Chesapeake Energy Corporation Reports Financial and Operational Results for the 2008 Third Quarter
Company Reports 2008 Third Quarter Net Income to Common Shareholders of $3.282 Billion, or $5.61 per Fully Diluted Common Share; Adjusted Net Income Available to Common Shareholders Is $486 Million, or $0.85 per Fully Diluted Common Share, an Increase of 47% Over 2007 Third Quarter Company Reports 2008 Third Quarter Production of 2.3 Bcfe per Day, an Increase of 15% Over 2007 Third Quarter Production Proved Reserves Reach 12.1 Tcfe and Increase 11% Year-to-Date on 1.2 Tcfe of Net Additions; Company Delivers First Three Quarters of 2008 Reserve Replacement Rate of 290% and a Drilling and Net Acquisition Cost of $1.35 per Mcfe

OKLAHOMA CITY--(BUSINESS WIRE)--Oct. 30, 2008--Chesapeake Energy Corporation (NYSE:CHK) today announced financial and operating results for the 2008 third quarter. For the quarter, Chesapeake reported net income to common shareholders of $3.282 billion ($5.61 per fully diluted common share), operating cash flow of $1.400 billion (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $5.963 billion (defined as net income (loss) before income taxes, interest expense, and depreciation, depletion and amortization expense) on revenue of $7.491 billion and production of 214 billion cubic feet of natural gas equivalent (bcfe). The results above include the following items that are typically not included in published estimates of the company's financial results by certain securities analysts:

    --  an unrealized noncash after-tax mark-to-market (MTM) gain of
        $2.846 billion from future period natural gas, oil and
        interest rate hedges primarily resulting from lower natural
        gas and oil prices as of September 30, 2008 compared to June
        30, 2008;

    --  an after-tax loss of $19.0 million on the early redemption of
        the company's $300 million 7.75% Senior Notes due 2015;

    --  an after-tax consent fee of $6.3 million paid to amend certain
        provisions contained in five of the company's senior note
        indentures; and

    --  a reduction of net income available to common shareholders of
        $24.5 million resulting from exchanges of the company's
        preferred stock for common stock that reduced future preferred
        stock dividend payment requirements.

Including the items noted above, Chesapeake reported adjusted net income to common shareholders during the quarter of $486 million ($0.85 per fully diluted common share) and adjusted ebitda of $1.386 billion, increases of 47% and 16%, respectively, over the 2007 third quarter. A reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 14 - 17 of this release.

          Key Operational and Financial Statistics Summarized

The table below summarizes Chesapeake's key results during the 2008 third quarter and compares them to results during the 2008 second quarter and the 2007 third quarter.

                                                 Three Months Ended:
                                               -----------------------
                                               9/30/08 6/30/08 9/30/07
                                               ------- ------- -------
Average daily production (in mmcfe)              2,321   2,328   2,026
Natural gas as % of total production                92      92      91
Natural gas production (in bcf)                  196.7   195.0   170.3
Average realized natural gas price ($/mcf) (a)    8.02    8.18    7.41
Oil production (in mbbls)                        2,810   2,816   2,680
Average realized oil price ($/bbl) (a)           75.74   76.96   69.25
Natural gas equivalent production (in bcfe)      213.5   211.9   186.4
Natural gas equivalent realized price ($/mcfe)
 (a)                                              8.38    8.55    7.76
Natural gas and oil marketing income ($/mcfe)      .11     .12     .10
Service operations income ($/mcfe)                 .04     .04     .06
Production expenses ($/mcfe)                    (1.12)  (1.03)   (.89)
Production taxes ($/mcfe)                        (.41)   (.41)   (.30)
General and administrative costs ($/mcfe) (b)    (.38)   (.38)   (.23)
Stock-based compensation ($/mcfe)                (.12)   (.10)   (.10)
DD&A of natural gas and oil properties
 ($/mcfe)                                       (2.25)  (2.47)  (2.57)
D&A of other assets ($/mcfe)                     (.23)   (.19)   (.24)
Interest expense ($/mcfe) (a)                    (.26)   (.36)   (.52)
Operating cash flow ($ in millions) (c)          1,400   1,443   1,085
Operating cash flow ($/mcfe)                      6.56    6.81    5.82
Adjusted ebitda ($ in millions) (d)              1,386   1,435   1,195
Adjusted ebitda ($/mcfe)                          6.49    6.77    6.41
Net income (loss) to common shareholders ($ in
 millions)                                       3,282 (1,649)     346
Earnings (loss) per share - assuming dilution
 ($)                                              5.61  (3.17)     .72
Adjusted net income to common shareholders
($ in millions) (e)                                486     479     330
Adjusted earnings per share - assuming
 dilution ($)                                      .85     .89     .69

(a) includes the effects of realized gains or (losses) from hedging, but does not include the effects of unrealized gains or (losses) from hedging

(b) excludes expenses associated with noncash stock-based compensation

(c) defined as cash flow provided by operating activities before changes in assets and liabilities

(d) defined as net income (loss) before income taxes, interest expense, and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 16

(e) defined as net income (loss) available to common shareholders, as adjusted to remove the effects of certain items detailed on page 16

2008 Third Quarter Average Daily Production Increases 15% over 2007 Third Quarter Production

Daily production for the 2008 third quarter averaged 2.321 bcfe, a decrease of 7 mmcfe, or 0.3%, over the 2.328 bcfe produced per day in the 2008 second quarter and an increase of 295 mmcfe, or 15%, over the 2.026 bcfe produced per day in the 2007 third quarter. Adjusted for the company's year-end 2007, second quarter 2008 and third quarter 2008 VPP sales of 55, 47 and 47 mmcfe per day, respectively, and the company's sale of Woodford Shale and Fayetteville Shale properties of 47 and 45 mmcfe per day, respectively, Chesapeake's sequential and year-over-year production growth rates were 3% and 23%, respectively. In addition, during the quarter hurricane-related production curtailments totaled approximately 1.6 bcfe while voluntary production cutbacks due to low wellhead natural gas prices totaled approximately 0.6 bcfe.

Chesapeake's average daily production for the 2008 third quarter consisted of 2.138 billion cubic feet of natural gas (bcf) and 30,543 barrels of oil and natural gas liquids (bbls). The company's 2008 third quarter production of 213.5 bcfe was comprised of 196.7 bcf (92% on a natural gas equivalent basis) and 2.81 million barrels of oil and natural gas liquids (mmbbls) (8% on a natural gas equivalent basis).

Natural Gas and Oil Proved Reserves Reach 12.1 Tcfe on 1.2 Tcfe of Net Additions; During the First Three Quarters of 2008, Company Delivers a Reserve Replacement Rate of 290% and a Drilling and Net Acquisition Cost of $1.35 per Mcfe

Chesapeake began 2008 with estimated proved reserves of 10.879 trillion cubic feet of natural gas equivalent (tcfe) and ended the third quarter with 12.075 tcfe, an increase of 1.196 tcfe, or 11%. During the first three quarters of 2008, Chesapeake replaced 630 bcfe of production with an estimated 1.826 tcfe of new proved reserves for a reserve replacement rate of 290%. Reserve replacement through the drillbit was 2.286 tcfe, or 363% of production. This includes 1,128 bcfe of positive performance revisions (including 987 bcfe related to infill drilling and increased density locations) and 13 bcfe of positive revisions resulting from natural gas and oil price increases between December 31, 2007 and September 30, 2008. Acquisitions of proved reserves completed during the first three quarters of 2008 were 165 bcfe at a cost of $357 million, or $2.16 per mcfe, while sales of proved reserves during the first three quarters of 2008 totaled 638 bcfe for proceeds of $2.335 billion, or $3.66 per mcfe. Sales of undeveloped leasehold during the first three quarters of 2008 generated proceeds of $3.6 billion compared to a cost basis of approximately $750 million for the leasehold sold.

Chesapeake's total drilling and net acquisition costs for the first three quarters of 2008 were $1.35 per mcfe. This calculation excludes costs of $3.3 billion for the acquisition of unproved properties and leasehold (net of sales), $289 million for capitalized interest on unproved properties, $234 million for seismic, and $19 million relating to tax basis step-up and asset retirement obligations, as well as positive revisions of proved reserves from higher natural gas and oil prices. Excluding these items and acquisition and divestiture activity, Chesapeake's exploration and development costs through the drillbit during the first three quarters of 2008 were $1.94 per mcfe. A complete reconciliation of finding and acquisition costs and a roll-forward of proved reserves are presented on page 12 of this release.

During the first three quarters of 2008, Chesapeake continued the industry's most active drilling program and drilled 1,435 gross operated wells (1,193 net with an average working interest of 83.1%) and participated in another 1,439 gross wells operated by other companies (195 net with an average working interest of 13.6%). The company's drilling success rate was 99% for company-operated wells and 97% for non-operated wells. Also during the first three quarters of 2008, Chesapeake invested $3.852 billion in operated wells (using an average of 148 operated rigs) and $576 million in non-operated wells (using an average of 118 non-operated rigs) for total drilling, completing and equipping costs of $4.428 billion.

As of September 30, 2008, Chesapeake's estimated future net cash flows from proved reserves, discounted at an annual rate of 10% before income taxes (PV-10), were $24.4 billion using field differential adjusted prices of $6.48 per thousand cubic feet of natural gas (mcf) (based on a NYMEX quarter-end price of $7.12 per mcf) and $96.66 per bbl (based on a NYMEX quarter-end price of $100.66 per bbl). Chesapeake's PV-10 changes by approximately $420 million for every $0.10 per mcf change in natural gas prices and approximately $60 million for every $1.00 per bbl change in oil prices. Chesapeake's enterprise value (market equity value plus long-term debt less working capital excluding current portion of derivative assets and liabilities) as of October 29, 2008 was approximately $27 billion.

By comparison, the December 31, 2007 PV-10 of the company's proved reserves was $20.6 billion ($15.0 billion applying the SFAS 69 standardized measure) using field differential adjusted prices of $6.19 per mcf (based on a NYMEX year-end price of $6.80 per mcf) and $90.58 per bbl (based on a NYMEX year-end price of $96.00 per bbl). The September 30, 2007 PV-10 of the company's proved reserves was $19.4 billion using field differential adjusted prices of $5.85 per mcf (based on a NYMEX quarter-end price of $6.38 per mcf) and $76.76 per bbl (based on a NYMEX quarter-end price of $81.56 per bbl).

The company calculates the standardized measure of future net cash flows in accordance with SFAS 69 only at year end because applicable income tax information on properties, including recently acquired natural gas and oil interests, is not readily available at other times during the year. As a result, the company is not able to reconcile the interim period-end values to the standardized measure at such dates. The only difference between the two measures is that PV-10 is calculated before considering the impact of future income tax expenses, while the standardized measure includes such effects.

In addition to the PV-10 value of its proved reserves and the very significant value of its undeveloped leasehold, particularly in the Haynesville, Marcellus, Barnett and Fayetteville shale plays, the net book value of the company's other assets (including gathering systems, compressors, land and buildings, investments and other non-current assets) was $4.9 billion as of September 30, 2008, $3.1 billion as of December 31, 2007 and $2.9 billion as of September 30, 2007.

Average Realized Prices, Hedging Results and Hedging Positions Detailed

Average prices realized during the 2008 third quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $8.02 per mcf and $75.74 per bbl, for a realized natural gas equivalent price of $8.38 per mcfe. Realized gains and losses from natural gas and oil hedging activities during the 2008 third quarter generated a $0.71 loss per mcf and a $37.79 loss per bbl for a 2008 third quarter realized hedging loss of $246 million, or $1.15 per mcfe. Excluding hedging activity, Chesapeake's average realized pricing basis differentials to NYMEX during the 2008 third quarter were a negative $1.52 per mcf and a negative $4.46 per bbl.

By comparison, average prices realized during the 2007 third quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $7.41 per mcf and $69.25 per bbl, for a realized natural gas equivalent price of $7.76 per mcfe. Realized gains from natural gas and oil hedging activities during the 2007 third quarter generated a $1.70 gain per mcf and a $1.51 loss per bbl for a 2007 third quarter realized hedging gain of $286 million, or $1.53 per mcfe. Excluding hedging activity, Chesapeake's average realized pricing basis differentials to NYMEX during the 2007 third quarter were a negative $0.45 per mcf and a negative $4.62 per bbl.

The following tables summarize Chesapeake's open hedge position through swaps and collars as of October 30, 2008. Depending on changes in natural gas and oil futures markets and management's view of underlying natural gas and oil supply and demand trends, Chesapeake may either increase or decrease its hedging positions at any time in the future without notice.

              Open Swap Positions as of October 30, 2008

                                    Natural Gas             Oil
                                 -----------------   -----------------
Quarter or Year                  % Hedged  $ NYMEX   % Hedged  $ NYMEX
==============================   ========  =======   ========  =======
2008 Q4                               62%     9.15        43%    78.09
==============================   ========  =======   ========  =======
2009 Total                            38%     9.33        48%    81.19
==============================   ========  =======   ========  =======
2010 Total                            40%     9.58        37%    90.25
==============================   ========  =======   ========  =======
       Open Natural Gas Collar Positions as of October 30, 2008

                                                   Average    Average
                                                    Floor     Ceiling
Quarter or Year                        % Hedged    $ NYMEX    $ NYMEX
====================================  ==========  =========  =========
2008 Q4                                      14%       7.75       9.32
====================================  ==========  =========  =========
2009 Total                                   30%       7.21       9.27
====================================  ==========  =========  =========
2010 Total                                    2%       7.71      11.46
====================================  ==========  =========  =========

Certain open natural gas swap positions include knockout swaps with knockout provisions at $6.50 per mcf covering 9 bcf in the 2008 fourth quarter, and prices ranging from $5.65 to $7.25 per mcf covering 150 bcf in 2009 and $5.45 to $7.40 per mcf covering 321 bcf in 2010. Certain open natural gas collar positions include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 per mcf covering 105 bcf in 2009 and at $6.00 per mcf covering 4 bcf in 2010. Also, certain open oil swap positions include cap-swaps and knockout swaps with provisions limiting the counterparty's exposure below prices ranging from $45 to $60 per bbl covering 1 mmbbls in the 2008 fourth quarter, from $50 to $60 per bbl covering 6 mmbbls in 2009 and $60 per bbl covering 5 mmbbls in 2010. As of October 24, 2008, Chesapeake's natural gas and oil hedging positions with a diversified group of 19 different counterparties had a positive mark-to-market (MTM) value of approximately $1.0 billion.

The company's updated forecasts for 2008 through 2010 are attached to this release in an Outlook dated October 30, 2008, labeled as Schedule "A," which begins on page 18. This Outlook has been changed from the Outlook dated October 14, 2008 (attached as Schedule "B," which begins on page 23) to reflect various updated information.

Company Continues to Improve Balance Sheet and Liquidity

As a result of strong earnings growth and favorable changes in the MTM value of the company's open hedging positions during the 2008 third quarter, Chesapeake's net debt to book capitalization ratio decreased from 57% at June 30, 2008 to 43% at September 30, 2008. The company's goal is to end 2008 with cash and cash equivalents on hand or bank credit availability of approximately $3.0 billion and to generate at least $1.0 billion of excess cash in each of 2009 and 2010. The company's revolving credit facility matures in November 2012 and the first maturity of its senior unsecured notes is in July 2013.

Management Comments

Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We are pleased to report our financial and operational results for the 2008 third quarter. During the quarter, we earned almost $3.3 billion, improved our balance sheet and liquidity and closed approximately $7.5 billion of asset monetization transactions. Those transactions included selling a VPP for approximately $600 million in cash, selling 20% of our Haynesville Shale properties for $3.3 billion in cash and drilling carries, selling 25% of our Fayetteville Shale properties for $1.9 billion in cash and drilling carries and selling 100% of our remaining Woodford Shale properties for $1.7 billion in cash. Furthermore we are progressing on additional asset monetizations for the 2008 fourth quarter and we look forward to disclosing the details of these transactions later this quarter.

"Although financial market volatility remains high, Chesapeake is very well-positioned to continue growing and creating value in the 2008 fourth quarter and in 2009 and 2010. Our commodity hedges, our Haynesville and Fayetteville Shale drilling cost carries, our progress in the Marcellus Shale and our balance sheet, which has $2.0 billion in cash on it and requires no debt payments for four years, should enable Chesapeake to prosper during these difficult economic times. I am very excited to see the company continue realizing its full potential through the ongoing execution of our successful strategy and the full development of our top-tier properties."

Conference Call Information

A conference call to discuss this release has been scheduled for Friday morning, October 31, 2008, at 9:00 a.m. EDT. The telephone number to access the conference call is 913-312-1437 or toll-free 888-240-9345. The passcode for the call is 7433119. We encourage those who would like to participate in the call to dial the access number between 8:50 and 9:00 a.m. EDT. For those unable to participate in the conference call, a replay will be available for audio playback from 2:00 p.m. EDT on October 31, 2008 through midnight EST on Friday, November 14, 2008. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 7433119. The conference call will also be webcast live on the Internet and can be accessed by going to Chesapeake's website at www.chk.com and selecting the "News & Events" section. The webcast of the conference call will be available on our website for one year.

This press release and the accompanying Outlooks include "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 natural gas and oil reserves, expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, planned capital expenditures for drilling, leasehold acquisitions and seismic data and planned asset sales, as well as statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures 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. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information.

Factors that could cause actual results to differ materially from expected results are described in "Risk Factors" in the Prospectus Supplement we filed with the U.S. Securities and Exchange Commission on July 10, 2008. These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; our ability to compete effectively against strong independent natural gas and oil companies and majors; the availability of capital on an economic basis, including 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; uncertainties in evaluating natural gas and oil reserves of acquired properties and associated potential liabilities; our ability to effectively consolidate and integrate acquired properties and operations; unsuccessful exploration and development drilling; declines in the values of our natural gas and oil properties resulting in ceiling test write-downs; lower prices realized on natural gas and oil sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities; the negative impact lower natural gas and oil 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.

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 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.

Chesapeake Energy Corporation is the largest producer of natural gas in the U.S. Headquartered in Oklahoma City, the company's operations are focused on exploratory and developmental drilling and corporate and property acquisitions in the Fort Worth Barnett Shale, Haynesville Shale, Fayetteville Shale, Anadarko Basin, Arkoma Basin, Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast and Ark-La-Tex regions of the United States. Further information is available at www.chk.com.

                    CHESAPEAKE ENERGY CORPORATION
                CONSOLIDATED STATEMENTS OF OPERATIONS
           ($ in millions, except per-share and unit data)
                             (unaudited)

                                    September 30,      September 30,

THREE MONTHS ENDED:                     2008               2007
----------------------------------------------------------------------
                                     $      $/mcfe      $      $/mcfe
                                  -------- --------  -------- --------

REVENUES:
   Natural gas and oil sales        6,408    30.01     1,492     8.00
   Natural gas and oil marketing
    sales                           1,038     4.86       501     2.69
   Service operations revenue          45     0.21        34     0.18
                                  -------- --------  -------- --------
       Total Revenues               7,491    35.08     2,027    10.87
                                  -------- --------  -------- --------

OPERATING COSTS:
   Production expenses                239     1.12       165     0.89
   Production taxes                    87     0.41        56     0.30
   General and administrative
    expenses                          108     0.50        62     0.33
   Natural gas and oil marketing
    expenses                        1,014     4.75       483     2.59
   Service operations expense          37     0.17        23     0.12
   Natural gas and oil
    depreciation, depletion and
    amortization                      480     2.25       479     2.57
   Depreciation and amortization
    of other assets                    48     0.23        44     0.24
                                  -------- --------  -------- --------
        Total Operating Costs       2,013     9.43     1,312     7.04
                                  -------- --------  -------- --------

INCOME FROM OPERATIONS              5,478    25.65       715     3.83
                                  -------- --------  -------- --------

OTHER INCOME (EXPENSE):
   Interest and other income           (2)   (0.01)        1     0.01
   Interest expense                   (48)   (0.22)     (116)   (0.62)
   Loss on repurchase of
    Chesapeake debt                   (31)   (0.14)       --       --
   Consent solicitation fees          (10)   (0.05)       --       --
                                  -------- --------  -------- --------
       Total Other Income
        (Expense)                     (91)   (0.42)     (115)   (0.61)
                                  -------- --------  -------- --------

INCOME BEFORE INCOME TAXES          5,387    25.23       600     3.22

   Income Tax Expense:
     Current                          193     0.90         9     0.05
     Deferred                       1,881     8.81       219     1.17
                                  -------- --------  -------- --------
       Total Income Tax Expense     2,074     9.71       228     1.22
                                  -------- --------  -------- --------

NET INCOME                          3,313    15.52       372     2.00
                                  -------- --------  -------- --------

   Preferred stock dividends           (6)   (0.03)      (26)   (0.14)
   Loss on conversion/exchange of
    preferred stock                   (25)   (0.12)       --       --
                                  -------- --------  -------- --------

NET INCOME AVAILABLE TO COMMON
 SHAREHOLDERS                       3,282    15.37       346     1.86
                                  ======== ========  ======== ========

EARNINGS PER COMMON SHARE:

   Basic                          $  5.93            $  0.76
                                  ========           ========
   Assuming dilution              $  5.61            $  0.72
                                  ========           ========

WEIGHTED AVERAGE COMMON AND
 COMMON EQUIVALENT SHARES
 OUTSTANDING (in millions)

   Basic                              554                454
                                  ========           ========
   Assuming dilution                  588                517
                                  ========           ========
                    CHESAPEAKE ENERGY CORPORATION
                CONSOLIDATED STATEMENTS OF OPERATIONS
           ($ in millions, except per-share and unit data)
                             (unaudited)

                                    September 30,      September 30,

NINE MONTHS ENDED:                      2008               2007
----------------------------------------------------------------------
                                     $      $/mcfe      $      $/mcfe
                                  -------- --------  -------- --------

REVENUES:
   Natural gas and oil sales        5,587     8.87     4,164     8.16
   Natural gas and oil marketing
    sales                           2,934     4.66     1,446     2.84
   Service operations revenue         127     0.20       101     0.20
                                  -------- --------  -------- --------
       Total Revenues               8,648    13.73     5,711    11.20
                                  -------- --------  -------- --------

OPERATING COSTS:
   Production expenses                658     1.04       461     0.90
   Production taxes                   250     0.40       151     0.30
   General and administrative
    expenses                          288     0.46       168     0.33
   Natural gas and oil marketing
    expenses                        2,864     4.55     1,394     2.73
   Service operations expense         104     0.16        67     0.13
   Natural gas and oil
    depreciation, depletion and
    amortization                    1,518     2.41     1,314     2.58
   Depreciation and amortization
    of other assets                   125     0.20       120     0.24
                                  -------- --------  -------- --------
        Total Operating Costs       5,807     9.22     3,675     7.21
                                  -------- --------  -------- --------

INCOME FROM OPERATIONS              2,841     4.51     2,036     3.99
                                  -------- --------  -------- --------

OTHER INCOME (EXPENSE):
   Interest and other income          (13)   (0.02)       12     0.02
   Interest expense                  (212)   (0.33)     (279)   (0.54)
   Gain on sale of investment          --       --        83     0.16
   Loss on repurchase of
    Chesapeake debt                   (31)   (0.05)       --       --
   Consent solicitation fees          (10)   (0.02)       --       --
                                  -------- --------  -------- --------
       Total Other Income
        (Expense)                    (266)   (0.42)     (184)   (0.36)
                                  -------- --------  -------- --------

INCOME BEFORE INCOME TAXES          2,575     4.09     1,852     3.63

   Income Tax Expense:
     Current                          196     0.31        19     0.04
     Deferred                         795     1.26       685     1.34
                                  -------- --------  -------- --------
       Total Income Tax Expense       991     1.57       704     1.38
                                  -------- --------  -------- --------

NET INCOME                          1,584     2.52     1,148     2.25
                                  -------- --------  -------- --------

   Preferred stock dividends          (27)   (0.04)      (77)   (0.15)
   Loss on conversion/exchange of
    preferred stock                   (67)   (0.11)       --       --
                                  -------- --------  -------- --------

NET INCOME AVAILABLE TO COMMON
 SHAREHOLDERS                       1,490     2.37     1,071     2.10
                                  ======== ========  ======== ========

EARNINGS PER COMMON SHARE:

   Basic                          $  2.85            $  2.37
                                  ========           ========
   Assuming dilution              $  2.73            $  2.23
                                  ========           ========

WEIGHTED AVERAGE COMMON AND
 COMMON EQUIVALENT SHARES
 OUTSTANDING (in millions)

   Basic                              523                452
                                  ========           ========
   Assuming dilution                  557                516
                                  ========           ========
                    CHESAPEAKE ENERGY CORPORATION
                     CONSOLIDATED BALANCE SHEETS
                           ($ in millions)
                             (unaudited)

                                           September 30,  December 31,
                                               2008           2007
----------------------------------------------------------------------

Cash                                         $     1,964    $        1
Other current assets                               2,147         1,395
                                           -------------  ------------
    Total Current Assets                           4,111         1,396
                                           -------------  ------------

Property and equipment (net)                      34,845        28,337
Other assets                                       1,062         1,001
                                           -------------  ------------
    Total Assets                             $    40,018    $   30,734
                                           =============  ============

Current liabilities                          $     3,601    $    2,760
Long-term debt, net                               14,345        10,950
Asset retirement obligation                          260           236
Other long-term liabilities                          715           692
Deferred tax liability                             4,690         3,966
                                           -------------  ------------
    Total Liabilities                             23,611        18,604

Stockholders' Equity                              16,407        12,130
                                           -------------  ------------

Total Liabilities & Stockholders' Equity     $    40,018    $   30,734
                                           =============  ============

Common Shares Outstanding (in millions)              581           511
                                           =============  ============
                    CHESAPEAKE ENERGY CORPORATION
                            CAPITALIZATION
                           ($ in millions)
                             (unaudited)


                                % of Total                % of Total
                September 30,      Book       June 30,       Book
                    2008      Capitalization    2008    Capitalization
----------------------------------------------------------------------

Total debt, net
 cash            $     12,381           43%   $  13,703           57%
Stockholders'
 equity                16,407           57%      10,276           43%
                ------------- -------------- ---------- --------------
    Total        $     28,788          100%   $  23,979          100%
                ============= ============== ========== ==============

                                                         % of Total
                                       December 31,         Book
                                           2007        Capitalization
----------------------------------------------------------------------

Total debt, net cash                    $     10,949              47%
Stockholders' equity                          12,130              53%
                                      --------------  ----------------
    Total                               $     23,079             100%
                                      ==============  ================
                    CHESAPEAKE ENERGY CORPORATION
  RECONCILIATION OF 2008 ADDITIONS TO NATURAL GAS AND OIL PROPERTIES
                ($ in millions, except per-unit data)
                             (unaudited)

                                                    Reserves
                                            Cost    (in bcfe)  $/mcfe
----------------------------------------------------------------------

Exploration and development costs         $  4,428   2,286(a)     1.94
Acquisition of proved properties               357     165        2.16
Sale of proved properties                   (2,335)   (638)       3.66
                                          --------- --------- --------
    Drilling and net acquisition cost        2,450   1,813        1.35
                                          --------- --------- --------

Revisions - price                               --      13          --

Acquisition of unproved properties and
 leasehold                                   6,931      --          --
Sale of unproved properties and leasehold   (3,587)     --          --
                                          --------- --------- --------
          Net leasehold and unproved
           property acquisition              3,344      --          --
                                          --------- --------- --------

Capitalized interest on leasehold and
 unproved property                             289      --          --
Geological and geophysical costs               234      --          --
                                          --------- --------- --------
          Geological, geophysical and
           capitalized interest                523      --          --
                                          --------- --------- --------

    Subtotal                                 6,317   1,826        3.46
                                          --------- --------- --------

Tax basis step-up                               13      --          --
Asset retirement obligation and other            6      --          --
                                          --------- --------- --------
    Total                                 $  6,336   1,826        3.47
                                          ========= ========= --------

(a) Includes 1,128 bcfe of positive performance revisions (987 bcfe relating to infill drilling and increased density locations and 141 bcfe of other performance related revisions) and excludes positive revisions of 13 bcfe resulting from natural gas and oil price increases between December 31, 2007 and September 30, 2008.

                    CHESAPEAKE ENERGY CORPORATION
                   ROLL-FORWARD OF PROVED RESERVES
                 NINE MONTHS ENDED SEPTEMBER 30, 2008
                             (unaudited)

                                                              Bcfe
----------------------------------------------------------------------

Beginning balance, 01/01/08                                   10,879
Production                                                      (630)
Acquisitions                                                     165
Divestitures                                                    (638)
Revisions - performance                                        1,128
Revisions - price                                                 13
Extensions and discoveries                                     1,158
                                                           -----------
Ending balance, 09/30/08                                      12,075
                                                           ===========

Reserve replacement                                            1,826
Reserve replacement ratio (a)                                    290%

(a) The company uses the reserve replacement ratio as an indicator of the company's ability to replenish annual production volumes and grow its reserves. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

                    CHESAPEAKE ENERGY CORPORATION
  SUPPLEMENTAL DATA - NATURAL GAS AND OIL SALES AND INTEREST EXPENSE
                             (unaudited)

                              THREE MONTHS ENDED    NINE MONTHS ENDED
                                 September 30,        September 30,
                              -------------------  -------------------
                                2008      2007       2008      2007
                              --------- ---------  --------- ---------
Natural Gas and Oil Sales ($
 in millions):
    Natural gas sales          $ 1,717   $   971    $ 5,046   $ 2,918
    Natural gas derivatives -
     realized gains (losses)      (140)      290       (174)      890
    Natural gas derivatives -
     unrealized gains
     (losses)                    3,854        73        325       (58)
                              --------- ---------  --------- ---------

        Total Natural Gas
         Sales                   5,431     1,334      5,197     3,750
                              --------- ---------  --------- ---------

    Oil sales                      319       190        915       443
    Oil derivatives -
     realized gains (losses)      (106)       (4)      (280)       26
    Oil derivatives -
     unrealized gains
     (losses)                      764       (28)      (245)      (55)
                              --------- ---------  --------- ---------

        Total Oil Sales            977       158        390       414
                              --------- ---------  --------- ---------

        Total Natural Gas and
         Oil Sales             $ 6,408   $ 1,492    $ 5,587   $ 4,164
                              ========= =========  ========= =========

Average Sales Price -
 excluding gains (losses) on
 derivatives:
    Natural gas ($ per mcf)    $  8.73   $  5.71    $  8.71   $  6.25
    Oil ($ per bbl)            $113.53   $ 70.76    $109.28   $ 61.91
    Natural gas equivalent ($
     per mcfe)                 $  9.54   $  6.23    $  9.47   $  6.59

Average Sales Price -
 excluding unrealized gains
 (losses) on derivatives:
    Natural gas ($ per mcf)    $  8.02   $  7.41    $  8.41   $  8.15
    Oil ($ per bbl)            $ 75.74   $ 69.25    $ 75.82   $ 65.55
    Natural gas equivalent ($
     per mcfe)                 $  8.38   $  7.76    $  8.75   $  8.39

Interest Expense ($ in
 millions):
    Interest                   $    51   $    98    $   220   $   266
    Derivatives - realized
     (gains) losses                  5        (1)         1        --
    Derivatives - unrealized
     (gains) losses                 (8)       19         (9)       13
                              --------- ---------  --------- ---------
        Total Interest
         Expense               $    48   $   116    $   212       279
                              ========= =========  ========= =========
                    CHESAPEAKE ENERGY CORPORATION
                CONDENSED CONSOLIDATED CASH FLOW DATA
                           ($ in millions)
                             (unaudited)

                                        September 30,   September 30,

THREE MONTHS ENDED:                         2008            2007
----------------------------------------------------------------------

Beginning cash                           $          1    $          4
Cash provided by operating activities           1,550           1,267
Cash (used in) investing activities            (1,872)         (2,485)
Cash provided by financing activities           2,285           1,216
Ending cash                                     1,964               2


======================================================================


                                        September 30,   September 30,

NINE MONTHS ENDED:                          2008            2007
----------------------------------------------------------------------

Beginning cash                           $          1    $          3
Cash provided by operating activities           4,305           3,389
Cash (used in) investing activities            (8,201)         (6,488)
Cash provided by financing activities           5,859           3,098
Ending cash                                     1,964               2
                    CHESAPEAKE ENERGY CORPORATION
           RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
                           ($ in millions)
                             (unaudited)

                             September 30,   June 30,    September 30,

THREE MONTHS ENDED:              2008          2008          2007
----------------------------------------------------------------------

CASH PROVIDED BY OPERATING
 ACTIVITIES                   $     1,550    $     1,256  $     1,267

Adjustments:
   Changes in assets and
    liabilities                      (150)           187         (182)
                             ------------- ------------- -------------

OPERATING CASH FLOW(1)        $     1,400    $     1,443  $     1,085
                             ============= ============= =============

(1) Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity.

                             September 30,   June 30,    September 30,

THREE MONTHS ENDED:              2008          2008          2007
----------------------------------------------------------------------

NET INCOME (LOSS)              $     3,313   $   (1,597)   $       372

Income tax expense (benefit)         2,074       (1,000)           228
Interest expense                        48           63            116
Depreciation and
 amortization of other
 assets                                 48           40             44
Natural gas and oil
 depreciation, depletion and
 amortization                          480          523            479
                             ------------- ------------- -------------

EBITDA(2)                      $     5,963   $   (1,971)   $     1,239
                             ============= ============= =============

(2) Ebitda represents net income (loss) before income tax expense, interest expense and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreement and is used in the financial covenants in our bank credit agreement and our senior note indentures. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP. Ebitda is reconciled to cash provided by operating activities as follows:

                             September 30,   June 30,    September 30,

THREE MONTHS ENDED:              2008          2008          2007
----------------------------------------------------------------------

CASH PROVIDED BY OPERATING
 ACTIVITIES                   $     1,550   $     1,256   $     1,267

Changes in assets and
 liabilities                         (150)          187          (182)
Interest expense                       48            63           116
Unrealized gains (losses) on
 natural gas and oil
 derivatives                        4,618        (3,404)           45
Other non-cash items                 (103)          (73)           (7)
                             ------------- ------------- -------------

EBITDA                        $     5,963   $    (1,971)  $     1,239
                             ============= ============= =============
                    CHESAPEAKE ENERGY CORPORATION
           RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
                           ($ in millions)
                             (unaudited)

                                          September 30,  September 30,

NINE MONTHS ENDED:                            2008           2007
----------------------------------------------------------------------

CASH PROVIDED BY OPERATING ACTIVITIES      $      4,305   $     3,389

Adjustments:
   Changes in assets and liabilities                 49          (104)
                                          -------------  -------------

OPERATING CASH FLOW(1)                     $      4,354   $     3,285
                                          =============  =============

(1) Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity.

                                          September 30,  September 30,

NINE MONTHS ENDED:                            2008           2007
----------------------------------------------------------------------

NET INCOME                                 $      1,584   $      1,148

Income tax expense (benefit)                        991            704
Interest expense                                    212            279
Depreciation and amortization of other
 assets                                             125            120
Natural gas and oil depreciation,
 depletion and amortization                       1,518          1,314
                                          -------------  -------------

EBITDA(2)                                  $      4,430   $      3,565
                                          =============  =============

(2) Ebitda represents net income (loss) before income tax expense, interest expense and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreement and is used in the financial covenants in our bank credit agreement and our senior note indentures. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP. Ebitda is reconciled to cash provided by operating activities as follows:

                                          September 30,  September 30,

NINE MONTHS ENDED:                            2008           2007
----------------------------------------------------------------------

CASH PROVIDED BY OPERATING ACTIVITIES      $     4,305    $     3,389

Changes in assets and liabilities                   49           (104)
Interest expense                                   212            279
Unrealized gains (losses) on natural gas
 and oil derivatives                                80           (113)
Other noncash items                               (216)           114
                                          -------------  -------------

EBITDA                                     $     4,430    $     3,565
                                          =============  =============
                    CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
                ($ in millions, except per-share data)
                             (unaudited)

                             September 30,   June 30,    September 30,
THREE MONTHS ENDED:              2008          2008          2007
----------------------------------------------------------------------

Net income (loss) available
 to common shareholders        $    3,282    $   (1,649)   $      346

Adjustments:
   Unrealized (gains) losses
    on derivatives, net of
    tax                            (2,846)        2,085           (16)
   Loss on repurchase of
    Chesapeake debt, net of
    tax                                19            --            --
   Consent fees on senior
    notes, net of tax                   6            --            --
   Loss on
    conversion/exchange of
    preferred stock                    25            43            --
                             ------------- ------------- -------------

Adjusted net income
 available to common
 shareholders(1)                      486           479           330
   Preferred stock dividends            6             9            26
   Interest on 2.75%
    contingent convertible
    notes, net of tax                   3             3            --
   Interest on 2.50%
    contingent convertible
    notes, net of tax                   7            --            --
                             ------------- ------------- -------------
Total adjusted net income      $      502    $      491    $      356
                             ============= ============= =============

Weighted average fully
 diluted shares
 outstanding(2)                       589           553           517

Adjusted earnings per share
 assuming dilution(1)          $     0.85    $     0.89    $     0.69
                             ============= ============= =============

(1) Adjusted net income available to common and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because:

(a) Management uses adjusted net income available to common to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies.

(b) Adjusted net income available to common is more comparable to earnings estimates provided by securities analysts.

(c) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

(2) Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

                    CHESAPEAKE ENERGY CORPORATION
                  RECONCILIATION OF ADJUSTED EBITDA
                           ($ in millions)
                             (unaudited)

                             September 30,   June 30,    September 30,
THREE MONTHS ENDED:              2008          2008          2007
----------------------------------------------------------------------

EBITDA                         $    5,963    $   (1,971)   $    1,239

Adjustments, before tax:
   Unrealized (gains) losses
    on natural gas and oil
    derivatives                    (4,618)        3,406           (45)
   Loss on repurchase of
    Chesapeake debt                    31            --            --
   Consent fees on senior
    notes                              10            --            --
                             ------------- ------------- -------------

Adjusted ebitda(1)             $    1,386    $    1,435    $    1,194
                             ============= ============= =============

(1) Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to ebitda because:

(a) Management uses adjusted ebitda to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies.

(b) Adjusted ebitda is more comparable to estimates provided by securities analysts.

(c) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

                    CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
                ($ in millions, except per-share data)
                             (unaudited)

                                          September 30,  September 30,
NINE MONTHS ENDED:                            2008           2007
----------------------------------------------------------------------

Net income available to common
 shareholders                              $     1,490    $     1,071

Adjustments:
   Unrealized (gains) losses on
    derivatives, net of tax                        (55)            78
   Gain on sale of investment, net of
    cash                                            --            (51)
   Loss on repurchase of Chesapeake debt,
    net of tax                                      19             --
   Consent fees on senior notes, net of
    tax                                              6             --
   Loss on conversion/exchange of
    preferred stock                                 67             --
                                          -------------  -------------

Adjusted net income available to common
 shareholders(1)                                 1,527          1,098
   Preferred stock dividends                        27             77
   Interest on 2.75% contingent
    convertible notes, net of tax                    5             --
   Interest on 2.50% contingent
    convertible notes, net of tax                    7             --
                                          -------------  -------------

Total adjusted net income                  $     1,566    $     1,175
                                          =============  =============

Weighted average fully diluted shares
 outstanding(2)                                    564            516

Adjusted earnings per share assuming
 dilution(1)                               $      2.78    $      2.28
                                          =============  =============

(1) Adjusted net income available to common and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because:

(a) Management uses adjusted net income available to common to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies.

(b) Adjusted net income available to common is more comparable to earnings estimates provided by securities analysts.

(c) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

(2) Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

                    CHESAPEAKE ENERGY CORPORATION
                  RECONCILIATION OF ADJUSTED EBITDA
                           ($ in millions)
                             (unaudited)

                                          September 30,  September 30,
NINE MONTHS ENDED:                            2008           2007
----------------------------------------------------------------------

EBITDA                                     $     4,430    $     3,565

Adjustments, before tax:
   Unrealized (gains) losses on natural
    gas and oil derivatives                        (80)           113
   Gain on sale of investment                       --            (83)
   Loss on repurchase of Chesapeake debt            31             --
   Consent fees on senior notes                     10             --
                                          -------------  -------------

Adjusted ebitda(1)                         $     4,391    $     3,595
                                          =============  =============

(1) Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to ebitda because:

(a) Management uses adjusted ebitda to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies.

(b) Adjusted ebitda is more comparable to estimates provided by securities analysts.

(c) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

    SCHEDULE "A"

    CHESAPEAKE'S OUTLOOK AS OF OCTOBER 30, 2008

Quarter Ending December 31, 2008 and Years Ending December 31, 2009 and 2010.

We have adopted a policy of periodically providing guidance on certain factors that affect our future financial performance. As of October 30, 2008, we are using the following key assumptions in our projections for the fourth quarter of 2008 and the full years 2009 and 2010.

The primary changes from our October 14, 2008 Outlook are in italicized bold and are explained as follows:

1) Natural gas production assumption for the quarter ending 12/31/08 has been reduced to reflect anticipated voluntary curtailments due to low wellhead price realizations;

2) Projected effects of changes in our hedging positions have been updated;

3) Our NYMEX natural gas and oil price assumptions for realized hedging effects and estimating future operating cash flow have been reduced for the quarter ending 12/31/08; and

4) Certain cost and cash income tax assumptions have been updated.

                             Quarter Ending Year Ending  Year Ending
                               12/31/2008    12/31/2009    12/31/2010
                             -------------- ------------ -------------
Estimated Production(a)
   Natural gas - bcf           188 - 192     893 - 913   1,032 - 1,072
   Oil - mbbls                   2,825         12,000       13,000
   Natural gas equivalent -
    bcfe                       205 - 209     965 - 985   1,110 -1,150

Daily natural gas equivalent
 midpoint - mmcfe                2,250         2,670         3,095

Year-over-year production
 increase                         1.4%         16.8%         15.9%

NYMEX Prices (b) (for calculation of realized hedging effects only):
   Natural gas - $/mcf           $7.00         $8.00         $8.00
   Oil - $/bbl                   $60.00        $80.00       $80.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices
 above):
   Natural gas - $/mcf           $1.96         $0.70         $0.82
   Oil - $/bbl                   $5.48         $1.32         $4.79
Estimated Differentials to
 NYMEX Prices:
   Natural gas - $/mcf          10 - 14%      10 - 14%     10 - 14%
   Oil - $/bbl                   5 - 7%        5 - 7%       5 - 7%
Operating Costs per Mcfe of Projected Production:
   Production expense         $1.00 - 1.15  $1.10 - 1.20 $1.15 - 1.25
   Production taxes (about
    5% of O&G revenues) (c)   $0.30 - 0.35  $0.35 - 0.40 $0.35 - 0.40
   General and
    administrative(d)         $0.33 - 0.37  $0.33 - 0.37 $0.33 - 0.37
   Stock-based compensation
    (non-cash)                $0.10 - 0.13  $0.10 - 0.12 $0.10 - 0.12
   DD&A of natural gas and
    oil assets                $2.25 - 2.30  $2.20 - 2.30 $2.15 - 2.25
   Depreciation of other
    assets                    $0.20 - 0.25  $0.20 - 0.24 $0.20 - 0.24
   Interest expense(e)        $0.30 - 0.35  $0.40 - 0.45 $0.35 - 0.40
Other Income per Mcfe:
   Natural gas and oil
    marketing income          $0.09 - 0.11  $0.09 - 0.11 $0.09 - 0.11
   Service operations income  $0.04 - 0.06  $0.04 - 0.06 $0.04 - 0.06
Book Tax Rate                    38.5%         38.5%         38.5%
Cash Income Taxes - in
 millions                      $550 - 650    $200 - 300   $200 - 300

Equivalent Shares
 Outstanding - in millions:
   Basic                       560 - 565     565 - 570     575 - 580
   Diluted                     580 - 585     585 - 590     595 - 600
Cash Flow
 Projections - in  Quarter Ending    Year Ending       Year Ending
 millions             12/31/2008       12/31/2009        12/31/2010
                   --------------- ----------------- -----------------
Net inflows:
------------------
  Operating cash
   flow before
   changes in
   assets and
   liabilities
   (f)(g)          $1,250 - 1,375   $5,800 - 6,000    $6,250 - 6,750
  Leasehold and
   producing
   property
   transactions:
------------------
     Sale of
      leasehold
      and
      producing
      properties
      (a)          $2,100 - 2,500   $1,250 - 2,000    $1,250 - 2,000
     Sale of
      producing
      properties
      via VPP's(a)   $400 - 500     $1,000 - 1,250    $1,000 - 1,250
     Acquisition
      of leasehold
      and
      producing
      properties   ($750 - $1,000) ($1,250 - $1,750) ($1,000 - $1,500)
------------------ --------------- ----------------- -----------------
     Net leasehold
      and
      producing
      property
      transactions $1,750 - 2,000   $1,000 - 1,500    $1,250 - 1,750
  Debt and equity
   offerings              -                -                 -
  Midstream
   financings      $1,050 - 1,275     $500 - 700        $500 - 700
  Proceeds from
   investments and
   other                  -            $500- 750        $150 - 250
                   --------------- ----------------- -----------------
Total Cash Inflows $4,050 - 4,650   $7,800 - 8,950    $8,150 - 9,450
                   =============== ================= =================

Net outflows:
------------------
  Drilling         $1,200 - 1,300   $4,250 - 4,750    $4,750 - 5,250
  Geophysical
   costs                 $75          $225 - 275        $225 - 275
  Midstream
   infrastructure
   and compression   $300 - 325     $1,000 - 1,200     $900 - 1,000
  Other PP&E          $50 - 75        $250 - 300        $250 - 300
  Dividends,
   senior notes
   redemption,
   capitalized
   interest, etc.    $150 - 200       $575 - 600        $575 - 600
  Cash income
   taxes             $550 - 650       $200 - 300        $200 - 300
                   --------------- ----------------- -----------------
Total Cash
 Outflows          $2,325 - 2,625   $6,500 - 7,425    $6,900 - 7,725
                   =============== ================= =================

Net Cash Change    $1,725 - 2,025    $1,300 -1,525    $1,250 - 1,725
                   =============== ================= =================

(a) The 2008 fourth quarter production and cash flow forecasts reflect anticipated sales by the company of: 1) producing properties for approximately $450 million in a volumetric production payment (VPP); and 2) producing properties in South Texas and undeveloped leasehold in the Marcellus Shale and other areas for approximately $2.3 billion. The 2009 and 2010 production and cash flow forecasts reflect anticipated sales by the company of: 1) producing properties for approximately $1.1 billion in each year in VPP transactions; and 2) undeveloped leasehold or other producing properties for approximately $1.6 billion in each year.

(b) NYMEX natural gas prices have been updated for actual contract prices through October 2008.

(c) Severance tax per mcfe is based on NYMEX prices of $60.00 per bbl of oil and $6.50 to $7.50 per mcf of natural gas during the 2008 fourth quarter; $80.00 per bbl of oil and $7.50 to $8.50 per mcf of natural gas during 2009; and $80.00 per bbl of oil and $7.50 to $8.50 per mcf of natural gas during 2010.

(d) Excludes expenses associated with noncash stock compensation.

(e) Does not include gains or losses on interest rate derivatives (SFAS 133).

(f) A non-GAAP financial measure. We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.

(g) Assumes NYMEX natural gas prices of $6.50 to $7.50 per mcf and NYMEX oil prices of $60.00 per bbl in the 2008 fourth quarter and NYMEX natural gas prices of $7.00 to $8.00 per mcf and NYMEX oil prices of $80.00 per bbl in 2009 and 2010.

Commodity Hedging Activities

The company utilizes hedging strategies to hedge the price of a portion of its future natural gas and oil production. These strategies include:

(i) For swap instruments, Chesapeake receives a fixed price and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

(ii) Basis protection swaps are arrangements that guarantee a price differential for oil or natural gas from a specified delivery point. For Mid-Continent basis protection swaps, which have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. For Appalachian basis protection swaps, which have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

(iii) For knockout swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty's exposure to zero, in any given month, if the floating market price is lower than certain predetermined knockout prices.

(iv) For cap-swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a "cap" limiting the counterparty's exposure. In other words, there is no limit to Chesapeake's exposure but there is a limit to the downside exposure of the counterparty

(v) For written call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake.

(vi) Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.

(vii) A three-way collar contract consists of a standard collar contract plus a written put option with a strike price below the floor price of the collar. In addition to the settlement of the collar, the put option requires Chesapeake to make a payment to the counterparty equal to the difference between the put option price and the settlement price if the settlement price for any settlement period is below the put option strike price.

Commodity markets are volatile, and as a result, Chesapeake's hedging activity is dynamic. As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction.

Chesapeake enters into natural gas and oil derivative transactions in order to mitigate a portion of its exposure to adverse market changes in natural gas and oil prices. Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to natural gas and oil sales. All realized gains and losses from natural gas and oil derivatives are included in natural gas and oil sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these nonqualifying derivatives that occur prior to their maturity (i.e., because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within natural gas and oil sales.

Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in natural gas and oil sales.

Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following open natural gas swaps in place and also has the following gains (losses) from lifted natural gas swaps:

                                                              Total
                                      Open Swap               Lifted
                                     Positions     Total       Gain
                   Avg.                  as a       Gains   (Loss) per
                    NYMEX  Assuming     % of     (Losses)     Mcf of
                   Strike  Natural    Estimated     from    Estimated
            Open    Price     Gas      Total      Lifted      Total
             Swaps  of    Production   Natural      Swaps    Natural
             in     Open  in Bcf's      Gas         ($          Gas
             Bcf's  Swaps     of:     Production  millions) Production
======================================================================
Q4 2008     108.2  $9.27     190         57%       $85.2      $0.45
======================================================================

======================================================================
Total
 2009(1)    327.7  $9.43     903         36%      ($36.7)    ($0.04)
======================================================================

======================================================================
Total
 2010(1)    422.6  $9.58    1,052        40%       $33.9      $0.03
======================================================================

(1) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty's exposure below $6.50 covering 9 bcf in 2008 and prices ranging from $5.65 to $7.25 covering 150 bcf in 2009 and $5.45 to $7.40 covering 321 bcf in 2010.

The company currently has the following open natural gas collars in place:

                                                          Open Collars
                                               Assuming    as a % of
                                              Natural Gas  Estimated
               Open    Avg. NYMEX Avg. NYMEX  Production      Total
               Collars   Floor     Ceiling     in Bcf's   Natural Gas
              in Bcf's    Price      Price        of:      Production
======================================================================
Q4 2008         26.6     $7.75       $9.32        190         14%
======================================================================

======================================================================
Total 2009(1)  267.5     $7.21       $9.27        903         30%
======================================================================

======================================================================
Total 2010(1)   25.6     $7.71      $11.46       1,052         2%
======================================================================

(1) Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 105 bcf in 2009 and at $6.00 covering 4 bcf in 2010.

The company currently has the following natural gas written call options in place:

                                                        Call Options
                                            Assuming      as a % of
             Call                 Avg.    Natural Gas  Estimated Total
            Options  Avg. NYMEX  Premium   Production    Natural Gas
           in Bcf's  Call Price  per mcf  in Bcf's of:   Production
======================================================================
Q4 2008      32.2      $10.37     $0.74       190            17%
======================================================================

======================================================================
Total 2009   216.2     $11.40     $0.63       903            24%
======================================================================

======================================================================
Total 2010   231.8     $10.77     $0.72      1,052           22%
======================================================================

The company has the following natural gas basis protection swaps in place:

                              Mid-Continent           Appalachia
                          ---------------------  ---------------------
                          Volume in    NYMEX     Volume in    NYMEX
                            Bcf's     less(1):     Bcf's     plus(1):
                          ---------  ----------  ---------  ----------
Q4 2008                        32.1   $    0.45        5.8   $    0.33
2009                           77.1        0.35       16.9        0.28
2010                             --          --       10.2        0.26
2011                           45.1        0.64       12.1        0.25
2012                           43.2        0.48         --          --
                          ---------  ----------  ---------  ----------
Totals                        197.5   $    0.46       45.0   $    0.27
                          =========  ==========  =========  ==========

(1) weighted average

We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition in November 2005. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($76 million as of September 30, 2008). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our natural gas and oil revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to natural gas and oil revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in natural gas and oil revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR.

Pursuant to SFAS 149 "Amendment of SFAS 133 on Derivative Instruments and Hedging Activities," the assumed CNR derivative instruments are deemed to contain a significant financing element and all cash flows associated with these positions are reported as financing activity in the statement of cash flows.

The following details the CNR derivatives (natural gas swaps) we have assumed:

                                                            Open Swap
                   Avg.                                     Positions
                    NYMEX                                     as a %
                  Strike    Avg. Fair             Assuming     of
                    Price  Value Upon             Natural    Estimated
            Open  Of Open  Acquisition  Initial      Gas       Total
           Swaps   Swaps        of     Liability Production  Natural
            in     (per    Open Swaps  Acquired  in Bcf's       Gas
            Bcf's   Mcf)    (per Mcf)  (per Mcf)     of:    Production
======================================================================
Q4 2008     9.7    $4.66      $7.84     ($3.17)     190         5%
======================================================================

======================================================================
Total 2009  18.3   $5.18      $7.28     ($2.10)     903         2%
======================================================================

Note: Not shown above are collars covering 3.7 bcf of production in 2009 at an average floor and ceiling of $4.50 and $6.00.

The company also has the following crude oil swaps in place:

                                                   Total      Total
                                      Open Swap     Gains     Lifted
                                     Positions   (Losses)     Gain
                           Assuming     as a %      from      (Loss)
             Open  Avg.      Oil         of       Lifted    per bbl of
            Swaps   NYMEX Production  Estimated     Swaps   Estimated
             in    Strike in mbbls   Total Oil      ($      Total Oil
             mbbls  Price     of:     Production  millions) Production
======================================================================
Q4 2008(1)  1,214  $78.09   2,825        43%       ($2.3)    ($0.81)
======================================================================

======================================================================
Total
 2009(1)    5,728  $81.19   12,000       48%       $38.5      $3.21
======================================================================

======================================================================
Total
 2010(1)    4,745  $90.25   13,000       37%         --         --
======================================================================

(1) Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty's exposure below prices ranging from $45.00 to $60.00 covering 982 mbbls in 2008, from $50.00 to $60.00 covering 6,038 mbbls in 2009 and $60.00 covering 4,745 mbbls in 2010.

Note: Not shown above are written call options covering 768 mbbls of production in 2008 at a weighted average price of $85.86 for a weighted average premium of $4.05, 5,110 mbbls of production in 2009 at a weighed average price of $133.93 for a weighted average premium of $3.90 and 5,110 mbbls of production in 2010 at a weighed average price of $140.00 for a weighted average premium of $4.46.

    SCHEDULE "B"

    CHESAPEAKE'S PREVIOUS OUTLOOK AS OF OCTOBER 14, 2008

    (PROVIDED FOR REFERENCE ONLY)

    NOW SUPERSEDED BY OUTLOOK AS OF OCTOBER 30, 2008

Quarter Ending December 31, 2008 and Years Ending December 31, 2009 and 2010.

We have adopted a policy of periodically providing guidance on certain factors that affect our future financial performance. As of October 14, 2008, we are using the following key assumptions in our projections for the fourth quarter of 2008 and the full years 2009 and 2010.

The primary changes from our September 22, 2008 Outlook are in italicized bold and are explained as follows:

1) Projected effects of changes in our hedging positions have been updated;

2) Certain cost assumptions and budgeted capital expenditure assumptions have been updated;

3) Our NYMEX oil price assumption for realized hedging effects and estimating future operating cash flow has been reduced; and

4) Shares outstanding have been updated to remove the effects of certain contingent convertible senior notes that are not presently convertible at the current stock price level.

                             Quarter Ending Year Ending  Year Ending
                               12/31/2008    12/31/2009    12/31/2010
                             -------------- ------------ -------------
Estimated Production(a)
   Natural gas - bcf           197 - 201     893 - 913   1,032 - 1,072
   Oil - mbbls                   2,825         12,000       13,000
   Natural gas equivalent -
    bcfe                       214 - 218     965 - 985   1,110 -1,150

Daily natural gas equivalent
 midpoint - mmcfe                2,350         2,670         3,095

Year-over-year production
 increase                         5.9%         15.6%         15.9%

NYMEX Prices (b) (for calculation of realized hedging effects only):
   Natural gas - $/mcf           $7.82         $8.00         $8.00
   Oil - $/bbl                   $80.00        $80.00       $80.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices
 above):
   Natural gas - $/mcf           $1.48         $1.04         $0.82
   Oil - $/bbl                  ($2.82)        $2.42         $4.79
Estimated Differentials to
 NYMEX Prices:
   Natural gas - $/mcf          10 - 14%      10 - 14%     10 - 14%
   Oil - $/bbl                   5 - 7%        5 - 7%       5 - 7%
Operating Costs per Mcfe of Projected Production:
   Production expense         $1.00 - 1.10  $1.10 - 1.20 $1.15 - 1.25
   Production taxes (about
    5% of O&G revenues) (c)   $0.35 - 0.40  $0.35 - 0.40 $0.35 - 0.40
   General and
    administrative(d)         $0.33 - 0.37  $0.33 - 0.37 $0.33 - 0.37
   Stock-based compensation
    (non-cash)                $0.10 - 0.12  $0.10 - 0.12 $0.10 - 0.12
   DD&A of natural gas and
    oil assets                $2.30 - 2.35  $2.20 - 2.30 $2.15 - 2.25
   Depreciation of other
    assets                    $0.20 - 0.24  $0.20 - 0.24 $0.20 - 0.24
   Interest expense(e)        $0.30 - 0.35  $0.40 - 0.45 $0.35 - 0.40
Other Income per Mcfe:
   Natural gas and oil
    marketing income          $0.09 - 0.11  $0.09 - 0.11 $0.09 - 0.11
   Service operations income  $0.04 - 0.06  $0.04 - 0.06 $0.04 - 0.06
Book Tax Rate                    38.5%         38.5%         38.5%
Cash Income Taxes - in
 millions                      $350 - 450    $200 - 300   $200 - 300

Equivalent Shares
 Outstanding - in millions:
   Basic                       560 - 565     565 - 570     575 - 580
   Diluted                     580 - 585     585 - 590     595 - 600
Cash Flow
 Projections - in  Quarter Ending    Year Ending       Year Ending
 millions             12/31/2008       12/31/2009        12/31/2010
                   --------------- ----------------- -----------------
Net inflows:
------------------
  Operating cash
   flow before
   changes in
   assets and
   liabilities
   (f)(g)          $1,375 - 1,425   $5,800 - 6,000    $6,250 - 6,750
  Leasehold and
   producing
   property
   transactions:
------------------
     Sale of
      leasehold
      and
      producing
      properties
      (a)          $2,100 - 2,500   $1,250 - 2,000    $1,250 - 2,000
     Sale of
      producing
      properties
      via VPP's(a)   $400 - 500     $1,000 - 1,250    $1,000 - 1,250
     Acquisition
      of leasehold
      and
      producing
      properties   ($750 - $1,000) ($1,250 - $1,750) ($1,000 - $1,500)
------------------ --------------- ----------------- -----------------
     Net leasehold
      and
      producing
      property
      transactions $1,750 - 2,000   $1,000 - 1,500    $1,250 - 1,750
  Debt and equity
   offerings              -                -                 -
  Midstream
   financings      $1,050 - 1,275     $500 - 700        $500 - 700
  Proceeds from
   investments and
   other                  -           $500 - 750        $150 - 250
                   --------------- ----------------- -----------------
Total Cash Inflows $4,175 - 4,700   $7,800 - 8,950    $8,150 - 9,450
                   =============== ================= =================

Net outflows:
------------------
  Drilling         $1,200 - 1,300   $4,250 - 4,750    $4,750 - 5,250
  Geophysical
   costs                 $75          $225 - 275        $225 - 275
  Midstream
   infrastructure
   and compression   $300 - 325     $1,000 - 1,200     $900 - 1,000
  Other PP&E          $50 - 75        $250 - 300        $250 - 300
  Dividends,
   senior notes
   redemption,
   capitalized
   interest, etc.    $150 - 200       $575 - 600        $575 - 600
  Cash income
   taxes             $350 - 450       $200 - 300        $200 - 300
                   --------------- ----------------- -----------------
Total Cash
 Outflows          $2,125 - 2,425   $6,500 - 7,425    $6,900 - 7,725
                   =============== ================= =================

Net Cash Change    $2,050 - 2,275    $1,300 -1,525    $1,250 - 1,725
                   =============== ================= =================

(a) The 2008 fourth quarter production and cash flow forecasts reflect anticipated sales by the company of: 1) producing properties for approximately $450 million in a volumetric production payment (VPP); and 2) producing properties in South Texas and undeveloped leasehold in the Marcellus Shale and other areas for approximately $2.3 billion. The 2009 and 2010 production and cash flow forecasts reflect anticipated sales by the company of: 1) producing properties for approximately $1.1 billion in each year in VPP transactions; and 2) undeveloped leasehold or other producing properties for approximately $1.6 billion in each year.

(b) NYMEX natural gas prices have been updated for actual contract prices through October 2008.

(c) Severance tax per mcfe is based on NYMEX prices of $80.00 per bbl of oil and $7.50 to $8.50 per mcf of natural gas during Q4 2008; $80.00 per bbl of oil and $7.50 to $8.50 per mcf of natural gas during 2009; and $80.00 per bbl of oil and $7.50 to $8.50 per mcf of natural gas during 2010.

(d) Excludes expenses associated with noncash stock compensation.

(e) Does not include gains or losses on interest rate derivatives (SFAS 133).

(f) A non-GAAP financial measure. We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.

(g) Assumes NYMEX natural gas of $7.00 to $8.00 per mcf and NYMEX oil prices of $80.00 per bbl.

Commodity Hedging Activities

The company utilizes hedging strategies to hedge the price of a portion of its future natural gas and oil production.

These strategies include:

(i) For swap instruments, Chesapeake receives a fixed price and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

(ii) Basis protection swaps are arrangements that guarantee a price differential for oil or natural gas from a specified delivery point. For Mid-Continent basis protection swaps, which have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. For Appalachian basis protection swaps, which have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

(iii) For knockout swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty's exposure to zero, in any given month, if the floating market price is lower than certain predetermined knockout prices.

(iv) For cap-swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a "cap" limiting the counterparty's exposure. In other words, there is no limit to Chesapeake's exposure but there is a limit to the downside exposure of the counterparty

(v) For written call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake.

(vi) Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.

(vii) A three-way collar contract consists of a standard collar contract plus a written put option with a strike price below the floor price of the collar. In addition to the settlement of the collar, the put option requires Chesapeake to make a payment to the counterparty equal to the difference between the put option price and the settlement price if the settlement price for any settlement period is below the put option strike price.

Commodity markets are volatile, and as a result, Chesapeake's hedging activity is dynamic. As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction.

Chesapeake enters into natural gas and oil derivative transactions in order to mitigate a portion of its exposure to adverse market changes in natural gas and oil prices. Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to natural gas and oil sales. All realized gains and losses from natural gas and oil derivatives are included in natural gas and oil sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these nonqualifying derivatives that occur prior to their maturity (i.e., because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within natural gas and oil sales.

Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in natural gas and oil sales.

Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following open natural gas swaps in place and also has the following gains (losses) from lifted natural gas swaps:

                                    Open Swap
                                   Positions     Total    Total Lifted
                                       as a       Gains       Gain
                 Avg.    Assuming     % of     (Losses)   (Loss) per
                 NYMEX   Natural    Estimated     from       Mcf of
         Open   Strike      Gas      Total      Lifted     Estimated
          Swaps  Price  Production   Natural      Swaps      Total
          in    of Open in Bcf's      Gas         ($       Natural Gas
          Bcf's  Swaps      of:     Production  millions)  Production
======================================================================
Q4 2008  110.6   $9.30     199         56%       $79.70      $0.40
======================================================================

======================================================================
Total
 2009(1) 533.0   $9.46     903         59%      ($36.70)    ($0.04)
======================================================================

======================================================================
Total
 2010(1) 422.6   $9.58    1,052        40%       $33.90      $0.03
======================================================================

(1) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty's exposure below prices ranging from $5.45 to $6.50 covering 35 bcf in 2008, $5.45 to $7.25 covering 356 bcf in 2009 and $5.45 to $7.40 covering 318 bcf in 2010.

The company currently has the following open natural gas collars in place:

                                                         Open Collars
                                              Assuming     as a % of
                           Avg.      Avg.    Natural Gas  Estimated
                Open       NYMEX     NYMEX   Production      Total
                Collars   Floor    Ceiling    in Bcf's    Natural Gas
               in Bcf's    Price     Price       of:      Production
======================================================================
Q4 2008          26.6      $7.75     $9.32       199          13%
======================================================================

======================================================================
Total 2009(1)    63.9      $8.05    $11.18       903          7%
======================================================================

======================================================================
Total 2010(1)    25.6      $7.71    $11.46      1,052         2%
======================================================================

(1) Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.50 to $6.00 covering 38 bcf in 2009 and at $6.00 covering 4 bcf in 2010.

The company currently has the following natural gas written call options in place:

                                                         Call Options
                                                          as a % of
                                             Assuming     Estimated
             Call                 Avg.     Natural Gas       Total
            Options  Avg. NYMEX   Premium   Production   Natural Gas
           in Bcf's  Call Price  per mcf   in Bcf's of:   Production
======================================================================
Q4 2008      34.0      $10.39     $0.70        199           17%
======================================================================

======================================================================
Total 2009   225.5     $11.37     $0.61        903           25%
======================================================================

======================================================================
Total 2010   231.8     $10.77     $0.72       1,052          22%
======================================================================

The company has the following natural gas basis protection swaps in place:

                          Mid-Continent              Appalachia
                     -----------------------   -----------------------
                     Volume in     NYMEX       Volume in     NYMEX
                       Bcf's      less(1):       Bcf's      plus(1):
                     ---------  ------------   ---------  ------------
Q4 2008                   32.1    $     0.45         5.8    $     0.33
2009                      77.1          0.35        16.9          0.28
2010                        --            --        10.2          0.26
2011                      45.1          0.64        12.1          0.25
2012                      43.2          0.48          --            --
                     ---------  ------------   ---------  ------------
Totals                   197.5    $     0.46        45.0    $     0.27
                     =========  ============   =========  ============

(1) weighted average

We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition in November 2005. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($102 million as of June 30, 2008). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our natural gas and oil revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to natural gas and oil revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in natural gas and oil revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR.

Pursuant to SFAS 149 "Amendment of SFAS 133 on Derivative Instruments and Hedging Activities," the assumed CNR derivative instruments are deemed to contain a significant financing element and all cash flows associated with these positions are reported as financing activity in the statement of cash flows.

The following details the CNR derivatives (natural gas swaps) we have assumed:

                                                            Open Swap
                    Avg.                                    Positions
                    NYMEX                                     as a %
                   Strike   Avg. Fair             Assuming     of
                    Price  Value Upon             Natural    Estimated
             Open  Of Open Acquisition  Initial      Gas       Total
            Swaps   Swaps       of     Liability Production  Natural
             in     (per   Open Swaps  Acquired  in Bcf's       Gas
             Bcf's   Mcf)   (per Mcf)  (per Mcf)     of:    Production
======================================================================
Q4 2008      9.7    $4.66     $7.84     ($3.17)     199         5%
======================================================================

======================================================================
Total 2009   18.3   $5.18     $7.28     ($2.10)     903         2%
======================================================================

Note: Not shown above are collars covering 3.7 bcf of production in 2009 at an average floor and ceiling of $4.50 and $6.00.

The company also has the following crude oil swaps in place:

                                      Open Swap    Total      Total
                                     Positions     Losses     Lifted
                           Assuming     as a %     from     Losses per
            Open   Avg.      Oil         of        Lifted     bbl of
           Swaps   NYMEX  Production  Estimated    Swaps    Estimated
            in    Strike  in mbbls   Total Oil      ($      Total Oil
            mbbls  Price      of:     Production  millions) Production
======================================================================
Q4 2008(1) 1,702  $77.57    2,825        60%       ($4.7)    ($1.68)
======================================================================

======================================================================
Total
 2009(1)   8,364  $82.38    12,000       70%       ($0.6)    ($0.05)
======================================================================

======================================================================
Total
 2010(1)   4,745  $90.25    13,000       37%         --         --
======================================================================

(1) Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty's exposure below prices ranging from $45.00 to $60.00 covering 1,104 mbbls in 2008, from $52.50 to $60.00 covering 7,848 mbbls in 2009 and $60.00 covering 4,745 mbbls in 2010.

Note: Not shown above are written call options covering 890 mbbls of production in 2008 at a weighted average price of $86.43 for a weighted average premium of $3.63, 3,285 mbbls of production in 2009 at a weighed average price of $122.22 for a weighted average premium of $6.07 and 3,285 mbbls of production in 2010 at a weighed average price of $131.67 for a weighted average premium of $6.94.

CONTACT: Chesapeake Energy Corporation
Jeffrey L. Mobley, CFA, 405-767-4763
Senior Vice President - Investor Relations and Research
jeff.mobley@chk.com
or
Marc Rowland, 405-879-9232
Executive Vice President
and Chief Financial Officer
marc.rowland@chk.com
SOURCE: Chesapeake Energy Corporation