Chesapeake Energy Corporation Reports Record Results for the Fourth Quarter and Full-Year 2004
Company Reports 2004 Fourth Quarter Net Income Available to Common Shareholders of $163 Million on Revenue of $942 Million and Production of 103 Bcfe
Company Reports Full-Year 2004 Net Income Available to Common Shareholders of $439 Million on Revenue of $2,709 Million and Production of 363 Bcfe
Proved Reserves Reach 4.9 Tcfe from Proved Reserve Adds of 1.7 Tcfe; Reserve Replacement Equals 578% at the Attractive Drilling and Acquisition Cost of $1.21 Per Mcfe; Proved Reserves Now Expected to Exceed 5.4 Tcfe by Year-End 2005 and 5.8 Tcfe by Year-End 2006
Oil and Natural Gas Production Increases 40% Quarter-over-Quarter, 35% Year-over-Year, and 9% Sequential Quarter-over-Quarter; Organic Growth in 2004 Reaches 20%, Exceeds 2003's Excellent Organic Growth Rate of 18%; Chesapeake Now 4th Largest Independent Producer of U.S. Natural Gas
PRNewswire-FirstCall
OKLAHOMA CITY

Chesapeake Energy Corporation today reported financial and operating results for the fourth quarter of 2004 and for the full-year 2004. For the quarter, Chesapeake generated net income available to common shareholders of $163.2 million ($0.52 per fully diluted common share), operating cash flow of $423.7 million (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $550.1 million (defined as income before income taxes, interest expense, and depreciation, depletion and amortization expense) on revenue of $942.1 million and production of 102.9 billion cubic feet of natural gas equivalent (bcfe).

For the full-year 2004, Chesapeake generated net income available to common shareholders of $439.0 million ($1.53 per fully diluted common share), operating cash flow of $1,418.8 million and ebitda of $1,583.6 million on revenue of $2,709.3 million and production of 362.6 bcfe.

The company's fourth quarter and full-year 2004 net income available to common shareholders and ebitda include various items that are typically not included in published estimates of the company's financial results by certain securities analysts. Such items and their after-tax effects on fourth quarter and full-year reported results are described as follows:

   *  an unrealized mark-to-market gain of $69.2 million for the fourth
      quarter and a $22.8 million gain for the full year resulting from the
      company's oil and natural gas and interest rate hedging programs;
   *  an $11.3 million loss for the fourth quarter and a $15.7 million loss
      for the full year resulting from the early extinguishment of certain
      Chesapeake debt securities;
   *  a $2.9 million loss for the fourth quarter and for the full year
      related to the settlement of certain litigation; and
   *  an adjustment to net income available to common shareholders of
      $36.7 million representing a loss on the retirement of preferred stock
      related to the exchange of substantially all of our 6.0% convertible
      preferred stock for common stock in the fourth quarter.

Adjusted for the above-mentioned gains and losses and giving effect to the issuance of common shares for preferred shares, Chesapeake's net income to common shareholders in the fourth quarter of 2004 would have been $153.5 million ($0.44 per fully diluted common share) and ebitda would have been $464.7 million. Similarly adjusted, Chesapeake's net income to common shareholders for the full year 2004 would have been $511.0 million ($1.56 per fully diluted common share) and ebitda would have been $1,571.7 million. The foregoing items do not affect the calculation of operating cash flow. A reconciliation of operating cash flow, ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 15-17 of this release.

  Oil and Natural Gas Production Again Sets Record; Fourth Quarter 2004
  Production Up 40% Over Fourth Quarter 2003; Full-Year 2004 Production
35% Higher than Full-Year 2003 Production; Sequential Organic Growth Rate
           8% in Fourth Quarter 2004 and 20% in Full-Year 2004

Production for the 2004 fourth quarter was 102.9 bcfe, an increase of 29.6 bcfe, or 40%, over the 73.3 bcfe produced in the 2003 fourth quarter and an increase of 8.7 bcfe, or 9%, over the 94.2 bcfe produced in the 2004 third quarter. The 29.6 bcfe increase in 2004's fourth quarter production over 2003's fourth quarter production consisted of 14.4 bcfe (49%) generated from organic drillbit growth and 15.2 bcfe (51%) generated from acquisitions. The 8.7 bcfe increase in sequential quarterly production consisted of 6.7 bcfe (77%) generated from organic drillbit growth and 2.0 bcfe (23%) generated from acquisitions. The company's 2004 fourth quarter production exceeded its December 27, 2004 forecasted 2004 fourth quarter mid-point production by 4.4 bcfe, or 4.5%, because of stronger than expected drilling and operational results.

Production for the full-year 2004 was 362.6 bcfe, an increase of 94.2 bcfe, or 35%, over the 268.4 bcfe produced in 2003 and an increase of 181.1 bcfe, or 100%, over the 181.5 bcfe produced in 2002. The 94.2 bcfe increase in 2004's production over 2003's production consisted of 52.2 bcfe (55%) generated from organic drillbit growth and 42.0 bcfe (45%) generated from acquisitions.

Chesapeake's 2004 organic growth rate of 20% follows organic growth of 18% in 2003, 6% in 2002 and 9% in 2001. During these four years, Chesapeake's total organic growth rate has been 69% and its average annual organic growth rate has been 14%. Total company production growth was 35% in 2004, 48% in 2003, 19% in 2002 and 25% in 2001 (U.S. only). Chesapeake is projecting total company production growth rates of 20% in 2005 and 11% in 2006 and organic growth rates of 10% in 2005 and 10% in 2006.

Chesapeake's 2004 fourth quarter production of 102.9 bcfe was comprised of 92.2 billion cubic feet of natural gas (bcf) (90% on a natural gas equivalent basis) and 1.79 million barrels of oil and natural gas liquids (mmbo) (10% on a natural gas equivalent basis). Chesapeake's average daily production rate for the quarter was 1,119 million cubic feet of natural gas equivalent production (mmcfe), consisting of 1,002 mmcf of gas and 19,478 barrels of oil and natural gas liquids. The 2004 fourth quarter was Chesapeake's 14th consecutive quarter of sequential production growth. During these 14 quarters, Chesapeake's U.S. production has increased 186%, for an average compound quarterly growth rate of 7.8% and an average compound annual growth rate of 34.6%.

Production for the full-year 2004 of 362.6 bcfe was comprised of 322.0 bcf (89% on a natural gas equivalent basis) and 6.76 mmbo (11% on a natural gas equivalent basis). Chesapeake's average daily production rate for the year was 991 mmcfe, consisting of 880 mmcf of gas and 18,481 barrels of oil and natural gas liquids. The full-year 2004 was Chesapeake's 15th consecutive year of sequential production growth. During these 15 years, Chesapeake's production has increased at an average compound annual growth rate of 74%.

Oil and Natural Gas Proved Reserves Reach Record Level of 4.9 Tcfe; Drilling

and Acquisition Costs are $1.21 per Mcfe as Company Adds 2.1 Tcfe; Reserve
                         Replacement Reaches 578%

Chesapeake began 2004 with estimated proved reserves of 3,169 bcfe and ended the year with 4,902 bcfe, an increase of 1,733 bcfe, or 55%. During 2004, the company replaced its 363 bcfe of production with an estimated 2,096 bcfe of new proved reserves, for a reserve replacement rate of 578% at a drilling and acquisition cost of $1.21 per thousand cubic feet of natural gas equivalent (mcfe). Reserve replacement through the drillbit was 962 bcfe, or 265% of production (including 141 bcfe from performance revisions and 5 bcfe from oil and natural gas price increases), or 46% of the total increase, at a cost of $1.03 per mcfe. Reserve replacement through acquisitions (reduced for 4 bcfe sold during the year) was 1,134 bcfe, or 313% of production, or 54% of the total increase, at a cost of $1.36 per mcfe.

Total costs incurred, including drilling, completion, acquisition, seismic, leasehold, capitalized internal costs, non-cash tax basis step-up from corporate acquisitions ($464 million in 2004, or $0.22 per mcfe, frequently booked as goodwill in the industry), asset retirement obligations and all other miscellaneous costs capitalized to our oil and natural gas properties were $1.80 per mcfe. These costs exclude future development costs of proved undeveloped reserves. A complete reconciliation of finding and acquisition cost information and a roll forward of proved reserves is presented on page 13 of this release.

Of the company's estimated proved reserves at year-end 2004, 66% were proved developed compared to 74% in 2003, 74% in 2002 and 71% in 2001. Seventy-five percent of this year's estimated proved reserves are covered by reports prepared by independent third-party reservoir engineers (as opposed to reviews or audits of internally prepared estimates), compared to 74% in 2003, 73% in 2002 and 71% in 2001.

As of December 31, 2004, the company's estimated future net cash flows discounted at 10% before taxes (PV-10) from its proved reserves were $10.5 billion using field differential adjusted prices of $39.91 per bo (based on a NYMEX year-end price of $43.39 per bo) and $5.65 per mcf (based on a NYMEX year-end price of $6.18 per mcf). In addition to the PV-10 value of proved reserves, the company believes that its drilling rig investments are worth $175 million, its midstream gas gathering and compression assets are worth $100 million, and its 4,000 bcfe of non-proved reserves are worth $1.0-2.0 billion.

Last year's PV-10 of its proved reserves was $7.3 billion using field differential adjusted prices of $30.22 per bo (based on a NYMEX year-end price of $32.47 per bo) and $5.68 per mcf (based on a NYMEX year-end price of $5.97 per mcf). Chesapeake's PV-10 changes by approximately $215 million for every $0.10 per mcf change in gas prices and approximately $40 million for every $1.00 per bo change in oil prices. The company's proved developed producing reserves decline rate is projected to be 26% in the first year (2005), 18% in year two, 14% in year three, 12% in year four and 11% in year five.

Average Prices Realized and Hedging Results and Hedging Positions Detailed

Average prices realized during the 2004 fourth quarter (including realized gains or losses from oil and gas derivatives, but excluding unrealized gains or losses on such derivatives) were $28.70 per bo and $5.50 per mcf, for a realized gas equivalent price of $5.42 per mcfe. Chesapeake's average realized pricing differentials to NYMEX during the fourth quarter were a negative $3.20 per bo and a negative $1.19 per mcf. Realized gains or losses from oil and natural gas hedging activities during the quarter generated a $15.40 loss per bo and a $0.65 loss per mcf, for a 2004 fourth quarter realized hedging loss of $87.3 million, or $0.85 per mcfe.

Average prices realized during the full-year 2004 (including realized gains or losses from oil and gas derivatives, but excluding unrealized gains or losses on such derivatives) were $28.33 per bo and $5.29 per mcf, for a realized gas equivalent price of $5.23 per mcfe. Chesapeake's average realized pricing differentials to NYMEX during 2004 were a negative $2.35 per bo and a negative $0.77 per mcf. Realized gains or losses from oil and natural gas hedging activities during the year generated a $10.24 loss per bo and a $0.27 loss per mcf, for a full-year 2004 realized hedging loss of $154.9 million, or $0.43 per mcfe. This compares to oil and gas hedging gains of $184.0 million realized from 2001-03.

In the past two months, Chesapeake has added to its hedge positions in 2005 and 2006. The following tables compare Chesapeake's projected 2005-06 oil and natural gas production volumes that have been hedged as of February 22, 2005 to what had been previously hedged as of December 27, 2004.

                 Hedged Positions as of February 22, 2005

                                  Oil                   Natural Gas
  Quarter or Year         % Hedged    $ NYMEX       % Hedged    $ NYMEX
  2005 1Q                    53%       $41.87          68%        $6.82
  2005 2Q                    61%       $42.39          54%        $5.98
  2005 3Q                    15%       $38.00          46%        $5.96
  2005 4Q                     9%       $32.15          26%        $5.87
  2005 Total                 34%       $41.02          48%        $6.24
  2006                      ---           ---           9%        $6.15


                 Hedged Positions as of December 27, 2004

                                  Oil                   Natural Gas
  Quarter or Year         % Hedged    $ NYMEX       % Hedged    $ NYMEX
  2005 1Q                    52%       $41.76          67%        $6.80
  2005 2Q                    52%       $41.63          39%        $5.78
  2005 3Q                     8%       $31.16          34%        $5.75
  2005 4Q                     8%       $30.62          23%        $5.74
  2005 Total                 30%       $40.20          40%        $6.17
  2006                      ---           ---           9%        $6.15

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 initial 2005 first quarter forecast and updated 2005 and 2006 forecasts are attached to this release in an Outlook dated February 22, 2005 labeled as Schedule "A". This Outlook has been changed from the Outlook dated December 27, 2004 (attached as Schedule "B" for investors' convenience) to reflect various updated information.

Key Operational and Financial Statistics are Summarized Below for the 2004
                  Fourth Quarter and the Full-Year 2004



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

                                                  Three Months Ended:
                                             12/31/04   9/30/04   12/31/03
  Average daily production (in mmcfe)          1,119     1,024       797
  Gas as % of total production                    90        88        90
  Natural gas production (in bcf)               92.2      83.2      66.3
  Average realized gas price ($/mcf) (A)        5.50      5.17      5.15
  Oil production (in mbbls)                    1,792     1,834     1,165
  Average realized oil price ($/bo) (A)        28.70     29.15     23.76
  Natural gas equivalent production (in bcfe)  102.9      94.2      73.3
  Gas equivalent realized price ($/mcfe) (A)    5.42      5.13      5.03
  Net marketing income ($/mcfe)                  .07       .04       .04
  General and administrative costs ($/mcfe) (B) (.08)     (.09)     (.10)
  Production taxes ($/mcfe)                     (.34)     (.33)     (.28)
  Production expenses ($/mcfe)                  (.55)     (.57)     (.49)
  Interest expense ($/mcfe) (A)                 (.43)     (.45)     (.51)
  DD&A of oil and gas properties ($/mcfe)      (1.67)    (1.63)    (1.41)
  D & A of other assets ($/mcfe)                (.09)     (.08)     (.06)
  Operating cash flow ($ in millions) (C)      423.7     353.4     262.4
  Operating cash flow ($/mcfe)                  4.12      3.75      3.58
  Ebitda ($ in millions) (D)                   550.1     361.3     257.8
  Ebitda ($/mcfe)                               5.34      3.83      3.52
  Net income to common shareholders
   ($ in millions)                             163.2      85.6      62.4

   (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



In addition, the table below summarizes Chesapeake's key statistics during 2004 and compares them to the prior two years' results:

                                                      Year Ended:
                                             12/31/04   12/31/03   12/31/02
  Average daily production (in mmcfe)            991       735       497
  Gas as % of total production                    89        90        89
  Natural gas production (in bcf)              322.0     240.4     160.7
  Average realized gas price ($/mcf) (A)        5.29      4.85      3.54
  Oil production (in mbbls)                    6,764     4,665     3,466
  Average realized oil price ($/bbl) (A)       28.33     25.85     25.22
  Natural gas equivalent production (in bcfe)  362.6     268.4     181.5
  Gas equivalent realized price ($/mcfe) (A)    5.23      4.79      3.61
  Net marketing income ($/mcfe)                  .05       .04       .03
  General and administrative costs ($/mcfe) (B) (.09)     (.08)     (.10)
  Production taxes ($/mcfe)                     (.29)     (.29)     (.17)
  Lease operating expenses ($/mcfe)             (.56)     (.51)     (.54)
  Interest expense ($/mcfe) (A)                 (.45)     (.55)     (.61)
  DD&A of oil and gas properties ($/mcfe)      (1.61)    (1.38)    (1.22)
  D & A of other assets ($/mcfe)                (.08)     (.06)     (.08)
  Operating cash flow ($ in millions) (C)    1,418.8     903.9     412.5
  Operating cash flow ($/mcfe)                  3.91      3.37      2.27
  Ebitda ($ in millions) (D)                 1,583.6   1,041.6     414.4
  Ebitda ($/mcfe)                               4.37      3.88      2.28
  Net income to common shareholders
   ($ in millions)                             439.0     290.5      30.2

   (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 and cumulative effect of
       accounting change, interest expense, and depreciation, depletion and
       amortization expense

Company's Leasehold and 3-D Seismic Inventories Now Exceed 3.3 Million and

9.9 Million Net Acres; Identified Non-Proved Reserves in Company's Extensive

Gas Resource Plays Exceed 4.0 Tcfe

Chesapeake's exploratory and development drilling programs and production enhancement operations on its existing and acquired properties continue to produce operational results that exceed the company's forecasts and distinguish the company among its peers. During 2004, Chesapeake drilled 561 gross (425 net) operated wells and participated in another 890 gross (121 net) wells operated by other companies. The company's drilling success rate was 96% for company-operated wells and 96% for non-operated wells. During the year, Chesapeake invested $756 million in operated wells (using an average of 56 operated rigs during 2004), $236 million in non-operated wells (using an average of approximately 65 non-operated rigs during 2004) and $300 million in acquiring new 3-D seismic data and new leases (exclusive of leases acquired through acquisitions).

The key to Chesapeake's strong organic growth rates during 2004 and in the past four years was our early recognition that oil and gas prices were undergoing structural change. We subsequently reacted by investing more than $1.3 billion in new leasehold and 3-D seismic acquisitions. In addition, during the past four years, we have significantly strengthened our technical capabilities by tripling our land, geoscience and engineering staff to more than 400 employees.

In addition to making significant additions to our existing core leasehold positions in the Anadarko and Arkoma Basins, South Texas, Texas Gulf Coast and Permian Basin projects, Chesapeake has also been aggressively building significant leasehold positions in the following gas resource plays: Sahara in the northwestern Anadarko Basin (approximately 600,000 prospective net acres acquired to date), the Mountain Front Deep Springer play in the western and southern Anadarko Basin (approximately 100,000 prospective net acres acquired to date), the Granite Wash and Cherokee/Atoka Wash plays in the western Anadarko Basin (approximately 200,000 prospective net acres acquired to date), the Hartshorne Coal and the Caney, Woodford and Fayetteville Shale plays of the Arkoma Basin (approximately 250,000 prospective acres acquired to date), the Barnett Shale play in North Texas (approximately 30,000 prospective net acres acquired to date, mainly in northern Johnson County), the Cotton Valley play in Northern Louisiana's Sligo Field (25,000 prospective net acres acquired to date) and, most recently, the Haley Deep play in West Texas (approximately 100,000 prospective net acres acquired to date).

Chesapeake believes it has built the largest onshore U.S. inventories of leasehold and 3-D seismic in the industry (more than 3.3 million and 9.9 million net acres, respectively) and believes it has identified more than a seven-year drilling backlog of 7,000 locations on which the company expects to develop more than 4.0 trillion cubic feet of natural gas equivalent (tcfe) of internally estimated non-proved reserves.

Balance Sheet Continues to Strengthen in 2004

As of December 31, 2004, Chesapeake's long-term debt was $3.1 billion and its stockholders' equity was $3.2 billion, for a debt-to-total capitalization ratio of 49%, compared to a debt-to-total capitalization ratio of 54% at year- end 2003. At year-end 2004, the company's estimated proved reserves were 4.9 tcfe, for long-term debt per mcfe of proved reserves of $0.63, compared to $0.65 per mcfe at year-end 2003. Pro forma for the BRG acquisition that closed on February 1, 2005, Chesapeake's estimated proved reserves were 5.1 tcfe. Given Chesapeake's strong reserve replacement record through the drillbit, low operating costs and high returns on invested capital, the company believes that it will continue to strengthen its balance sheet in the years ahead.

In late January 2005, Chesapeake increased its financial flexibility by amending its secured revolving bank credit facility to expand the borrowing base and amount available to $1.25 billion and to extend the maturity to January 2010.

Management Comments

Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "Today's announcement of very strong operational and financial results for the fourth quarter and full-year 2004 provides 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;
   *  exceptional organic growth for the 2004 fourth quarter and the full-
      year 2004, organic growth that we believe is the best performance
      among all public mid- and large-cap E&P companies;
   *  a 9% increase in sequential quarterly production in the 2004 fourth
      quarter compared to the 2004 third quarter;
   *  a 40% increase in year-over-year fourth quarter production;
   *  a 35% increase in full-year 2004 production over 2003 production;
   *  a 20% increase in estimated 2005 production over 2004 production;
   *  an 11% increase in estimated 2006 production over estimated 2005
      production;
   *  reserve replacement for the year of 578% at a drilling and acquisition
      cost of $1.21 per mcfe;
   *  excellent operating cost control and high returns on equity and total
      capital; and
   *  a seven-year inventory of drilling projects with estimated development
      potential of at least 4.0 tcfe of estimated non-proved 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 an approximate 1,400% increase in our common stock price during the past 12 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."

Conference Call Information

A conference call has been scheduled for Wednesday morning, February 23, 2005 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, February 23, 2005 through midnight EST on March 8, 2005. The number to access the conference call replay is 719.457.0820 and the passcode is 9640052. 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 exchange offer prospectus dated November 30, 2004 (as amended on December 16, 2004) filed with the Securities and Exchange Commission on December 20, 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 fourth 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:          December 31, 2004     December 31, 2003
                                   $        $/mcfe       $        $/mcfe
  REVENUES:
    Oil and gas sales           665,782      6.47     345,697      4.72
    Oil and gas marketing sales 276,269      2,68     111,044      1.51
      Total Revenues            942,051      9.15     456,741      6.23

  OPERATING COSTS:
    Production expenses          56,321      0.55      35,919      0.49
    Production taxes             35,372      0.34      20,557      0.28
    General and administrative
     expenses:
      General and administrative
       (excluding stock-based
       compensation)              8,270      0.08       7,068      0.09
      Stock-based compensation    1,703      0.02         433      0.01
    Oil and gas marketing
     expenses                   269,109      2.61     108,224      1.48
    Oil and gas depreciation,
     depletion, and
     amortization               171,900      1.67     103,334      1.41
    Depreciation and
     amortization of other
     assets                       9,030      0.09       4,146      0.06
    Provision for legal
     settlements                  4,500      0.04       5,400      0.07
      Total Operating Costs     556,205      5.40     285,081      3.89

  INCOME FROM OPERATIONS        385,846      3.75     171,660      2.34

  OTHER INCOME (EXPENSE):
    Interest and other income       913      0.01       1,471      0.02
    Interest expense            (43,288)    (0.42)    (38,465)    (0.52)
    Loss on repurchases or
     exchanges of Chesapeake
     debt                       (17,632)    (0.17)    (20,759)    (0.28)
    Loss on investment in
     Seven Seas                     ---       ---      (2,015)    (0.03)
      Total Other Income
       (Expense)                (60,007)    (0.58)    (59,768)    (0.81)

  Income Before Income Taxes    325,839      3.17     111,892      1.53

  Income Tax Expense:
    Current                         ---       ---       4,670      0.06
    Deferred                    117,301      1.14      37,849      0.52
      Total Income Tax Expense  117,301      1.14      42,519      0.58

  NET INCOME                    208,538      2.03      69,373      0.95

  Preferred stock dividends      (8,707)    (0.08)     (6,985)    (0.10)
  Loss on conversion/exchange
   of preferred stock           (36,678)    (0.36)        ---       ---

  NET INCOME AVAILABLE TO
   COMMON SHAREHOLDERS          163,153      1.59      62,388      0.85

  EARNINGS PER COMMON SHARE:

    Basic                         $0.59                 $0.29
    Assuming dilution             $0.52                 $0.25

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

    Basic                       277,410               216,571
    Assuming dilution           328,029               273,169



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

   TWELVE MONTHS ENDED:        December 31, 2004     December 31, 2003
                                  $        $/mcfe       $        $/mcfe
  REVENUES:
    Oil and gas sales         1,936,176      5.34   1,296,822      4.83
    Oil and gas marketing
     sales                      773,092      2.13     420,610      1.57
      Total Revenues          2,709,268      7.47   1,717,432      6.40

  OPERATING COSTS:
    Production expenses         204,821      0.56     137,583      0.51
    Production taxes            103,931      0.29      77,893      0.29
    General and administrative
     expenses:
      General and administrative
       (excluding stock-based
       compensation)             32,217      0.09      22,808      0.09
      Stock-based compensation    4,828      0.01         945       ---
    Oil and gas marketing
     expenses                   755,314      2.08     410,288      1.53
    Oil and gas depreciation,
     depletion, and
     amortization               582,137      1.61     369,465      1.38
    Depreciation and
     amortization of other
     assets                      29,185      0.08      16,793      0.06
    Provision for legal
     settlements                  4,500      0.01       6,402      0.02
      Total Operating Costs   1,716,933      4.73   1,042,177      3.88

  INCOME FROM OPERATIONS        992,335      2.74     675,255      2.52

  OTHER INCOME (EXPENSE):
    Interest and other income     4,476      0.01       2,827      0.01
    Interest expense           (167,328)    (0.46)   (154,356)    (0.57)
    Loss on repurchases or
     exchanges of Chesapeake
     debt                       (24,557)    (0.07)    (20,759)    (0.08)
    Loss on investment in
     Seven Seas                     ---       ---      (2,015)    (0.01)
      Total Other Income
       (Expense)               (187,409)    (0.52)   (174,303)    (0.65)

  Income Before Income Taxes
   and Cumulative Effect
   of Accounting Change         804,926      2.22     500,952      1.87

  Income Tax Expense:
    Current                         ---       ---       5,000      0.02
    Deferred                    289,771      0.80     185,360      0.69
      Total Income Tax Expense  289,771      0.80     190,360      0.71

  NET INCOME BEFORE CUMULATIVE
   EFFECT OF ACCOUNTING CHANGE,
   NET OF TAX                   515,155      1.42     310,592      1.16

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

  NET INCOME                    515,155      1.42     312,981      1.17

  Preferred stock dividends     (39,506)    (0.11)    (22,469)    (0.09)
  Loss on conversion/exchange
   of preferred stock           (36,678)    (0.10)        ---       ---

  NET INCOME AVAILABLE TO
   COMMON SHAREHOLDERS          438,971      1.21     290,512      1.08

  EARNINGS PER COMMON SHARE:

    Basic
      Income Before Cumulative
       Effect of Accounting
       Change                     $1.73                 $1.36
      Cumulative Effect of
       Accounting Change            ---                  0.02
      Net Income                  $1.73                 $1.38

    Assuming dilution
      Income Before Cumulative
       Effect of Accounting
       Change                     $1.53                 $1.20
      Cumulative Effect of
       Accounting Change            ---                  0.01
      Net Income                  $1.53                 $1.21

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

    Basic                       253,212               211,203
    Assuming dilution           305,718               258,567



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

                                             December 31,   December 31,
                                                 2004           2003

  Cash                                           $6,896        $40,581
  Other current assets                          560,644        301,823
      TOTAL CURRENT ASSETS                      567,540        342,404

  Property and equipment (net)                7,444,384      4,133,117
  Other assets                                  232,585         96,770
      TOTAL ASSETS                           $8,244,509     $4,572,291

  Current liabilities                          $963,953       $513,156
  Long term debt                              3,075,109      2,057,713
  Asset retirement obligation                    73,718         48,812
  Long term liabilities                          34,973         28,774
  Deferred tax liability                        933,873        191,026
      TOTAL LIABILITIES                       5,081,626      2,839,481

  STOCKHOLDERS' EQUITY                        3,162,883      1,732,810

  TOTAL LIABILITIES & STOCKHOLDERS' EQUITY   $8,244,509     $4,572,291

  COMMON SHARES OUTSTANDING                     311,869        216,784



                      CHESAPEAKE ENERGY CORPORATION
                  RECONCILIATION OF 2004 COSTS INCURRED
                  ($ in 000's, except per unit amounts)
                               (unaudited)

                                                      Reserves        $
                                            Cost     (in mmcfe)    Per Unit
  Exploration and development costs (A)   $991,903      962,246      1.03
  Acquisition of proved properties       1,541,920    1,137,463      1.36
    Subtotal                             2,533,823    2,099,709      1.21

  Acquisition of unproved properties       570,495          ---       ---
  Divestitures                             (12,048)      (3,940)    (3.06)
  Leasehold acquisition costs              110,530          ---       ---
  Geological and geophysical costs          55,618          ---       ---
    Adjusted subtotal                    3,258,418    2,095,769      1.55
  Tax basis step-up                        463,949          ---       ---
  Asset retirement obligation and other     41,924          ---       ---
    Total                               $3,764,291    2,095,769      1.80

   (A)  Reserves include revisions to previous estimates



                      CHESAPEAKE ENERGY CORPORATION
                         ROLLFORWARD OF RESERVES
                               (unaudited)

                                                    Mmcfe

  Beginning balance, 12/31/03                    3,168,575
  Production                                      (362,593)
  Acquisitions                                   1,137,463
  Divestitures                                      (3,940)
  Revisions-performance                            140,568
  Revisions-price                                    4,950
  Extensions and discoveries                       816,728
  Ending balance, 12/31/04                       4,901,751

  Reserve replacement                            2,095,769
  Reserve replacement rate                             578%



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

                              Three Months Ended     Twelve Months Ended
                                 December 31,           December 31,
                                2004      2003        2004       2003

  Oil and Gas Sales ($ in thousands):
    Oil sales                  $79,033   $30,819    $260,915    $132,630
    Oil derivatives -
     realized gains (losses)   (27,595)   (3,134)    (69,267)    (12,058)
    Oil derivatives -
     unrealized gains (losses)  25,379    (8,447)      3,454      (9,440)

      Total oil sales          $76,817   $19,238    $195,102    $111,132

    Gas sales                 $566,492  $281,452  $1,789,275  $1,171,050
    Gas derivatives -
     realized gains (losses)   (59,658)   59,697     (85,634)     (5,331)
    Gas derivatives -
     unrealized gains (losses)  82,131   (14,690)     37,433      19,971

      Total gas sales         $588,965  $326,459  $1,741,074  $1,185,690

      Total oil and gas sales $665,782  $345,697  $1,936,176  $1,296,822

  Average Sales Price
   (excluding gains (losses)
   on derivatives):
    Oil ($ per bbl)             $44.10    $26.45      $38.57      $28.43
    Gas ($ per mcf)              $6.15     $4.25       $5.56       $4.87
    Gas equivalent
     ($ per mcfe)                $6.27     $4.26       $5.65       $4.86

  Average Sales Price
   (excluding unrealized
   gains (losses) on
   derivatives):
    Oil ($ per bbl)             $28.70    $23.76      $28.33      $25.85
    Gas ($ per mcf)              $5.50     $5.15       $5.29       $4.85
    Gas equivalent
     ($ per mcfe)                $5.42     $5.03       $5.23       $4.79

  Interest Expense ($ in thousands):
    Interest                  $(44,446) $(38,665)  $(162,781)  $(151,676)
    Derivatives - realized
     (gains) losses                607     1,406         791       3,859
    Derivatives - unrealized
     (gains) losses                551    (1,206)     (5,338)     (6,539)
      Total Interest
       Expense                $(43,288) $(38,465)  $(167,328)  $(154,356)



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

   THREE MONTHS ENDED:                        December 31,    December 31,
                                                   2004            2003

  Cash provided by operating activities           $410,349       $292,085

  Cash (used in) investing activities             (712,963)      (476,449)

  Cash provided by financing activities            260,437        186,467


   TWELVE MONTHS ENDED:                       December 31,   December 31,
                                                    2004           2003

  Cash provided by operating activities         $1,448,555       $945,602

  Cash (used in) investing activities           (3,381,204)    (2,077,217)

  Cash provided by financing activities          1,898,964        924,559



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

   THREE MONTHS ENDED:                         December 31,   December 31,
                                                   2004           2003

  CASH PROVIDED BY OPERATING ACTIVITIES           $410,349       $292,085

  Adjustments:
    Changes in assets and liabilities               13,330        (29,647)

  OPERATING CASH FLOW*                            $423,679       $262,438

   *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:                          December 31,   December 31,
                                                    2004           2003

  Net income                                      $208,538        $69,373

  Income tax expense                               117,301         42,519
  Interest expense                                  43,288         38,465
  Depreciation and amortization of other assets      9,030          4,146
  Oil and gas depreciation, depletion and
   amortization                                    171,900        103,334

  EBITDA**                                        $550,057       $257,837

   **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:                         December 31,   December 31,
                                                   2004           2003

  CASH PROVIDED BY OPERATING ACTIVITIES           $410,349       $292,085

  Changes in assets and liabilities                 13,330        (29,647)
  Interest expense                                  43,288         38,465
  Unrealized gains (losses) on oil and gas
   derivatives                                     107,510        (23,137)
  Other non-cash items                             (24,420)       (19,929)

  EBITDA                                          $550,057       $257,837


   TWELVE MONTHS ENDED:                        December 31,   December 31,
                                                   2004           2003

  CASH PROVIDED BY OPERATING ACTIVITIES         $1,448,555       $945,602

  Adjustments:
    Changes in assets and liabilities              (29,752)       (41,673)

  OPERATING CASH FLOW*                          $1,418,803       $903,929

   *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.



   TWELVE MONTHS ENDED:                        December 31,    December 31,
                                                  2004            2003

  Net income before cumulative effect of
   accounting change                              $515,155       $310,592

  Income tax expense                               289,771        190,360
  Interest expense                                 167,328        154,356
  Depreciation and amortization of other assets     29,185         16,793
  Oil and gas depreciation, depletion and
   amortization                                    582,137        369,465

  EBITDA**                                      $1,583,576     $1,041,566

   **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:

   TWELVE MONTHS ENDED:                        December 31,   December 31,
                                                   2004           2003

  CASH PROVIDED BY OPERATING ACTIVITIES         $1,448,555       $945,602

  Changes in assets and liabilities                (29,752)       (41,673)
  Interest expense                                 167,328        154,356
  Unrealized gains (losses) on oil and gas
   derivatives                                      40,887         10,531
  Other non-cash items                             (43,442)       (27,250)

  EBITDA**                                      $1,583,576     $1,041,566



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

                                  Three Months Ended  Twelve Months Ended
                                   December 31, 2004    December 31, 2004

  Net income available to
   common shareholders                  $163,153             $438,971

  Adjustments:
    Preferred stock dividends              8,707               39,506
    Loss on conversion/exchange
     of preferred stock**                 36,678               36,678
  Net income                            $208,538             $515,155

  Adjustments, net of tax:
    Unrealized (gains) losses
     on derivatives                      (69,159)             (22,751)
    Loss on repurchases or
     exchanges of debt                    11,284               15,716
    Provision for legal
     settlements                           2,880                2,880

  Adjusted earnings*                    $153,543             $511,000

  Adjusted earnings per share
   assuming dilution**                     $0.44                $1.56


  EBITDA                                $550,057           $1,583,576

  Adjustments, before tax:
    Unrealized (gains) losses on
     oil and gas derivatives            (107,510)             (40,887)
    Loss on repurchases or
     exchanges of debt                    17,632               24,557
    Provision for legal
     settlements                           4,500                4,500

  Adjusted EBITDA*                      $464,679           $1,571,746

   *Adjusted earnings and adjusted earnings per share assuming dilution and
    adjusted EBITDA, 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.

   **For purposes of calculating fully diluted shares and earnings per share
     assuming dilution for the fourth quarter and full-year 2004, accounting
     rules prohibit the company from assuming the conversion of the 6.0%
     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 the
     converted shares as though they were converted at the beginning of the
     period (fully diluted share count of 347.8 million for the fourth
     quarter and 327.1 million for the full-year).



                               SCHEDULE "A"

               CHESAPEAKE'S OUTLOOK AS OF FEBRUARY 22, 2005

Quarter Ending March 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 February 22, 2005, we are using the following key assumptions in our projections for the first quarter of 2005, the full-year 2005 and the full- year 2006.

The primary changes from our December 27, 2004 Outlook are in the table and are explained as follows:

   1)  We have provided our first production forecast for the first quarter
       of 2005.
   2)  We have increased capital expenditures by $100 million in 2005 and
       $50 million in 2006 to reflect a planned increase in drilling
       activity on various company properties.
   3)  We have updated the projected effects from changes in our hedging
       positions since our December 27, 2004 Outlook.
   4)  We have included our expectations for future NYMEX oil and gas prices
       to illustrate hedging effects only.



                               Quarter Ending   Year Ending    Year Ending
                                 March 31,     December 31,   December 31,
                                    2005           2005           2006
  Estimated Production:
    Oil - Mbo                      1,650          6,600          6,600
    Gas - Bcf                     91 - 92       391 - 399      438 - 448
    Gas Equivalent - Bcfe        101 - 102      430 - 438      478 - 488
    Daily gas equivalent
     midpoint -in Mmcfe            1,128          1,190          1,325
  NYMEX Prices (for calculation
   of realized hedging effects only):
    Oil - $/Bo                     $42.28         $40.57         $40.00
    Gas - $/Mcf                     $6.17          $6.04          $6.00

  Estimated Differentials to
   NYMEX Prices:
    Oil - $/Bo                     -$2.75         -$2.75         -$2.75
    Gas - $/Mcf                    -$0.75         -$0.70         -$0.70

  Estimated Realized Hedging
   Effects (based on expected
   NYMEX prices above):
    Oil - $/Bo                     -$0.23          $0.04          $0.00
    Gas - $/Mcf                     $0.56          $0.07          $0.00

  Operating Costs per Mcfe of
   Projected Production:
    Production expense          $0.62 - 0.67   $0.62 - 0.67   $0.68 - 0.72
    Production taxes (generally
     7% of O&G revenues)        $0.38 - 0.40   $0.38 - 0.40   $0.38 - 0.40
    General and administrative  $0.10 - 0.11   $0.10 - 0.11   $0.11 - 0.12
    Stock-based compensation
     (non-cash)                 $0.02 - 0.04   $0.04 - 0.06   $0.09 - 0.10
    DD&A - oil and gas          $1.70 - 1.75   $1.75 - 1.80   $1.80 - 1.90
    Depreciation of other
     assets                     $0.09 - 0.11   $0.09 - 0.11   $0.10 - 0.12
    Interest expense(A)         $0.43 - 0.47   $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

  Book Tax Rate                    36.5%          36.5%          36.5%

  Equivalent Shares Outstanding:
    Basic                          314 mm         315 mm         318 mm
    Diluted                        352 mm         352 mm         355 mm

  Capital Expenditures:
    Drilling, leasehold and
     seismic                     $350-$375    $1,400-$1,500   $1,500-$1,600
                                     mm             mm              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.                     Open
                         NYMEX            NYMEX                     Swap
                         Strike   Gain    Price                   Positions
                          Price  (Loss)  Including    Assuming    as a % of
                  Open     Of     from    Open &        Gas       Estimated
                  Swaps   Open   Locked   Locked     Production   Total Gas
                in Bcf's  Swaps  Swaps   Positions  in Bcf's of:  Production

  2005:
  1st Qtr         62.2   $7.00   -$0.18    $6.82        91.5         68%
  2nd Qtr         52.2   $6.17   -$0.19    $5.98        97.0         54%
  3rd Qtr         46.4   $6.19   -$0.23    $5.96       101.5         46%
  4th Qtr         27.5   $6.26   -$0.39    $5.87       105.0         26%
  Total 2005(A)  188.3   $6.46   -$0.22    $6.24       395.0         48%

  Total 2006(A)   39.3   $6.77   -$0.62    $6.15       443.0          9%

  Total 2007(B)    ---     ---      ---      ---       470.0         ---

  TOTALS
  2005-2007      227.6   $6.51   -$0.29    $6.22     1,308.0         17%

   (A)  Certain hedging arrangements include swaps with knockout prices
        ranging from $3.75 to $5.50 covering 70.0 bcf in 2005 and $3.75 to
        $5.50 covering 28.4 bcf in 2006.
   (B)  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.

   Note: Not shown above are collars covering 4.4 bcf of production in 2005
   at a weighted average floor and ceiling of $3.10 and $4.44. and call
   options covering 7.3 bcf of production in 2005 at a weighted average
   price of $6.00.



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

  2005             188.6           0.26            392.0         48%
  2006             130.1           0.32            440.0         30%
  2007             126.5           0.28            470.0         27%
  2008             118.6           0.27            495.0         24%
  2009              86.6           0.29            520.0         17%
  Totals           650.4          $0.28          2,317.0         28%
   * weighted average



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

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

  Q1 - 2005         870.5      $41.87         1,650            53%
  Q2 - 2005       1,001.0      $42.39         1,650            61%
  Q3 - 2005         246.0      $38.00         1,650            15%
  Q4 - 2005         153.5      $32.15         1,650             9%
  Total 2005(A)   2,271.0      $41.02         6,600            34%

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



                               SCHEDULE "B"

          CHESAPEAKE'S PREVIOUS OUTLOOK AS OF DECEMBER 27, 2004
                      (PROVIDED FOR REFERENCE ONLY)

            NOW SUPERSEDED BY OUTLOOK AS OF FEBRUARY 22, 2005

   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 December 27, 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.

We expect to record non-operating losses in Q4 2004 in connection with our pending cash tender offer for our $209.8 million of 8.375% senior notes due 2008 and our pending offer to exchange our 6.0% convertible preferred stock for our common stock. If we purchase all of our 8.375% senior notes pursuant to the tender offer, we estimate that an after-tax loss on the early redemption of the notes of $12 million will be recorded in Q4 2004 as an adjustment to net earnings. If all our 6.0% preferred stock is exchanged for common stock, we estimate that a loss on the early conversion of the preferred stock of approximately $37 million will be reflected as an adjustment to net income available to common shareholders for the purpose of calculating basic earnings per share in Q4 2004.

The primary changes from our November 30, 2004 Outlook are in the table and are explained as follows:

   1) We have updated our previous production forecasts for 2005 and 2006
      to reflect increases in production of 35 mmcfe per day in 2005
      (excluding January) and 55 mmcfe per day in 2006 as a result of the
      announced acquisition of BRG Petroleum Corporation.  This increases
      our full-year 2005 production forecast by 2.8% to a mid-point of
      1,190 mmcfe per day and our 2006 production forecast by 4.3% to a
      mid-point of 1,325 mmcfe per day.
   2) We have increased capital expenditures by $50 million in 2005 and
      $100 million in 2006 to reflect planned increased drilling activity
      planned on the BRG and other company properties.
   3) We have updated the projected effects from changes in our hedging
      positions since our November 30, 2004 Outlook.
   4) We have included our expectations for future NYMEX oil and gas
      prices to illustrate hedging effects only.



                      Quarter Ending  Year Ending  Year Ending  Year Ending
                        December 31,  December 31, December 31, December 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    391 - 399    438 - 448
     Gas Equivalent
      - Bcfe              98 - 99      356 - 358    430 - 438    478 - 488
     Daily gas
      equivalent midpoint
       -in Mmcfe           1,069           975        1,190        1,325

   NYMEX Prices (for
    calculation of
    realized hedging
    effects only):
     Oil - $/Bo           $46.67        $41.00       $40.00       $40.00
     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        $0.05       -$0.01

   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   $1.75-1.80   $1.80-1.90
     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       313 mm       316 mm
     Diluted             347 mm        327 mm       351 mm       354 mm
   Capital Expenditures:
     Drilling,
      leasehold and
      seismic         $300-$325  $1,100-$1,150  $1,300-$1,400  $1,450-$1,550
                          mm           mm             mm             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                   Open Swap
                       NYMEX   Gain     Price                   Positions
                      Strike  (Loss)  Including   Assuming      as a % of
             Open      Price   from     Open &       Gas        Estimated
             Swaps    Of Open  Locked   Locked    Production    Total Gas
            in Bcf's   Swaps   Swaps   Positions  in Bcf's 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(A)   70.7    $5.49  -$0.09    $5.40       83.2           85%
   4th Qtr(A)   76.5    $5.88  -$0.11    $5.77       89.0           86%

   Total 2004  278.9    $5.63  -$0.05    $5.58      318.8           88%

   2005:
   1st Qtr      62.4    $6.91  -$0.11    $6.80       93.4           67%
   2nd Qtr      38.5    $6.05  -$0.27    $5.78       97.5           39%
   3rd Qtr      34.5    $6.06  -$0.31    $5.75      100.8           34%
   4th Qtr      23.5    $6.20  -$0.46    $5.74      103.0           23%

   Total
    2005(A)    158.9    $6.41  -$0.24    $6.17      394.7           40%

   Total
    2006(A)     39.3    $6.77  -$0.62    $6.15      443.0            9%

   Total
    2007(B)      ---      ---     ---      ---      470.0          ---

   TOTALS
   2005-2007   198.2    $6.48  -$0.31    $6.17    1,307.7           15%

   (A) Certain hedging arrangements include swaps with knockout prices
       ranging from $3.50 to $5.25 covering 25.4 bcf in 2004, $3.75 to $5.50
       covering 60.2 bcf in 2005 and $3.75 to $5.50 covering 28.4 bcf in
       2006.
   (B) 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.

   Note: 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 in Bcf's
              Volume in Bcf's    NYMEX less:          of:           % Hedged
   2004            157.4             0.17            318.8              49%
   2005            188.6             0.26            394.7              48%
   2006            130.1             0.32            443.0              29%
   2007            126.5             0.28            470.0              27%
   2008            118.6             0.27            495.0              24%
   2009             86.6             0.29            520.0              17%
   Totals          807.8            $0.26          2,641.5              31%
   * weighted average



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

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

   Q1 - 2004            1,270    $28.58       1,465              87%
   Q2 - 2004            1,540    $30.00       1,673              92%
   Q3 - 2004(A)         1,519    $30.32       1,834              83%
   Q4 - 2004(A)         1,518    $30.10       1,588              96%
   Total 2004(A)        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(A)        1,996    $40.20       6,600              30%

   (A) 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.

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