO

August 12, 2013


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Extensive Inventory ofLow-Risk, High-Return

Drilling Opportunities

Industry LeadingProduction and Reserve

Growth

Low Cost Structure

Strong Financial Positionand Financial Flexibili ty

Over 3,000 identified dri lling locations in the sweet spot o f the Marcellus Shale withrates of return that rival or exceed all of the top U.S. liquids plays at currentcommodity prices

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

Increased 2013 produ ction gu idance range from 35% - 50% to 44% - 54%

Midpoin t of 2013 guidance impl ies a three-year production CAGR of 45%

2012 proved reserve g rowth of 27% for a three-year reserve CAGR of 23%

Q2 2013 per unit cash cos ts1 of $1.36 per Mcfe

2012 all sources fin ding co sts o f $0.87 per Mcfe

2012 all sources Marcellus fi nding costs of $0.49 per Mcfe

$566 million of l iquid ity as o f 6/30/2013

Net debt t o adjus ted capitalization ratio of 32% as of 6/30/2013

Approximately 65% hedged at the midpoint o f 2013 production guidance

45 natural gas collar contracts fo r 2014 at a weighted average floor of $4.10 per Mcf

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

KEY INVESTMENT HIGHLIGHTS


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Marcellus Shale~200,000 net acresCurrent Rig Count: 6 (as of August 21, 2013)2013E Drilling Act ivity: ~100 net wells

Marmaton Penn Lime~70,000 net acres2013E Drilling Activi ty: ~10 net wells

Eagle Ford Shale / Pearsall Shale~62,000 net Eagle Ford acres~71,000 net Pearsall acresCurrent Rig Count: 22013E Drilli ng Activ ity: ~45 net wells

ASSET OVERVIEW

2012 Year-End Proved Reserves: 3.8 Tcfe

Q2 2013 Production: 1.046 Bcfe per day

2013E Drilling Activ ity: 155 165 net wells


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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


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?

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


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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

$/M

cfe

Al l-Sources F&D Costs

SUPERIOR RESERVE REPLACEMENT AND FINDING COSTS


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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


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

2013 Capital Program:$1.1 billion - $1.2 billion

Marcellus

63%

ProductionEquipment /

Other4%

Drilling83%

Land9%

Exploration4%

Other10%

Eagle Ford /Marmaton /

Pearsall30%

Marcellus

65%

Land5%

Drilling87%

ProductionEquipment /

Other5%

Exploration3%

Other5%

DISCIPLINED CAPITAL SPENDING FOCUSED ON THE DRILL-BIT

Eagle Ford /Marmaton /

Pearsall27%


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$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

$/Mcfe

Operating Transportation Taxes O/T Income G&A Financing

1Excludes stock-based compensation and pension termination expenses

INDUSTRY LEADING COST STRUCTURE


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$34mm$75mm

2014E Capital Expenditures Current Regular Dividend(Recently i ncreased by 100%

effective August 2013)

Estimated Capital Commitmentfor Constitution Pipeline

Implied 2014Free Cash Flow

2014E Cash Flow

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

Broker

EstimateRange:

$1,190mm

$1,548mm

Average:

$1,342mm

USE OF PROCEEDS FOR POTENTIAL FREE CASH FLOW IN 2014

Broker

Estimate

Range:

$1,477mm

$1,981mm

Average:

$1,729mm

Implied

Free Cash

Flow:$278mm

Acceleration of Marcellus Dri ll ing Program

Accelerat ion of Eagle Ford Dri ll ing ProgramDividend Policy(Increase Regular Dividend / Share

Buybacks / Special Dividend)

Average 2014 Henry Hu b /WTI Broker Estimates:

$4.01 per Mmbt u / $92.00 per Bbl

Pay Down Revolver Borrowings


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MARCELLUS SHALE


12/25Bare Earth LiDAR with Aerial photo , Townsh ip Lines, Cabot Wells and Acreage ~ 3 Miles

CABOT MARCELLUS SUMMARY

Reilly

PadZick 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


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EVOLUTION OF CABOTS MARCELLUS PROGRAM

0100200300400500600

700800900

1,0001,100

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

Mm

cfpd

Gross Marcellus Daily Produc tion

2010 2011 20122013 andbeyond

13% HBP Reduced stage spacing f rom

300 ft. to 250 ft. Divested midstream assets 44 produc ing Hz wells

29% HBP Drilling days reduced Reduced completion cost

per stage 107 produc ing 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% HBPby year-end 2013

Transition intodevelopment mode(improved efficiencies /reduced costs)

Addi tional test ing of Upper

Marcellus Addi tional downspac ing

testing


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2.1

2.7

3.43.8

4.1

0.00.51.01.52.02.53.03.5

4.04.5

2008 2009 2010 2011 2012

ThousandFt.

Horizontal Length

7.48.7

15.116.8 17.4

5.97.2

11.9 14.014.5

0.0

5.0

10.0

15.0

20.0

2008 2009 2010 2011 2012

Mmcfpd

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

S

tages

Average Number of Stages

5.0

7.8

11.2

13.214.1

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 40

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

CONTINUED PERFORMANCE IMPROVEMENTS IN THE MARCELLUS


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26

20

1614

0

10

20

30

2010 2011 2012 2013 YTD

Days

Drilling Days to TD

Record of8 days

$165$150

$105


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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 Different ial: 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%IRR

Henry Hub ($ / Mmbtu)

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

Typical Well IRR Sensitiv ity


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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


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NY

VT NH

PA

NJ

CT

MA

RI

Iroquois

Millennium

Springville

TGP 200 Line

Canada

Boston

Hartford

LongIsland

Laser

TGP 300 Line

Transco

Constitution

New YorkCity

Charlotte

INTERSTATE PIPELINE MARKETS

SusquehannaCounty

Current MarketsTennessee Gas Pipel ine (300)

Transco Gas PipelineMillennium Gas Pipeline

2015 Market Addit ionsIroquois Pipeline

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


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FIRM TRANSPORTATION AND LONG-TERM SALES CONTRACTS

Firm Transportation Contracts

2013 (current) 325 Mmcf per day

2014 (current / target) 325 Mmcf per day / 450 Mmcf per day

2015 (current / target)*** 875 Mmcf per day / 1 Bcf per day

Long-Term Sales Contracts (8-15 years in duration)

2013 (current) 325 Mmcf per day

2014 450 Mmcf per day

2015 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 fo rward as new opportun ities become available

***The increase from 2014 to 2015 includes 500 Mmcf/d of firm c apacity associated with Constitu tion Pipeline

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

Targeted firm transportation volumes are subject to clos ing on agreements COG is currently negotiating

100% of COGs volumes are gathered under a long-term fi rm agreement


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INFRASTRUCTURE UPDATE

Maximum Interstate Delivery Capacity

Note: Capacity volumes above are indicative deliverability estimates for facilities thatare in place or planned for those periods; these are not product ion estimates.

Compression, Dehydration & Measurement Capacity

Year-end 2013 2.2 Bcf per day




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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 pr icing are hedged through 2013

COG Unhedged Realized Marcellus Pricing

PeriodDifferential to NYMEX

($/Mcf)

Q1 2013 ($0.01)Q2 2013 $0.01

July 2013 ($0.15)

Estimated August December 2013 ($0.10 - $0.15)


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EAGLE FORD SHALE


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EAGLE FORD SHALE SUMMARY

~62,000 net acres

Current operated rig count: 2

Added a second r ig in late July that wil lfocus 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 dril ling expected to reducewell costs by $500,000 - $600,000 per well

400 down-spacing results continue to reinforcethe concept, resulting in ~500 identifiedundrilled locations remaining in COGs 100%owned and operated Buckhorn area

Recently completed an extended lateral well(8,000+) with a 24-hour peak rate of ~1,130Boepd and a 120-day rate of ~1,100 Boepd

15

109

0

5

10

15

2012 Q1 2013 Q2 2013

Day

s

Drilling Days to TD

650

900

450

570

0

250

500

750

1,000

Program Average Last 6 Wells

Boepd

Peak 24-Hour Rate and 30-Day Rate


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

at Current Drilling Levels

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

Our Identified Locations

Transit ioning From Acreage Capture toEfficient Pad Development in 2014

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

SIMPLE GROWTH STORY


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Thank youThe statements regarding future financial performance and results and the otherstatements which are not historical facts contained in this presentation are

forward-looking statements that involve risks and uncertainties, including, butnot limited to, market factors, the market price of natural gas and oil, results of

future drilling and marketing activity, future production and costs, and otherfactors detailed in the Companys Securities and Exchange Commission filings.

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Cabot Oil & Gas