A presentation made at the Howard Weil Energy Conference in New Orleans, LA on March 18, 2013 by Cabot Oil & Gas. The presentation contains important information about their drilling cost structure--showing they have some of the lowest shale drilling costs in the industry.

1. Investor Presentation
Howard Weil Energy Conference
New Orleans, LA
March 18, 2013

2. KEY INVESTMENT HIGHLIGHTS
– Over 3 000 identified drilling locations in the sweet spot of the Marcellus Shale
3,000
Extensive Inventory of with rates of return that rival or exceed all of the top U.S. liquids plays at current
commodity prices
Low-Risk, High-Return
– Oil-focused initiatives in the Eagle Ford Shale, Marmaton oil play and Pearsall
Drilling Opportunities
g pp Shale
– Production growth of approximately 43% for the second consecutive year
Industry Leading
– Midpoint of 2013 guidance implies a third consecutive year exceeding 40%
p g p y g
Production and Reserve production growth
Growth – 2012 proved reserve growth of 27% for a three-year reserve CAGR of 23%
– 2012 all sources finding costs of $0.87 per Mcfe
Low Cost Structure – 2012 all sources Marcellus finding costs of $0.49 per Mcfe
– 2012 per unit cash costs1 of $1.67 p Mcfe
p $ per
– $605 million of liquidity as of 12/31/2012
Strong Financial Position – Net debt to adjusted capitalization of 33% as of 12/31/2012
and Financial Flexibility – Net debt to proved reserves of $0.27 per Mcfe as of 12/31/2012
– Approximately 53% hedged at the midpoint of 2013 production guidance
1Excludes DD&A, exploration expense, stock-based compensation and pension termination expenses
stock based

3. ASSET OVERVIEW
2012 Production: 267.7 Bcfe
2012 Year-End Proved Reserves: 3.8 Tcfe
Marcellus Shale
~200,000 net acres
2012 Drilling Activity: 69.7 net wells
Current Rig Count: 5
Marmaton – Penn Lime
~70,000 net acres
2012 Drilling Activity: 18.9 net wells
Eagle Ford Shale / Pearsall Shale Current Rig Count: 2
~62,000 net Eagle Ford acres
~71,000 net Pearsall acres
2012 Drilling Activity: 25.8 net wells
Current Rig Count: 4

4. PROVEN TRACK RECORD OF PRODUCTION GROWTH…
400
350
300
267.7
2013
Bcfe
250
Guidance:
35% - 50%
200 187.5
Liquids (N t)
Li id (Net)
42.8%
Gas (Net)
150 130.6
43.5%
100
50
0
2010 2011 2012 2013E

5. …AND RESERVE GROWTH
?
4.5
4.0 3.8
3.5
3.0
30
3.0
2.7 26.7%
2.5 12.3%
cfe
2.1 Liquids (Net)
Tc
2.0
31.1% Gas (Net)
1.5
1.0
0.5
0.0
2009 2010 2011 2012 2013E

6. POSITIVE RESERVE REVISIONS DESPITE LOW NATURAL GAS PRICES
370
927 (115) (67) (38) 3,842
(268)
3,033
cfe
Bc
Year-End 2011 Additions Performance Pricing Deletions¹ Sales Production Year-End 2012
Proved Revisions Revisions Proved
Reserves Reserves
96% Gas 96% Gas
59% PD 60% PD
16.2 R/P 14.4 R/P
1Deletions
e et o s assoc ated with t e 5 yea PUD rule, p a y in East Texas
associated t the 5-year U u e, primarily ast e as

7. SUPERIOR RESERVE REPLACEMENT AND FINDING COSTS
Reserve Replacement Ratio
700%
603%
600%
500% 443% 417%
390%
400%
300% 255%
200%
100%
0%
2008 2009 2010 2011 2012
All-Sources F&D Costs
$4.00
$3.42
$3.00
$2.26
$/Mcfe
$2.00
$1.05 $1.21
$0.87
$1.00
$0.00
2008 2009 2010 2011 2012

8. PEER LEADING PRODUCTION AND RESERVE GROWTH
Production Per Debt-Adjusted Share CAGR (2010 – 2012)
42%
30%
26% 24% 22%
17% 16% 15%
Peer median: 11%
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
Reserves Per Debt-Adjusted Sh CAGR (2010 – 2012)
R P D bt Adj t d Share
18% 17% 15%
9%
5% 4% 2% 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 filings
Peer group includes: CXO, EQT, KWK, NBL, NFX, PXD, QEP, RRC, SM, SWN, UPL, WPX, XCO and XEC

9. DISCIPLINED CAPITAL SPENDING FOCUSED ON THE DRILL-BIT
2012 Capital Program: $979 million 2013 Capital Program:
($809 million net of JV and asset sales) $950 million - $1.025 billion
Other Other
10% 5%
Eagle Ford /
Marmaton /
Eagle Ford / Pearsall
Marmaton / 30%
Pearsall
27%
Marcellus Marcellus
63% 65%
Production
Equipment / Exploration Land Exploration
Other 4% Production 6% 3%
4% Equipment /
Land Other
9% 6%
Drilling Drilling
83% 85%

10. INDUSTRY LEADING COST STRUCTURE
Operating Transportation Taxes O/T Income G&A¹ Financing
$2.47
$2.50
$0.57 $2.12
$2.00
$0.52 $1.76
$1.67
$1 67
$0.42
$0.38 $0.26 $1.30 - $1.70
$1.50
$ / Mcfe
$0.40 $0.20 –
$0.25
$0.43
$0 43 $0.25
$0.27
$0 27 $0.15
$0 15 –
$0.20
$0.29 $0.15 $0.18 $0.10 –
$1.00 $0.13 $0.20
$0.15
$0 39
$0.39
$0.54 $0.50
$0 50 –
$0.60
$0.50 $0.91
$0.76
$0.57
$0.44
$0 44 $0.35
$0 35 –
$0.45
$0.00
2009 2010 2011 2012 2013E
1 Excludes stock-based compensation and p
p pension termination expenses
p

11. USE OF PROCEEDS FOR POTENTIAL FREE CASH FLOW IN 2014
Broker
$75mm Estimate
$17mm
Range:
Broker Implied
$1,361mm
Estimate Free Cash
–
Range: Flow
$1,894mm
$900mm – Median:
$1,250mm $376mm
Median:
Median: $1,579mm
$1 579mm
$1,111mm
2014E Capital Expenditures¹ Current Regular Dividend Estimated Capital Implied 2014 Free Cash Flow 2014E Cash Flow¹
Commitment for Constitution Median 2014 Henry Hub /
WTI Broker Estimates:
p
Pipeline
$4.00
$4 00 per Mmbtu / $92.02 per Bbl
M bt $92 02
Acceleration of Marcellus Drilling Program
g g
Dividend Policy
(Special Di id d I
(S i l Dividend / Increase Regular
R l Pay D
P Down Revolver Borrowings
R l B i
Dividend / Share Buybacks)
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

13. CABOT MARCELLUS SUMMARY
Wells Producing: 197 H 39 V
H,
WOPL: 14 wells (235 Stages)
Completing: 8 wells (179 Stages)
WOC: 11 wells (204 Stages)
Horizontal Rigs: 5
Cumulative
Production
7+ BCF
Reilly
Pad
6-7 BCF
Zick Pad
5-6 BCF
4-5
4 5 BCF
3-4 BCF
2-3 BCF ~ 3 Miles
Bare Earth LiDAR with Aerial photo, Township Lines, Cabot Wells and Acreage

14. EVOLUTION OF CABOT’S MARCELLUS PROGRAM
2013 and
2010 2011 2012
beyond
• 13% HBP • 29% HBP • 43% HBP • Expected to be 60% HBP
• Reduced stage spacing from • Drilling days reduced • Implemented 200 ft. stage by year-end 2013
300 ft. to 250 ft. • Reduced completion cost spacing • Transition into
• Divested midstream assets per stage • Tested Upper Marcellus development mode
• 44 producing Hz wells • 107 producing Hz wells • Tested downspacing (improved efficiencies /
• De-risked eastern edge of reduced costs)
our acreage position • Additional testing of Upper
• 185 producing Hz wells Marcellus
• Record gross production of • Additional downspacing
1.038
1 038 Bcf per day testing
1,100 Gross Marcellus Daily Production
1,000
900
800
Mmcfpd
700
600
500
400
300
200
100
0
Dec-09 Dec-10 Dec-11 Dec-12

15. CONTINUED PERFORMANCE IMPROVEMENTS IN THE MARCELLUS
Horizontal Length Average IP and 30-Day Rate
30 Day
4.5 4.1 20.0
3.8 16.8 17.4
4.0 3.4 15.1 14.5
3.5 15.0 14.0
Thousand Ft.
3.0
30 2.7 11.9
11 9
Mmcfpd
d
d
2.5 2.1 8.7
10.0
2.0 7.4 7.2
1.5 5.9
1.0 5.0
0.5
05
0.0 0.0
2008 2009 2010 2011 2012 2008 2009 2010 2011 2012
Average Number of Stages EUR
20.0 15.0 14.1
17.7 13.2
15.6 11.2
15.0 13.4
10.0
10 0
Stages
s
7.8
Bcf
10.0 8.5
5.0
4.6 5.0
5.0
0.0 0.0
2008 2009 2010 2011 2012 2008 2009 2010 2011 2012
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

16. MARCELLUS OPERATING EFFICIENCIES
Drilling Days to TD
40
32
30 26
Days
20
20 16
10
Record of
10 days
0
2009 2010 2011 2012
Completion Cost Per Stage
$200 $180
$165
$150
ge
$150
$000s Per Stag
$105
$100
$50
$0
2009 2010 2011 2012

17. EVOLUTION OF MARCELLUS FRAC STAGE SPACING
125 ft. 50 ft
ft.
Composite Bridge Plug Avg. Lateral Length 3,500 ft.
Avg. Number Stages 10
2 ft. perf cluster 6 SPF Avg. EUR 8.0 Bcf
(Shots per foot)
350 ft. Spacing
75 ft. 50 ft.
Avg. Lateral Length 3,500 ft.
Avg. Number Stages 14
Avg.
Avg EUR 11.2
11 2 Bcf
250 ft. Spacing
50 ft. 50 ft.
Avg. Lateral Length 3,500 ft.
Avg. Number Stages 17-18
Avg.
A EUR 14.0 Bcf
14 0 B f
200 ft. Spacing
p g

18. CABOT HAD 15 OF THE TOP 20 PA MARCELLUS HORIZONTAL
WELLS IN 2012
8.0
Cabot is the only publicly-traded company in the top 20!
7.0
6.0
Cumulativ Production (Bcf)
5.0
50
n
4.0
ve
3.0
2.0
0
1.0
0.0
PEER PEER COG COG COG COG COG COG COG PEER PEER COG COG COG COG COG COG COG COG PEER
#1 #1 #1 #1 #1

19. MARCELLUS PROGRAM OVERVIEW AND ECONOMICS
2012 Program Highlights 2013 Planned Activities
 69.7 net wells drilled  Operate 5 rigs for the majority of the year
 6 wells turned in line with an EUR over 20 Bcf  Expect to spud ~85 wells
 Fastest well to 5 Bcf of cumulative production:  2013 program will average slightly longer lateral lengths
accomplished in 205 days than the 2012 program
 4 wells turned in line reached 1 Bcf of cumulative  Entire 2013 program will utilize 200’ frac stage spacing
production in 40 days or less
 Continue to focus on operational efficiencies to further
 5 wells turned in line in with a peak 24-hour production improve well economics
rate over 30 Mmcf per day
 4 wells achieved spud to TD in 10 days
Typical Well Parameters (Based on 2012 Program) Typical Well IRR Sensitivity
 EUR: 14 Bcf 150%
130%
 IP Rate: 17.3 Mmcfpd
125%
 Lateral Length: 4,100’
BTAX %IRR
100%
 Number of Stages Per Well: 18 100%
 Total D&C: $6.5 million 70%
75%
 Average Working Interest: 100%
 Average Revenue Interest: 85% 50%
$3.00 $3.50 $4.00
 Gas Price Differential: NYMEX less $0.05 per Mmbtu Henry Hub $ / Mmbtu

20. HYPOTHETICAL 10-WELL PAD WITH 160+ POTENTIAL STAGES
Current Hypothetical
2-well
2 well pad 10 well pad
10-well
Location & road costs / well $200,000 $40,000
Rig mobilization / well $175,000 $35,000
Frac mobilization / well $110,000 $22,000
Idle move day rig costs / well $225,000 $85,000
Total $710,000 $182,000
1,000 ft Cost savings / well
(relative to 2-well pad) $528,000
$
500 ft
N 1,000 ft.

21. GROWING CAPACITY IN THE MARCELLUS
– 2013 program: Right-of-ways and permits essentially complete
Ri ht f d it ti ll l t
Compression – 2014 program: Right-of-ways essentially complete and permitting on schedule
– Exit rate gathering / dehydration capacity:
and – 2012: 1.4 Bcf per day
Dehydration – 2013E: 2.0 Bcf per day
– 2014E: 2.9 Bcf per day
– C
Current Markets:
tM k t
– Tennessee Gas Pipeline – 300 Line: OH, PA, NY, NJ, CT
Takeaway – Transco Pipeline – Liedy System: PA, NY, NJ, DC, MD
and – Millennium Pipeline: NY, NJ, RI, CT
Markets – Planned Markets – March 2015:
– Tennessee Gas Pipeline – 200 Line: MA
– Iroquois Pipeline Zones 1 & 2: NY, CT, Canada
– Evaluate all opportunities for participation in expansion projects
Firm Transportation – Firm Transportation:
and – C
Current: 300 Mmcf per d
t M f day
Firm Sales – March 2015: 850 Mmcf per day
– Firm Sales: 400 Mmcf per day

23. EAGLE FORD AND PEARSALL
Austin Chalk
San A t i
S Antonio
target
Eagle Ford Powderhorn
Presidio
Buda
Del Rio Shale Buckhorn
Georgetown
Edwards
Glen Rose
Rodessa
Upper Bexar
Lower Bexar target
Pearsall target
Cow Creek (James) Net acres
Pine Island Shale target
Eagle Ford: ~62,000
Sligo Pearsall: ~71,000

24. EAGLE FORD - BUCKHORN
All W ll
Wells Down-spacing R lt
D i Results
Average 30- EUR / Lateral
Wells Drilled: 44 Day Rate Foot
Stages (Boepd) (Boe)
Current Drilling: 1 Spacing
Well A 23 766 79
g
Wells Producing: 41 1,200
1 200’
Completing / Waiting on Well B 25 492 60
3
Completion
Avg 24 Hour IP: ~650 Boepd
p Well C 20 790 80
(Plant yield of 90 Bbl Ngl / mmcf)
400’
Avg 30 day rate: ~440 Boepd Well D 20 493 56
Avg completed lateral length: ~5 000 Ft
5,000 Ft. Well E 16 410 76
400’
EUR Range all wells: 380-550 Mboe 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

25. PEARSALL SHALE
4 Pearsall wells with 30+ days of production Wells Drilled: 9
30-day average production rate: 631 Boepd
Current Drilling: 3
~56% oil
Wells Producing / Flowing Back 5
Drilling days: 40-45 days spud to spud
Average CWC (including science): ~$10.0MM Completing / WOC / WOPL 4
Estimated 2013 Gross Well Count 15
N S
Rodessa
~20
20 Pearsall
miles
Sligo
Consistent Pearsall section across COG acreage position
g p
Frio Atascosa
La Salle McMullen
~71,000 Net Acres

26. PENN LIME – MARMATON
 Extended Reach Laterals
– 4 extended reach lateral wells drilled to date
with 3 wells currently producing
– Average lateral length: ~9,300’
N
Beaver
– Average frac stages per well: 30
– Average EUR: 230 Mboe
g Texas Beaver
– Average IP rate: 792 Boepd .
OK
TX
– ~90% oil
Perryton
– $4 3MM - $4 5MM estimated CWC
$4.3MM $4.5MM ti t d Hansf ord
S Lipscomb
Ochiltree 0 4 8 mi
 COG Operated Wells
– 24 producing wells
– 4 wells drilling / waiting on completion ~70,000 Net Acres

27. U.S. NATURAL GAS DEMAND DRIVERS CONTINUE TO LOOK FAVORABLE…
Over
O 45 gigawatts of coal-fired generating capacity is estimated to be retired between 2012 and 2016...
i tt f l fi d ti it i ti t d t b ti d b t d 2016
25.0 22.4
20.0
watts
15.0 10.9
10 9
Gigaw
10.0 8.2
5.0 1.4 2.7
0.0
2012 2013 2014 2015 2016
Source: EIA Annual Energy Outlook 2013 Early Release Reference case
…with a potential for over 48 gigawatts of capacity from gas-fired generation newbuilds coming online during the same time period
15.0 Under Construction Proposed
10.5
10 5 10.9 10.2
10 2
10.0 8.5 8.8
Gigawatts
5.0
0.0
00
2012 2013 2014 2015 2016
Source: BENTEK Energy, “Power Jump-Starts New Gas Market Cycle”
Potential for incremental industrial demand of 3.3 Bcf/d by 2019 from new ethylene crackers, methanol and fertilizer plants, and gas-to-liquids projects
4.0
3.3
3.0
2.3
Bcf /d
2.0 1.6
1.3
1.0
10 0.7
07
0.1 0.2
0.0
2013 2014 2015 2016 2017 2018 2019
Source: Companies data, Morgan Stanley Commodities Research estimates

28. …RESULTING IN A POSITIVE OUTLOOK FOR LONG-TERM DEMAND
New i li
N pipeline systems in Mexico could potentially add 5 1 B f/d of incremental export capacity b 2016
t i M i ld t ti ll dd 5.1 Bcf/d f i t l t it by
6.0 5.1
3.7
4.0
2.7
27
Bcf /d
d
2.0
0.9
0.0
2013 2014 2015 2016
Source: Company reports and presentations
Over 24 Bcf/d of proposed/potential U.S. LNG export facilities are currently approved or pending approval
4.0 3.4
3.0
30 2.8
28 2.6
26 2.4
2.1
1.8 1.7
Bcf /d
2.0 1.5 1.4 1.3 1.3 1.1
1.0 0.8
0.0
00
Gulf Coast Golden Pass Lake Charles Cheniere - Freeport LNG Cameron LNG Gulf LNG Excelerate Oregon LNG Sabine Pass Pangea LNG Cove Point Others
Corpus Christi
Source: FERC Office of Energy Projects (as of March 11, 2013)
Increased demand for natural gas in transportation could reach 3.6 Bcf/d by 2020 as natural gas vehicles penetrate heavy use end markets
4.0 3.6
3.0 2.7
Bcf /d
1.9
2.0 1.3
0.8
1.0
10 0.5
0.2 0.3
0.0
2013 2014 2015 2016 2017 2018 2019 2020
Source: Credit Suisse Equity Research estimates

29. INVESTMENT SUMMARY
Simple Growth Story
3,000+ Remaining Locations in the
Sweet Spot of the Marcellus Shale
Transitioning from Acreage Capture to
Efficient Pad Development by 2014
p y
Cash Flow Positive Investment Program in 2013
($3.50 per Mmbtu and $90 per barrel)

30. Thank you
Thank you
The statements regarding future financial performance and results and the other
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
f d illi d k i i i f d i d d h
factors detailed in the Company’s Securities and Exchange Commission filings.