Chesapeake Energy Corporation Posts Strong Results for the 2004 Third Quarter and Increases Production Forecasts for the Twelfth Consecutive Quarter
Company Reports 2004 Third Quarter Net Income Available to Common Shareholders of $86 Million on Revenue of $630 Million and Production of 94.2 Bcfe; Excellent Drilling Results Drive Production Forecasts Higher; Company Now Sees Production Growth of At Least 33% in 2004, 14% in 2005 and 8% in 2006
Proved Reserves Reach 4.45 Tcfe From Reserve Replacement of 789% at $1.02 Per Mcfe; Proved Reserves Expected to Reach 4.6 Tcfe By Year-End 2004, 5.0 Tcfe by YEAR-End 2005 and 5.4 Tcfe By Year-End 2006
PRNewswire-FirstCall
OKLAHOMA CITY

Chesapeake Energy Corporation today reported its financial and operating results for the 2004 third quarter. For the quarter, Chesapeake generated net income available to common shareholders of $85.6 million ($0.29 per fully diluted common share), operating cash flow of $353.4 million (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $361.3 million (defined as income before income taxes, interest expense, and depreciation, depletion and amortization expense) on revenue of $629.8 million.

The company's 2004 third quarter net income available to common shareholders includes an unrealized after-tax mark-to-market loss of $24.8 million ($0.08 per fully diluted common share) resulting from the company's oil and natural gas and interest rate hedging programs. This item is typically excluded from analysts' estimates.

If this item had been excluded, Chesapeake's net income to common shareholders would have been $110.3 million ($0.37 per fully diluted common share) and ebitda would have been $393.8 million. This item does not affect the calculation of operating cash flow.

Oil and Natural Gas Production and Proved Reserves Again Set Records; Reserve Replacement Rate of 789% Achieved at Attractive Cost of $1.02 Per Mcfe

Production for the 2004 third quarter was 94.2 billion cubic feet of natural gas equivalent (bcfe), an increase of 23.2 bcfe, or 33%, over the 71.0 bcfe produced in the 2003 third quarter and an increase of 7.7 bcfe, or 9%, over the 86.5 bcfe produced in the 2004 second quarter. The 23.2 bcfe increase in this year's third quarter production over 2003 third quarter production consisted of approximately 9.3 bcfe (40%) generated from organic drillbit growth and approximately 13.9 bcfe (60%) generated from acquisitions. The company's 2004 third quarter production exceeded its July 26, 2004 forecasted 2004 third quarter production by 2.2 bcfe, or 2.4%, because of stronger than forecasted drilling results in 2004.

Chesapeake's annualized organic growth rate during the first three quarters of 2004 has been 13%, well above the company's previously forecasted organic growth rate of 5% and among the best organic growth performances reported by public mid- and large-cap E&P companies this year. In addition, the balance between Chesapeake's growth through the drillbit and growth through acquisitions reflects the continued successful execution of the company's successful growth strategy. The company is projecting annual organic growth rates of 13% in 2004, 10% in 2005 and 8% in 2006. Total projected company production growth rates are 33% in 2004, 14% in 2005 and 8% in 2006.

Production in the 2004 third quarter of 94.2 bcfe was comprised of 83.2 billion cubic feet of natural gas (bcf) (88% on a natural gas equivalent basis) and 1.83 million barrels of oil and natural gas liquids (mmbo) (12% on a natural gas equivalent basis). Chesapeake's average daily production rate for the quarter was 1,024 million cubic feet of natural gas equivalent production (mmcfe), consisting of 905 mmcf of gas and 19,935 barrels of oil and natural gas liquids. The 2004 third quarter was Chesapeake's 13th consecutive quarter of sequential production growth. During these 13 quarters, Chesapeake's production has increased 141%, for an average compounded quarterly growth rate of 7% and an average compounded annual growth rate of 31%.

During the 2004 third quarter, the company replaced its 94.2 bcfe of production with an internally estimated 744 bcfe of new proved reserves, for a reserve replacement rate of 789% at a drilling and acquisition cost of $1.02 per mcfe. Reserve replacement through the drillbit was 364 bcfe (including 91 bcfe from performance revisions and 18 bcfe from oil and natural gas price increases), or 49% of the total increase, and reserve replacement through acquisitions was 380 bcfe, or 51% of the total increase. At the end of the third quarter, Chesapeake's estimated proved reserves were 4.45 trillion cubic feet of natural gas equivalent (tcfe). The company anticipates that its year- end 2004 proved reserves will be approximately 4.6 tcfe and that its year-end 2005 and 2006 proved reserves should be approximately 5.0 tcfe and 5.4 tcfe, respectively, excluding any potential proved reserves added through future acquisitions.

Average prices realized during the 2004 third quarter (including realized gains or losses from oil and gas derivatives, but excluding unrealized gains or losses on such derivatives) were $29.15 per barrel of oil (bo) and $5.17 per thousand cubic feet of natural gas (mcf), for a realized gas equivalent price of $5.13 per thousand cubic feet of natural gas equivalent (mcfe). Chesapeake's average realized pricing differentials to NYMEX during the quarter were a negative $2.98 per bo and a negative $0.56 per mcf. Realized gains or losses from oil and natural gas hedging activities generated an $11.16 loss per bo and a $0.21 loss per mcf, for a 2004 third quarter realized hedging loss of $38.0 million, or $0.40 per mcfe.

Key Operational and Financial Statistics for the 2004 Third Quarter

The table below summarizes Chesapeake's key results during the 2004 third quarter and compares them to the 2004 second quarter and the 2003 third quarter:

                                                Three Months Ended:

                                            9/30/04     6/30/04     9/30/03
   Average daily production (in mmcfe)        1,024         951         772
   Gas as % of total production                  88          88          90
   Natural gas production (in bcf)             83.2        76.5        63.7
   Average realized gas price ($/mcf)(a)       5.17        4.87        4.92
   Oil production (in mbbls)                  1,834       1,673       1,216
   Average realized oil price ($/bo)(a)       29.15       28.12       26.20
   Natural gas equivalent production
    (in bcfe)                                  94.2        86.5        71.0
   Gas equivalent realized price ($/mcfe) (a)  5.13        4.85        4.86
   General and administrative costs
    ($/mcfe) (b)                                .09         .09         .07
   Production taxes ($/mcfe)                    .33         .26         .30
   Production expenses ($/mcfe)                 .57         .57         .51
   Interest expense ($/mcfe) (a)                .45         .44         .53
   DD&A of oil and gas properties ($/mcfe)     1.63        1.58        1.38
   Operating cash flow ($ in millions) (c)    353.4       308.2       247.7
   Operating cash flow ($/mcfe)                3.75        3.56        3.49
   Ebitda ($ in millions) (d)                 361.3       324.1       285.3
   Ebitda ($/mcfe)                             3.83        3.74        4.02
   Net income to common shareholders
    ($ in millions)                            85.6        85.8        81.9

  (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

Strong Drilling Results and Significant Leasehold Additions Lead to Increased Production Estimates; Leasehold and 3-D Seismic Inventories Reach 3.5 Million

            and 9.0 Million Net Acres and Identified Probable
                  and Possible Reserves Exceed 4.0 Tcfe

Chesapeake's exploratory and development drilling programs and production enhancement operations on its properties continue to produce operational results that exceed the company's forecasts and distinguish the company among its peers. During the 2004 third quarter, Chesapeake drilled 182 gross (143 net) operated wells and participated in another 292 gross (38 net) wells operated by other companies. The company's drilling success rate was 98% for company-operated wells and 96% for non-operated wells. During the quarter, Chesapeake invested $224 million in operated wells, $68 million in non- operated wells and $66 million in acquiring new leasehold and 3-D seismic data.

In addition to adding significant leasehold to its existing leasehold positions in Bray, Cement, Cordell, Mayfield, Sahara, Texoma, Watonga- Chickasha, Anadarko Shelf and other existing core Anadarko and Arkoma Basin projects, Chesapeake also has been aggressively building industry-leading leasehold positions in the Granite Wash and Cherokee/Atoka Wash gas resource plays in the Anadarko Basin (approximately 200,000 prospective net acres acquired to date), in the Hartshorne Coal and Caney Shale gas resource plays of the Arkoma Basin (approximately 200,000 prospective acres acquired to date) and in the Barnett Shale gas resource play in North Texas (approximately 15,000 prospective net acres acquired to date, mainly in our Hallwood JV in Johnson County).

Chesapeake believes it has built the largest onshore U.S. inventories of leasehold and 3-D seismic in the industry (more than 3.5 million and 9.0 million net acres, respectively) and believes it has identified more than a seven-year drilling backlog of 5,000 locations on which the company expects to develop more than 4.0 tcfe of internally estimated probable and possible reserves.

   Strong Operational Results Lead to Another Increase in 2004 and 2005
  Production Forecasts and to a Strong Initial 2006 Production Forecast

For the 12th consecutive quarter, Chesapeake is increasing its production forecasts. Chesapeake now estimates that its 2004 fourth quarter production will range from 98 to 99 bcfe (1,069 mmcfe per day at the midpoint), up 2.1% from its previous forecast of 96 to 97 bcfe (1,049 mmcfe per day at the midpoint) issued on July 26, 2004. Production in the 2004 fourth quarter should exceed 2003 fourth quarter production by approximately 25 bcfe, or 34%.

For the full-year 2004, the company has increased its mid-point production forecast by 3.0 bcfe (0.8%) to a range of 356 to 358 bcfe (975 mmcfe per day at the mid-point) from its previous forecast of 353 to 355 bcfe (967 mmcfe per day at the mid-point) issued on July 26, 2004. Production for the full-year 2004 should exceed full-year 2003 production by approximately 89 bcfe, or 33%, 40% of which is projected organic growth.

For the full-year 2005, the company has increased its mid-point production forecast by 12.0 bcfe (3.0%) to a range of 403 to 411 bcfe (1,115 mmcfe per day at the mid-point) from its previous forecast of 390 to 400 bcfe (1,082 mmcfe per day at the mid-point) issued on July 26, 2004. Production for the full-year 2005 should exceed full-year 2004 production by approximately 50 bcfe, or 14%, 70% of which is projected organic growth.

For the full-year 2006, the company has released its initial mid-point production forecast of a range of 433 to 443 bcfe (1,200 mmcfe per day at the mid-point). Production for the full-year 2006 should exceed full-year 2005 production by approximately 31 bcfe, or 8%, all of which is projected organic growth.

      Chesapeake Takes Advantage of Recent Natural Gas and Oil Price
        Strength and Adds to its Natural Gas and Oil Price Hedges

Chesapeake has taken advantage of recent natural gas and oil price strength and has added to its hedge positions in 2004, 2005 and 2006. In addition, by taking advantage of natural gas price weakness during the 2004 second quarter and lifting all of its hedges for 2006 and 2007 natural gas production and then reinstating hedges for 3% of its projected 2006 natural gas production in the third quarter, the company has saved approximately $25 million to date in potential hedging losses. The following tables compare Chesapeake's projected 2004-2007 oil and natural gas production volumes that have been hedged as of November 1, 2004 to what had been previously hedged as of July 26, 2004.

                   Hedged Positions as of November 1, 2004
                                    Oil                     Natural Gas
   Quarter or Year          % Hedged    $ NYMEX        % Hedged      $ NYMEX

   2004 1Q                    87 %       $28.58            99 %       $5.97
   2004 2Q                    92 %       $30.00            81 %       $5.15
   2004 3Q                    83 %       $30.32            85 %       $5.40
   2004 4Q                    96 %       $30.10            86 %       $5.77
   2004 Total                 89 %       $29.80            88 %       $5.58
   2005 1Q                    52 %       $41.76            64 %       $6.70
   2005 2Q                    52 %       $41.63            34 %       $5.51
   2005 3Q                     8 %       $31.16            28 %       $5.41
   2005 4Q                     8 %       $30.62            18 %       $5.22
   2005 Total                 30 %       $40.20            35 %       $5.96
   2006                      ---            ---             3 %       $4.87


                    Hedged Positions as of July 26, 2004
                                    Oil                      Natural Gas
   Quarter or Year          % Hedged    $ NYMEX        % Hedged      $ NYMEX

   2004 1Q                    87 %       $28.58            99 %       $5.97
   2004 2Q                    92 %       $30.00            81 %       $5.15
   2004 3Q                    95 %       $30.32            68 %       $5.25
   2004 4Q                    95 %       $30.10            40 %       $5.12
   2004 Total                 92 %       $29.80            71 %       $5.41
   2005                        9 %       $31.56            17 %       $4.74
   2006                      ---            ---           ---           ---

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 2004 and 2005 forecasts and initial 2006 forecast are attached to this release in an Outlook dated November 1, 2004 labeled as Schedule "A". This Outlook has been changed from the Outlook dated July 26, 2004 (attached as Schedule "B" for investors' convenience) to reflect today's increased production forecasts and the projected effects from hedging position changes.

Balance Sheet Continues to Strengthen

As of September 30, 2004, Chesapeake's long-term debt was $2.76 billion and its stockholders' equity was $2.82 billion, for a debt-to-total capitalization ratio of 49%. The company's proved reserves were 4.45 tcfe, for long-term debt per mcfe of proved reserves of $0.62. One year ago, the company's debt-to-total capitalization ratio was 56% and its long-term debt per mcfe of proved reserves was $0.68, reflecting improvements of 13% and 9%, respectively. Given Chesapeake's strong reserve replacement record through the drillbit, low operating costs and high returns on invested capital, the company believes that its balance sheet will continue to strengthen in the years ahead. During November 2004, the company expects to cause conversion of its $135.7 million of 6.75% perpetual preferred stock into 17,624,658 shares of common stock.

Management Comments

Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "Today's announcement of very strong operational and financial results for the 2004 third quarter and increased production forecasts for the 2004 fourth quarter and the full-years of 2004, 2005 and 2006 provide compelling evidence that Chesapeake's business strategy continues to create significant shareholder value. Key measures reflecting this increase in shareholder value are:

   *  a record level of proved reserves, production, net income to common
      shareholders, cash flow and ebitda;
   *  a 9% increase in sequential quarterly production from the 2004 second
      quarter to the 2004 third quarter;
   *  a 33% increase in year-over-year quarterly production;
   *  a 33% increase in estimated 2004 production over 2003 production;
   *  a 14% increase in estimated 2005 production over estimated 2004
      production;
   *  an 8% increase in estimated 2006 production over estimated 2005
      production;
   *  reserve replacement for the quarter of 789% at an estimated drilling
      and acquisition cost of $1.02 per mcfe;
   *  excellent operating cost control and high returns on equity and total
      capital;
   *  a seven-year inventory of drilling projects with development potential
      of at least 4.0 tcfe of estimated probable and possible reserves in
      the years ahead.

The company's business strategy has worked very well for our shareholders since our IPO on February 4, 1993, generating a 1,150% increase in our common stock price during the past 11 years. Our business strategy features delivering growth through a balance of acquisitions and organic 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 on capital. 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."

November 2004 Investor Conference Information

Chesapeake has scheduled three management conferences with qualified institutional investors on the following dates and places: Tuesday, November 16, 2004 from 12:00 p.m. - 5:00 p.m. EST at the Four Seasons Hotel in New York; Wednesday, November 17, 2004 from 7:30 a.m. - 12:30 p.m. EST at the Ritz Carlton Boston Common in Boston; and Thursday, November 18, 2004 from 7:30 a.m. - 12:30 p.m. PST at the Peninsula Hotel, Los Angeles. Representing the company will be Aubrey McClendon (CEO), Tom Ward (COO), Marc Rowland (CFO), Tom Price (SVP - IR) and Mark Lester (SVP - Exploration). Seating space is limited and those investors wishing to attend must communicate interest in attending by emailing Robin Evans at revans@chkenergy.com and indicating the conference venue desired.

Conference Call Information

A conference call has been scheduled for Tuesday morning, November 2, 2004 at 9:00 a.m. EST to discuss this earnings release. The telephone number to access the conference call is 913.981.5520. For those unable to participate in the conference call, a replay will be available from 12:00 p.m. EST, November 2, 2004 through midnight EST on November 15, 2004. The number to access the conference call replay is 719.457.0820 and the passcode is 840912. 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. Disclosures concerning 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 our prospectus dated September 10, 2004 filed with the Securities and Exchange Commission on September 10, 2004. They include the volatility of oil and gas prices; adverse effects our substantial indebtedness and preferred stock obligations could have on our operations and future growth; our ability to compete effectively against strong independent oil and gas companies and majors; possible financial losses and significant collateral requirements as a result of our commodity price and interest rate risk management activities; uncertainties inherent in estimating quantities of oil and gas reserves, including reserves we acquire; projecting future rates of production and the timing of development expenditures; exposure to potential liabilities of acquired properties and companies; our ability to replace reserves; the availability of capital; writedowns of oil and gas carrying values if commodity prices decline; environmental and other claims in excess of insured amounts resulting from drilling and production operations; and the loss of key personnel. 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. 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" and "possible" reserves or other descriptions of 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.

Chesapeake Energy Corporation is the fifth 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 producing property acquisitions in the Mid-Continent, Permian Basin, South Texas, Texas Gulf Coast and Ark-La-Tex 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:                     September 30,     September 30,
                                               2004             2003
                                            $      $/mcfe    $        $/mcfe
  REVENUES:
    Oil and gas sales                    450,936     4.79  345,587     4.87
    Oil and gas marketing sales          178,860     1.90  108,962     1.53
      Total Revenues                     629,796     6.69  454,549     6.40

  OPERATING COSTS:
    Production expenses                   54,102     0.57   35,944     0.51
    Production taxes                      30,872     0.33   21,638     0.30
    General and administrative expenses:
      General and administrative
      (excluding stock based
      compensation)                        8,361     0.09   4,726      0.07
      Stock based compensation               584     0.01     147       ---
    Provisions for legal settlements         ---      ---     716      0.01
    Oil and gas marketing expenses       175,426     1.86 105,849      1.49

    Oil and gas depreciation,
     depletion, and amortization         153,586     1.63  97,947      1.38
    Depreciation and amortization
     of other assets                       7,700     0.08   4,841      0.07
      Total Operating Costs              430,631     4.57 271,808      3.83

  INCOME FROM OPERATIONS                 199,165     2.12 182,741      2.57

  OTHER INCOME (EXPENSE):
    Interest and other income                885     0.01    (188)      ---
    Interest expense                     (48,689)   (0.52)(40,851)    (0.57)
      Total Other Income (Expense)       (47,804)   (0.51)(41,039)    (0.57)

  Income Before Income Taxes             151,361     1.61 141,702      2.00

  Income Tax Expense:
    Current                                  ---      ---     330       ---
    Deferred                              54,489     0.58  53,513      0.76
      Total Income Tax Expense            54,489     0.58  53,843      0.76

  NET INCOME                              96,872     1.03  87,859      1.24

  Preferred Stock Dividends              (11,287)   (0.12) (5,979)    (0.09)

  NET INCOME AVAILABLE TO COMMON
  SHAREHOLDERS                            85,585     0.91  81,880      1.15

  EARNINGS PER COMMON SHARE:
     Basic                                 $0.33            $0.38
     Assuming dilution                     $0.29            $0.33

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

    Basic                                257,096          216,080
    Assuming dilution                    319,473          265,545



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

  NINE MONTHS ENDED:                      September 30,      September 30,
                                              2004               2003
                                            $     $/mcfe       $      $/mcfe
  REVENUES:
    Oil and gas sales                   1,270,394   4.89     951,125   4.87
    Oil and gas marketing sales           496,823   1.91     309,566   1.59
      Total Revenues                    1,767,217   6.80   1,260,691   6.46

  OPERATING COSTS:
    Production expenses                   148,500   0.57     101,664   0.52
    Production taxes                       68,559   0.26      57,336   0.29
    General and administrative expenses:
      General and administrative
      (excluding stock based
      compensation)                        23,947   0.09      15,740   0.08
      Stock based compensation              3,125   0.01         512    ---
    Provision for legal settlements           ---    ---       1,002   0.01
    Oil and gas marketing expenses        486,205   1.88     302,064   1.55
    Oil and gas depreciation, depletion,
     and amortization                     410,237   1.58     266,131   1.36
    Depreciation and amortization
     of other assets                       20,155   0.08      12,647   0.07
      Total Operating Costs             1,160,728   4.47     757,096   3.88

  INCOME FROM OPERATIONS                  606,489   2.33     503,595   2.58

  OTHER INCOME (EXPENSE):
    Interest and other income               3,563   0.01       1,356   0.01
    Interest expense                     (124,040) (0.47)   (115,891) (0.59)
    Loss on repurchases or exchanges
     of Chesapeake debt                    (6,925) (0.03)        ---    ---
      Total Other Income (Expense)       (127,402) (0.49)   (114,535) (0.58)

  Income Before Income Taxes
   and Cumulative Effect
   of Accounting Change                   479,087   1.84     389,060   2.00

  Income Tax Expense:
    Current                                   ---    ---         330    ---
    Deferred                              172,470   0.66     147,511   0.76
      Total Income Tax Expense            172,470   0.66     147,841   0.76

  NET INCOME BEFORE CUMULATIVE EFFECT OF
    ACCOUNTING CHANGE, NET OF TAX         306,617   1.18     241,219   1.24

  Cumulative Effect of Accounting Change,
   Net of Income Tax of $1,464,000            ---    ---       2,389   0.01

  NET INCOME                              306,617   1.18     243,608   1.25

  Preferred Stock Dividends               (30,799) (0.12)    (15,484) (0.08)

  NET INCOME AVAILABLE TO COMMON
   SHAREHOLDERS                           275,818   1.06     228,124   1.17



  EARNINGS PER COMMON SHARE:

     Basic
       Income Before Cumulative
        Effect of Accounting Change         $1.13              $1.08
       Cumulative Effect of                   ---               0.01
        Accounting Change
       Net Income                           $1.13              $1.09

     Assuming dilution
       Income Before Cumulative
        Effect of Accounting Change         $0.98               $0.95
       Cumulative Effect of                   ---                0.01
        Accounting Change
       Net Income                           $0.98               $0.96

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

    Basic                                 245,087              209,394
    Assuming dilution                     307,438              253,567


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

                                                  September 30, December 31,
                                                       2004        2003

  Cash                                               $49,073     $40,581
  Other current assets                               471,445     301,823
       TOTAL CURRENT ASSETS                          520,518     342,404

  Property and equipment (net)                     6,792,727   4,133,117
  Other assets                                       113,046      96,770
       TOTAL ASSETS                               $7,426,291  $4,572,291

  Current liabilities                               $973,010    $513,156
  Long term debt                                   2,762,425   2,057,713
  Asset retirement obligation                         68,166      48,812
  Long term liabilities                               58,480      28,774
  Deferred tax liability                             740,895     191,026
       TOTAL LIABILITIES                           4,602,976   2,839,481

  STOCKHOLDERS' EQUITY                             2,823,315   1,732,810

  TOTAL LIABILITIES & STOCKHOLDERS' EQUITY        $7,426,291  $4,572,291

  COMMON SHARES OUTSTANDING                          269,718     216,784


                      CHESAPEAKE ENERGY CORPORATION
         SUPPLEMENTAL DATA - OIL & GAS SALES AND INTEREST EXPENSE

                                  Three Months Ended    Nine Months Ended
                                      September 30,        September 30,
                                     2004      2003       2004       2003


  Oil and Gas Sales
  ($ in thousands):
    Oil sales                     $ 73,921  $ 33,908    $181,882   $101,811
    Oil derivatives -
     realized gains (losses)       (20,464)   (2,045)    (41,672)    (8,924)
    Oil derivatives - unrealized
     gains (losses)                (14,436)      185     (21,925)      (993)

          Total oil sales           39,021    32,048     118,285     91,894

    Gas sales                      447,466   293,309   1,222,783    889,598
    Gas derivatives - realized
     gains (losses)                (17,514)   19,781     (25,976)   (65,028)
    Gas derivatives - unrealized
     gains (losses)                (18,037)      449     (44,698)    34,661

          Total gas sales          411,915   313,539   1,152,109    859,231

          Total oil
           and gas sales          $450,936  $345,587  $1,270,394   $951,125

  Average Sales Price
   (excluding gains (losses)
   on derivatives):
    Oil ($ per bbl)               $  40.31  $  27.88  $    36.58   $  29.09
    Gas ($ per mcf)               $   5.38  $   4.61  $     5.32   $   5.11
    Gas equivalent ($ per mcfe)   $   5.53  $   4.61  $     5.41   $   5.08

  Average Sales Price (excluding
   unrealized gains (losses) on
   derivatives):
    Oil ($ per bbl)               $  29.15  $  26.20  $    28.20   $  26.54
    Gas ($ per mcf)               $   5.17  $   4.92  $     5.21   $   4.74
    Gas equivalent ($ per mcfe)   $   5.13  $   4.86  $     5.15   $   4.70

  Interest Expense
   ($ in thousands):
    Interest                      $ 42,258  $ 38,855  $  118,335   $113,011
    Derivatives - realized
     (gains) losses                    221    (1,097)       (184)    (2,453)
    Derivatives - unrealized
     (gains) losses                  6,210     3,093       5,889      5,333
          Total Interest Expense  $ 48,689  $ 40,851  $  124,040   $115,891


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


  THREE MONTHS ENDED:                         September 30,    September 30,
                                                  2004              2003

  Cash provided by operating activities         $367,649          $276,884
  Cash (used in) investing activities        $(1,068,791)        $(284,994)
  Cash provided by financing activities         $673,978           $10,679

  NINE MONTHS ENDED:                          September 30,    September 30,
                                                  2004              2003

  Cash provided by operating activities       $1,038,206          $653,517
  Cash (used in) investing activities        $(2,668,241)      $(1,600,768)
  Cash provided by financing activities      $ 1,638,527          $738,092


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

  THREE MONTHS ENDED:                          September 30,   September 30,
                                                   2004            2003

  CASH PROVIDED BY OPERATING ACTIVITIES          $367,649        $276,884

  Adjustments:
    Changes in assets and liabilities             (14,252)        (29,175)

  OPERATING CASH FLOW*                           $353,397        $247,709

  NINE MONTHS ENDED:                           September 30,   September 30,
                                                   2004            2003

  CASH PROVIDED BY OPERATING ACTIVITIES        $1,038,206        $653,517

  Adjustments:
    Changes in assets and liabilities             (43,082)        (12,026)

  OPERATING CASH FLOW*                           $995,124        $641,491


   * 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.


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



  THREE MONTHS ENDED:                            September 30, September 30,
                                                     2004          2003

  NET INCOME                                       $96,872       $87,859

  Income tax expense                                54,489        53,843
  Interest expense                                  48,689        40,851
  Depreciation and amortization of other assets      7,700         4,841
  Oil and gas depreciation, depletion
   and amortization                                153,586        97,947

  EBITDA**                                        $361,336      $285,341

  NINE MONTHS ENDED:                             September 30, September 30,
                                                     2004          2003

  NET INCOME BEFORE CUMULATIVE EFFECT
   OF ACCOUNTING CHANGE                           $306,617      $241,219

  Income tax expense                               172,470       147,841
  Interest expense                                 124,040       115,891
  Depreciation and amortization of other assets     20,155        12,647

  Oil and gas depreciation, depletion
   and amortization                                410,237       266,131

  EBITDA**                                      $1,033,519      $783,729


  ** 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,
                                                     2004          2003

  CASH PROVIDED BY OPERATING                      $367,649       $276,884
  ACTIVITIES

  Changes in assets and liabilities                (14,252)       (29,175)
  Interest expense, realized                        42,479         37,758
  Unrealized gains (losses) on oil                 (32,473)           634
   and gas derivatives
  Other non-cash items                              (2,067)          (760)

  EBITDA                                          $361,336       $285,341

  NINE MONTHS ENDED:                             September 30, September 30,
                                                     2004          2003

  CASH PROVIDED BY OPERATING ACTIVITIES         $1,038,206       $653,517
  Changes in assets and liabilities                (43,082)       (12,026)
  Interest expense, realized                       118,151        110,558
  Unrealized gains (losses) on oil                 (66,623)        33,668
   and gas derivatives
  Other non-cash items                             (13,133)        (1,988)

  EBITDA                                        $1,033,519       $783,729


                      CHESAPEAKE ENERGY CORPORATION
          RECONCILIATION OF ADJUSTED EARNINGS & ADJUSTED EBITDA
                  ($ In 000's, except per share amounts)

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

  Net income available to common shareholders   $85,585        $275,818

  Adjustments, net of tax:
    Unrealized (gains)
     losses on derivatives                       24,757          46,408
    Loss on repurchases or exchanges of debt        ---           4,432

  Adjusted earnings*                           $110,342        $326,658

  Adjusted earnings per share
   assuming dilution                              $0.37           $1.14

  EBITDA                                       $361,336      $1,033,519

  Adjustments, before tax:
    Unrealized (gains) losses
     on oil and gas derivatives                  32,473          66,623
    Loss on repurchases or
     exchanges of debt                              ---           6,925

  Adjusted EBITDA*                             $393,809      $1,107,067

   * Adjusted earnings, adjusted earnings per share assuming dilution and
     adjusted EBITDA, both non-GAAP financial measures, 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 earnings and adjusted EBITDA to evaluate
        the Company's operational trends and performance relative to other
        oil and gas producing companies.
     b. Adjusted earnings 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.



                               SCHEDULE "A"

               CHESAPEAKE'S OUTLOOK AS OF NOVEMBER 1, 2004

Quarter Ending December 31, 2004; Year Ending December 31, 2004; 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 November 1, 2004, we are using the following key assumptions in our projections for the fourth quarter of 2004, the full-year 2004, the full-year 2005 and the full-year 2006.

The primary changes from our July 26, 2004 Outlook are in the table and are explained as follows:

   1)  We have deleted our 2004 third quarter forecast and have updated our
       forecasts for the 2004 fourth quarter, the full-year 2004 and full-
       year 2005 forecasts and have provided our initial 2006 forecast.
   2)  We have updated our previous production forecast for the full-year
       2004 to reflect actual third quarter 2004 production, which exceeded
       the mid-point of our guidance by 24 mmcfe per day, or 2.4%.  In
       addition, we have revised upward our fourth quarter 2004 production
       forecast by 20 mmcfe per day, or 2.0%, from the mid-point of our
       previous guidance, ii) our full-year 2004 production forecast by
       8 mmcfe per day, or 0.8%, from the mid-point of our previous
       guidance, iii) our full-year 2005 forecast by 33 mmcfe per day, or
       3.0%, from the mid-point of our previous guidance, all to account for
       better than expected 2004 drilling results.  The mid-point of our
       initial 2006 production forecast is 438 bcfe, or 1,200 mmcfe per day,
       a projected increase of 7.6% over the midpoint of our revised 2005
       forecast and 23.1% above the mid-point of our revised 2004 production
       forecast.
   3)  We have updated the projected effects from changes in our hedging
       positions since our July 26, 2004 Outlook.
   4)  We have included our expectations for future NYMEX oil and gas prices
       to illustrate hedging effects only.
   5)  For ease of reconciliation, please note that our first quarter 2004
       production was 78.9 bcfe, our second quarter 2004 production was
       86.5 bcfe, our third quarter production was 94.2 bcfe and our first
       nine months 2004 production was 259.7 bcfe.  Our July 26, 2004
       Outlook forecasted a third quarter 2004 production range of 91.5 to
       92.5 bcfe and a full-year 2004 production range of 353 to 355 bcfe.
       The differences are attributable to better than expected 2004
       drilling results.


                                 Quarter      Year        Year       Year
                                 Ending      Ending      Ending     Ending
                                 Dec. 31,    Dec. 31,    Dec. 31,   Dec. 31,
                                   2004        2004        2005       2006
  Estimated Production:
    Oil - Mbo                      1,588       6,560       6,600       6,600
    Gas - Bcf                  88.5-89.5     317-319     364-372     393-403
    Gas Equivalent - Bcfe          98-99     356-358     403-411     433-443
    Daily gas equivalent
     midpoint - in  Mmcfe          1,069         975       1,115       1,200
  NYMEX Prices (for calculation
   of realized hedging effects
   only):
    Oil - $/Bo                    $46.67      $41.00      $40.00      $36.00
    Gas - $/Mcf                    $6.60       $6.01       $6.00       $6.00
  Estimated Differentials to
  NYMEX Prices:
    Oil - $/Bo                    -$2.75      -$2.65      -$2.75      -$2.75
    Gas - $/Mcf                   -$0.75      -$0.70      -$0.70      -$0.70
  Estimated Realized Hedging
  Effects (based on expected
  NYMEX prices above):
    Oil - $/Bo                   -$15.85     -$10.19       $0.06       $0.00
    Gas - $/Mcf                   -$0.53      -$0.23       $0.00      -$0.04
  Operating Costs per Mcfe of
  Projected Production:
    Production expense        $0.57-0.62  $0.57-0.62  $0.62-0.67  $0.68-0.72
    Production taxes
     (generally 7%
     of O&G revenues)         $0.40-0.44  $0.28-0.33  $0.38-0.40  $0.38-0.40
    General and
     administrative           $0.10-0.11  $0.10-0.11  $0.10-0.11  $0.11-0.12
    Stock based compensation
     (non-cash)               $0.02-0.04  $0.02-0.04  $0.04-0.06  $0.09-0.10
    DD&A - oil and gas        $1.65-1.70  $1.60-1.65  $1.65-1.75  $1.75-1.85
    Depreciation
     of other assets          $0.08-0.10  $0.08-0.10  $0.09-0.11  $0.10-0.12

    Interest expense(a)       $0.45-0.49  $0.45-0.49  $0.43-0.47  $0.43-0.47
  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                    36%        36%         36%         36%

  Equivalent Shares Outstanding:
    Basic                         279 mm      254 mm      288 mm      290 mm
    Diluted                       347 mm      317 mm      349 mm      352 mm

  Capital Expenditures:
    Drilling, leasehold and
     seismic                $300-$325 mm    $1,100 -     $1,200 -   $1,300 -
                                            $1,150 mm   $1,300 mm  $1,400 mm

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

  2004:
  1st Qtr     69.5      $5.94      $0.03     $5.97       70.1         99 %
  2nd Qtr     62.2      $5.15      $0.00     $5.15       76.5         81 %
  3rd Qtr(1)  70.7      $5.49     -$0.09     $5.40       83.2         85 %
  4th Qtr(1)  76.5      $5.88     -$0.11     $5.77       89.0         86 %
  Total      278.9      $5.63     -$0.05     $5.58      318.8         88 %
  2004

  2005:
  1st Qtr     56.1      $6.82     -$0.12     $6.70       87.7         64 %
  2nd Qtr     30.4      $5.86     -$0.35     $5.51       90.7         34 %
  3rd Qtr     26.2      $5.77     -$0.36     $5.41       93.8         28 %
  4th Qtr     17.0      $5.85     -$0.63     $5.22       95.8         18 %
  Total
   2005(1)   129.7      $6.26     -$0.30     $5.96      368.0         35 %

  Total
   2006(1)    13.8      $6.64     -$1.77     $4.87      398.0          3 %

  Total
   2007(2)     ---        ---        ---       ---      430.0         ---

  TOTALS
   2005-2007 143.5      $6.30     -$0.44     $5.86    1,196.0         12 %


   (1)  Certain hedging arrangements include swaps with knockout prices
        ranging from $3.50 to $5.25 covering 25.4 bcf in 2004, $3.75 to
        $5.00 covering 52.9 bcf in 2005 and $3.75 to $5.25 covering 21.1 bcf
        in 2006.
   (2)  Swaps covering 25.6 bcf have been locked for 2007.  This will result
        in the recognition of $11.6 million of losses in 2007 when the
        hedging arrangements settle.
   (3)  Not shown above are collars covering 1.1 bcf and 4.4 bcf of
        production in Q4 2004 and in 2005, respectively, at a weighted
        average floor and ceiling of $3.10 and $4.44.  In addition, call
        options covering 10.2 bcf and 7.3 bcf of production in Q4 2004 and
        in 2005 at a weighted average price of $6.31 and $6.00 are not
        included in the table above.

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

                                               Assuming
                                                  Gas
                                               Production
                  Volume in        NYMEX       in Bcf's
                    Bcf's          less:          of:          % Hedged
  2004             157.4           0.17          318.8            49 %
  2005             175.2           0.25          368.0            48 %
  2006             113.1           0.30          398.0            28 %
  2007             107.7           0.26          430.0            25 %
  2008             108.0           0.25          460.0            23 %
  2009              80.3           0.28          490.0            16 %
  Totals           741.7          $0.26 *      2,464.8            30 % *

  * weighted average

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

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

  Q1 - 2004         1,270   $28.58       1,465                   87 %

  Q2 - 2004         1,540   $30.00       1,673                   92 %

  Q3 - 2004(1)      1,519   $30.32       1,834                   83 %

  Q4 - 2004(1)      1,518   $30.10       1,588                   96 %


  Total 2004(1)     5,847   $29.80      6,560                    89 %


  Q1 - 2005           855   $41.76      1,650                    52 %

  Q2 - 2005           865   $41.63      1,650                    52 %

  Q3 - 2005           138   $31.16      1,650                     8 %

  Q4 - 2005           138   $30.62      1,650                     8 %

  Total 2005(1)     1,996   $40.20      6,600                    30 %


  (1)  Certain hedging arrangements include swaps with knockout prices
       ranging from $21.00 to $26.00 covering 2,240 mbo in 2004 and knockout
       prices ranging from $26.00 to $34.00 covering 1,996 mbo in 2005.


                               SCHEDULE "B"

            CHESAPEAKE'S PREVIOUS OUTLOOK AS OF JULY 26, 2004
                      (PROVIDED FOR REFERENCE ONLY)

             NOW SUPERSEDED BY OUTLOOK AS OF NOVEMBER 1, 2004

Quarter Ending September 30, 2004; Quarter Ending December 31, 2004; Year Ending December 31, 2004; Year Ending December 31, 2005.

We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of July 26, 2004, we are using the following key assumptions in our projections for the third and fourth quarters of 2004, the full-year 2004 and the full-year 2005.

The primary changes from our May 11, 2004 guidance are explained as follows:

   1)  We have replaced our 2004 second quarter forecast with our initial
       forecasts for the 2004 third and fourth quarters, have revised our
       full year 2004 forecast and have provided our initial 2005 forecast.
   2)  We have updated our previous production forecasts for the full year
       2004 to include today's announced acquisitions and the results of
       recent drilling activities.  These include 30 mmcfe per day of
       production beginning August 2, 2004 and an additional 30 mmcfe per
       day beginning September 1, 2004 for the acquisitions and an
       additional 6.5 mmcfe per day beginning July 1, 2004 for better than
       expected drilling results during the second quarter.
   3)  We have updated the projected effects from the reductions in our
       hedging positions.
   4)  We have included our expectations for future NYMEX oil and gas prices
       to illustrate hedging effects only.  For ease of reconciliation,
       please note that our first quarter 2004 production was 78.9 bcfe, our
       second quarter 2004 production was 86.5 bcfe and our first half 2004
       production was 165.4 bcfe.  Our May 11, 2004 Outlook forecasted a
       second quarter 2004 production range of 83-84 bcfe and a full year
       2004 production range of  341-347 bcfe.
   5)  Solely for the purposes of this Schedule "A" we have included the
       projected effects of financing the recently announced acquisitions
       with the issuance of $300 million of long-term debt securities and
       23 million shares of common stock (including a 3 million share over-
       allotment option).  There is no assurance we will make or complete
       such offerings.

                                    Quarter   Quarter     Year      Year
                                     Ending    Ending    Ending     Ending
                                    Sept. 30,  Dec. 31,  Dec. 31,   Dec. 31,
                                      2004       2004      2004      2005
  Estimated Production:
    Oil - Mbo                        1,600      1,600     6,340      6,360
    Gas - Bcf                        82-83  86.5-87.5   315-317    352-362
    Gas Equivalent - Bcfe        91.5-92.5      96-97   353-355    390-400
    Daily gas equivalent midpoint    1,000      1,049       967      1,082
     - in  Mmcfe
  NYMEX Prices (for calculation
   of realized hedging effects
   only):
    Oil - $/Bo                      $34.00     $32.00    $34.87     $30.00
    Gas - $/Mcf                      $5.71      $5.50     $5.73      $5.00
  Estimated Differentials to
   NYMEX Prices:
    Oil - $/Bo                      -$2.75     -$2.75    -$2.75     -$2.75
    Gas - $/Mcf                     -$0.75     -$0.75    -$0.75     -$0.75
  Estimated Realized Hedging
  Effects (based on expected
  NYMEX prices above):
    Oil - $/Bo                        -$3.52    -$1.82    -$4.70      $0.13
    Gas - $/Mcf                       -$0.23     $0.01    -$0.09      $0.11
  Operating Costs per Mcfe of
  Projected Production:
    Production expense          $0.57-0.62 $0.57-0.62 $0.57-0.62 $0.60-0.65
    Production taxes
     (generally 7%
     of O&G revenues)           $0.34-0.38 $0.34-0.38 $0.28-0.33 $0.30-0.35
    General and administrative  $0.10-0.11 $0.10-0.11 $0.10-0.11 $0.10-0.11
    Stock based compensation
     (non-cash)                 $0.02-0.04 $0.02-0.04 $0.02-0.04 $0.06-0.07
    DD&A - oil and gas          $1.60-1.65 $1.60-1.65 $1.60-1.65 $1.65-1.70
    Depreciation
     of other assets            $0.08-0.10 $0.08-0.10 $0.08-0.10 $0.08-0.10
    Interest expense(a)         $0.46-0.50 $0.46-0.50 $0.45-0.49 $0.44-0.48
  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                      36 %       36 %       36 %       36 %

  Equivalent Shares Outstanding:
    Basic                           256 mm     278 mm     253 mm     285 mm
    Diluted(b)                      319 mm     328 mm     312 mm     328 mm

  Capital Expenditures:
    Drilling, leasehold and
     seismic                     $260-$290  $260-$290     $1,000-   $1,000 -
                                     mm         mm       $1,100 mm $1,100 mm

   (a)  Does not include gains or losses on interest rate derivatives
        (SFAS 133).
   (b)  Does not include the potential conversion of the company's 4.125%
        convertible preferred stock because the common stock price does
        not exceed the conversion price of the preferred.


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

  2004:
  1st Qtr      69.5      $5.94      $0.03     $5.97       70.1         99 %
  2nd Qtr      62.2      $5.15      $0.00     $5.15       76.5         81 %
  3rd Qtr(1)   56.3      $5.34     -$0.09     $5.25       82.5         68 %
  4th Qtr(1)   35.0      $5.39     -$0.27     $5.12       87.0         40 %

  Total 2004  223.0      $5.48     -$0.07     $5.41      316.1         71 %
  Total
   2005(1)     61.3      $5.24     -$0.50     $4.74      357.0         17 %
  Total 2006
   (1)(2)       ---        ---        ---       ---      375.0         ---
  Total
   2007(2)      ---        ---        ---       ---      395.0         ---
  TOTALS
   2004-2007  284.3      $5.43     -$0.29     $5.14    1,443.1         24 %

  (1)  Certain hedging arrangements include swaps with knockout price
       ranging from $3.75 to $4.75 covering 4.6 bcf in 2004, $3.75 to $4.75
       covering 9.1 bcf in 2005 and $3.75 covering 7.3 bcf in 2006.
  (2)  Swaps covering 32.9 bcf and 25.6 bcf have been locked for 2006 and
       2007.  This will result in the recognition of $22.6 million and
       $11.6 million of losses in 2006 and 2007, respectively, when the
       hedging arrangements settle.
  (3)  Not shown above are collars covering 1.5 bcf and 4.4 bcf of
       production in 2004 and 2005, respectively, at a weighted average
       floor and ceiling of $3.10 and $4.44.  In addition, call options
       covering 27.4 bcf and 7.3 bcf of production in 2004 and 2005 at
       weighted average price of $6.19 and $6.00 are not included in the
       table above.

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

                                                    Assuming
                                                      Gas
                                                   Production
                      Volume in        NYMEX        in Bcf's
                        Bcf's          less:           of:          % Hedged
  2004                  157.4          0.173          316.1            50 %
  2005                  109.5          0.156          357.0            31 %
  2006                   47.5          0.155          375.0            13 %
  2007                   63.9          0.166          395.0            16 %
  2008                   64.0          0.166          415.0            15 %
  2009                   37.0          0.160          435.0             9 %
  Totals                479.3        $0.164*        2,293.1            21 %
   * weighted average

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

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

  Q1 - 2004         1,270    $28.58           1,465                87 %

  Q2 - 2004         1,540    $30.00           1,673                92 %

  Q3 - 2004(1)      1,519    $30.32           1,600                95 %

  Q4 - 2004(1)      1,518    $30.10           1,600                95 %


  Total 2004(1)     5,847    $29.80           6,338                92 %

  Total 2005(1)       548    $31.56           6,360                 9 %

  (1)  Certain hedging arrangements include swaps with a knockout price
       ranging from $21.00 to $26.00 covering 2,240 mbo in 2004 and a
       knockout price of $26.00 covering 548 mbo in 2005.

SOURCE: Chesapeake Energy Corporation

CONTACT: Marc Rowland, Executive Vice President and Chief Financial
Officer, +1-405-879-9232, or Tom Price, Jr., Senior Vice President-Investor
Relations, +1-405-879-9257, both of Chesapeake Energy Corporation