Chesapeake Energy Corporation Reports Strong Operating and Financial Results for the 2005 Third Quarter
Company Reports 2005 Third Quarter Net Income Available to Common Shareholders of $149 Million on Revenue of $1.1 Billion and Production of 120 Bcfe
Oil and Natural Gas Production Reaches 1.308 Bcfe per Day, a 28% Increase Over 2004 Third Quarter and 5% Over 2005 Second Quarter; 2005 Total Production Growth Expected to Exceed 25%; 2005 and 2006 Organic Growth Expected to Exceed 10%; Initial 2007 Organic Growth Estimated at 7%
Pro Forma for Pending CNR Acquisition, Proved Reserves Reach 7.3 Tcfe and Total Reserves Reach 14 Tcfe; First Nine Months 2005 Proved Reserve Adds Total 1.3 Tcfe; Reserve Replacement Equals 488% at Attractive Drilling and Acquisition Cost of $1.47 Per Mcfe
PRNewswire-FirstCall
OKLAHOMA CITY

Chesapeake Energy Corporation today reported financial and operating results for the third quarter of 2005. For the quarter, Chesapeake generated net income available to common shareholders of $149.1 million ($0.43 per fully diluted common share), operating cash flow of $635.2 million (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $581.4 million (defined as income before income taxes, interest expense, and depreciation, depletion and amortization expense) on revenue of $1.083 billion and production of 120.4 billion cubic feet of natural gas equivalent (bcfe).

The company's 2005 third quarter net income available to common shareholders and ebitda include certain items that are not typically included in published estimates of the company's financial results by many securities analysts. Such items and their after-tax effects on third quarter reported results are described as follows:

   *  an unrealized mark-to-market loss of $66.8 million resulting from the
      company's oil, natural gas and interest rate hedging programs;

   *  a $0.5 million loss resulting from the early extinguishment of certain
      Chesapeake debt securities; and

   *  a reduction of net income available to common shareholders of
      $17.7 million resulting from a loss on the exchange of approximately
      $134 million of Chesapeake's 4.125% cumulative convertible preferred
      stock into 8.5 million shares of the company's common stock and
      $70 million of Chesapeake's 5.0% (series 2003) cumulative convertible
      preferred stock into 4.4 million shares of the company's common stock
      through unsolicited transactions with holders of the preferred stock.

Adjusted for the above-mentioned items, Chesapeake's net income to common shareholders in the 2005 third quarter would have been $234.1 million ($0.65 per fully diluted common share) and ebitda would have been $686.2 million. The foregoing items do not affect the calculation of operating cash flow. A reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted net income available to common shareholders to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 13-15 of this release.

 Oil and Natural Gas Production Sets Record for 17th Consecutive Quarter;
      2005 Third Quarter Average Daily Production Increases 28% Over
            2004 Third Quarter and 5% Over 2005 Second Quarter

Daily production for the 2005 third quarter averaged 1.308 bcfe, an increase of 284 million cubic feet of natural gas equivalent (mmcfe), or 27.7%, over the 1.024 bcfe produced per day in the 2004 third quarter and an increase of 64 mmcfe, or 5.1%, over the 1.244 bcfe produced per day in the 2005 second quarter. Of the 64 mmcfe daily increase in sequential quarterly production, 53% came from organic growth and 47% from acquisition growth, making the company's quarterly organic growth rate 2.9%, its year-to-date organic growth rate 8.0% and its annualized 2005 organic growth rate 10.7%. The company's 2005 third quarter production exceeded its September 7, 2005 forecasted mid-point production by 0.9 bcfe, or 0.7%, because of stronger than projected drilling and operational results. The effects of Hurricane Rita reduced Chesapeake's third quarter production by 0.3 bcfe as a result of onshore facility shut-ins.

Chesapeake's 2005 third quarter production of 120.4 bcfe was comprised of 108.8 billion cubic feet of natural gas (bcf) (90% on a natural gas equivalent basis) and 1.93 million barrels of oil and natural gas liquids (10% on a natural gas equivalent basis). Chesapeake's average daily production rate of 1.308 bcfe consisted of 1.183 bcf of gas and 20,935 barrels of oil and natural gas liquids (bbl).

The 2005 third quarter was Chesapeake's 17th consecutive quarter of production growth. During these 17 quarters, Chesapeake's U.S. production has increased 234%, for an average compound quarterly growth rate of 7.4% and an average compound annual growth rate of 33%.

   Oil and Natural Gas Proved Reserves Reach Record Level of 6.2 Tcfe;
 First Nine Months 2005 Drilling and Acquisition Costs are $1.47 per Mcfe
        as Company Adds 1.311 Tcfe and Replaces Production by 488%

Chesapeake began 2005 with estimated proved reserves of 4.902 trillion cubic feet of natural gas equivalent (tcfe) and ended the third quarter with an internally estimated 6.213 tcfe, an increase of 1.311 tcfe, or 27%. During the 2005 first nine months, the company replaced its 338 bcfe of production with an estimated 1.649 tcfe of new proved reserves, for a reserve replacement rate of 488% at a drilling and acquisition cost of $1.47 per mcfe. Reserve replacement through the drillbit was 929 bcfe, or 275% of production (including a negative 19 bcfe from performance revisions and a positive 94 bcfe from oil and natural gas price increases), or 56% of the total increase, at a cost of $1.42 per mcfe. Reserve replacement through acquisitions was 720 bcfe, or 213% of production, or 44% of the total increase, at a cost of $1.54 per mcfe. The above figures do not include the impact of the pending CNR acquisition, which should close by December 1, 2005 and will increase Chesapeake's proved reserves by an internally estimated 1.1 tcfe.

Total costs incurred to acquire and develop proved reserves during the first nine months of 2005 were $2.23 per mcfe. These total costs include drilling, completion, acquisition, seismic, leasehold, capitalized internal costs, non-cash tax basis step-up from various corporate acquisitions ($253 million, or $0.15 per mcfe), asset retirement obligations and all other capitalized miscellaneous costs. These costs exclude future development costs of proved undeveloped reserves, but include costs associated with acquisition of unproved properties on which proved reserves have not been booked. A complete reconciliation of finding and acquisition cost information and a roll-forward of proved reserves is presented on page 11 of this release.

As of September 30, 2005, the company's estimated future net cash flows discounted at 10% before taxes (PV-10) from its proved reserves were $28.6 billion using field differential adjusted prices of $62.01 per bbl (based on a NYMEX quarter-end price of $66.38 per bbl) and $11.36 per mcf (based on a NYMEX quarter-end price of $14.20 per mcf). Chesapeake's PV-10 changes by approximately $267 million for every $0.10 per mcf change in gas prices and approximately $49 million for every $1.00 per bbl change in oil prices. The above figures do not include the impact of the pending CNR acquisition, which would have added approximately $4.2 billion to the PV-10 total above had Chesapeake owned the CNR assets as of September 30, 2005.

      Key Operational and Financial Statistics are Summarized Below
    for the 2005 Third and Second Quarters and the 2004 Third Quarter

The table below summarizes Chesapeake's key results during the 2005 third quarter and compares them to results from the 2005 second quarter and the 2004 third quarter:

                                                 Three Months Ended
                                       9/30/05        6/30/05       9/30/04
  Average daily production (in mmcfe)   1,308          1,244         1,024
  Gas as % of total production             90             89            88
  Natural gas production (in bcf)       108.8          101.1          83.2
  Average realized gas price
   ($/mcf) (A)                           6.64           5.95          5.17
  Oil production (in mbbls)             1,926          2,012         1,834
  Average realized oil price
   ($/bbl) (A)                          53.30          42.82         29.15
  Natural gas equivalent production
   (in bcfe)                            120.4          113.2          94.2
  Gas equivalent realized price
   ($/mcfe) (A)                          6.85           6.08          5.13
  Net marketing income ($/mcfe)           .07            .05           .04
  General and administrative costs
   ($/mcfe) (B)                          (.09)          (.08)         (.09)
  Stock-based compensation ($/mcfe)      (.04)          (.02)         (.01)
  Production taxes ($/mcfe)              (.44)          (.42)         (.33)
  Production expenses ($/mcfe)           (.67)          (.64)         (.57)
  Interest expense ($/mcfe) (A)          (.48)          (.48)         (.45)
  DD&A of oil and gas properties
   ($/mcfe)                             (1.92)         (1.85)        (1.63)
  D & A of other assets ($/mcfe)         (.11)          (.10)         (.08)
  Operating cash flow ($ in
   millions) (C)                        635.2          513.3         353.4
  Operating cash flow ($/mcfe)           5.28           4.53          3.75
  Ebitda ($ in millions) (D)            581.4          580.2         361.3
  Ebitda ($/mcfe)                        4.83           5.13          3.83
  Net income to common shareholders
   ($ in millions)                      149.1          179.2          85.6

   (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 non-cash stock-based compensation
   (C)  defined as cash flow provided by operating activities before changes
        in assets and liabilities
   (D)  defined as income before income taxes, interest expense, and
        depreciation, depletion and amortization expense


Oil and Natural Gas Price Realizations Detailed, Hedging Positions Updated,

Outlooks for 2005 and 2006 Updated and Initial Outlook for 2007 Provided

Average prices realized during the 2005 third quarter (including realized gains or losses from oil and gas derivatives, but excluding unrealized gains or losses on such derivatives) were $53.30 per bbl and $6.64 per thousand cubic feet (mcf), for a realized gas equivalent price of $6.85 per mcfe. Chesapeake's average realized pricing differentials to NYMEX during the third quarter were a negative $4.81 per bbl and a negative $1.14 per mcf. Oil and natural gas hedging activities during the quarter decreased oil and gas sales by $122.6 million, or $5.68 per bbl and $1.03 per mcf, or $1.02 per mcfe.

Chesapeake has added to its 2005, 2006, 2007 and 2008 oil and natural gas hedge positions previously provided in our Outlook dated October 3, 2005. The following tables compare Chesapeake's hedged production volumes through swaps as of October 31, 2005 to those as of October 3, 2005:

                  Swap Positions as of October 31, 2005

                                  Oil                   Natural Gas
  Quarter or Year         % Hedge     $ NYMEX      % Hedged      $ NYMEX

  2005 3Q                    46%       $51.66          68%        $6.49
  2005 4Q                    55%       $54.97          73%        $8.14
  2006 1Q                    54%       $59.71          55%        $9.89
  2006 2Q                    53%       $59.60          41%        $8.01
  2006 3Q                    50%       $59.83          40%        $8.00
  2006 4Q                    47%       $59.45          34%        $8.21
  2006 Total                 51%       $59.65          42%        $8.63
  2007                        8%       $54.29           7%        $9.16
  2008                       ---          ---           2%        $8.37


                   Swap Positions as of October 3, 2005

                                  Oil                   Natural Gas
  Quarter or Year        % Hedged     $ NYMEX      % Hedged      $ NYMEX

  2005 3Q                    46%       $51.66          68%        $6.49
  2005 4Q                    55%       $54.97          70%        $7.92
  2006 1Q                    54%       $59.64          48%        $9.23
  2006 2Q                    53%       $59.57          35%        $7.60
  2006 3Q                    50%       $59.85          34%        $7.61
  2006 4Q                    47%       $59.55          28%        $7.70
  2006 Total                 51%       $59.65          36%        $8.14
  2007                        8%       $54.29           3%        $8.28


Depending on changes in oil and natural gas futures markets and management's view of underlying oil and natural gas supply and demand trends, Chesapeake may either increase or decrease its hedging positions at any time in the future without notice.

The company's updated 2005, 2006 and 2007 forecasts are attached to this release in an Outlook dated October 31, 2005 labeled as Schedule "A". This Outlook has been changed from the Outlook dated October 3, 2005 (attached as Schedule "B" for investors' convenience) to reflect updated information resulting from the company's operational performance during the third quarter. In addition, the company is providing its initial 2007 forecast, which features projected organic growth of 7% and relatively modest operating cost increases.

Pro forma for Pending CNR Acquisition Company's U.S. Leasehold and 3-D Seismic

     Inventories Increase to 8.0 Million and 11.0 Million Net Acres;
        Proved and Non-Proven Reserves on the Company's Extensive
                       Leasehold Now Exceed 14 Tcfe

Chesapeake's exploratory and development drilling programs and production enhancement operations continue to produce operational results that exceed the company's forecasts and distinguish the company among its peers. During the 2005 third quarter, Chesapeake drilled 241 gross (186 net) operated wells and participated in another 278 gross (32 net) wells operated by other companies. The company's drilling success rate was 97% for both company-operated wells and non-operated wells. During the quarter, Chesapeake invested $390 million in operated wells (using an average of 72 operated rigs), $75 million in non- operated wells (using an average of 65 non-operated rigs) and $91 million in acquiring new 3-D seismic data and new leasehold (excluding leasehold acquired through acquisitions).

During the past seven years and pro forma for the pending CNR acquisition, Chesapeake has built what it believes to be the largest inventories of onshore leasehold (8.0 million net acres) and 3-D seismic (11.0 million acres) in the U.S. On this leasehold, the company has identified more than a 10-year inventory of approximately 25,000 drillsites on which it believes it can develop approximately 2.6 tcfe of proved undeveloped reserves and approximately 7.0 tcfe of non-proven reserves.

Chesapeake characterizes its drilling activity by one of four play types: conventional gas resource, unconventional gas resource, emerging gas resource and Appalachian Basin gas resource. The company's leasehold and proved undeveloped and non-proven reserve totals are set forth below:

   *  2.6 million net acres in its traditional conventional areas (i.e.,
      much of the Mid-Continent, Permian, Gulf Coast, South Texas and other
      areas) on which it has identified approximately 2,300 drillsites,
      1.0 tcfe of proved undeveloped reserves and approximately 1.0 tcfe of
      non-proven reserves;

   *  1.0 million net acres in its unconventional gas resource areas (i.e.,
      Sahara, Granite/Cherokee/Atoka Washes, Hartshorne CBM, Barnett Shale
      and Ark-La-Tex tight sands) on which it has identified approximately
      12,000 drillsites, 1.2 tcfe of proved undeveloped reserves and
      approximately 3.4 tcfe of non-proven reserves;

   *  0.9 million net acres in its emerging gas resource areas (i.e.,
      Fayetteville Shale, Caney/Woodford Shales, Haley Deep and others) on
      which it has identified approximately 1,200 drillsites, 0.1 tcfe of
      proved undeveloped reserves and approximately 1.2 tcfe of non-proven
      reserves; and

   *  3.5 million net acres in the Appalachian Basin, where play types range
      from conventional to unconventional to emerging gas resource.  On the
      significant acreage base it is acquiring from CNR, Chesapeake has
      identified approximately 9,400 drillsites, 0.3 tcfe of proved
      undeveloped reserves and more than 1.4 tcfe of non-proven reserves.

Chesapeake continues to actively acquire more acreage throughout its operating areas with almost 500,000 acres acquired in the 2005 third quarter through an aggressive land acquisition program that is utilizing more than 600 landmen in the field. In addition to the pending CNR transaction through which the company will acquire 3.5 million net acres in the U.S. and 0.6 million net acres in Canada, Chesapeake's most significant land acquisition activities during the quarter took place in the Arkansas Fayetteville Shale play where the company has increased its acreage holdings to 600,000 net acres from the 200,000 net acres of leasehold previously disclosed. Chesapeake's initial six-well drilling program in the Fayetteville Shale is now underway.

Management Comments

Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "Today's announcement of very strong operational and financial results for the 2005 third quarter provides ongoing confirmation that Chesapeake's business strategy continues to create significant shareholder value. This strategy has generated a 90% increase in our common stock price during the past year and more than a 25-fold increase since our IPO in February 1993 through:

   *  delivering consistent and value-added growth through a balance of
      acquisitions and exploratory and developmental drilling;

   *  focusing on natural gas to take advantage of strong long-term natural
      gas supply/demand fundamentals; and

   *  building dominant regional scale to achieve low operating costs and
      high returns.

We believe Chesapeake's management team can continue the successful execution of the company's distinctive business strategy and continue to deliver significant shareholder value for years to come."

Conference Call Information

A conference call has been scheduled for Tuesday morning, November 1, 2005 at 9:00 a.m. EST to discuss this earnings release. The telephone number to access the conference call is 719.457.2630. For those unable to participate in the conference call, a replay will be available from 12:00 noon EST, November 1, 2005 through midnight EST on Monday, November 14, 2005. The number to access the conference call replay is 719.457.0820 and the passcode is 2076841. The conference call will also be simulcast live on the Internet and can be accessed at http://www.chkenergy.com/ by selecting "Conference Calls" under the "Investor Relations" section. The webcast of the conference call will be available on the 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 oil and gas reserves, expected oil and gas production and future expenses, projections of future oil and gas prices, planned capital expenditures for drilling, leasehold acquisitions and seismic data, and statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations, including the acquisition of CNR. 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.

Factors that could cause actual results to differ materially from expected results are described under "Risk Factors" in item 1 of our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 9, 2005. They include the volatility of oil and gas prices; adverse effects our level of indebtedness could have on our operations and future growth; our ability to compete effectively against strong independent oil and gas companies and majors; the availability of capital on an economic basis to fund reserve replacement costs; uncertainties inherent in estimating quantities of oil and gas reserves and projecting future rates of production and the timing of development expenditures; our ability to replace reserves and sustain production; uncertainties in evaluating oil and gas reserves of acquired properties and associated potential liabilities; unsuccessful exploration and development drilling; declines in the values of our oil and gas properties resulting in ceiling test write-downs; lower prices realized on oil and gas sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities; and drilling and operating risks. We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information.

Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Also, our internal estimates of reserves, particularly those in the properties recently acquired or proposed to be acquired where we may have limited review of data or experience with the reserves, may be subject to revision and may be different from estimates by our external reservoir engineers at year-end. 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.

The SEC has generally permitted oil and gas companies, in filings made with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the terms "probable", "possible" or "non-proven" to describe volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines may prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the company. While we believe our calculations of non-proven drillsites and estimation of non-proven reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third party engineers or appraisers.

Pro forma for the acquisition of Columbia Natural Resources, LLC and its affiliates, Chesapeake Energy Corporation is the second largest independent producer of natural gas in the U.S. Headquartered in Oklahoma City, the company's operations are focused on exploratory and developmental drilling and property acquisitions in the Mid-Continent, Permian Basin, South Texas, Texas Gulf Coast, Barnett Shale, Ark-La-Tex and Appalachian Basin regions of the United States. The company's Internet address is http://www.chkenergy.com/ .

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

                              Three Months Ended        Three Months Ended
                              September 30, 2005        September 30, 2004
                                $         $/mcfe          $         $/mcfe

  REVENUES:
    Oil and gas sales        720,928         5.99      450,936         4.79
    Oil and gas marketing
     sales                   361,915         3.01      178,860         1.90
      Total Revenues       1,082,843         9.00      629,796         6.69

  OPERATING COSTS:
    Production expenses       80,765         0.67       54,102         0.57
    Production taxes          53,102         0.44       30,872         0.33
    General and
     administrative
     expenses:
      General and
       administrative
       (excluding stock-
       based compensation)    10,536         0.09        8,361         0.09
      Stock-based
       compensation            5,249         0.04          584         0.01
    Oil and gas marketing
     expenses                353,510         2.94      175,426         1.86
    Oil and gas
     depreciation,
     depletion, and
     amortization            231,145         1.92      153,586         1.63
    Depreciation and
     amortization of
     other assets             12,902         0.11        7,700         0.08
      Total Operating Costs  747,209         6.21      430,631         4.57

  INCOME FROM OPERATIONS     335,634         2.79      199,165         2.12

  OTHER INCOME (EXPENSE):
    Interest and other
     income                    2,428         0.02          885         0.01
    Interest expense         (58,593)       (0.48)     (48,689)       (0.52)
    Loss on repurchases or
     exchanges of Chesapeake
     debt                       (747)       (0.01)         ---          ---
      Total Other Income
       (Expense)             (56,912)       (0.47)     (47,804)       (0.51)

  Income Before Income
   Taxes                     278,722         2.32      151,361         1.61

  Income Tax Expense:
    Current                      ---          ---          ---          ---
    Deferred                 101,734         0.85       54,489         0.58
      Total Income Tax
       Expense               101,734         0.85       54,489         0.58

  NET INCOME                 176,988         1.47       96,872         1.03

  Preferred stock dividends  (10,204)       (0.08)     (11,287)       (0.12)
  Loss on conversion/
   exchange of preferred
   stock                     (17,725)       (0.15)         ---          ---

  NET INCOME AVAILABLE TO
   COMMON SHAREHOLDERS       149,059         1.24       85,585         0.91


  EARNINGS PER COMMON SHARE:

    Basic                      $0.46                     $0.33
    Assuming dilution          $0.43                     $0.29

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

    Basic                    322,101                   257,096
    Assuming dilution        367,639                   338,285



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

                              Nine Months Ended        Nine Months Ended
                             September 30, 2005        September 30, 2004
                              $           $/mcfe        $           $/mcfe

  REVENUES:
    Oil and gas sales     2,032,271         6.01    1,270,394         4.89
    Oil and gas marketing
     sales                  882,040         2.61      496,823         1.91
      Total Revenues      2,914,311         8.62    1,767,217         6.80

  OPERATING COSTS:
    Production expenses     222,660         0.66      148,500         0.57
    Production taxes        136,313         0.40       68,559         0.26
    General and
     administrative
     expenses:
      General and
       administrative
       (excluding stock-
       based compensation)   29,468         0.09       23,947         0.09
      Stock-based
       compensation          10,172         0.03        3,125         0.01
    Oil and gas marketing
     expenses               860,789         2.55      486,205         1.88
    Oil and gas
     depreciation,
     depletion, and
     amortization           621,484         1.84      410,237         1.58
    Depreciation and
     amortization of
     other assets            34,791         0.10       20,155         0.08
      Total Operating
       Costs              1,915,677         5.67    1,160,728         4.47

  INCOME FROM OPERATIONS    998,634         2.95      606,489         2.33

  OTHER INCOME (EXPENSE):
    Interest and other
     income                   7,790         0.02        3,563         0.01
    Interest expense       (155,623)       (0.46)    (124,040)       (0.47)
    Loss on repurchases
     or exchanges of
     Chesapeake debt        (70,047)       (0.20)      (6,925)       (0.03)
      Total Other Income
       (Expense)           (217,880)       (0.64)    (127,402)       (0.49)

  Income Before Income
   Taxes                    780,754         2.31      479,087         1.84

  Income Tax Expense:
    Current                     ---          ---          ---          ---
    Deferred                284,977         0.84      172,470         0.66
      Total Income Tax
       Expense              284,977         0.84      172,470         0.66

  NET INCOME                495,777         1.47      306,617         1.18

  Preferred stock
   dividends                (25,526)       (0.08)     (30,799)       (0.12)
  Loss on conversion/
   exchange of preferred
   stock                    (22,468)       (0.07)         ---          ---

  NET INCOME AVAILABLE TO
   COMMON SHAREHOLDERS      447,783         1.32      275,818         1.06


  EARNINGS PER COMMON SHARE:

    Basic                     $1.42                     $1.13
    Assuming dilution         $1.32                     $0.96

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

    Basic                   314,425                   245,087
    Assuming dilution       352,210                   320,089



                      CHESAPEAKE ENERGY CORPORATION
                       CONSOLIDATED BALANCE SHEETS
                                (in 000's)
                               (unaudited)

                                              September 30,    December 31,
                                                   2005           2004

  Cash                                            $127,102         $6,896
  Other current assets                           1,216,464        560,644
    Total Current Assets                         1,343,566        567,540

  Property and equipment (net)                  10,677,424      7,444,384
  Other assets                                     344,639        232,585
    Total Assets                               $12,365,629     $8,244,509

  Current liabilities                           $2,042,478       $963,953
  Long term debt                                 4,250,160      3,075,109
  Asset retirement obligation                       86,022         73,718
  Other long term liabilities                      121,521         34,973
  Deferred tax liability                         1,659,128        933,873
    Total Liabilities                            8,159,309      5,081,626

  STOCKHOLDERS' EQUITY                           4,206,320      3,162,883

  TOTAL LIABILITIES & STOCKHOLDERS' EQUITY     $12,365,629     $8,244,509

  COMMON SHARES OUTSTANDING                        344,059        311,869



                      CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF COSTS INCURRED FOR NINE MONTHS ENDED SEPTEMBER 30, 2005
                  ($ in 000's, except per unit amounts)
                               (unaudited)
                                                 Reserves
                                    Cost        (in mmcfe)       $/mcfe

  Exploration and development
   costs (A)                     $1,317,984       928,708         $1.42
  Acquisition of proved
   properties                     1,108,932       720,953          1.54
    Subtotal                      2,426,916     1,649,661          1.47

  Acquisition of unproved
   properties                       767,595           ---           ---
  Divestitures                       (1,881)         (491)          ---
  Leasehold acquisition costs       164,568           ---           ---
  Geological and geophysical
   costs                             44,300           ---           ---
    Adjusted subtotal             3,401,498     1,649,170          2.06
  Tax basis step-up                 253,194           ---           ---
  Asset retirement obligation
   and other                         20,130           ---           ---
    Total                        $3,674,822     1,649,170         $2.23

   (A)  Reserves include revisions to previous estimates



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

                                              Mmcfe

  Beginning balance, 12/31/04               4,901,751
  Extensions and discoveries                  853,297
  Acquisitions                                720,953
  Divestitures                                   (491)
  Revisions-performance                       (18,612)
  Revisions-price                              94,023
  Production                                 (338,164)
  Ending balance, 9/30/05                   6,212,757

  Reserve replacement                       1,649,170
  Reserve replacement rate                       488%



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

                            Three Months Ended         Nine Months Ended
                               September 30,             September 30,
                             2005         2004         2005         2004

  Oil and Gas Sales
   ($ in thousands):
    Oil sales              $113,590      $73,921     $290,332     $181,882
    Oil derivatives -
     realized gains
     (losses)               (10,937)     (20,464)     (28,654)     (41,672)
    Oil derivatives -
     unrealized gains
     (losses)                (4,009)     (14,436)      (5,951)     (21,925)

      Total Oil Sales       $98,644      $39,021     $255,727     $118,285

    Gas sales              $833,992     $447,466   $2,005,670   $1,222,783
    Gas derivatives -
     realized gains
     (losses)              (111,668)     (17,514)     (97,955)     (25,976)
    Gas derivatives -
     unrealized gains
     (losses)              (100,040)     (18,037)    (131,171)     (44,698)

      Total Gas Sales      $622,284     $411,915   $1,776,544   $1,152,109

      Total Oil and Gas
       Sales               $720,928     $450,936   $2,032,271   $1,270,394

  Average Sales Price
   (excluding gains
   (losses) on
   derivatives):
    Oil ($ per bbl)          $58.98       $40.31       $51.08       $36.58
    Gas ($ per mcf)           $7.67        $5.38        $6.60        $5.32
    Gas equivalent
     ($ per mcfe)             $7.87        $5.53        $6.79        $5.41

  Average Sales Price
   (excluding unrealized
   gains (losses) on
   derivatives):
    Oil ($ per bbl)          $53.30       $29.15       $46.04       $28.20
    Gas ($ per mcf)           $6.64        $5.17        $6.27        $5.21
    Gas equivalent
     ($ per mcfe)             $6.85        $5.13        $6.42        $5.15

  Interest Expense
   ($ in thousands):
    Interest                $58,206      $42,258     $160,209     $118,335
    Derivatives - realized
     (gains) losses            (843)         221       (2,639)        (184)
    Derivatives - unrealized
     (gains) losses           1,230        6,210       (1,947)       5,889
      Total Interest
       Expense              $58,593      $48,689     $155,623     $124,040



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

  THREE MONTHS ENDED:                        September 30,   September 30,
                                                  2005           2004

  Cash provided by operating activities         $558,061       $367,649

  Cash (used in) investing activities         (1,115,166)    (1,068,791)

  Cash provided by financing activities          684,207        673,978



  NINE MONTHS ENDED:                         September 30,   September 30,
                                                  2005           2004

  Cash provided by operating activities       $1,638,368     $1,038,206

  Cash (used in) investing activities         (3,655,044)    (2,668,241)

  Cash provided by financing activities        2,136,882      1,638,527



                      CHESAPEAKE ENERGY CORPORATION
               RECONCILIATION OF CERTAIN FINANCIAL MEASURES
                                (in 000's)
                               (unaudited)

  THREE MONTHS ENDED:                          September 30,   September 30,
                                                    2005           2004

  CASH PROVIDED BY OPERATING ACTIVITIES           $558,061       $367,649

  Adjustments:
    Changes in assets and liabilities               77,150        (14,252)

  OPERATING CASH FLOW*                            $635,211       $353,397

*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 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 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:                          September 30,   September 30,
                                                    2005           2004

  Net income                                      $176,988        $96,872

  Income tax expense                               101,734         54,489
  Interest expense                                  58,593         48,689
  Depreciation and amortization of other assets     12,902          7,700
  Oil and gas depreciation, depletion and
   amortization                                    231,145        153,586

  EBITDA**                                        $581,362       $361,336

**Ebitda represents net income (loss) before cumulative effect of accounting change, income tax expense (benefit), 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:                          September 30,  September 30,
                                                    2005           2004

  CASH PROVIDED BY OPERATING ACTIVITIES           $558,061       $367,649

  Changes in assets and liabilities                 77,150        (14,252)
  Interest expense                                  58,593         48,689
  Unrealized gains (losses) on oil and gas
   derivatives                                    (104,049)       (32,473)
  Other non-cash items                              (8,393)        (8,277)

  EBITDA                                          $581,362       $361,336



                      CHESAPEAKE ENERGY CORPORATION
               RECONCILIATION OF CERTAIN FINANCIAL MEASURES
                                (in 000's)
                               (unaudited)

  NINE MONTHS ENDED:                           September 30,  September 30,
                                                    2005           2004

  CASH PROVIDED BY OPERATING ACTIVITIES         $1,638,368     $1,038,206

  Adjustments:
    Changes in assets and liabilities               15,589        (43,082)

  OPERATING CASH FLOW*                          $1,653,957       $995,124

*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 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 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.

  NINE MONTHS ENDED:                           September 30,  September 30,
                                                    2005           2004

  Net income                                      $495,777       $306,617

  Income tax expense                               284,977        172,470
  Interest expense                                 155,623        124,040
  Depreciation and amortization of other assets     34,791         20,155
  Oil and gas depreciation, depletion and
   amortization                                    621,484        410,237

  EBITDA**                                      $1,592,652     $1,033,519

**Ebitda represents net income (loss) before cumulative effect of accounting change, income tax expense (benefit), 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:

  NINE MONTHS ENDED:                           September 30,   September 30,
                                                    2005           2004

  CASH PROVIDED BY OPERATING ACTIVITIES         $1,638,368     $1,038,206

  Changes in assets and liabilities                 15,589        (43,082)
  Interest expense                                 155,623        124,040
  Unrealized gains (losses) on oil and gas
   derivatives                                    (137,122)       (66,623)
  Other non-cash items                             (79,806)       (19,022)

  EBITDA                                        $1,592,652     $1,033,519



                      CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON & ADJUSTED EBITDA

                  ($ in 000's, except per share amounts)
                               (unaudited)

                                               Three Months    Nine Months
                                                   Ended          Ended
                                               September 30,  September 30,
                                                    2005           2005

  Net income available to common shareholders     $149,059       $447,783

  Adjustments:
    Loss on conversion/exchange of preferred
     stock                                          17,725         22,468
  Net Income                                      $166,784       $470,251

  Adjustments, net of tax:
    Unrealized (gains) losses on derivatives        66,851         85,836
    Loss on repurchases or exchanges of debt           474         44,480

  Adjusted net income available to common*        $234,109       $600,567

  Adjusted earnings per share assuming
   dilution**                                        $0.65          $1.71


  EBITDA                                          $581,362     $1,592,652

  Adjustments, before tax:
    Unrealized (gains) losses on oil and
     gas derivatives                               104,049        137,122
    Loss on repurchases or exchanges of debt           747         70,047

  Adjusted EBITDA*                                $686,158     $1,799,821

*Adjusted net income available to common and adjusted earnings per share assuming dilution and adjusted EBITDA 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 and EBITDA because:

     a.  Management uses adjusted net income available to common and
         adjusted EBITDA to evaluate the company's operational trends and
         performance relative to other oil and gas producing companies.
     b.  Adjusted net income available to common and adjusted EBITDA are
         more comparable to earnings and EBITDA 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.

**For purposes of calculating fully diluted shares and earnings per share assuming dilution for the three and nine months ended September 30, 2005, accounting rules prohibit the company from assuming the conversion of the 4.125% preferred stock, 4.50% preferred stock and 5.00% (Series 2003) preferred stock for common shares prior to conversion or exchange for either period since the effect would have been anti-dilutive. In determining adjusted earnings per share, we have reflected these shares as though they were converted at the beginning of the period which increases the fully diluted share count to 376.6 million and 365.1 million for the three and nine months ended September 30, 2005, respectively.

                               SCHEDULE "A"

               CHESAPEAKE'S OUTLOOK AS OF OCTOBER 31, 2005

Quarter Ending December 31, 2005; Year Ending December 31, 2005; 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 October 31, 2005, we are using the following key assumptions in our projections for the fourth quarter of 2005, the full-year 2005, the full-year 2006 and the full-year 2007.

The primary changes from our October 3, 2005 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 since our October 3, 2005 Outlook.
   2)  We have updated our expectations for future NYMEX oil and gas prices
       based on current market conditions in order to illustrate hedging
       effects only.
   3)  We have updated certain of our costs to reflect changing market
       conditions.
   4)  We have provided our initial guidance for the full-year 2007.
   5)  We have not reflected any of CNR's derivative positions.  We will
       record such positions at fair value in the purchase price allocation
       as a liability on the date of acquisition.  Changes in fair value
       subsequent to the acquisition date for the derivative positions
       assumed will result in adjustments to our oil and gas revenues only
       upon cash settlement.

                      Quarter Ending  Year Ending  Year Ending  Year Ending
                          12/31/2005   12/31/2005   12/31/2006   12/31/2007

  Estimated Production:
    Oil - Mbo                1,950        7,650        7,700        7,750
    Gas - Bcf              112 - 114    416 - 419    512 - 522    553 - 563
    Gas Equivalent - Bcfe  124 - 126    462 - 465    558 - 568    599 - 609
    Daily gas equivalent
     midpoint -in Mmcfe      1,359        1,270        1,543        1,655

  NYMEX Prices (for
   calculation of realized
   hedging effects only):
    Oil - $/Bo              $60.00       $56.59       $50.00       $50.00
    Gas - $/Mcf             $10.64        $8.05        $7.00        $7.00

  Estimated Differentials
   to NYMEX Prices:
    Oil - $/Bo                6-8%         6-8%         6-8%         6-8%
    Gas - $/Mcf             10-15%        8-12%        8-12%        8-12%

  Estimated Realized
   Hedging Effects
   (based on expected
   NYMEX prices above):
    Oil - $/Bo              -$2.78       -$4.30        $4.94        $0.35
    Gas - $/Mcf             -$1.58       -$0.41        $0.80        $0.26

  Operating Costs per
   Mcfe of Projected
   Production:
    Production expense   $0.70 - 0.74 $0.68 - 0.72 $0.77 - 0.82 $0.80 - 0.85
    Production taxes
     (generally
     6.5% of O&G
     revenues) (A)       $0.60 - 0.64 $0.45 - 0.50 $0.40 - 0.45 $0.40 - 0.45
    General and
     administrative      $0.10 - 0.12 $0.10 - 0.12 $0.11 - 0.13 $0.11 - 0.13
    Stock-based
     compensation
     (non-cash)          $0.03 - 0.05 $0.03 - 0.05 $0.08 - 0.10 $0.10 - 0.12
    DD&A - oil and gas   $2.05 - 2.10 $1.85 - 1.95 $2.15 - 2.20 $2.25 - 2.30
    Depreciation of
     other assets        $0.10 - 0.12 $0.09 - 0.11 $0.10 - 0.12 $0.11 - 0.13
    Interest
     expense (B)         $0.48 - 0.52 $0.45 - 0.49 $0.48 - 0.53 $0.50 - 0.55
  Other Income and
   Expense per Mcfe:
    Marketing and
     other income        $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04

  Book Tax Rate
   (approximately
   equal to 95%
   deferred)                 36.5%        36.5%        36.5%        36.5%

  Equivalent Shares
   Outstanding:
    Basic                   345 mm       322 mm       360 mm       364 mm
    Diluted                 406 mm       375 mm       424 mm       429 mm
  Capital Expenditures:
    Drilling, leasehold
     and seismic            $575 -     $2,000 -     $2,700 -     $3,100 -
                            625 mm     2,200 mm     2,900 mm     3,300 mm

   (A)  Severance tax per mcfe is based on NYMEX prices of $60.00 per bo and
        natural gas prices ranging from $9.00 to $11.30 per mcf during Q4
        2005, $60.00 per bo and natural gas prices ranging from $7.25 to
        $12.50 per mcf during calendar 2005, $50.00 per bo and $6.75 to
        $7.60 per mcf during calendar 2006 and 2007.
   (B)  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 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 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 gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and 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 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.

  The company currently has in place the following natural gas swaps:

                                                           % Hedged
                                                                  Open Swap
                          Avg.          Avg. NYMEX                Positions
                         NYMEX    Gain     Price                  as a % of
                         Strike  (Loss)  Including   Assuming     Estimated
                  Open   Price    from     Open         Gas          Total
                 Swaps  Of Open  Locked  & Locked   Production        Gas
               in Bcf's  Swaps    Swaps  Positions  in Bcf's of:  Production

  2005:
  Q4 2005(A)      82.2    $8.27  -$0.13    $8.14       113.0          73%

  2006:
  Q1              67.5   $10.01  -$0.12    $9.89       122.0          55%
  Q2              51.9    $8.11  -$0.10    $8.01       127.0          41%
  Q3              52.4    $8.10  -$0.10    $8.00       132.0          40%
  Q4              45.7    $8.31  -$0.10    $8.21       136.0          34%
  Total 2006(A)  217.5    $8.74  -$0.11    $8.63       517.0          42%

  Total 2007      38.1    $9.47  -$0.31    $9.16       558.0           7%

  Total 2008      11.0    $8.37     ---    $8.37       585.0           2%

   (A)  Certain hedging arrangements include swaps with knockout prices
        ranging from $3.75 to $5.50 covering 20.1 bcf in 2005 and $3.75 to
        $5.50 covering 43.0 bcf in 2006.

Note: Not shown above are collars covering 1.4 bcf of production in 2005 at a weighted average floor and ceiling of $3.49 and $5.27 and 0.2 bcf of production in 2006 at a weighted average floor and ceiling of $6.00 and $9.70 and call options covering 1.8 bcf of production in 2005 at a weighted average price of $5.86, 7.3 bcf of production in 2006 at a weighted average price of $12.50, 7.3 bcf of production in 2007 at a weighted average price of $12.50 and 7.3 bcf of production in 2008 at a weighed average price of $12.50.

The company has also entered into the following natural gas basis protection swaps:

                                                   Assuming Gas
                          Volume                    Production
                         in Bcf's   NYMEX less*:   in Bcf's of:   % Hedged

  4th Quarter 2005          49.4        $0.27          113          44%
  2006                     130.1         0.32          517          25%
  2007                     126.5         0.28          558          23%
  2008                     118.6         0.27          585          20%
  2009                      86.6         0.29          615          14%

  Totals                   511.2        $0.29        2,388          21%

   * weighted average



  The company has entered into the following crude oil hedging arrangements:

                                                           % Hedged
                                                                   Open Swap
                                                                   Positions
                                                                    as % of
                                                     Assuming        Total
                       Open Swaps    Avg. NYMEX   Oil Production   Estimated
                        in mbo's    Strike Price   in mbo's of:   Production

  2005:
  Q4 2005(A)             1,073.5        $54.97       1,950.0           55%

  2006:
  Q1                     1,035.0        $59.71       1,900.0           54%
  Q2                     1,016.5        $59.60       1,920.0           53%
  Q3                       966.0        $59.83       1,940.0           50%
  Q4                       920.0        $59.45       1,940.0           47%

  Total 2006(A)          3,937.5        $59.65       7,700.0           51%

  Total 2007               635.0        $54.29       7,750.0            8%

   (A)  Certain hedging arrangements include swaps with knockout prices
        ranging from $26.00 to $42.00 covering 276 mbo in 2005 and $40.00 to
        $42.00 covering 501.5 mbo in 2006.



                               SCHEDULE "B"

           CHESAPEAKE'S PREVIOUS OUTLOOK AS OF OCTOBER 3, 2005
                      (PROVIDED FOR REFERENCE ONLY)

             NOW SUPERSEDED BY OUTLOOK AS OF OCTOBER 31, 2005

Quarter Ending September 30, 2005; Quarter Ending December 31, 2005; Year Ending December 31, 2005; Year Ending December 31, 2006.

We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of October 3, 2005, we are using the following key assumptions in our projections for the third quarter of 2005, the fourth quarter of 2005, the full-year 2005 and the full-year 2006.

The primary changes from our September 7, 2005 Outlook are in italicized bold in the table and are explained as follows:

   1)  We have shown the operational and financial effects of the pending
       acquisition and anticipated financing as described in our press
       release dated October 3, 2005.  We have assumed that the CNR
       acquisition will close no later than December 15, 2005.
   2)  We have updated the projected effect of changes in our hedging
       positions since our September 7, 2005 Outlook.
   3)  We have updated our expectations for future NYMEX oil and gas prices
       based on current market conditions in order to illustrate hedging
       effects only.
   4)  We have updated certain of our costs to reflect changing market
       conditions and the impact of the CNR acquisition.
   5)  We have increased our estimated basic common share count to reflect
       the common stock issued in connection with the exchanges of a portion
       of our preferred stock during September 2005.
   6)  We have provided guidance for the fourth quarter of 2005.


                           Quarter     Quarter
                            Ending      Ending     Year Ending  Year Ending
                          9/30/2005   12/31/2005    12/31/2005   12/31/2006

  Estimated Production:
    Oil - Mbo                1,950        1,950        7,650        7,700
    Gas - Bcf             107 - 109     112 - 114    416 - 419    512 - 522
    Gas Equivalent -
     Bcfe               118.5 - 120.5   124 - 126    462 - 465    558 - 568
    Daily gas
     equivalent
     midpoint - in
     Mmcfe                   1,300        1,359        1,270        1,543

  NYMEX Prices (for
   calculation of
   realized hedging
   effects only):
    Oil - $/Bo              $61.34       $60.00       $56.09       $50.00
    Gas - $/Mcf              $8.53        $9.00        $7.64        $7.00

  Estimated Differentials
   to NYMEX Prices:
    Oil - $/Bo              -$4.50       -$4.50       -$4.50       -$4.50
    Gas - $/Mcf             -$0.80       -$1.50       -$1.00       -$1.00

  Estimated Realized
   Hedging Effects
   (based on expected
   NYMEX prices above):
    Oil - $/Bo              -$4.48       -$2.78       -$4.09        $4.94
    Gas - $/Mcf             -$1.21       -$0.33       -$0.21        $0.66
  Operating Costs per
   Mcfe of Projected
   Production:
    Production expense  $0.68 - 0.72 $0.70 - 0.74 $0.68 - 0.72 $0.77 - 0.82
    Production taxes
     (generally 7%
     of O&G
     revenues) (A)      $0.51 - 0.56 $0.56 - 0.60 $0.45 - 0.50 $0.45 - 0.50
    General and
     administrative     $0.10 - 0.12 $0.10 - 0.12 $0.10 - 0.12 $0.11 - 0.13
    Stock-based
     compensation
     (non-cash)         $0.03 - 0.05 $0.03 - 0.05 $0.03 - 0.05 $0.04 - 0.06
    DD&A - oil and gas  $1.85 - 1.95 $2.05 - 2.10 $1.85 - 1.95 $2.15 - 2.20
    Depreciation of
     other assets       $0.09 - 0.11 $0.10 - 0.12 $0.09 - 0.11 $0.10 - 0.12
    Interest
     expense (B)        $0.48 - 0.52 $0.48 - 0.52 $0.45 - 0.49 $0.48 - 0.53
  Other Income and
   Expense per Mcfe:
    Marketing and other
     income             $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04

  Book Tax Rate
   (approximately
   equal to 95%
   deferred)                 36.5%        36.5%        36.5%        36.5%

  Equivalent Shares
   Outstanding:
    Basic                   322 mm       342 mm       321 mm       355 mm
    Diluted                 376 mm       399 mm       373 mm       418 mm
  Capital Expenditures:
    Drilling, leasehold
     and seismic           $485 -       $575 -      $2,000 -     $2,500 -
                           $535 mm      $625 mm     $2,200 mm    $2,700 mm

   (A)  Severance tax per mcfe is based on NYMEX prices of $60.00 per bo and
        natural gas prices ranging from $8.70 to $10.00 per mcf during Q3
        2005, $60.00 per bo and natural gas prices ranging from $9.25 to
        $10.00 per mcf during Q4 2005,  $60.00 per bo and natural gas prices
        ranging from $8.25 to $10.00 per mcf during calendar 2005 and $50.00
        per bo and $7.15 to $7.90 per mcf during calendar 2006.
   (B)  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 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 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 gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and 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 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.

  The company currently has in place the following natural gas swaps:

                                                           % Hedged
                                                                  Open Swap
                          Avg.          Avg. NYMEX                Positions
                         NYMEX    Gain     Price                  as a % of
                         Strike  (Loss)  Including   Assuming     Estimated
                  Open   Price    from     Open         Gas          Total
                 Swaps  Of Open  Locked  & Locked   Production        Gas
               in Bcf's  Swaps    Swaps  Positions  in Bcf's of:  Production

  2005:
  Q3             72.9    $6.64   -$0.15    $6.49       108.0         68%
  Q4             79.5    $8.06   -$0.14    $7.92       113.0         70%
  Remaining
   2005(A)      152.4    $7.38   -$0.14    $7.24       221.0         69%

  2006:
  Q1             58.5    $9.38   -$0.15    $9.23       122.0         48%
  Q2             44.6    $7.73   -$0.13    $7.60       127.0         35%
  Q3             45.1    $7.73   -$0.12    $7.61       132.0         34%
  Q4             38.4    $7.82   -$0.12    $7.70       136.0         28%

  Total
   2006 (A)     186.6    $8.27   -$0.13    $8.14       517.0         36%

  Total 2007     14.4    $9.09   -$0.81    $8.28       555.0          3%

   (A)  Certain hedging arrangements include swaps with knockout prices
        ranging from $3.75 to $5.50 covering 42.6 bcf in 2005 and $3.75 to
        $5.50 covering 43.0 bcf in 2006.

Note: Not shown above are collars covering 3.0 bcf of production in 2005 at a weighted average floor and ceiling of $3.59 and $5.37 and 0.2 bcf of production in 2006 at a weighted average floor and ceiling of $6.00 and $9.70 and call options covering 3.7 bcf of production in 2005 at a weighted average price of $5.79, 7.3 bcf of production in 2006 at a weighted average price of $12.50 and 7.3 bcf of production in 2007 at a weighted average price of $12.50.

The company has also entered into the following natural gas basis protection swaps:

                                                    Assuming Gas
                                                     Production
                    Volume in Bcf's   NYMEX less*:  in Bcf's of:   % Hedged

  3rd & 4th
   Quarter 2005           96.3            $0.27           221          44%
  2006                   130.1             0.32           517          25%
  2007                   126.5             0.28           555          23%
  2008                   118.6             0.27           580          20%
  2009                    86.6             0.29           605          14%
  Totals                 558.1            $0.29         2,478          23%

   * weighted average



  The company has entered into the following crude oil hedging arrangements:

                                                           % Hedged
                                                                   Open Swap
                                                                   Positions
                                                                    as % of
                                                     Assuming        Total
                       Open Swaps    Avg. NYMEX   Oil Production   Estimated
                        in mbo's    Strike Price   in mbo's of:   Production

  2005:
  Q3                      903.5        $51.66          1,950          46%
  Q4                    1,073.5        $54.97          1,950          55%
  Remaining 2005 (A)    1,977.0        $53.46          3,900          51%

  2006:
  Q1                    1,035.0        $59.64        1,900.0          54%
  Q2                    1,016.5        $59.57        1,920.0          53%
  Q3                      966.0        $59.85        1,940.0          50%
  Q4                      920.0        $59.55        1,940.0          47%

  Total 2006 (A)        3,937.5        $59.65        7,700.0          51%

  Total 2007              635.0        $54.29        7,750.0           8%

   (A)  Certain hedging arrangements include swaps with knockout prices
        ranging from $26.00 to $42.00 covering 552 mbo in 2005 and $40.00 to
        $42.00 covering 501.5 mbo in 2006.

SOURCE: Chesapeake Energy Corporation

CONTACT: investors, Jeffrey L. Mobley, CFA, Vice President - Investor
Relations and Research, +1-405-767-4763, or jmobley@chkenergy.com , or media,
Thomas S. Price, Jr., Senior Vice President - Corporate Development,
+1-405-879-9257, or tprice@chkenergy.com , both of Chesapeake Energy
Corporation