Southern Gas Association

1
Southern Gas Association 2008 Management
Conference Centennial Celebration Gas Supply
Marketing Roundtable April 21, 2008
2
Introduction to CHK

• 1 independent producer of U.S. natural gas 3
  overall including majors, and moving up fast
• 1 driller in U.S. 138 operated rigs, 84
  non-operated rigs, 14 info only rigs, collector
  of 15 of all daily drilling information
  generated in the U.S. (20 in our areas of
  interest)
• 1 hedger in industry 2006 and 2007 realized
  gains of 2.5 billion
• 1 large-cap production growth 2,219 mmcfe/day
  4Q'07 production up 34 YOY and 10
  sequentially production increased 23 in '07,
  projecting increases of 20-22 in 08 and 15-17
  in 09
• 1 large-cap proved reserve growth 10.9 tcfe
  estimated proved reserves at 12/31/07, increased
  21 YOY, 93 natural gas, 64 proved developed,
  15 year R/P expect 13 tcfe in proved reserves
  by 12/08 and 15 tcfe by 12/09
• 1 gas resource play 33 tcfe of risked unproved
  reserve potential in i) conventional gas
  resource,ii) unconventional gas resource, iii)
  emerging gas resource and iv) Appalachian gas
  resource playsgt10-year drilling inventory of
  36,300 net drilling locations, BEFORE counting
  potential contributions from the Haynesville
  Shale and new unconventional oil projects
• 1 inventory of U.S. onshore leasehold and 3-D
  seismic 13.2 mm net acres of U.S. onshore
  leasehold and 19.2 mm acres of 3-D seismic
• 37 billion enterprise value 26 billion equity
  value, 10 billion long-term debt and 1 billion
  net working capital deficit

• Data above incorporates
• CHKs Outlook and realized and locked gains as of
  3/31/08
• An assumed common stock price of 46.00, NYMEX
  prices of 8.00/mcf and 82.36/bbl for 2008 and
  excludes effects ofFAS 133 (unrealized hedging
  gain or loss)
• Reconciliations of ebitda and operating cash flow
  (before changes in assets and liabilities) to
  GAAP measures
• Risk disclosure regarding unproved reserve
  estimates appears in page 27

3
CHK is the 3rd Largest U.S. Gas Producer
(and the largest independent gas producer)
Majors continue to deplete their reserves,
independents continue to increase theirs Majors
declines will help keep U.S. gas production from
increasing very much
(a) Based on company reports (b) In
mmcf/day (c) Independents in green, majors in
black, pipelines in red (d) Based on annualized
4Q07 production (e) Source Smith International
Survey (operated rig count)
4
CHK Strategy

• Around 2000, CHK was early to recognize
• Natural gas (and oil) prices were poised to move
  structurally higher
• Horizontal drilling and completion technologies
  were rapidly improving
• Unconventional reservoirs, such as tight sands
  and shales, could become economic with higher gas
  prices and improved horizontal drilling and
  completion technologies
• Since then, CHK has moved aggressively to
• Acquire proved reserves 1 tcfe to 11 tcfe in 8
  years
• Acquire leasehold 1 mm net acres to 13 mm net
  acres in 8 years
• Acquire 3D seismic 1 mm acres to 16 mm acres in
  8 years
• Hire and develop human talent 500 EP employees
  to 2,500 in 8 years (6,500 overall), 40 lt 30
  years old
• Result?
• CHK highest large-cap production and proved
  reserve growth rates in the industry
• CHK deepest backlog of drilling opportunities in
  the industry 36,300 net drilling locations
• Well positioned for top-tier growth for decades
  to come

Our strategy has us perfectly positioned for
todays natural gas challenges and opportunities
5
CHK Key Properties Overview
6
Location of CHKs Shale Properties

• Gas-focused
• Well-diversified
• All onshore U.S.
• Not in the GOM (high and dry)
• Not in the Rockies (fewer hassles, better gas
  prices)
• Not international (lower political risk)

Appalachian Basin
New Albany Shale
Anadarko Basin
Arkoma Basin
Woodford Shale
Eastern Overthrust Belt
Scale 1 inch 275 miles
Fayetteville Shale
Barnett Shale
Barnett and Woodford Shale Plays
Alabama Shales
Permian Basin
Ark-La-Tex
Ouachita Thrust Belt
Delaware Basin
Texas Gulf Coast
Laramide Thrust Belt
South Texas
Mississippian Devonian black shales
Thrust Belt
7
Whats New at CHK?

• Announced three significant new unconventional
  natural gas discoveries and five new
  unconventional oil projects potentially 10-25
  tcfe net to CHK (1)
• Haynesville Shale, potentially 7.5-20 tcfe net to
  CHK (1)
• Colony Granite Wash, potentially 1.0 tcfe net to
  CHK (1)
• Mountain Front Granite Wash, potentially 1.0
  tcfe net to CHK (1)
• Five new unconventional oil projects, potentially
  1 billion bbls net to CHK (1)
• Announced plans to increase drilling and
  leasehold acquisition activities on new and
  existing shale plays
• Fort Worth Barnett Shale increasing from 40 to
  45 rigs(2)
• Fayetteville Shale increasing from 12 to 25
  rigs(2)
• Haynesville Shale increasing from 4 to 10
  rigs(2)
• Marcellus and Lower Huron Shales plan to drill
  165 wells in 2008 and 2009

The Haynesville Shale could potentially have a
larger impact on the company than any other play
CHK has ever made or been a part of

• Depending on ultimate recovery factors and
  acreage positions. Risk disclosure regarding
  unproved reserve estimates appears on page 27
• By year-end 2008

8
What Else is New at CHK?

• Increased 2008 and 2009 capital spending plans
  for drilling and leasehold by 950 mm to more
  fully capitalize on new discovery/projects and
  existing plays
• Increasing rig count 10
• Expecting higher per well recovery in key shale
  plays
• Experiencing decreasing per well costs
• Accelerating the development of new
  unconventional natural gas discoveries and oil
  projects
• Increasing leasehold expenditures to capture
  value identified by CHKs proprietary expertise
• Increased 2008 and 2009 production growth
  guidance by 5 and 33, from 20 to 21 in 2008
  and from 12 to 16 in 2009
• Added natural gas hedges in response to price
  strength in early March
• Revised capital funding program to include
  accessing the public capital markets, as
  necessary, rather than failing to capture
  opportunities we have created

Note Reflects CHKs Outlook as of 3/31/08
9
Has CHK Discovered the Next Barnett in the
Haynesville?

• Potentially CHKs largest discovery since its
  inception
• Haynesville Shale play developed in CHK
  geoscience department two years ago
• First time such a young shale has been targeted
  150 million years old compared to 325-375
  million years old for Barnett, Fayetteville,
  Woodford and Marcellus Shales
• CHK began drilling in 3Q06 evaluated cores in
  early 2007 at CHKs state-of-the-art Reservoir
  Technology Center (RTC) play elevated to test
  drilling phase
• Drilled four vertical and three horizontal wells
  well results confidential, but very encouraging
• Currently drilling with 4 rigs and planning for
  10 rigs by year-end 2008
• Currently own or have commitments for
  approximately 200,000 net acres of leasehold,
  potentially leading to 7.5 tcfe of ultimate
  reserve recoveries net to CHK
• Have active leasing program underway with the
  goal of owning up to 500,000 net acres in the
  play and 20 tcfe of ultimate reserve recoveries
  net to CHK

The Haynesville is another example of why the
U.S. power industry can feel comfortable relying
on natural gas for increasing power demand for
decades to come
10
Whats New in the Barnett Shale?

• In Barnett, competitive pressures from companies
  with smaller Tarrant County leasehold position
  have doubled to tripled leasehold prices in past
  few months CHK still leasing, just having to
  pay more than in the past
• Fortunately higher natural gas prices, which we
  have locked in through additional hedging, have
  more than offset the 0.25 per mcfe higher
  finding costs from higher leasehold costs
• Continue to actively lease with 1,000 landmen
  and leasehold brokers working on CHKs behalf
• Expect to own 250,000 net acres in Johnson,
  Tarrant, Dallas counties by YE08 and 280,000 net
  acres by year-end 2009 expect ultimate gas
  recovery of at least 8 tcfe net to CHK
• DFW drilling meeting expectations and expect even
  better results going forward
• Best well to date 7 mmcfe/day initial rate
• CHK net production now 450 mmcfe/day, up 13
  from YE07 and 160 from YE06
• Increasing rig count from 40 to 45 rigs by
  year-end 2008 to accelerate acreage development
  and capture strong returns

The Barnett remains 1 in CHKs portfolio, but
the Haynesville Shale could be even bigger some
day
Note Risk disclosure regarding unproved reserve
estimates appears on page 27
11
Fort Worth Barnett Shale

• Established a Top-2 position in less than 4 years
• Now have 260,000 net acres in the play (220,000
  net acres in Core Tier 1)
• 3,550 potential net wells to develop 6.8 tcfe
  (net) of PUD and risked unproved reserves
• Can drill 450 net wells per year with a 39-rig
  program

Texas
Active Rigs
CHK Operated
CHK Leasehold
Net Production vs. Operated Rig Count
DFW Intl. Airport
Expected Core Tier 1 Economics Sensitivity
Analysis
Average gross reserves of 2.45 bcfe for a
Core/Tier 1 well
12
Barnett Shale Gross OperatedDaily Production by
Major Players
Barnett Shale - Oct 2007Production 3.1 BCFED
Source Drilling Info
13
Ft. Worth Basin Production
14
Fort Worth Basin Rig Count
15
Select Barnett Shale County Production
16
Whats New in the Fayetteville Shale?

• In Fayetteville, leasehold costs have doubled in
  the past six months, but still 50-75 below
  Tarrant County Barnett leasehold prices
• Play keeps getting better
• Of last 30 CHK-operated wells, 22 IPed over 2
  mmcfe/day
• CHK net production now exceeds 130 mmcfe/day up
  1,000 YOY
• Increased expected EURs by 10 to 2.2 bcfe per
  well
• Boosting drilling to hold leasehold and
  accelerate PV creation
• Adding 5 rigs to previous ramp up plans
• Increasing from 12 rigs currently to 25 rigs by
  year-end 2008
• Per well drilling costs on the decline
• Unit service costs substantially lower due to
  increased industry capacity
• Experiencing greater economies of scale and even
  further along the learning curve

With almost 600,000 net acres, CHK could drill up
to 5,700 Fayetteville Shale wells and ultimately
recover 10 tcfe net to CHK CHK production
should increase to over 0.5 bcf/d in next three
years
Note Risk disclosure regarding unproved reserve
estimates appears on page 27
17
Arkansas Fayetteville Shale
Acreage Position

• Second-largest leasehold owner in the Core area
  of the play with approximately 420,000 net acres
• 3,100 net potential drilling locations _at_ 2.0
  bcfe/well 5.0 tcfe (net) of PUD and risked
  unproved reserves
• 12-rig program currently
• Net production has doubled over the past three
  months to 60 mmcfe/d

Active Rigs
CHK Operated
CHK Leasehold
Fayetteville Core Outline
132 miles
Arkansas
Net Production vs. Operated Rig Count
Expected Economics Sensitivity Analysis
154 miles
Average well cost of 3.0 mm/well, RDR 39.8 _at_
8.00 NYMEX gas
18
Arkansas Monthly Production
19
Fayetteville Shale Gross Operated Daily
Production by Operator
Source Arkansas Oil and Gas Commission website
20
NW Oklahoma Sahara
Acreage Position

• Foundational asset with 800,000 net acres
• Grass roots play that CHK started developing 10
  years ago and today completely dominates
• Primarily Mississippi, Chester and Hunton
  formations mostly vertical, some horizontal
• Over 10-year inventory of drilling locations

Kansas border
67 miles
Net Production vs. Operated Rig Count
Oklahoma
Active Rigs
CHK Operated
CHK Leasehold
78 miles
Expected Economics Sensitivity Analysis
Average gross reserves of 0.6 bcfe/well
21
Whats New in Appalachia?

• In Marcellus Shale, leasehold costs have
  quadrupled in past few months to over 2,000 per
  acre
• Competition from Barnett players and many of
  those left behind in the shale sweepstakes seem
  determined not to miss this play
• However, lease terms (5 years) and royalties
  (12.5 to 20) remain attractive and natural gas
  prices are 1.00-1.50 per mcfe higher than in
  Barnett
• CHKs Marcellus leasehold now exceeds 1.1 mm net
  acres and is growing steadily
• Lower Huron Shale looking good as well
• CHKs Lower Huron leasehold now exceeds 500,000
  net acres
• Have drilled 26 vertical and horizontal Marcellus
  and Lower Huron Shale wells to date and have
  plans to drill 165 vertical and horizontal wells
  in 2008/2009

• CHK realized the potential of Appalachia earlier
  than any other large-cap EP
• Marcellus could be a 50 tcf play over time

22
Arkoma Woodford
Acreage Position

• Second-largest leaseholder in the play with
  100,000 net acres
• Costs remain a challenge, although production and
  reserve results have improved in the play during
  2007
• Five-rig program planned for 2008
• 160-acre spacing appears appropriate now, however
  80-acre spacing is being tested
• _at_ 160-acre CHK upside 450 bcfe
• _at_ 80-acre CHK upside 970 bcfe

Active Rigs
CHK Operated
Net Production vs. Operated Rig Count
Expected Economics Sensitivity Analysis
Average gross reserves of 2.2 bcfe/well
23
West Texas Delaware BasinBarnett/Woodford Shales
Acreage Position

• Largest leasehold owner in the play, enormous
  upside
• Have acquired 800,000 net acres, primarily in
  Reeves, Brewster, Pecos and Culberson counties
  through multiple transactions with various public
  and private companies
• Shales much thicker than in Fort Worth Barnett,
  Arkansas or SE OK also higher gas-in-place
  estimates (2-4x higher)
• However, it is approximately twice as deep well
  costs are higher and recovery factors are
  currently unknown
• Working to solve the engineering challenge of
  economically liberating the tremendous amounts of
  gas-in-place
• Potentially, the play has the greatest upside at
  CHK - but still lots of risk
• Five-rig program planned for 2008

110 miles
105 miles
Comparison of West Texas Shales and Fort Worth
Barnett Shale
Expected Economics Sensitivity Analysis
Ft. Worth
West Texas
Ft. Worth
Delaware Basin Shale
Barnett Shale
Shales
Barnett Shale
6,500

8,500
10,000

16,000
Depth (feet)
6,500

8,500
10,000

15,000
Depth (feet)
Net thickness
Net thickness
50

400
400

1,000
(feet)
50

400
400

1,000
(feet)
Gas
-
in
-
place
Gas
-
in
-
place
50

200
100

1,000
(bcf/section)
approx 500
(bcf/section)
approx 150
12

30
???
Recovery factor
25

30
???
Recovery factor
Average gross reserves of 3.0 bcfe/well
5-7 million

2.7 million
???
Avg. well cost

2.5 million
Avg. well cost
CHK owns 1,000 square miles of leasehold in the
Delaware Basin Shale gas window, overlaying 500
bcf per square mile. If a 10 recovery factor is
achieved, this equals 50 tcfe of captured
unrisked, unproved reserves. Certainly worth the
effort to try and commercialize the play.
24
Annual Production by Region (Bcf/d)
25
U.S. Gas Well Production
26
Summary Points

• Shale production is the manufacturing process of
  the gas production business. Cost containment is
  a major focus of all shale producers.

• Producers are in discussions with the SEC
  concerning shale gas reserve calculations. We
  believe the current system underreports proved
  and probable shale reserves.

• We believe some of the international energy
  consulting groups have underestimated shale
  production potential. The by-product of this
  mistake will be errors in their US gas supply
  curves, estimates of pipeline infrastructure
  needs and basis projections.

• There will be additional interstate
  infrastructure built to support shale production.

• We look for Perryville to become an important gas
  hub and have its own pricing point.

• The larger independent producers will increase
  there market visibility with LDCs and large end
  users.

• The Marcellus and Huron shale plays will be
  challenged to develop as quickly as Mid-continent
  shale plays because of service and infrastructure
  restrictions.

27
Certain Reserve Production Information

• The Securities and Exchange Commission has
  generally permitted oil and gas companies, in
  their filings with the SEC, to disclose only
  proved reserves that a company has demonstrated
  by actual production or conclusive formation
  tests to be economically and legally producible
  under existing economic and operating conditions.
  We use the terms probable, possible and
  unproved reserves, reserve potential or
  upside or other descriptions of volumes of
  reserves potentially recoverable through
  additional drilling or recovery techniques that
  the SECs guidelines may prohibit us from
  including in filings with the SEC. To estimate
  unproved reserves, the company uses a
  probability-weighted statistical approach to
  estimate the potential number of drillsites and
  potential unproved reserves associated with such
  drillsites. These estimates are by their nature
  more speculative than estimates of proved
  reserves and accordingly are subject to
  substantially greater risk of being actually
  realized by the company. The company's
  methodology for estimating "unproved" reserves is
  different than the methodology and guidelines
  used by the Society of Petroleum Engineers for
  estimating "probable" and "possible" reserves.
• Our production forecasts are dependent upon many
  assumptions, including estimates of production
  decline rates from existing wells and the outcome
  of future drilling activity. Also, our internal
  estimates of reserves, particularly those in our
  recent acquisitions where we may have limited
  review of data or experience with the properties,
  may be subject to revision and may be different
  from those estimates by our external reservoir
  engineers at year end. Although we believe the
  expectations, estimates and forecasts reflected
  in these and other forward-looking statements 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.

28
Forward-Looking Statements
This report 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 oil and gas reserves, expected oil
and gas production and future expenses,
projections of future oil and gas prices, planned
capital expenditures for drilling, leasehold
acquisitions and seismic data, and statements
concerning anticipated cash flow and liquidity,
our business strategy and other plans and
objectives for future operations. In addition,
statements concerning the fair value of
derivative contracts and their estimated
contribution 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 these
and other forward-looking statements are
reasonable, we can give no assurance they will
prove to have 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 in Risk Factors in Item
1A of our 2007 Annual Report on Form 10-K filed
with the Securities and Exchange Commission on
February 29, 2008. These risk factors include
the volatility of oil and natural gas prices the
limitations our level of indebtedness may have on
our financial flexibility our ability to compete
effectively against strong independent oil and
gas companies and majors the availability of
capital on an economic basis to fund reserve
replacement costs our ability to replace
reserves and sustain production uncertainties
inherent in estimating quantities of oil and
natural gas reserves and projecting future rates
of production and the amount and timing of
development expenditures uncertainties in
evaluating oil and natural gas reserves of
acquired properties and associated potential
liabilities unsuccessful exploration and
development drilling declines in the values of
our oil and natural gas properties resulting in
ceiling test write-downs lower prices realized
on oil and natural gas sales and collateral
required to secure hedging liabilities resulting
from our commodity price risk management
activities the negative impact lower oil and
natural gas prices could have on our ability to
borrow drilling and operating risks, including
potential environmental liabilities production
interruptions that could adversely affect our
cash flow and pending or future litigation. We
caution you not to place undue reliance on these
forward-looking statements, which speak only as
of the date of this presentation, and we
undertake no obligation to update this
information. We urge you to carefully review and
consider the disclosures made in this
presentation and our filings with the Securities
and Exchange Commission that attempt to advise
interested parties of the risks and factors that
may affect our business.