/FIRST ADD -- DATH033 -- Chesapeake Energy Corporation Earnings/
PRNewswire
                      CHESAPEAKE ENERGY CORPORATION
                  CONSOLIDATED STATEMENTS OF OPERATIONS
                   ($ in 000's, except per share data)
                               (unaudited)


  THREE MONTHS ENDED:                   June 30,                June 30,
                                         2006                    2005
                                     $        $/mcfe         $        $/mcfe

  REVENUES:
    Oil and natural gas sales    1,186,383      8.32       772,401     6.83
    Marketing sales                367,610      2.57       275,617     2.43
    Service operations revenue      30,023      0.21           ---      ---
      Total Revenues             1,584,016     11.10     1,048,018     9.26

  OPERATING COSTS:
    Production expenses            120,697      0.85        72,333     0.64
    Production taxes                33,923      0.24        47,253     0.42
    General and administrative
     expenses                       33,555      0.24        11,788     0.10
    Marketing expenses             355,688      2.48       270,003     2.39
    Service operations expense      15,667      0.11           ---      ---
    Oil and natural gas
     depreciation, depletion
     and amortization              328,159      2.30       209,371     1.85
    Depreciation and amortization
     of other assets                23,163      0.16        11,807     0.10
      Total Operating Costs        910,852      6.38       622,555     5.50

  INCOME FROM OPERATIONS           673,164      4.72       425,463     3.76

  OTHER INCOME (EXPENSE):
    Interest and other income
     4,974      0.03         2,005     0.02
    Interest expense               (73,456)    (0.51)      (53,902)   (0.48)
    Loss on repurchases or
     exchanges of Chesapeake debt      ---       ---       (68,400)   (0.60)
      Total Other Income (Expense) (68,482)    (0.48)     (120,297)   (1.06)

    Income Before Income Taxes     604,682      4.24       305,166     2.70

    Income Tax Expense:
      Current                          ---       ---           ---      ---
      Deferred                     244,779      1.72       111,387     0.99
        Total Income Tax Expense   244,779      1.72       111,387     0.99

  NET INCOME                       359,903      2.52       193,779     1.71

    Preferred stock dividends      (18,228)    (0.12)       (9,859)   (0.09)
    Loss on exchange/conversion
     of preferred stock             (9,547)    (0.07)       (4,743)   (0.04)

  NET INCOME AVAILABLE
   TO COMMON SHAREHOLDERS          332,128      2.33       179,177     1.58

  EARNINGS PER COMMON SHARE:

    Basic                            $0.87                   $0.58
    Assuming dilution                $0.82                   $0.52

  WEIGHTED AVERAGE COMMON
   AND COMMON EQUIVALENT SHARES
   OUTSTANDING (in 000's)

    Basic                          380,675                 311,181
    Assuming dilution              428,169                 364,063



                      CHESAPEAKE ENERGY CORPORATION
                  CONSOLIDATED STATEMENTS OF OPERATIONS
                   ($ in 000's, except per share data)
                               (unaudited)

  SIX MONTHS ENDED:                        June 30,            June 30,
                                             2006                2005
                                           $     $/mcfe       $      $/mcfe

  REVENUES:
    Oil and natural gas sales          2,697,204   9.66   1,311,343   6.01
    Marketing sales                      771,977   2.76     520,125   2.39
    Service operations revenue            59,402   0.21         ---    ---
      Total Revenues                   3,528,583  12.63   1,831,468   8.40

  OPERATING COSTS:
    Production expenses                  240,089   0.86     141,895   0.65
    Production taxes                      89,296   0.32      83,211   0.38
    General and administrative expenses   62,346   0.22      23,855   0.11
    Marketing expenses                   747,048   2.67     507,279   2.33
    Service operations expense            30,104   0.11         ---    ---
    Oil and natural gas depreciation,
     depletion and amortization          633,116   2.27     390,339   1.79
    Depreciation and amortization
     of other assets                      47,035   0.17      21,889   0.10
    Employee retirement expense           54,753   0.20         ---    ---

      Total Operating Costs            1,903,787   6.82   1,168,468   5.36

  INCOME FROM OPERATIONS               1,624,796   5.81     663,000   3.04

  OTHER INCOME (EXPENSE):
    Interest and other income             14,610   0.05       5,362   0.02
    Interest expense                    (146,114) (0.52)    (97,030) (0.44)
    Gain on sale of investment           117,396   0.42         ---    ---
    Loss on repurchases or exchanges
     of Chesapeake debt                      ---    ---     (69,300)  (0.32)
      Total Other Income (Expense)       (14,108) (0.05)   (160,968)  (0.74)

    Income Before Income Taxes         1,610,688   5.76     502,032    2.30

    Income Tax Expense:
      Current                                ---    ---         ---     ---
      Deferred                           627,062   2.24     183,243    0.84
        Total Income Tax Expense         627,062   2.24     183,243    0.84

  NET INCOME                             983,626   3.52     318,789    1.46
    Preferred stock dividends            (37,040) (0.13)    (15,322)  (0.07)
    Loss on exchange/conversion
      of preferred stock                 (10,556) (0.04)     (4,743)  (0.02)

  NET INCOME AVAILABLE TO COMMON
   SHAREHOLDERS                          936,030   3.35     298,724    1.37

  EARNINGS PER COMMON SHARE:
    Basic                                  $2.50              $0.96
    Assuming dilution                      $2.27              $0.88


  WEIGHTED AVERAGE COMMON AND COMMON
   EQUIVALENT SHARES OUTSTANDING (in 000's)

    Basic                                374,683            310,523
    Assuming dilution                    433,414            356,478



                      CHESAPEAKE ENERGY CORPORATION
                       CONSOLIDATED BALANCE SHEETS
                                (in 000's)
                               (unaudited)
                                                  June 30,    December 31,
                                                    2006           2005


  Cash                                            $366,270        $60,027
  Other current assets                           1,289,467      1,123,370
    Total Current Assets                         1,655,737      1,183,397

  Property and equipment (net)                  17,775,369     14,411,887
  Other assets                                     629,945        523,178
    Total Assets                               $20,061,051    $16,118,462

  Current liabilities                           $1,776,469     $1,964,088
  Long term debt                                 6,330,115      5,489,742
  Asset retirement obligation                      171,430        156,593
  Other long term liabilities                      357,120        528,738
  Deferred tax liability                         2,435,731      1,804,978
    Total Liabilities                           11,070,865      9,944,139

  STOCKHOLDERS' EQUITY                           8,990,186      6,174,323

  TOTAL LIABILITIES & STOCKHOLDERS' EQUITY     $20,061,051    $16,118,462

  COMMON SHARES OUTSTANDING                        418,876        370,190



CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF SIX MONTHS ENDED JUNE 30, 2006 ADDITIONS TO OIL AND NATURAL

                              GAS PROPERTIES
                  ($ in 000's, except per unit amounts)
                               (unaudited)
                                                         Reserves
                                              Cost      (in mmcfe)    $/mcfe


  Exploration and development costs       $1,338,205     786,027(A)    $1.70
  Acquisition of proved properties
        494,278     269,239       $1.84
    Subtotal                               1,832,483   1,055,266       $1.74

  Divestitures                                   (73)        (89)        ---
  Geological and geophysical costs            71,675         ---         ---
    Adjusted subtotal                      1,904,085   1,055,177       $1.80

  Revisions - price                              ---    (195,541)        ---
  Acquisition of unproved properties       1,256,132         ---         ---
  Leasehold acquisition costs                323,856         ---         ---
    Adjusted subtotal                      3,484,073     859,636       $4.05

  Tax basis step-up                           81,373         ---
  Asset retirement obligation and other       11,774         ---
    Total                                 $3,577,220     859,636       $4.16

   (A) Includes positive performance revisions of 352 bcfe and excludes
       downward revisions of 196 bcfe resulting from natural gas price
       declines between December 31, 2005 and June 30, 2006.



                      CHESAPEAKE ENERGY CORPORATION
                     ROLL-FORWARD OF PROVED RESERVES
                               (unaudited)
                                                         Mmcfe

    Beginning balance, 12/31/05                         7,520,690
    Extensions and discoveries                            434,414
    Acquisitions                                          269,239
    Divestitures                                              (89)
    Revisions - performance                               351,613
    Revisions - price                                    (195,541)
    Production                                           (279,428)
    Ending balance, 6/30/06                             8,100,898

    Reserve replacement                                   859,636
    Reserve replacement rate                                  308%



                      CHESAPEAKE ENERGY CORPORATION
    SUPPLEMENTAL DATA - OIL AND NATURAL GAS SALES AND INTEREST EXPENSE
                                (in 000's)
                               (unaudited)

                                 THREE MONTHS ENDED       SIX MONTHS ENDED
                                       June 30,                June 30,
                                   2006       2005        2006        2005

  Oil and Natural Gas Sales
  ($ in thousands):
    Oil sales                   $138,241    $96,798    $262,908    $176,742
    Oil derivatives
     - realized gains (losses)   (12,227)   (10,650)    (16,035)    (17,717)
    Oil derivatives - unrealized
     gains (losses)               (2,564)    10,900      (3,899)     (1,942)

      Total Oil Sales            123,450     97,048     242,974     157,083

    Natural gas sales            774,259    635,901   1,714,577   1,171,678
    Natural gas derivatives -
     realized gains (losses)     269,650    (33,702)    521,679      13,713

    Natural gas derivatives -
     unrealized gains (losses)    19,024     73,154     217,974     (31,131)

      Total Natural Gas Sales  1,062,933    675,353   2,454,230   1,154,260
      Total Oil and Natural
       Gas Sales              $1,186,383   $772,401  $2,697,204  $1,311,343

  Average Sales Price
   (excluding gains (losses)
    on derivatives):
    Oil ($ per bbl)               $64.51     $48.11      $61.73      $47.03
    Natural gas ($ per mcf)        $5.96      $6.29       $6.75       $6.00
    Natural gas equivalent
     ($ per mcfe)                  $6.40      $6.47       $7.08       $6.19

  Average Sales Price
   (excluding unrealized gains
   (losses) on derivatives):
    Oil ($ per bbl)               $58.80     $42.82      $57.97      $42.32
    Natural gas ($ per mcf)        $8.04      $5.95       $8.81       $6.07
    Natural gas equivalent
     ($ per mcfe)                  $8.20      $6.08       $8.89       $6.17

  Interest Expense
  ($ in thousands)
    Interest                     $73,834    $54,710    $146,732    $102,003
    Derivatives - realized
     (gains) losses
            (1,163)      (675)     (2,407)     (1,796)
    Derivatives - unrealized
     (gains) losses                  785       (133)      1,789      (3,177)
      Total Interest Expense     $73,456    $53,902    $146,114     $97,030



                      CHESAPEAKE ENERGY CORPORATION
                  CONDENSED CONSOLIDATED CASH FLOW DATA
                                (in 000's)
                               (unaudited)

   THREE MONTHS ENDED:                          June 30,         June 30,
                                                  2006             2005

   Cash provided by operating activities    $   1,077,686    $    507,232

   Cash (used in) investing activities         (1,823,996)     (1,365,941)

   Cash provided by financing activities        1,074,294         858,709


   SIX MONTHS ENDED:                             June 30,          June 30,
                                                   2006              2005

   Cash provided by operating activities    $   2,045,144    $    1,019,917

   Cash (used in) investing activities         (3,784,057)       (2,539,878)

   Cash provided by financing activities        2,045,156         1,513,065



                      CHESAPEAKE ENERGY CORPORATION
             RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
                                (in 000's)
                               (unaudited)

   THREE MONTHS ENDED:                       June 30,   March 31,  June 30,
                                              2006        2006      2005

   CASH PROVIDED BY OPERATING ACTIVITIES  $1,077,686  $  967,458  $507,232

   Adjustments:
       Changes in assets and liabilities    (163,520)     79,405   (53,498)

   OPERATING CASH FLOW*                   $  914,166  $1,046,863  $453,734

* 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 an oil and natural gas 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 oil and natural gas 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.

   THREE MONTHS ENDED:                   June 30,      March 31,   June 30,
                                           2006          2006        2005

   NET INCOME                          $  359,903    $  623,723    $193,779

   Income tax expense                     244,779       382,283     111,387
   Interest expense                        73,456        72,658      53,902
   Depreciation and amortization
    of other assets                        23,163        23,872      11,807
   Oil and natural gas depreciation,
    depletion and amortization            328,159       304,957     209,371

   EBITDA**                            $1,029,460    $1,407,493    $580,246

** Ebitda represents net income 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:

   THREE MONTHS ENDED:                   June 30,     March 31,   June 30,
                                           2006         2006        2005

   CASH PROVIDED BY OPERATING
    ACTIVITIES                        $1,077,686      $967,458    $507,232

   Changes in assets and liabilities    (163,520)       79,405     (53,498)
   Interest expense                       73,456        72,658      53,902
   Unrealized gains (losses) on oil
    and natural gas derivatives           16,460       197,615      84,054
   Other non-cash items                   25,378        90,357     (11,444)

   EBITDA                             $1,029,460    $1,407,493    $580,246



                      CHESAPEAKE ENERGY CORPORATION
             RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
                                (in 000's)
                               (unaudited)

   SIX MONTHS ENDED:                               June 30,       June 30,
                                                     2006           2005

   CASH PROVIDED BY OPERATING ACTIVITIES         $2,045,144     $1,019,917

   Adjustments:
     Changes in assets and liabilities              (84,115)       (61,561)

   OPERATING CASH FLOW*                          $1,961,029       $958,356

* 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 an oil and natural gas 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 oil and natural gas 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.

  SIX MONTHS ENDED:                               June 30,       June 30,
                                                    2006           2005

   NET INCOME                                     $983,626       $318,789

   Income tax expense                              627,062        183,243
   Interest expense                                146,114         97,030
   Depreciation and amortization of other assets    47,035         21,889
   Oil and natural gas depreciation, depletion
    and amortization                               633,116        390,339

   EBITDA**                                     $2,436,953     $1,011,290

** Ebitda represents net income 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:

   SIX MONTHS ENDED:                               June 30,      June 30,
                                                     2006          2005
   CASH PROVIDED BY OPERATING ACTIVITIES         $2,045,144    $1,019,917

   Changes in assets and liabilities                (84,115)      (61,561)
   Interest expense                                 146,114        97,030
   Unrealized gains (losses) on oil
    and natural gas derivatives                     214,075       (33,073)
   Other non-cash items                             115,735       (11,023)
   EBITDA                                        $2,436,953    $1,011,290



                      CHESAPEAKE ENERGY CORPORATION
        RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON
                  ($ in 000's, except per share amounts)
                               (unaudited)

                                      June 30,      March 31,     June 30,
  THREE MONTHS ENDED:                   2006          2006          2005

  Net income available
   to common shareholders           $  332,128    $  603,902    $  179,177

  Adjustments:
    Loss on conversion/exchange
     of preferred stock                  9,547         1,009         4,743
    Unrealized (gains) losses
     on derivatives, net of tax         (9,720)     (121,899)      (53,458)
    Cumulative impact of new Texas
     margin tax                         15,000           ---           ---
    Reversal of severance tax accrual,
     net of tax                         (7,192)          ---           ---
    Gain on sale of investment,
     net of tax                            ---       (72,786)          ---
    Employee retirement expense,
     net of tax                            ---        33,947           ---
    Loss on repurchases or exchanges
     of debt, net of tax                   ---           ---        43,434

  Adjusted net income available
   to common shareholders*             339,763       444,173       173,896
    Preferred dividends                 18,228        18,812         9,859

  Total adjusted net income         $  357,991    $  462,985    $  183,755

  Weighted average fully diluted
   shares outstanding**                434,915       431,723       366,677

  Adjusted earnings per share
   assuming dilution                $     0.82    $     1.07    $     0.50


* 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
       oil and natural gas 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.

** Weighted average fully diluted shares outstanding includes shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

                      CHESAPEAKE ENERGY CORPORATION
                    RECONCILIATION OF ADJUSTED EBITDA
                               ($ in 000's)
                               (unaudited)

                                       June 30,      March 31,     June 30,
  THREE MONTHS ENDED:                    2006           2006         2005

  EBITDA                            $ 1,029,460    $ 1,407,493    $ 580,246

  Adjustments, before tax:
    Unrealized (gains) losses on oil
     and natural gas derivatives        (16,460)      (197,615)     (84,054)
    Reversal of severance tax accrual   (11,600)           ---          ---
    Gain on sale of investment              ---       (117,396)         ---
    Employee retirement expense             ---         54,753          ---
    Loss on repurchases or exchanges
     of debt                                ---            ---       68,400

  Adjusted EBITDA*                  $ 1,001,400    $ 1,147,235    $ 564,592

* 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 oil and natural gas
       producing companies.
   b.  Adjusted EBITDA 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.



                      CHESAPEAKE ENERGY CORPORATION
        RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON
                  ($ in 000's, except per share amounts)
                               (unaudited)

                                                       June 30,     June 30,
  SIX MONTHS ENDED:                                      2006         2005

  Net income available to common shareholders         $ 936,030    $ 298,724

  Adjustments:
      Loss on conversion/exchange of preferred stock     10,556        4,743
      Unrealized (gains) losses on derivatives,
       net of tax                                      (131,619)      18,985
      Cumulative impact of new Texas margin tax          15,000          ---
      Reversal of severance tax accrual, net of tax      (7,192)         ---
      Gain on sale of investment, net of tax            (72,786)         ---
      Employee retirement expense, net of tax            33,947          ---
      Loss on repurchases or exchanges of debt,
       net of tax                                           ---       44,006

  Adjusted net income available
   to common shareholders*                              783,936      366,458
      Preferred dividends                                37,040       15,322

  Total adjusted net income                           $ 820,976    $ 381,780

  Weighted average fully diluted shares outstanding**   433,414      359,136

  Adjusted earnings per share assuming dilution       $    1.89    $    1.06


* 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
       oil and natural gas 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.

** Weighted average fully diluted shares outstanding includes shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

                      CHESAPEAKE ENERGY CORPORATION
                    RECONCILIATION OF ADJUSTED EBITDA
                               ($ in 000's)
                               (unaudited)

                                                    June 30,       June 30,
  SIX MONTHS ENDED:                                   2006           2005

  EBITDA                                         $ 2,436,953    $ 1,011,290

   Adjustments, before tax:
      Unrealized (gains) losses on oil
       and natural gas derivatives                  (214,075)        33,073
      Reversal of severance tax accrual              (11,600)           ---
      Gain on sale of investment                    (117,396)           ---
      Employee retirement expense                     54,753            ---
      Loss on repurchases or exchanges of debt           ---         69,300

   Adjusted EBITDA*                              $ 2,148,635    $ 1,113,663

*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 oil and natural gas
       producing companies.
   b.  Adjusted EBITDA 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.



                               SCHEDULE "A"

                 CHESAPEAKE'S OUTLOOK AS OF JULY 27, 2006

Quarter Ending September 30, 2006; Year Ending December 31, 2006; Year Ending

December 31, 2007.

We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of July 27, 2006, we are using the following key assumptions in our projections for the third quarter of 2006, the full-year 2006 and the full-year 2007.

The primary changes from our June 5, 2006 Outlook are in italicized bold in the table and are explained as follows:

   1)  We have updated the projected effect of changes in our hedging
       positions;
   2)  Production, certain costs and capital expenditure assumptions have
       been updated;
   3)  We have shown our projections for the quarter ending September 30,
       2006 for the first time.



                             Quarter Ending   Year Ending      Year Ending
                               9/30/2006      12/31/2006        12/31/2007

  Estimated Production (A):
    Oil - mbbls                 2,000           8,400             8,400
    Natural gas - bcf         136 - 140       531 - 541         595 - 605
    Natural gas
     equivalent - bcfe        148 - 152       581 - 591         645 - 655
    Daily natural gas
     equivalent midpoint
     - in mmcfe                 1,630           1,605             1,781
  NYMEX Prices (B) (for
   calculation of realized
   hedging effects only):
    Oil - $/bbl                $56.25          $61.67            $56.25
    Natural gas - $/mcf         $6.96           $7.57             $7.50
  Estimated Realized Hedging
   Effects (based on assumed
   NYMEX prices above):
    Oil - $/bbl                 $7.26           $1.92            $11.43
    Natural gas - $/mcf         $1.89           $1.99             $1.89
  Estimated Differentials
   to NYMEX Prices:
    Oil - $/bbl                 6 - 8%          7 - 9%            6 - 8%
    Natural gas - $/mcf         8 - 12%        10 - 15%           9 - 13%
  Operating Costs per Mcfe
   of Projected Production:
    Production expense       $0.85-0.95      $0.85-0.95        $0.90-1.00
    Production taxes
     (generally 6.0% of
     O&G revenues) (C)       $0.38-0.42      $0.41-0.46        $0.41-0.46
    General and
     administrative          $0.15-0.20      $0.15-0.20        $0.15-0.20
    Stock-based compensation
     (non-cash)              $0.05-0.07      $0.06-0.08        $0.08-0.10
    DD&A of oil and natural
     gas assets              $2.35-2.40      $2.30-2.40        $2.40-2.50
    Depreciation of
     other assets            $0.18-0.22      $0.18-0.22        $0.24-0.28
    Interest expense (D)     $0.55-0.59      $0.54-0.58        $0.60-0.65
  Other Income per Mcfe:
    Marketing and
     other income            $0.02-0.04      $0.04-0.06        $0.04-0.06
    Service operations
     income                  $0.10-0.12      $0.08-0.12        $0.10-0.15

  Book Tax Rate (approximately
   equal to 95% deferred)        38%             38%               38%

  Equivalent Shares Outstanding:
    Basic                      418 mm          397 mm            423 mm
    Diluted                    484 mm          459 mm            488 mm
  Capital Expenditures:
    Drilling, leasehold
     and seismic           $900-1,100 mm   $3,700-4,000 mm   $3,800-4,100 mm

   (A)  Production forecast for Q3 2006 and calendar 2006 excludes
        provisions for possible production curtailments that the industry
        and Chesapeake may experience as a result of high pipeline pressures
        and/or early filling of U.S. natural gas storage facilities.
   (B)  Oil NYMEX prices have been updated for actual contract prices
        through June 2006 and natural gas NYMEX prices have been updated for
        actual contract prices through July 2006.
   (C)  Severance tax per mcfe is based on NYMEX prices of $56.25 per bbl of
        oil and $6.80 to $7.60 per mcf of natural gas during Q3 2006, $57.35
        per bbl of oil and $7.50 to $8.50 per mcf of natural gas during
        calendar 2006 and $56.25 per bbl of oil and $7.50 to $8.50 per mcf
        of natural gas during calendar 2007.
   (D)  Does not include gains or losses on interest rate derivatives (SFAS
        133).

  Commodity Hedging Activities

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

   (i)   For swap instruments, we receive a fixed price for the hedged
         commodity and pay a floating market price, as defined in each
         instrument, 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)  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.
   (iii) Basis protection swaps are arrangements that guarantee a price
         differential of oil or natural gas from a specified delivery point.
         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.

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 oil and natural gas derivative transactions in order to mitigate a portion of its exposure to adverse market changes in oil and natural gas prices. Accordingly, associated gains or loses from the derivative transactions are reflected as adjustments to oil and natural gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and natural gas 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 non-qualifying 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 oil and natural gas 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 oil and natural gas sales.

Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following natural gas swaps in place:

                                                             % Hedged
                                                                   Open Swap
                                                                   Positions
                                           Avg. NYMEX              as a % of
                                             Price                 Estimated
                   Avg. NYMEX              Including   Assuming      Total
                  Strike Price Gain (Loss)   Open &   Natural Gas   Natural
         Open Swaps  Of Open  from Locked    Locked   Production      Gas
          in Bcf's    Swaps      Swaps     Positions in Bcf's of: Production
  2006:
  Q1        93.8     $10.81     -$0.09      $10.72      124.1         76%
  Q2       101.4      $8.82     -$0.05       $8.77      129.8         78%
  Q3       117.9      $8.80     -$0.05       $8.75      138.0         85%
  Q4       114.9      $9.46     -$0.04       $9.42      144.1         80%
  Total
   2006(A) 428.0      $9.42     -$0.05       $9.37      536.0         80%

  Total
   2007    392.1      $9.99     -$0.03       $9.96      600.0         65%

  Total
   2008    329.4      $9.53        ---       $9.53      642.0         51%

  Total
   2009      3.7      $9.02        ---       $9.02      687.0          1%

   (A)  Certain hedging arrangements include swaps with knockout prices
        ranging from $3.75 to $5.50 covering 43.0 bcf in 2006, $5.75 to
        $6.50 covering 53.9 bcf in 2007 and $5.75 to $6.50 covering 69.5 bcf
        in 2008, respectively.

Note: Not shown above are collars covering 0.2 bcf of production in 2006 at a weighted average floor and ceiling of $6.00 and $9.70 and call options covering 7.3 bcf of production in 2006 at a weighted average price of $12.50, 25.6 bcf of production in 2007 at a weighted average price of $10.53 and 7.3 bcf of production in 2008 at a weighed average price of $12.50.

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

                      Mid-Continent                      Appalachia
            Volume in Bcf's   NYMEX less*:    Volume in Bcf's   NYMEX plus*:
  2006          130.1            $0.32              ---             $---
  2007          137.2             0.33             36.5             0.35
  2008          118.6             0.27             36.6             0.35
  2009           86.6             0.29             18.2             0.31
  Totals        472.5            $0.30             91.3            $0.34
  * 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 ($469 million as of June 30, 2006). 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas 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 derivative instruments assumed in connection with the CNR acquisition 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:

                                                          % Hedged
                                                                  Open Swap
                 Avg. NYMEX  Avg. Fair                            Positions
                   Strike    Value Upon                             as a %
                    Price   Acquisition  Initial     Assuming   of Estimated
                   Of Open    of Open   Liability   Natural Gas     Total
        Open Swaps  Swaps      Swaps     Acquired   Production   Natural Gas
         in Bcf's (per Mcf)  (per Mcf)  (per Mcf)  in Bcf's of:  Production
  2006:
  Q1       7.9      $4.91     $12.14     ($7.23)       124.1          6%
  Q2      10.5      $4.86      $9.97     ($5.11)       129.8          8%
  Q3      10.6      $4.86      $9.95     ($5.09)       138.0          8%
  Q4      10.6      $4.86     $10.38     ($5.52)       144.1          7%
  Total
   2006   39.6      $4.87     $10.51     ($5.64)       536.0          7%

  Total
   2007   42.0      $4.82      $9.18     ($4.36)       600.0          7%

  Total
   2008   38.4      $4.67      $8.01     ($3.34)       642.0          6%

  Total
   2009   18.3      $5.18      $7.28     ($2.10)       687.0          3%

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, respectively.

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

                                                     % Hedged
                                                             Open Swap
                                                             Positions
                                 Avg.        Assuming Oil  as % of Total
            Open Swaps          NYMEX         Production     Estimated
             in mbbls        Strike Price    in mbbls of:   Production
  2006:
  Q1         1,109.5           $60.03            2,116          52%
  Q2         1,379.5           $61.85            2,143          64%
  Q3         1,747.0           $64.83            2,000          87%
  Q4         1,840.0           $65.64            2,141          86%
  Total
   2006(A)   6,076.0           $63.52            8,400          72%
  Total
   2007      6,110.0           $71.42            8,400          73%
  Total
   2008      5,032.0           $71.45            8,000          63%
  Total
   2009        182.5           $66.10            8,000           2%

   (A)  Certain hedging arrangements include swaps with knockout prices
        ranging from $40.00 to $60.00 covering 654.5 mbbls in 2006, $45.00
        to $60.00 covering 1,460.0 mbbls in 2007 and $45.00 to $60.00
        covering 1,098.0 mbbls in 2008, respectively.



                               SCHEDULE "B"

             CHESAPEAKE'S PREVIOUS OUTLOOK AS OF JUNE 5, 2006
                      (PROVIDED FOR REFERENCE ONLY)

              NOW SUPERSEDED BY OUTLOOK AS OF JULY 27, 2006

 Quarter Ending June 30, 2006; Year Ending December 31, 2006; Year Ending
                            December 31, 2007.

We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of June 5, 2006, we are using the following key assumptions in our projections for the second quarter of 2006, the full-year 2006 and the full-year 2007.

The primary changes from our May 1, 2006 Outlook are in italicized bold in the table and are explained as follows:

   1) We have updated the projected effect of changes in our hedging
      positions;
   2) Production, certain costs and capital expenditures have increased as a
      result of the acquisitions announced today; and
   3) Share count has been adjusted to reflect our tender offer to convert
      our 4.125% preferred stock and 5.0% preferred stock to common stock,
      recent repurchases of common stock and an expected preferred equity
      offering in the near future.




                               Quarter Ending   Year Ending   Year Ending
                                  6/30/2006      12/31/2006    12/31/2007
  Estimated Production:
    Oil - mbbls                     2,000           8,000         8,000
    Natural gas - bcf             127 - 132       533 - 543     592 - 602
    Natural gas equivalent - bcfe 139 - 144       581 - 591     640 - 650
    Daily natural gas equivalent
     midpoint -in mmcfe             1,555           1,605         1,767

  NYMEX Prices(A) (for
   calculation of realized
   hedging effects only):
    Oil - $/bbl                    $58.39          $56.72        $52.50
    Natural gas - $/mcf             $7.16           $7.54         $7.00

  Estimated Realized Hedging
   Effects (based on assumed
   NYMEX prices above):
    Oil - $/bbl                     $2.62           $4.83         $9.39
    Natural gas - $/mcf             $1.68           $2.00         $2.19

  Estimated Differentials to
   NYMEX Prices:
    Oil - $/bbl                     6 - 8%          6 - 8%        6 - 8%
    Natural gas - $/mcf             8 - 12%         9 - 13%       9 - 13%

  Operating Costs per Mcfe of
   Projected Production:
    Production expense          $0.85 - 0.95    $0.85 - 0.95  $0.90 - 1.00
    Production taxes
     (generally 6.0% of
    O&G revenues)(B)            $0.40 - 0.45    $0.41 - 0.46  $0.36 - 0.41
    General and administrative  $0.15 - 0.20    $0.15 - 0.20  $0.15 - 0.20
    Stock-based compensation
     (non-cash)                 $0.05 - 0.07    $0.06 - 0.08  $0.08 - 0.10
    DD&A of oil and natural
     gas assets                 $2.25 - 2.35    $2.30 - 2.40  $2.40 - 2.50
    Depreciation of other
     assets                     $0.16 - 0.20    $0.18 - 0.22  $0.24 - 0.28
    Interest expense(C)         $0.52 - 0.57    $0.52 - 0.57  $0.53 - 0.58
  Other Income per Mcfe:
    Marketing and other income  $0.02 - 0.04    $0.04 - 0.06  $0.04 - 0.06
    Service operations income   $0.10 - 0.15    $0.10 - 0.15  $0.10 - 0.15

  Book Tax Rate (approximately
   95% deferred)                   37.5%           37.5%         37.5%

  Equivalent Shares Outstanding:
    Basic                          379 mm          380 mm        389 mm
    Diluted                        434 mm          441 mm        452 mm

  Capital Expenditures:
    Drilling, leasehold
     and seismic                 $900-1,000    $3,500-3,800   $3,500-3,800
                                     mm              mm             mm

  (A) Oil NYMEX prices have been updated for actual contract prices through
      April 2006 and natural gas NYMEX prices have been updated for actual
      contract prices through May 2006.
  (B) Severance tax per mcfe is based on NYMEX prices of $58.39 per bbl of
      oil and $7.20 to $8.20 per mcf of natural gas during Q2 2006, $56.72
      per bbl of oil and $7.35 to $8.35 per mcf of natural gas during
      calendar 2006, and $52.50 per bbl of oil and $6.50 to $7.50 per mcf of
      natural gas during calendar 2007.
  (C) Does not include gains or losses on interest rate derivatives (SFAS
      133).

  Commodity Hedging Activities

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

    (i) For swap instruments, we receive a fixed price for the hedged
        commodity and pay a floating market price, as defined in each
        instrument, 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) 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.
  (iii) Basis protection swaps are arrangements that guarantee a price
        differential of oil or natural gas from a specified delivery point.
        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.

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 oil and natural gas derivative transactions in order to mitigate a portion of its exposure to adverse market changes in oil and natural gas prices. Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to oil and natural gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and natural gas 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 non-qualifying 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 oil and natural gas 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 oil and natural gas sales.

Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following natural gas swaps in place:

                                                             % Hedged
                                                                   Open Swap
                                                                   Positions
                                           Avg. NYMEX              as a % of
                                             Price                 Estimated
                   Avg. NYMEX              Including   Assuming      Total
                  Strike Price Gain (Loss)   Open &   Natural Gas   Natural
         Open Swaps  Of Open  from Locked    Locked   Production      Gas
          in Bcf's    Swaps      Swaps     Positions in Bcf's of: Production
  2006:
  Q1        93.8     $10.81     -$0.09      $10.72      124.1         76%
  Q2       101.4      $8.82     -$0.05       $8.77      129.5         78%
  Q3       117.9      $8.80     -$0.05       $8.75      138.5         85%
  Q4       114.9      $9.46     -$0.04       $9.42      145.9         79%
  Total
   2006(A) 428.0      $9.42     -$0.05       $9.37      538.0         80%

  Total
   2007(A) 370.2      $9.98     -$0.04       $9.94      597.0         62%

  Total
   2008(A) 311.1      $9.50        ---       $9.50      637.0         49%

  Total
   2009      3.7      $9.02        ---       $9.02      682.0          1%

   (A)  Certain hedging arrangements include swaps with knockout prices
        ranging from $3.75 to $5.50 covering 43.0 bcf in 2006, $5.75 to
        $6.50 covering 32.0 bcf in 2007 and $5.75 to $6.50 covering 51.2 bcf
        in 2008, respectively.

Note: Not shown above are collars covering 0.2 bcf of production in 2006 at a weighted average floor and ceiling of $6.00 and $9.70 and call options covering 7.3 bcf of production in 2006 at a weighted average price of $12.50, 25.6 bcf of production in 2007 at a weighted average price of $10.53 and 7.3 bcf of production in 2008 at a weighed average price of $12.50.

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

                    Mid-Continent                      Appalachia
           Volume in Bcf's  NYMEX less*:    Volume in Bcf's   NYMEX plus*:
  2006          130.1          $0.32               ---           $---
  2007          137.2           0.33              36.5           0.35
  2008          118.6           0.27              36.6           0.35
  2009           86.6           0.29              18.2           0.31
  Totals        472.5          $0.30              91.3          $0.34
   * weighted average


We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($523 million as of March 31, 2006). 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas 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 derivative instruments assumed in connection with the CNR acquisition 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:

                                                          % Hedged
                                                                  Open Swap
                 Avg. NYMEX  Avg. Fair                            Positions
                   Strike    Value Upon                             as a %
                    Price   Acquisition  Initial     Assuming   of Estimated
                   Of Open    of Open   Liability   Natural Gas     Total
        Open Swaps  Swaps      Swaps     Acquired   Production   Natural Gas
         in Bcf's (per Mcf)  (per Mcf)   (per Mcf) in Bcf's of:  Production
  2006:
  Q1       7.9      $4.91     $12.14      ($7.23)     124.1          6%
  Q2      10.5      $4.86      $9.97      ($5.11)     129.5          8%
  Q3      10.6      $4.86      $9.95      ($5.09)     138.5          8%
  Q4      10.6      $4.86     $10.38      ($5.52)     145.9          7%
  Total
   2006   39.6      $4.87     $10.51      ($5.64)     538.0          7%

  Total
   2007   42.0      $4.82      $9.18      ($4.36)     597.0          7%

  Total
   2008   38.4      $4.67      $8.01      ($3.34)     637.0          6%

  Total
   2009   18.3      $5.18      $7.28      ($2.10)     682.0          3%

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, respectively.

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

                                                     % Hedged
                                                             Open Swap
                                                             Positions
                                 Avg.        Assuming Oil  as % of Total
            Open Swaps          NYMEX         Production     Estimated
             in mbbls        Strike Price    in mbbls of:   Production
  2006:
  Q1         1,109.5           $60.03           2,116           52%
  Q2         1,379.5           $61.85           2,000           69%
  Q3         1,625.0           $63.90           1,942           84%
  Q4         1,656.0           $63.76           1,942           85%
  Total
   2006(A)   5,770.0           $62.63           8,000           72%
  Total
   2007      4,452.0           $68.79           8,000           56%
  Total
   2008      3,843.0           $69.50           8,000           48%
  Total
   2009        182.5           $66.26           8,000            2%

   (A)  Certain hedging arrangements include swaps with knockout prices
        ranging from $40.00 to $42.00 covering 501.5 mbbls in 2006, $45.00
        covering 182.5 mbbls in 2007 and $45.00 covering 183.0 mbbls in
        2008, respectively.

PRNewswire -- July 27
END FIRST AND FINAL ADD

SOURCE: Chesapeake Energy Corporation