January 2011 Investor Presentation€¦ · 3/5/2012 · January 2011 Investor Presentation CHK...

January 2011 Investor Presentation


CHK Overview

Second-largest producer of U.S. natural gas4Q’10 natural gas production of ~2.6 bcf/d, total company production of ~2.9 bcfe/d

Most active driller in U.S. Most active driller in U.S. 150 operated rigs currently, ~115 non-operated rigs & ~15 info only rigs; collector of ~20% of all daily drilling information generated in the U.S. (~25% in our areas of interest)― 50% of 2011 drilling capex in natural gas plays and 50% in liquids-rich plays

Shifting capital spending mix between natural gas plays and liquids rich plays to 30/70% by 2012― Shifting capital spending mix between natural gas plays and liquids-rich plays to 30/70% by 2012

Consistent production growth – 21 consecutive years of sequential production growth2010 YOY daily production growth of ~14%; projecting two year growth rate of ~25% (net of asset sales) ― 2010 production growth from liquids growth of 55%, projecting increases of ~85% and ~60% in '11 and '12

Best assets in the industry~16.9 tcfe of proved reserves at 12/31/10(1)

~100 tcfe of risked unproved resource potential (~250 tcfe of unrisked unproved resource potential)

PXP BP STO TOT d CEO JV lid t t lit d lPXP, BP, STO, TOT and CEO JVs validate asset quality and value

Unparalleled inventory of U.S. onshore leasehold and 3D seismic~13.6 mm net acres of U.S. onshore leasehold and ~27.4 mm acres of 3D seismic data

2

Data above incorporates:• Preliminary operational report dated 1/6/11• Risk disclosure regarding unproved resource estimates appears on page 321) Preliminary estimate based on 12-month average price required by SEC rules


CHK: Industry Leadership Since 1993

#1 driller of wells in the U.S.; 150 rigs drilling out of ~1,694 total U.S. land rigs, or 9%#1 driller in the U.S. during the past 20 years; ~11,000 wells#1 driller in the world of horizontal wells over the past 20 years; ~4 000 wells#1 driller in the world of horizontal wells over the past 20 years; 4,000 wells#1 driller in the world of horizontal shale wells over the past 10 years; ~3,100 wells#2 producer of U.S. natural gas; ~2.6 bcf/day in 4Q '10#1 producer of shale gas in the world; ~1.7 bcf/day average in 12/10#3 owner of U.S. natural gas proved reserves, 15.2 tcf#1 owner of natural gas assets in the U.S.; ~142 tcfe of net unrisked unproved resources#1 combined owner of U.S. onshore leasehold (13.6 mm net acres) and 3D seismic (27.4 mm net acres)net acres)#1 owner of leasehold in best U.S. shale plays: Marcellus, Haynesville, Bossier, Barnett, Fayetteville, Eagle Ford and Niobrara; ~4.0 mm net acres(1)

#1 inventory of shale core rock data #1 JV sponsor: Sold assets for $12.8 billion to some of world’s largest energy companies

Still retain 75% in Barnett, 80% in Haynesville, 75% in Fayetteville, 67.5% in Marcellus and 66.7% in Eagle Ford

#1 hedging track record in industry; ~$6 billion in realized gains since 2001

3

CHK’s track record of operational achievements during the past 20 years has been unique and has positioned the company for superior performance for years to come

1) Bossier shale acreage overlaps with Haynesville Shale acreage and is excluded from the shale play sub-total to avoid double counting of acreage


2010: A Year of Important Transition for CHK

At YE 2009, we looked into the future and saw two emerging significant “game changers”An emerging ability to find and develop huge new unconventional oil and NGL resources in the U.S.A persistent and widening value gap between world oil prices and U.S. natural gas pricespe s ste t a d de g a ue gap bet ee o d o p ces a d U S atu a gas p ces

With more conviction than others, we acted aggressively in response to these “game changers”

As a consequence, CHK will soon no longer be “just a proxy for US natural gas prices” As a further consequence, CHK’s per unit profitability and returns on capital should increase dramatically in the years ahead as the cap-ex invested in our liquids plays moves from 10% in 2009 to ~70% in 2012

The shift in strategy came at a price (~$5.0 billion in net undeveloped leasehold in 2010), but a price that should be fully recovered from JV partners in next few years and CHK will be left with ~12.6 billion boe of liquids resource potential on the remaining acreage

CHK solidified its industry-leading positions in the Granite Wash, Cleveland, Tonkawa and Mississippian plays in the Anadarko BasinCHK solidified its industry-leading positions in the Avalon, Wolfcamp and Bone Springs plays in the CHK solidified its industry leading positions in the Avalon, Wolfcamp and Bone Springs plays in the Permian Basin CHK established industry-leading positions in the Eagle Ford, Niobrara and an undisclosed liquids play

4


What Did CHK Accomplish In 2010?

CHK expects to deliver these results for 2010:Deliver ebitda, cash flow and net income of ~$4.9 billion, ~$4.6 billion and ~$1.8 billion(1)$4.6 billion and $1.8 billionAcquire ~$5.0 billion (net of leasehold sales) of primarily liquids-focused leasehold, most in industryGenerate JV sales of ~$4.4 billion, including ~$2.5 billion of carries, best in industryDevelop ~4.8 tcfe of proved reserves through the drillbit at a drilling and completion cost of <$1.15/mcfe; best finding costs in the industryyIncrease production by 14% after asset sales; best growth rate among large-cap peersGenerate realized hedging gains of ~$2.0 billion; best in i d tindustry

5

1) Based on $4.50 gas prices and $77 oil prices

In just one year, CHK has set the stage for decades of more profitable growth through the capture of industry-leading liquids-rich leasehold positions


CHK’s 2011-12 “25/25 Plan”

CHK’s plan for the next two years is very simple:Reduce long-term debt by 25%, through a combination of substantially reduced net leasehold expenditures and asset monetizations leasehold expenditures and asset monetizations

Increase production by 25%, net of asset sales (reduced from prior target of 30 - 40%)2011E production ~3.13 bcfe/d2012E production ~3.55 bcfe/dIncrease liquids mix to 20-25% of production from ~10% in 2010

Deliver combined 2011-12 ebitda, cash flow and net income of ~$10.8 billion, ~$10.2 billion and ~$3.8 billion(1)

E ti l i t t ith M 2010 g l f d i g d bt d i i g il d NGL Entirely consistent with May 2010 goal of reducing debt and acquiring oil and NGL resource plays

In 2010, paid down senior notes by $1.4 billionIn 2010, invested ~$5.0 billion of leasehold in liquids-rich plays which will be largely recouped from JV transactionsIncreased liquids production from ~32,000 bbls/d average in 2009 to ~60,000 bbls/d 2010 exit rate; targeting 150,000 bbls/d exit rate in 2012 and 250,000 bbls/d exit rate in 2015

6

With long-term debt down 25%, production up 25% and oil and NGL production surging, 2011-12 should be big years for CHK shareholders



CHK's Strategy Has Delivered Per Share Growth, Will Accelerate From Here

20

25

30

d sh

are

Proved Reserves(1)/Fully Diluted Share

1 2

1.4

1.6

1.8

dilu

ted

shar

e

Production/Weighted Average Fully Diluted Share

5

10

15

20

mcf

e/fu

lly d

ilute

d

0 2

0.4

0.6

0.8

1.0

1.2

/wei

ghte

d av

g fu

lly d

0 0.0

0.2

mcf

e/

$1 00Net Debt(2)/Proved Reserves(1)

80%Net Debt(2) to Book Capitalization Ratio(3)

$0 40$0.50$0.60$0.70$0.80$0.90$1.00

ebt/

mcf

e

30%

40%

50%

60%

70%

80%

$0.00$0.10$0.20$0.30$0.40

net d

e

0%

10%

20%

30%

7

Impressive production and reserve growth per share with decreasing financial leverage Data above incorporates:• Preliminary operational report dated 1/6/111) Reserve growth based on 2.0 - 2.5 tcfe add per year2) Net debt = long-term debt less cash3) Assumes NYMEX prices of $5.00 per mcf and $85.00 per bbl in 2010 - 2012


Tremendous Benefits of Shifting from Natural Gas to Liquids

Shifting output from a product valued at ~$4/mcfe to one valued at ~$15/mcfe will drive per unit ebitda, cash flow, net income and overall shareholder returns much higherFinding and production costs should be only slightly higher, while unhedged revenues per unit g p y g y g , g pshould increase ~3.5xTargeting 250,000 bbls/d by YE 2015, becoming a Top 5 U.S. liquids producer while likely maintaining a Top 2 U.S. natural gas production rankingT g ti g $10 2 billi f bitd $10 0 billi f h fl d $4 4 billi f t i Targeting ~$10.2 billion of ebitda, ~$10.0 billion of cash flow and ~$4.4 billion of net income by 2015(1)

Targeting ~30 tcfe (~5.0 bboe) of proved reserves by YE 2015 against lower than present debtIn just the past 18 months, CHK has captured leading positions in 5 of the 6 best j p , p g punconventional oil plays in the U.S.

#2 in the Eagle Ford with 425,000 net acres and 2.4 bboe of unrisked unproved resources#1 in the Niobrara with 800,000 net acres and 4.5 bboe of unrisked unproved resources#1 in the Anadarko with 1 000 000 net acres and 3 8 bboe of unrisked unproved resources#1 in the Anadarko with 1,000,000 net acres and 3.8 bboe of unrisked unproved resources#1 in the Permian with 675,000 net acres and 1.9 bboe of unrisked unproved resources#1 in an unnamed big liquids play (details to come 1H '11) with >1,000,000 net acres

8

This strategy should lead CHK to ~$10 billion of ebitda in 2015(1) and an enterprise value of $60 billion+ vs. $34 billion today – that should be >$35 per share of equity value creation from today



JV’s and Asset Monetizations Have Funded Leasehold Spend

$15,000

Drilling CarriesAcquisition of Proved and Unproved Properties and LeaseholdSale of Proved and Unproved Properties and LeaseholdNet Acquisition and Sale of Proved and Unproved Properties and Leasehold

$10,000

Drilling Carries and Net Acquisition and Sale of Proved and Unproved Properties and Leasehold

Barnett JVEagle Ford JV

Haynesville JVFayetteville JVMarcellus JV

Niobrara JVUnnamed JV

Gas Shale

$0

$5,000

Unconventional Oil “Land Grab” Largely Over by

$in

mm “Land Grab”

Ends in 2009

($5,000)

Largely Over by 1H ‘11

Unconventional Oil “Land Grab” Begins in 2010

$2.5 Billion Gap to be Funded by JV Carries Over Next 2 Years

($10,000)

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010E 2011E“Get Long Gas” via Drilling and M&A Gas Shale “Land Grab” Unconventional Oil

“Land Grab”

Next 2 Years

9

Having captured the best natural gas and oil resource base in the U.S., CHK will soon shift to net positive cash flow on leasehold and will have 142 tcf and 12.6 bboe of net unrisked resource upside as a result


What Have We Captured? Potential Net Potential Net

Unrisked Unrisked ResourceNet Acres Partner Undrilled Wells (bcfe)

Gas Shale Land Grab (2006-2009)( )Barnett Shale 215,000 Total 2,300 4,000Fayetteville Shale 440,000 BP 4,900 9,300Haynesville Shale 525,000 PXP 6,300 28,300

Bossier Shale(1) 200 000 PXP 2 500 10 200Bossier Shale 200,000 PXP 2,500 10,200Marcellus Shale 1,620,000 StatOil 20,200 89,700 Subtotal 2,800,000 36,200 141,500

Unconventional Oil Land Grab (2009-2010)(2)Anadarko Basin(2) 1,015,000 None 6,700 23,100

Eagle Ford Shale 425,000 CNOOC 5,300 14,100

Permian Basin(3) 680,000 None 4,900 11,300

Powder River and DJ Basin(4) 800,000 TBD 11,100 27,200

Risk disclosure regarding unproved resource estimates appears on page 321) Bossier shale acreage overlaps with Haynesville Shale acreage and is excluded from the shale play sub-total2) Includes Colony, Texas Panhandle and other Granite Washes, Cleveland, Tonkawa and Mississippian plays3) Includes only Avalon Shale Bone Spring Wolfcamp and Spraberry plays

Subtotal 2,920,000 28,000 75,700 (12.6 Bboe)

Totals 5,720,000 64,200 217,200

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3) Includes only Avalon Shale, Bone Spring, Wolfcamp and Spraberry plays4) Includes only Niobrara and Frontier plays

CHK believes it now owns the largest resources base in the U.S.: potential net unrisked resource of 142 tcf of natural gas and 12.6 billion barrels of oil


CHK's Liquids Production at an Important Inflection Point

40%300 NGL, MBLPDOil MBOPD

Actual Forecast

CHK Liquids Production Profile

30%

35%

200

250

oduc

tion

MB

PD

Oil, MBOPD% Liquid

15%

20%

25%

150

200

Equi

vale

nt P

ro

oduc

tion

Rat

e,

5%

10%

15%

50

100

% o

f Pro

0%-

Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16

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CHK’s modeling indicates YE 2015 goal of 250,000 bbls/day should be achievable


And CHK Knows How to Ramp Up Production

3,500

) Natural gas, mmcf/d (before production divestments)

CHK Natural Gas Production Profile

2,500

3,000

tion

(mm

cf/d

g , / ( p )Natural gas, mmcf/d (after production divestments)

1,500

2,000

l G

as P

rodu

ct

500

1,000

Net

Nat

ura

0

12

Divestments include:VPP's 1 thru 8Fayetteville Shale existing production to BPWoodford Shale to BPBarnett Shale existing production to TOT

CHK’s Assets: Best in the Business


CHK’s Operating Areas

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Low-risk, U.S. onshore asset base; not exposed to economic, geopolitical or technological risks internationally or in the Gulf of Mexico


1,000 BOE/Day Producers Everywhere

FrontierWagonhound 23-1H

1,230 boe/d(1 0 f/d 1 064 bbl /d)

NiobraraSpillman Draw Unit State 16-1H

705 boe/d(0.3 mmcf/d + 655 bbls/d)

T k

(1.0 mmcf/d + 1,064 bbls/d)MississippianSerenity 1-3H1,609 boe/d

(1.1 mmcf/d + 1,427 bbls/d)

Cl l d

RockiesAnadarko BasinGranite WashPermian

TX PH Granite WashGrayson 22 5H

TonkawaDay 1011H

1,351 boe/d(1.2 mmcf/d + 1,151 bbls/d)

ClevelandBarney 1-8H1,713 boe/d

(2.1 mmcf/d + 1,358 bbls/d)

Colony Granite Wash

PermianEagle Ford

WolfcampUniversity 5-26 1

Avalon ShaleRoss Ranch 6 Federal 1H

1 528 b /d

Grayson 22 5H5,404 boe/d

(16.2 mmcf/d +2,712 bbls/d)

Colony Granite WashJames 1-33H5,279 boe/d

(12.0 mmcf/d + 3,273 bbls/d)

y523 boe/d

(0.1 mmcf/d + 504 bbls/d)

Eagle Ford ShalePGE Brown 1H1,865 boe/d

(4 0 mmcf/d + 1 200 bbls/d)

Bone SpringMonroe 1-17 1H

1,858 boe/d(1.3 mmcf/d + 1,632 bbls/d)

1,528 boe/d(2.3 mmcf/d + 1,153 bbls/d)

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CHK is drilling big oil and liquid-rich wells in multiple developing plays

(4.0 mmcf/d + 1,200 bbls/d)( / , / )


Aggressively Shifting Capital to Liquids-Rich Plays

50%

30%80%

100%

mpl

etio

n C

apex

Total Natural Gas Capex Total Liquids CapexCHK plans to reduce drilling of natural gas wells in 2011, except for those required to HBP leasehold or to use a drilling carry provided by a

32%

50%

70%

87% 90%

68%

20%

40%

60%

HK

Ope

rate

d D

rillin

g an

d Co

m

JV partner, until natural gas prices rise above $6.00 per mcf

Accelerating drilling of liquids-rich plays until YE'12 when CHK's drilling capex is 30/70%

13% 10%

32%

0%

2008 2009 2010 2011 2012

% o

f CH

120

140Carry Natural Gas RigsHBP Natural Gas RigsLiquids Rich Rigs

YE 12 when CHK s drilling capex is 30/70% between natural gas plays and liquids-rich plays

Dramatically improving drilling rates of return and unit profitability

60

80

100

HK

Ope

rate

d R

igs

Liquids-Rich RigsExploratory RigsContinuing to add proved reserves, net of

monetizations and divestitures, of 2.0 - 2.5 tcfe (335 - 415 mmboe) annually

0

20

40CH

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CHK will fund shift to liquids-rich plays by decreasing gas drilling and utilizing drilling carries from new JV partners


Liquid Plays' Rate of Return Profiles

Colony Granite Wash Texas Panhandle Granite Wash

1400%

1600%

1800%

940 Mboe

1,170 Mboe

1,405 Mboe700%

800%

900%

930 Mboe

1,160 Mboe

1 395 Mboe

400%

600%

800%

1000%

1200%

Pre

-tax

RO

R

1,405 Mboe

200%

300%

400%

500%

600%

Pre

-tax

RO

R

1,395 Mboe

315% 180%

Cleveland/Tonkawa Eagle Ford Shale

0%

200%

400%

$60/$4.00 $70/$4.50 $80/$5.00 $90/$5.50 $100/$6.00

NYMEX Price ($/bbl and $/mcf)

0%

100%

200%

$60/$4.00 $70/$4.50 $80/$5.00 $90/$5.50 $100/$6.00


120%

140%

160%

180%

OR

475 Mboe

595 Mboe

715 Mboe

Cleveland/Tonkawa Eagle Ford Shale

300%

350%

400%

450%

OR

585 Mboe

735 Mboe

880 Mboe

20%

40%

60%

80%

100%

Pre

-tax

RO

50%

100%

150%

200%

250%

Pre

-tax

RO

50%125%

17

0%

$60/$4.00 $70/$4.50 $80/$5.00 $90/$5.50 $100/$6.00


0%

$60/$4.00 $70/$4.50 $80/$5.00 $90/$5.50 $100/$6.00



Top 20 U.S. Natural Gas Producers

Daily U.S. Natural Gas 2009 Reported Proved U.S. U.S. U.S. U.S. Gas Rigs

Production(1)(2)3Q'10 3Q'10 U.S. Net Natural Gas Gas Rigs Gas Rigs % Dri l l ing

vs. 2Q'10 vs. 3Q'09 Proved Natural RP Reserves Dri l l ing on Dril l ing on Change Since

Company(3)Ticker 3Q'10 2Q'10 3Q'09 % Change % Change Gas Reserves Ratio(4)

Ranking 11/19/10(5) 1/1/10(5)1/1/2010

1 ExxonMobil XOM 3,726 3,810 3,681 (2.2%) 1.2% 24,189 18 1 64 52 23%

2 Chesapeake CHK 2,748 2,497 2,286 10.1% 20.2% 13,510 13 3 96 110 (13%)

3 Anadarko APC 2,234 2,324 2,144 (3.9%) 4.2% 7,764 10 6 27 24 13%

4 BP BP 2,190 2,240 2,278 (2.2%) (3.9%) 15,216 19 2 16 12 33%

5 Devon DVN 1,942 1,982 1,999 (2.0%) (2.9%) 8,127 11 5 50 34 47%

6 ConocoPhill ips COP 1,820 1,822 2,043 (0.1%) (10.9%) 10,742 16 4 13 10 30%

7 EnCana ECA 1,731 1,805 1,524 (4.1%) 13.6% 5,713 9 8 41 40 3%

8 Chevron CVX 1,255 1,317 1,420 (4.7%) (11.6%) 2,698 6 14 2 1 100%

9 EOG EOG 1,175 1,069 1,128 9.9% 4.2% 6,350 15 7 40 31 29%

10 Shell RDS 1,151 1,145 1,017 0.5% 13.2% 2,258 5 18 15 14 7%

11 Southwestern SWN 1,138 1,077 793 5.7% 43.5% 3,650 9 11 17 16 6%

12 Will iams WMB 1,135 1,110 1,148 2.3% (1.1%) 4,255 10 9 16 14 14%

13 Apache APA 737 675 699 9.1% 5.4% 2,438 9 17 11 8 38%

14 Occidental OXY 656 681 653 (3.7%) 0.5% 2,799 12 12 3 1 200%

15 Petrohawk HK 654 599 482 9.2% 35.7% 2,700 11 13 19 19 0%

16 El Paso EP 618 636 619 (2.8%) (0.2%) 2,052 9 19 7 8 (13%)

17 QEP Resources QEP 597 525 426 13.7% 40.1% 2,525 12 16 12 15 (20%)

18 Ultra UPL 580 554 477 4.7% 21.6% 3,737 18 10 10 11 (9%)

19 N fi ld NFX 547 564 462 (3 0%) 18 4% 2 605 13 15 8 14 (43%)19 Newfield NFX 547 564 462 (3.0%) 18.4% 2,605 13 15 8 14 (43%)

20 Noble NBL 399 414 397 (3.6%) 0.5% 1,534 11 20 10 8 25%

Totals / Average 27,033 26,846 25,676 0.7% 5.3% 124,862 477 442 8%

Other Producers 476 362 31%Total 953 804 19%

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1) Based on 3Q’10 company reports2) In mmcf/day3) Independents in blue, majors in black, pipelines in green4) Based on annualized production5) Source: Smith Bits, a Schlumberger Company; CHK is internal count


Top 20 U.S. Liquids Producers

Daily U.S. Liquids 2009 Reported Proved U.S. U.S. U.S. U.S. Liquids Rigs

Production(1)(2)3Q'10 3Q'10 U.S. Net Liquids Liquids Rigs Liquids Rigs % Dri l l ing

vs. 2Q'10 vs. 3Q'09 Proved Liquids RP Reserves Dri l l ing on Dri l l ing on Change Since (3) (4) (5) (5)Company(3)

Ticker 3Q'10 2Q'10 3Q'09 % Change % Change Reserves Ratio(4)Ranking 11/19/10(5) 1/1/10(5)

1/1/2010

1 BP BP 669 581 669 15.1% 0.0% 3,073 13 1 3 5 (40%)2 Chevron CVX 482 488 509 (1.2%) (5.3%) 1,361 8 4 3 5 (40%)3 ExxonMobil XOM 430 441 461 (2.6%) (6.7%) 2,004 13 2 6 4 50%4 ConocoPhil l ips COP 375 382 397 (1.8%) (5.5%) 685 5 7 9 6 50%5 Occidental OXY 270 269 269 0.4% 0.4% 1,606 16 3 19 11 73%6 Shell RDS 237 231 268 2.6% (11.6%) 710 8 6 0 4 (100%)7 Anadarko APC 190 196 190 (3.1%) 0.0% 760 11 5 11 5 120%8 Devon DVN 118 123 119 (3.9%) (0.8%) 559 13 8 14 7 100%9 Apache APA 114 101 97 12.7% 17.4% 524 13 9 10 2 400%

10 EOG EOG 98 85 75 14.8% 30.6% 280 8 11 35 13 169%11 Hess HES 93 85 85 9.4% 9.4% 249 7 12 11 4 175%12 BHP BHP 92 100 124 (8.1%) (25.4%) 204 6 15 0 0 0%13 Marathon MRO 80 57 63 40.4% 27.0% 170 6 17 6 5 20%14 Denbury DNR 64 66 35 (2.6%) 83.9% 193 8 16 1 1 0%15 Noble NBL 54 52 49 4.9% 10.2% 336 17 9 3 1 200%16 Whiting WLL 54 52 44 2.4% 23.2% 224 11 13 16 7 129%17 Chesapeake CHK 49 49 33 1.2% 49.8% 124 7 18 44 15 193%18 Pioneer PXD 49 47 43 5.3% 13.5% 316 18 10 27 8 238%

19 ENI(6) E 49 50 49 (1.4%) 0.0% 110 6 19 1 0 100%20 Plains PXP 46 45 47 2.4% (1.9%) 214 13 14 0 0 0%

Totals / Average 3,614 3,500 3,626 3.3% (0.3%) 13,700 219 103 113%Other Producers 428 272 57%Total 647 375 73%

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1) Based on 3Q’10 company reports2) In mbbls/day3) Independents in blue, majors in black, pipelines in green4) Based on annualized production5) Source: Smith Bits, a Schlumberger Company; CHK is internal count6) Applied yearly percentage regional split to quarterly production numbers


CHK Has Industry’s Best JV Partnerships

CHK/PXP – July 2008Haynesville Shale (Louisiana, Texas): 80%/20%; 550,000 net acres; $30,000 per net undeveloped acre; $3.16 billion; 50% cash/50% carrycash/50% carry

CHK/BP – September 2008Fayetteville Shale (Arkansas); 75%/25%; 540,000 net acres; $12,300 per net undeveloped acre; $1.9 billion; 58% cash/42% carry

CHK/STO – November 2008Marcellus Shale (New York, Pennsylvania, West Virginia); 67.5%/32.5%; 1.8 million net acres; $5,700 per net undeveloped / ; ; $ , p pacre; $3.375 billion; 37% cash/63% carry

CHK/TOT – January 2010Barnett Shale (Texas); 75%/25%; 270,000 net acres; $15,700 per net undeveloped acre; $2 25 billion; 36% cash/64% carrynet undeveloped acre; $2.25 billion; 36% cash/64% carry

CHK/CEO – November 2010Eagle Ford Shale (Texas); 66.7%/33.3%; 600,000 net acres; $10,800 per net undeveloped acre; $2.16 billion; 50% cash/50%

20

carry

CHK has earned its reputation as the U.S. partner of choice for many international oil and natural gas companies


Enormous Value Created ThroughJV Transactions – More to Come in '11

CHK was early to recognize shale gas would become the biggest game changer in the past 50 years within the U.S. natural gas industry

Initiated detailed shale science analysis and aggressive land acquisition program in late 2004Initiated detailed shale science analysis and aggressive land acquisition program in late 2004

Emerged with the best assets in the industry by 2008 and then sold off minority interests at a large profit to de-risk the plays

The five transactions described below created $13 billion in immediate direct value and highlight $37 billion of value in the interests CHK retained

Implied Value ofIntial Drilling Retained

$ in millions Date Payment Carry Total Propertiesy y p

Plains Exploration (20% of the Haynesville) July '08 $1,650 $1,510 $3,160 $13,200

BP America (25% of the Fayetteville) Sept '08 1,100 800 1,900 5,700

Statoil USA (32.5% of the Marcellus) Nov '08 1,250 2,125 3,375 7,000

Total S.A. (25% of the Barnett) Jan '10 800 1,450 2,250 6,800

CNOOC Limited (33% of the Eagle Ford) Nov '10 1,080 1,080 2,160 4,600

Total $5,880 $6,965 $12,845 $37,300

21

CHK’s unprecedented value creation through JV’s has largely been ignored by shareholders (to date), but has created big and lasting value nevertheless

Financial Overview


2011 Financial Projections at Various Natural Gas Prices

($ in millions; oil at $85 NYMEX) $4.00 $5.00 $6.00 $7.00

O/G revenue (unhedged) @ 1,140 bcfe(1) $4,940 $5,870 $6,810 $7,750

Hedging effect(2) 1,850 1,020 160 (740) g g , , ( )

Marketing and other (@ $0.13/mcfe) 150 150 150 150

Production taxes 5% (250) (290) (340) (390)

LOE (@ $0.90/mcfe) (1,030) (1,030) (1,030) (1,030)

G&A (@ $0.46/mcfe)(3) (520) (520) (520) (520)

Ebitda 5,140 5,200 5,230 5,220

Interest (@ $0.23/mcfe)(4) (260) (260) (260) (260)

Operating cash flow(2)(3)(4) 4,880 4,940 4,970 4,960

Oil and gas depreciation (@ $1.45/mcfe) (1,650) (1,650) (1,650) (1,650)

Depreciation of other assets (@ $0.23/mcfe) (260) (260) (260) (260)

Income taxes (38.5% rate) (1,140) (1,170) (1,180) (1,170)

Net income to common(1) $1,830 $1,860 $1,880 $1,880

Net income to common per fully diluted shares $2.43 $2.47 $2.50 $2.50

MEV/operating cash flow(5) 4.1x 4.0x 4.0x 4.0x

EV/ebitda(6) 6.6x 6.5x 6.5x 6.5x

PE ratio(7) 10.7x 10.5x 10.4x 10.4x

23

Data above as of 11/3/10 Outlook adjusted for hedging positions as of 1/6/111) Before effects of unrealized hedging gain or loss 2) Includes the non-cash effect of lifted hedges and financing derivatives3) Includes charges related to stock based compensation 4) Before changes in assets and liabilities 5) MEV (Market Equity Value) = $19.8 billion ($26.00/share x 761 mm fully diluted shares as of 9/30/10) 6) EV (Enterprise Value) = $33.9 billion (Market Equity Value, plus $11.6 billion in net long-term debt plus $2.5 billion working capital deficit as of 9/30/10) 7) Assuming a common stock price of $26.00/share


2012 Financial Projections at Various Natural Gas Prices

($ in millions; oil at $85 NYMEX) $4.00 $5.00 $6.00 $7.00

O/G revenue (unhedged) @ ~1,300 bcfe(1) $6,300 $7,280 $8,250 $9,230

Hedging effect(2) 410 250 90 (140) Hedging effect 410 250 90 (140) Marketing and other (@ $0.13/mcfe) 170 170 170 170 Production taxes 5% (320) (360) (410) (460) LOE (@ $0.90/mcfe) (1,170) (1,170) (1,170) (1,170)

G&A (@ $0.46/mcfe)(3) (590) (590) (590) (590) ( / ) ( ) ( ) ( ) ( )Ebitda 4,800 5,580 6,340 7,040 Interest (@ $0.23/mcfe) (290) (290) (290) (290)

Operating cash flow(2)(3)(4) 4,510 5,290 6,050 6,750 Oil and gas depreciation (@ $1.45/mcfe) (1,880) (1,880) (1,880) (1,880) Depreciation of other assets (@ $0.23/mcfe) (290) (290) (290) (290) Income taxes (38.5% rate) (900) (1,200) (1,490) (1,760)

Net income to common(1) $1,440 $1,920 $2,390 $2,820

Net income to common per fully diluted shares $1.90 $2.53 $3.15 $3.71

MEV/operating cash flow(5) 4.4x 3.7x 3.3x 2.9x

EV/ebitda(6) 7.1x 6.1x 5.3x 4.8x

PE ratio(7) 13.7x 10.3x 8.3x 7.0x

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Data above as of 11/3/10 Outlook adjusted for hedging positions as of 1/6/111) Before effects of unrealized hedging gain or loss 2) Includes the non-cash effect of lifted hedges and financing derivatives 3) Includes charges related to stock based compensation 4) Before changes in assets and liabilities 5) MEV (Market Equity Value) = $19.8 billion ($26.00/share x 761 mm fully diluted shares as of 9/30/10) 6) EV (Enterprise Value) = $33.9 billion (Market Equity Value, plus $11.6 billion in net long-term debt plus $2.5 billion working capital deficit as of 9/30/10) 7) Assuming a common stock price of $26.00/share


More Liquids Plus Hedged Gas = 2011 Value Creation > Expected

At year-end 2009, CHK's financial projections had yet to recognize what the transition to more liquids would deliver to its shareholders

The Oil Land Grab of 2010 and subsequent JVs will have dramatically positive The Oil Land Grab of 2010 and subsequent JVs will have dramatically positive implications on future earnings, as 2011 and beyond will benefit from the increased production of $15/mcfe units vs. $4/mcfe units

Aggressive hedging of natural gas also helped to lock in attractive margins

YE 2009 Projections Current Projections for 2011 for 2011

($ in mm) @ $5.00 NYMEX @ $5.00 NYMEX % change

Ebitda $3,700 $5,200 41%Operating cash flow $3,350 $4,940 47%Net income to common $800 $1,860 133%Net income to common per fully diluted share $1.24 $2.47 99%p y $ $

25

Proactive and skillful decisions have dramatically lifted CHK's 2011 cash generation and profitability vs. what would have otherwise occurred


Senior Note Maturity Schedule(1)

$3,200

$3,600$3,294(2)CHK Total Senior Notes: $9.7 billion

Average Maturity: 7.0 years

$2 000

$2,400

$2,800

M $1,876(2)

$2,152(2)

$1,900

$1,200

$1,600

$2,000

$ in

M

$1,876 $1,900

$4.0 billion bank credit facility matures

December 2015

$400

$800$500

ece be 0 5

$0

'08 '09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19 '20

1) As of 9/30/10

Rate:Rate: 7.625%

6.25%9.5% 6.625%6.5% 7.25%

6.875%

6.875%2.75% 2.5% 2.25%

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1) As of 9/30/102) Recognizes earliest investor put option as maturity for the 2.75% of 2035, 2.5% of 2037 and 2.25% of 2038 Convertible Senior Notes shown in green

Only $500 million of senior note maturities until February 2015


CHK’s Natural Gas and Oil Hedge Positions for 2011-12(1)(2)

Oil Swaps(4) % HedgedNYMEX

Avg PriceNatural Gas Swaps(3) % HedgedNYMEX

Avg. Price Oil Swaps % Hedged Avg. Price

2011 5% $99.39

2012 1% $109.50

Natural Gas Swaps % Hedged Avg. Price

2011 96% $5.84

2012 17% $6.19

2011-12 Hedging Strategy:NYMEX Strip Prices @ 1/3/2011 Oil Natural Gas

2011 $93 53 $4 70g g gy

Hedge offensively when opportunities present themselves, as they have 4-5 times during the past 18 months

2011 $93.53 $4.70

2012 $94.24 $5.13

2013 $93.01 $5.33

2014 $92.27 $5.48

2015 $92.30 $5.62

5-Year Average5 Year Average(2011-2015)

$93.06 $5.25

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(1) Excludes written calls and puts(2) Assumes approximately the midpoint of company production forecast for each item and includes hedging positions as of 1/6/11(3) Swap positions include the benefit of premiums received in connection with sold calls for a portion of future natural gas and oil production(4) Includes positions with knockout provisions for 3% and 1% in 2011 and 2012 oil production at knockout prices of $60


CHK Hedging Since Inception: ~$6 Billion of Realized Gains – Best in Industry, by Far

$4.00800

Quarterly Realized Gains and Losses1Q '01 - 3Q '10

CHK’ h dgi g g h

$2.00

$3.00

400

600

uctio

n

in m

illio

ns)

CHK’s hedging program has generated ~$6 billion in realized gains since inception in 2001

$0.00

$1.00

-

200

r m

cfe

of p

rodu

ins/

Loss

es ($

$3 00

-$2.00

-$1.00

600

(400)

(200)

$ p

er

Rea

lized

Ga

Realized Hedging Gains/Loses Realized Gains/Loses per Mcfe-$3.00(600)

28

We don’t hedge just to say we’re hedged, we hedge to make money, have successfully done so 17 of past 19 quarters. That’s not luck, that’s skill!

SSummary


Summary

2011-12’s simple “25/25” Plan: The Catalyst!Reduce long-term debt by 25%Increase production by 25%

I fl ti P i t N t l G t Li id T itiInflection Point on Natural Gas to Liquids TransitionRapidly shifting from ~90% gas to a more balanced oil/gas production mix of 75/25% in 2012Shift to liquids not yet reflected in market valuation

Great Leasehold = Great UpsideLargest leasehold position in the best U S onshore natural gas shale playsLargest leasehold position in the best U.S. onshore natural gas shale plays2.9 mm net acres of leasehold targeting liquids-rich plays

Great Reserves and Resources Decades of development drilling at low drilling and completion costs16 9 tcfe of proved resources(1)16.9 tcfe of proved resources( )

99 tcfe risked unproved resources (69 tcfe from natural gas shale plays, 3.9 billion boe from liquids-rich plays, 7 tcfe from conventional plays)

Value-Adding Joint VenturesWorld-class partners (BP PXP STO TOT and CEO) with $4 billion of future JV carriesWorld class partners (BP, PXP, STO, TOT and CEO) with $4 billion of future JV carriesSold assets for ~$13 billion, retained remaining JV assets valued by third-parties at ~$37 billionFurther JVs and asset monetizations on the way

Attractive Valuation and Still Delivering Value Through Growth of NAV per ShareTrade at a substantial discount to estimated NAV and way below single shale play companies

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Trade at a substantial discount to estimated NAV and way below single shale play companiesCHK’s 2011-12 “25/25” Plan will be the catalyst to unleashing CHK’s stock price performance

• Risk disclosures regarding unproved resource estimates on page 32. (1) Preliminary estimate based on 12-month average price required by SEC rules


Corporate Information

Chesapeake Headquarters6100 N. Western AvenueOklahoma Cit OK 73118

Corporate Contacts:Jeffrey L. Mobley, CFASenior Vice President –I t R l ti d R hOklahoma City, OK 73118

Web site: www.chk.comInvestor Relations and Research(405) [email protected]

John J. KilgallonManager – Investor Relations and

Other Publicly Traded Securities CUSIP Ticker7 625% Senior Notes due 2013 #165167BY2 CHKJ13 Manager Investor Relations and

Research(405) [email protected]

Domenic J. Dell’Osso

7.625% Senior Notes due 2013 #165167BY2 CHKJ139.5% Senior Notes due 2015 #165167CD7 CHK15K6.25% Senior Notes due 2017 #027393390 N/A6.50% Senior Notes due 2017 #165167BS5 CHK176.875% Senior Notes due 2018 #165167CE5 CHK18B7.25% Senior Notes due 2018 #165167CC9 CHK18A6.625% Senior Notes due 2020 #165167CF2 CHK20A6 875% Senior Notes d e 2020 #165167BU0 CHK20 Executive Vice President and CFO

(405) [email protected]

Aubrey K. McClendonChairman and CEO

6.875% Senior Notes due 2020 #165167BU0 CHK202.75% Contingent Convertible Senior Notes due 2035 #165167BW6 CHK352.50% Contingent Convertible Senior Notes due 2037 #165167BZ9/165167CA3 CHK37/CHK37A2.25% Contingent Convertible Senior Notes due 2038 #165167CB1 CHK384.5% Cumulative Convertible Preferred Stock #165167842 CHK PrD 5.0% Cumulative Convertible Preferred Stock (Series 2005B) #165167826 N/A5.75% Cumulative Convertible Preferred Stock #165167776/U16450204 N/A5 75% C l ti C tibl P f d St k (S i A) #165167784/U16450113 N/A Chairman and CEO

(405) [email protected]

5.75% Cumulative Convertible Preferred Stock (Series A) #165167784/U16450113 N/A

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Certain Reserve & Production Information

The Securities and Exchange Commission requires natural gas and oil companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of natural gas and oil that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be

i ll d ibl f gi d t f d f k i d d i ti g economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. In this presentation, we use the terms "risked and unrisked unproved resources" to describe Chesapeake's internal estimates of volumes of natural gas and oil that are not classified as proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques These are recoverable through exploratory drilling or additional drilling or recovery techniques. These are broader descriptions of potentially recoverable volumes than probable and possible reserves, as defined by SEC regulations. Estimates of unproved resources are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the company. We believe our estimates of unproved resources, both actually being realized by the company. We believe our estimates of unproved resources, both risked and unrisked, are reasonable, but such estimates have not been reviewed by independent engineers. Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Although we believe the forecasts are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions and data or by known or unknown risks and uncertainties.

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Forward-Looking StatementsThis presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. They include estimates of our natural gas and oil reserves and resources, expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices planned asset sales budgeted capital expenditures for drilling and acquisitions of leasehold and producing prices, planned asset sales, budgeted capital expenditures for drilling and acquisitions of leasehold and producing property, and other anticipated cash outflows, as well as statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Although we believe the expectations and forecasts reflected in forward-looking statements are reasonable, we can give no assurance they will prove to have b Th b ff d b i i b k k i k d i i been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results are described under "Risks Related to our Business" in our Prospectus Supplement filed with the U.S. Securities and Exchange Commission on August 10, 2010. These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the values of our natural gas and oil properties resulting in ceiling test write-downs; the availability of capital on an economic basis including through planned asset resulting in ceiling test write-downs; the availability of capital on an economic basis, including through planned asset monetization transactions, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and the amount and timing of development expenditures; inability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas and oil sales, the need to secure hedging liabilities and the

f finability of hedging counterparties to satisfy their obligations; a reduced ability to borrow or raise additional capital as a result of lower natural gas and oil prices; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business; general economic conditions negatively impacting us and our business counterparties; transportation capacity constraints and interruptions that could adversely affect our cash flow; and losses possible from pending or future litigation. We caution you not to place undue reliance on our forward-looking statements which speak only as of the date of

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We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this presentation, and we undertake no obligation to update this information.

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