Chesapeake Energy Corporation Reports Record Results for the 2006 First Quarter
Net Income Available to Common Shareholders Reaches $604 Million on Revenue of $1.94 Billion and Production of 137 Bcfe
Company Expects Total Production Growth of 24% in 2006 and 7-10% in 2007; Proved Reserves Reach Record Level of 7.8 Tcfe
Company Increases Hedges at Very Attractive Prices; Has Now Hedged 80%, 56% and 41% of Expected Full-Year 2006, 2007 and 2008 Oil and Natural Gas Production at Average NYMEX Prices of $9.45, $9.98 and $9.36 Per Mcfe
PRNewswire-FirstCall
OKLAHOMA CITY

Chesapeake Energy Corporation today reported financial and operating results for the first quarter of 2006. For the quarter, Chesapeake generated net income available to common shareholders of $604 million ($1.44 per fully diluted common share), operating cash flow of $1.047 billion (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $1.407 billion (defined as income before income taxes, interest expense, and depreciation, depletion and amortization expense) on revenue of $1.945 billion and production of 137 billion cubic feet of natural gas equivalent (bcfe).

The company's 2006 first quarter 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 2006 first quarter reported results are described as follows:

   *  an unrealized mark-to-market gain of $122 million resulting from the
      company's oil and natural gas and interest rate hedging programs;

   *  a realized gain of $73 million resulting from the sale of the
      company's investment in the common stock of Pioneer Drilling
      Corporation ;

   *  a charge of $34 million relating to the acceleration of vesting of
      stock options and restricted stock in connection with the retirement
      in February 2006 of Chesapeake's President and Chief Operating
      Officer, Tom L. Ward; and

   *  a reduction of net income available to common shareholders of $1
      million resulting from issuances of common stock upon various
      exchanges and conversions of preferred stock.

Excluding the above-mentioned items and giving effect to common shares issued for preferred shares during the period, Chesapeake's net income to common shareholders in the first quarter of 2006 would have been $444 million ($1.07 per fully diluted common share) and ebitda would have been $1.147 billion. The foregoing items do not affect the calculation of operating cash flow. A reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 15-16 of this release.

 Oil and Natural Gas Production Sets Record for 19th Consecutive Quarter;
  2006 First Quarter Average Daily Production Increases 31% and 7% Over
Production in the 2005 First Quarter and 2005 Fourth Quarter, Respectively

Daily production for the 2006 first quarter averaged 1.519 bcfe, an increase of 357 million cubic feet of natural gas equivalent (mmcfe), or 31%, over the 1.162 bcfe of daily production in the 2005 first quarter and an increase of 101 mmcfe, or 7%, over the 1.418 bcfe produced per day in the 2005 fourth quarter. Of the 357 mmcfe increase in daily production from the year ago quarter, 42% was generated from organic drillbit growth and 58% was generated from acquisitions, with the company's trailing 12-month organic production growth rate calculated as 13%. Of the 101 mmcfe daily increase in sequential quarterly production, 22% was generated from organic drillbit growth and 78% was generated from acquisitions, with the company's sequential quarterly organic production growth rate calculated as 1.7%. Chesapeake is anticipating total production growth of 24% in 2006 and organic growth rates of at least 10% in 2006 and 7-10% in 2007.

Chesapeake's 2006 first quarter production of 136.8 bcfe was comprised of 124.1 billion cubic feet of natural gas (bcf) (91% on a natural gas equivalent basis) and 2.12 million barrels of oil and natural gas liquids (mmbbls) (9% on a natural gas equivalent basis). Chesapeake's average daily production for the quarter of 1.519 bcfe consisted of 1.378 bcf of natural gas and 23,511 barrels (bbls) of oil. The 2006 first quarter was Chesapeake's 19th consecutive quarter of sequential U.S. production growth. Over these 19 quarters, Chesapeake's U.S. production increased 280%, for an average compound quarterly growth rate of 7.3% and an average compound annual growth rate of 32.2%.

Average Prices Realized, Hedging Results and Hedging Positions Detailed

Average prices realized during the 2006 first quarter (including realized gains or losses from oil and natural gas derivatives, but excluding unrealized gains or losses on such derivatives) were $57.12 per bbl and $9.61 per thousand cubic feet (mcf), for a realized natural gas equivalent price of $9.60 per thousand cubic feet of natural gas equivalent (mcfe). Chesapeake's average realized pricing differentials to NYMEX during the first quarter were a negative $5.04 per bbl and a negative $1.61 per mcf. Realized gains and losses from oil and natural gas hedging activities during the quarter generated a $1.80 loss per bbl and a $2.03 gain per mcf, for a 2006 first quarter realized hedging gain of $248 million, or $1.82 per mcfe.

During the past few weeks, Chesapeake has significantly added to its 2006, 2007 and 2008 oil and natural gas hedging positions previously announced on February 23, 2006. The following tables compare Chesapeake's hedged production volumes (including only swaps and excluding CNR's swaps) as of May 1, 2006 to those as of February 23, 2006.

                     Swap Positions as of May 1, 2006

                           Natural Gas                   Oil
  Quarter or Year    % Hedged      $ NYMEX      % Hedged      $ NYMEX
  2006 1Q               76%         $10.72         52%         $60.03
  2006 2Q               78%          $8.77         69%         $61.85
  2006 3Q               86%          $8.75         84%         $63.90
  2006 4Q               81%          $9.42         85%         $63.76
  2006 Total            80%          $9.37         72%         $62.63
  2007 Total            57%          $9.90         44%         $67.07
  2008 Total            41%          $9.22         37%         $68.20



                    Swap Positions as of February 23, 2006

                          Natural Gas                    Oil
  Quarter or Year    % Hedged      $ NYMEX      % Hedged      $ NYMEX
  2006 1Q               74%         $10.72         58%         $60.03
  2006 2Q               73%          $8.82         67%         $61.13
  2006 3Q               74%          $8.87         64%         $61.50
  2006 4Q               64%          $9.36         62%         $61.33
  2006 Total            71%          $9.43         63%         $61.02
  2007 Total            36%          $9.85         22%         $62.42
  2008 Total            22%          $9.10         14%         $65.48


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 2006 and 2007 forecasts are attached to this release in an Outlook dated May 1, 2006 labeled as Schedule "A", which begins on page 17. This Outlook has been changed from the Outlook dated February 23, 2006 (attached as Schedule "B", which begins on page 21) to reflect various updated information.

        Key Operational and Financial Statistics Summarized Below
                        for the 2006 First Quarter

The table below summarizes Chesapeake's key results during the 2006 first quarter and compares them to the 2005 fourth quarter and first quarter:

                                                 Three Months Ended:
                                            3/31/06    12/31/05    3/31/05
  Average daily production (in mmcfe)        1,519      1,418       1,162
  Natural gas as % of total production          91         91          90
  Natural gas production (in bcf)            124.1      118.3        94.1
  Average realized natural gas price
   ($/mcf) (A)                                9.61       8.08        6.20
  Oil production (in mbbls)                  2,116      2,014       1,746
  Average realized oil price ($/bbl) (A)     57.12      52.65       41.74
  Natural gas equivalent production
   (in bcfe)                                 136.8      130.4       104.6
  Natural gas equivalent realized
   price ($/mcfe) (A)                         9.60       8.14        6.27
  Marketing income ($/mcfe)                    .10        .10         .07
  Service operations income ($/mcfe)           .11        ---         ---
  Production expenses ($/mcfe)                (.87)      (.72)       (.66)
  Production taxes ($/mcfe)                   (.40)      (.55)       (.34)
  General and administrative costs
   ($/mcfe) (B)                               (.17)      (.15)       (.09)
  Stock-based compensation ($/mcfe)           (.05)      (.04)       (.02)
  DD&A of oil and natural gas properties
   ($/mcfe)                                  (2.23)     (2.09)      (1.73)
  D&A of other assets ($/mcfe)                (.17)      (.12)       (.10)
  Interest expense ($/mcfe) (A)               (.52)      (.49)       (.44)
  Operating cash flow ($ in millions) (C)  1,046.9      832.8       504.6
  Operating cash flow ($/mcfe)                7.66       6.39        4.82
  Adjusted ebitda ($ in millions) (D)      1,147.2      887.7       549.1
  Adjusted ebitda ($/mcfe)                    8.39       6.81        5.25
  Net income to common shareholders
   ($ in millions)                           603.9      431.8       119.5

   (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, as adjusted to
        remove the effects of certain items detailed on page 16.


   Oil and Natural Gas Proved Reserves Reach Record Level of 7.8 Tcfe;
     Drilling and Acquisition Costs Average $2.13 per Mcfe as Company
           Adds 290 Bcfe for a Reserve Replacement Rate of 312%

Chesapeake began 2006 with estimated proved reserves of 7.521 trillion cubic feet of natural gas equivalent (tcfe) and ended the quarter with 7.811 tcfe, an increase of 290 bcfe, or 4%. During the 2006 first quarter, Chesapeake replaced its 137 bcfe of production with an estimated 427 bcfe of new proved reserves, for a reserve replacement rate of 312%. Reserve replacement through the drillbit was 184 bcfe, or 135% of production (including 76 bcfe of positive performance revisions and 88 bcfe of downward revisions resulting from oil and natural gas price declines between December 31, 2005 and March 31, 2006) and 43% of the total increase. Excluding the impact of downward revisions from lower oil and natural gas prices, Chesapeake's exploration and development costs through the drillbit were $2.26 per mcfe during the 2006 first quarter. Reserve replacement through acquisitions of proved reserves was 243 bcfe, or 177% of production and 57% of the total increase, at a cost of $1.86 per mcfe.

Total costs incurred during the 2006 first quarter, including drilling, completion, acquisition, seismic, leasehold, capitalized internal costs, non- cash tax basis step-up from corporate acquisitions, asset retirement obligations and all other miscellaneous costs capitalized to oil and natural gas properties, were $1.901 billion. Excluding costs of $718 million for leasehold and unproved properties acquired during the quarter and $87 million of tax basis step-up, asset retirement obligations and other costs, as well as downward revisions of proved reserves from lower oil and natural gas prices, the company's total finding and acquisition costs were $2.13 per mcfe. A complete reconciliation of finding and acquisition costs and a roll-forward of proved reserves is presented on page 13 of this release.

As of March 31, 2006, Chesapeake's estimated future net cash flows discounted at 10% before income taxes (PV-10) were $17.6 billion using field differential adjusted prices of $62.06 per bbl (based on a NYMEX quarter-end price of $66.33 per bbl) and $6.69 per mcf (based on a NYMEX quarter-end price of $7.18 per mcf). In addition to the PV-10 value of its proved reserves, the book value of the company's other assets (including drilling rigs, land and buildings, investments in securities and other non-current assets) was $1.6 billion as of March 31, 2006.

By comparison, as of March 31, 2005, Chesapeake's PV-10 was $14.2 billion using field differential adjusted prices of $51.38 per bbl (based on a NYMEX quarter-end price of $55.32 per bbl) and $6.65 per mcf (based on a NYMEX quarter-end price of $7.17 per mcf). In addition to the PV-10 value of its proved reserves, the book value of the company's other assets (including drilling rigs, land and buildings, investments in securities and other non- current assets) was $0.6 billion as of March 31, 2005.

Chesapeake's PV-10 changes by approximately $300 million for every $0.10 per mcf change in natural gas prices and approximately $50 million for every $1.00 per bbl change in oil prices. The company calculates the standardized measure of future net cash flows in accordance with SFAS 69 only at year-end because applicable income tax information on properties, including recently acquired oil and natural gas interests, is not readily available at other times during the year. As a result, the company is not able to reconcile the March 31, 2006 and March 31, 2005 PV-10 values to the standardized measure at such dates. The only difference between the two measures is that PV-10 is calculated before considering the impact of future income tax expenses, while the standardized measure includes such effects.

Company's Leasehold and 3-D Seismic Inventories Now Exceed 8.9 Million Net
Acres and 12.3 Million Acres, Respectively; Estimated Unproved Reserves in
                     Company's Inventory Now 9.2 Tcfe

Chesapeake's exploratory and development drilling programs and production enhancement operations on its existing and acquired properties continue to produce operational results that distinguish the company among its peers. During the 2006 first quarter, Chesapeake drilled 262 gross (210 net) operated wells and participated in another 371 gross (45 net) wells operated by other companies. The company's drilling success rate was 97% for company-operated wells and 98% for non-operated wells. During the quarter, Chesapeake invested $505 million in operated wells (using an average of 77 operated rigs), $110 million in non-operated wells (using an average of 75 non-operated rigs) and $200 million in acquiring new 3-D seismic data and leases (exclusive of leases acquired through acquisitions).

Chesapeake attributes its strong organic growth rates during the 2006 first quarter and in this decade to management's early recognition that oil and natural gas prices were undergoing structural change and its subsequent decision to invest aggressively in the building blocks of value creation in the E&P industry -- people, land and seismic. Since 2000, Chesapeake has invested $3.8 billion in new leasehold and 3-D seismic acquisitions and now owns what it believes to be the largest inventories of onshore leasehold (8.9 million net acres) and 3-D seismic (12.3 million acres) in the U.S. On this leasehold, the company has more than a 10-year drilling inventory of an estimated 29,000 drilling locations on which it believes it can develop approximately 2.8 tcfe of proved undeveloped reserves and approximately 9.2 tcfe of unproved reserves.

In addition, Chesapeake has significantly strengthened its technical capabilities during the past five years by increasing its land, geoscience and engineering staff by 425% to over 650 employees. Today, the company has more than 3,600 employees, of which approximately 70% work in the company's E&P operations and 30% work in the company's oilfield service operations.

Chesapeake characterizes its drilling activity by one of four play types: conventional gas resource, unconventional gas resource, emerging gas resource and Appalachian Basin gas resource. In these plays, Chesapeake uses a probability-weighted statistical approach to estimate the potential number of drillsites and potential unproved reserves associated with such drillsites. The company's leasehold, proved undeveloped and estimated potential unproved reserve totals by play type are set forth below:

   *  2.9 million net acres in its traditional conventional areas (i.e.,
      much of the Mid-Continent, Permian, Gulf Coast, South Texas and other
      areas) on which it has approximately 2,700 drillsites, 1.0 tcfe of
      proved undeveloped reserves and approximately 1.0 tcfe of unproved
      reserves;

   *  1.1 million net acres in its unconventional gas resource areas (i.e.,
      Sahara, Granite/Cherokee/Atoka Washes, Hartshorne CBM, Barnett Shale
      and Ark-La-Tex tight sands) on which it has approximately 14,000
      drillsites, 1.3 tcfe of proved undeveloped reserves and approximately
      4.5 tcfe of unproved reserves;

   *  1.5 million net acres in its emerging gas resource areas (i.e.,
      Fayetteville Shale, Caney/Woodford Shales, Deep Haley, Deep Bossier
      and others) on which it has approximately 2,400 drillsites, 0.1 tcfe
      of proved undeveloped reserves and approximately 2.0 tcfe of unproved
      reserves; and

   *  3.4 million net acres in the Appalachian Basin, where play types range
      from conventional to unconventional to emerging gas resource.  On its
      significant Appalachian Basin acreage base acquired from CNR in
      November 2005, Chesapeake has approximately 10,000 drillsites, 0.4
      tcfe of proved undeveloped reserves and more than 1.7 tcfe of unproved
      reserves.

Chesapeake continues to actively acquire more acreage throughout its operating areas, having acquired approximately 500,000 net acres in the 2006 first quarter through an aggressive land acquisition program that is currently utilizing almost 1,000 contract landmen in the field.

Chesapeake's most significant land acquisition activities during the quarter took place in the Arkansas Fayetteville Shale, Deep Bossier and other East Texas plays in which the company now owns more than 1,000,000, 150,000 and 125,000 net acres, respectively. To date, Chesapeake has drilled five vertical and two horizontal wells in the Fayetteville Shale and now has three operated rigs in the play drilling horizontal wells. If results are encouraging, the company may increase its drilling activity in the Fayetteville Shale later this year. In addition, Chesapeake will drill its first Deep Bossier well in East Texas and its first horizontal Woodford well in Southeastern Oklahoma this summer.

The company continues to achieve outstanding drilling results in the Barnett Shale play of Johnson and Tarrant Counties, Texas. To date, Chesapeake has drilled and completed 83 Barnett Shale horizontal wells and has current daily net production of 110 mmcfe (145 mmcfe gross). According to our recent review of the State of Texas' production records as accessed through the database of the Energy Division of IHS Inc., Chesapeake's Barnett Shale wells have been the most productive in the industry as calculated by peak month average daily production per horizontal well as set forth in the table below.

                                     Peak Month Average  Peak Month Average
                 Reported Number of    Production Per   Daily Production Per
                   Barnett Shale      Horizontal Well     Horizontal Well
  Company         Horizontal Wells        (mcfe)               (mcfe)
  Chesapeake            40                76,783               2,524
  XTO                  108                60,718               1,996
  Chief (private)       65                58,280               1,916
  EOG                   60                52,544               1,727
  Devon                212                51,090               1,680
  EnCana                84                41,658               1,370
  Quicksilver           27                29,847                 981
  ConocoPhillips
   (Burlington)         46                27,230                 895

Source: The Energy Division of IHS, Inc. based on production reported through January 2006 and including only operators of more than 25 horizontal wells.

The company believes this achievement reflects its substantial experience in drilling and completing horizontal wells in the U.S. Chesapeake has drilled more horizontal wells than any other company in the industry and believes it is the only company currently active in all of the following shale plays: the Barnett and Woodford Shale in West Texas; the Barnett Shale near Fort Worth, Texas; the Caney and Woodford Shales in southeastern Oklahoma; the Fayetteville Shale in Arkansas; the New Albany Shale in Illinois and Kentucky; and various Devonian Shale plays in Appalachia. Because of this unique position in the industry, the company believes that it has the distinct opportunity and competitive advantage to transfer knowledge and technology across all of the major shale plays east of the Rockies. Also, when combined with Chesapeake's expertise and activity level in various tight gas sand plays in the southwestern U.S. and Appalachia, Chesapeake believes it has established the leading natural gas resource base in the U.S.

Chesapeake Records Gain from Sale of Pioneer Drilling Corporation Common Stock

and Incurs Charge Related to Early Retirement of Tom L. Ward

In February, Chesapeake elected to sell its 17% ownership interest in the common stock of Pioneer Drilling Corporation as public company valuations for onshore U.S. land drilling rigs reached levels that substantially exceeded the private market valuation of comparable rigs. On February 10, 2006, Chesapeake sold its 7.7 million shares of Pioneer and received proceeds of $159 million. The sale resulted in a pre-tax gain to Chesapeake of $117 million, or a pre- tax profit margin of 275%, on an investment which had an average holding period of approximately 2.3 years. With proceeds from the Pioneer sale, the company acquired 13 U.S. onshore drilling rigs from privately-owned Martex Drilling Company for $150 million in February 2006.

The Martex acquisition bolstered the company's 100% owned drilling rig subsidiary, Nomac Drilling Corporation, in which to date Chesapeake has invested a total of $283 million to build or acquire 34 operating rigs, has invested another $47 million in 23 rigs that Nomac is currently building and has budgeted an additional $157 million for completion of these rigs. In total, Chesapeake's rig fleet should reach 57 rigs within the next 12 months, which should represent one of the ten largest drilling rig fleets in the U.S.

Chesapeake has also invested $52 million in two private drilling rig contractors, DHS Drilling Company and Mountain Drilling Company, in which Chesapeake owns 45% and 49%, respectively. DHS owns 12 rigs and has three more rigs under construction. Mountain owns one rig and has ordered another nine rigs for delivery later in 2006 and 2007. Chesapeake's rig investments have served as an effective hedge to rising service costs and have also provided competitive advantages in making acquisitions and in developing its own leasehold on a more timely and efficient basis.

Also in the quarter, Chesapeake's co-founder, President and Chief Operating officer, Tom L. Ward, announced his retirement from the company and his resignation from the Board of Directors. As part of a negotiated separation agreement, Mr. Ward agreed to remain as a consultant to the company for no cash compensation through the term of his non-compete agreement, which expires on August 10, 2006. In recognition of Mr. Ward's role as a co-founder of the company and a key member of the senior management team that has guided Chesapeake to the second best stock price performance in the E&P industry since the company's IPO in February 1993 (and the #1 stock price performance since January 1, 1999 among all U.S. public companies with starting market capitalizations of greater than $50 million), the company's Board agreed to accelerate the vesting of Mr. Ward's unvested stock options and restricted stock. In connection with the early vesting, Chesapeake recognized an after- tax charge of $34 million during the 2006 first quarter. Subsequently, Mr. Ward exercised all of his stock options on March 14, 2006 and paid the company an aggregate exercise price of $37 million.

Management Comments

Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We are pleased to again report outstanding financial and operational results for the 2006 first quarter. The company delivered top-tier production growth from both the drillbit and acquisitions as well as record margins as higher oil and natural gas price realizations far outpaced modest cost inflation. We have also opportunistically hedged service costs and a substantial portion of our anticipated production over the next three years at exceptional prices in order to ensure strong profitability when others in the industry are likely to face margin compression.

"In light of continued strong returns available through the drillbit on our extensive prospect inventory, we continue to increase our industry leading U.S. drilling activity. We currently have 87 operated rigs working to generate new supplies of clean-burning, domestically-produced natural gas, up from an average of 73 operated rigs last year, and we anticipate increasing our drilling activity to over 100 operated rigs by year-end. This increase in drilling activity creates the potential for increased production levels in 2006 and 2007 and will allow an accelerated drilling program in several key areas including: the Barnett Shale, where we plan to operate an average of at least 12 rigs this year versus an average of four rigs last year; Sahara, where we plan to operate an average of 12 rigs this year versus an average of nine rigs last year; and, following the successful integration of CNR, we now plan to accelerate drilling in Appalachia to 10-12 rigs, up from four rigs at the time of acquisition last November.

"We are also pleased to be recognized by Fortune this year as one the country's 500 largest corporations. In that survey, we were ranked #451 by revenues, #226 by market value, #206 by assets, #178 by total profits, #28 by profits as a percentage of revenues, and, most importantly, #11 by total return to shareholders (an exceptional 94% in 2005). In addition, during the quarter we were also added to the S&P 500 Index.

"The inclusion of Chesapeake in the Fortune 500 and S&P 500 Index is a reminder of how well the company's business strategy has worked for investors, royalty owners, consumers and other company stakeholders over the years. Since our IPO on February 4, 1993, we have delivered an approximate 2,300% increase in our common stock price. Our business strategy features delivering growth through a balance of acquisitions and organic drilling, focusing on clean-burning, domestically-produced natural gas to take advantage of strong long-term natural gas supply and demand fundamentals, building dominant regional scale to achieve low operating costs and high returns on capital and successfully mitigating financial and operational risks. We believe Chesapeake's management team can continue the successful execution of the company's distinctive business strategy and continue to deliver significant value to the company's investors for years to come."

Conference Call Information

A conference call has been scheduled for Tuesday morning, May 2, 2006 at 9:00 a.m. EDT to discuss this release. The telephone number to access the conference call is 913.981.4911 and the confirmation code is 1324430. We encourage those who would like to participate in the call to dial the access number between 8:50 and 8:55 am EDT. For those unable to participate in the conference call, a replay will be available from 12:00 p.m. EDT, May 2, 2006 through midnight EDT on May 15, 2006. The number to access the conference call replay is 719.457.0820 and the passcode for the replay is 1324430. The conference call will also be webcast 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 our website indefinitely.

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 natural gas reserves, expected oil and natural gas production and future expenses, projections of future oil and natural 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 the fair value of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility.

Factors that could cause actual results to differ materially from expected results are described under "Risk Factors" in Item 1A of our 2005 Form 10-K filed with the Securities and Exchange Commission on March 14, 2006. They include the volatility of oil and natural gas prices; the limitations our level of indebtedness may have on our financial flexibility; our ability to compete effectively against strong independent oil and natural gas companies and majors; the availability of capital on an economic basis to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil and natural gas reserves and projecting future rates of production and the timing of development expenditures; uncertainties in evaluating oil and natural gas reserves of acquired properties and associated potential liabilities; our ability to effectively consolidate and integrate acquired properties and operations; unsuccessful exploration and development drilling; declines in the values of our oil and natural gas properties resulting in ceiling test write- downs; lower prices realized on oil and natural gas sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities; the negative impact lower oil and natural gas prices could have on our ability to borrow; and drilling and operating risks. We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information.

Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Also, our internal estimates of reserves, particularly those in the properties recently acquired or proposed to be acquired where we may have limited review of data or experience with the reserves, may be subject to revision and may be different from estimates by our external reservoir engineers at year-end. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.

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

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

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

  THREE MONTHS ENDED:                     March 31,            March 31,
                                           2006                  2005
                                       $        $/mcfe        $       $/mcfe

  REVENUES:
    Oil and natural gas sales      1,510,821     11.05     538,942     5.15
    Marketing sales                  404,367      2.96     244,508     2.34
    Service operations revenue        29,379      0.21         ---      ---
        Total Revenues             1,944,567     14.22     783,450     7.49

  OPERATING COSTS:
    Production expenses              119,392      0.87      69,562     0.66
    Production taxes                  55,373      0.40      35,958     0.34
    General and administrative
     expenses                         28,791      0.21      12,067     0.12
    Marketing expenses               391,360      2.87     237,276     2.27
    Service operations expense        14,437      0.11         ---      ---
    Oil and natural gas depreciation,
     depletion and amortization      304,957      2.23     180,968     1.73
    Depreciation and amortization
     of other assets                  23,872      0.17      10,082     0.10
    Early retirement expense          54,753      0.40         ---      ---
        Total Operating Costs        992,935      7.26     545,913     5.22

  INCOME FROM OPERATIONS             951,632      6.96     237,537     2.27

  OTHER INCOME (EXPENSE):
    Interest and other income          9,636      0.07       3,357     0.03
    Interest expense                 (72,658)    (0.53)    (43,128)   (0.41)
    Gain on sale of investment       117,396      0.86         ---      ---
    Loss on repurchases or exchanges
     of Chesapeake debt                  ---       ---        (900)   (0.01)
        Total Other Income (Expense)  54,374      0.40     (40,671)   (0.39)

    Income Before Income Taxes     1,006,006      7.36     196,866     1.88

    Income Tax Expense:
      Current                            ---       ---         ---      ---
      Deferred                       382,283      2.80      71,856     0.69
        Total Income Tax Expense     382,283      2.80      71,856     0.69

  NET INCOME                         623,723      4.56     125,010     1.19

    Preferred stock dividends        (18,812)    (0.13)     (5,463)   (0.05)
    Loss on exchange/conversion
     of preferred stock               (1,009)    (0.01)        ---      ---

  NET INCOME AVAILABLE TO
   COMMON SHAREHOLDERS               603,902      4.42     119,547     1.14

  EARNINGS PER COMMON SHARE:

    Basic                              $1.64                 $0.39
    Assuming dilution                  $1.44                 $0.36

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

    Basic                            368,625               309,857
    Assuming dilution                431,455               351,357



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

                                                     March 31,  December 31,
                                                       2006         2005

  Cash                                                $38,286      $60,027
  Other current assets                              1,155,910    1,123,370
      Total Current Assets                          1,194,196    1,183,397

  Property and equipment (net)                     16,307,278   14,411,887
  Other assets                                        550,886      523,178
      Total Assets                                $18,052,360  $16,118,462

  Current liabilities                              $1,591,931   $1,964,088
  Long term debt                                    6,320,915    5,489,742
  Asset retirement obligation                         166,249      156,593
  Other long term liabilities                         426,470      528,738
  Deferred tax liability                            2,183,972    1,804,978
      Total Liabilities                            10,689,537    9,944,139

  STOCKHOLDERS' EQUITY                              7,362,823    6,174,323

  TOTAL LIABILITIES & STOCKHOLDERS' EQUITY        $18,052,360  $16,118,462

  COMMON SHARES OUTSTANDING                           382,033      370,190



                        CHESAPEAKE ENERGY CORPORATION
    RECONCILIATION OF FIRST QUARTER 2006 ADDITIONS TO OIL AND NATURAL GAS
                                  PROPERTIES
                    ($ in 000's, except per unit amounts)
                                 (unaudited)

                                                        Reserves
                                             Cost      (in mmcfe)    $/mcfe

  Exploration and development costs        $615,338     272,544 (A)  $2.26
  Acquisition of proved properties          453,051     243,080       1.86
      Subtotal                            1,068,389     515,624       2.07

  Divestitures                                  (73)        (67)       ---
  Geological and geophysical costs           27,498         ---        ---
      Adjusted subtotal                   1,095,814     515,557       2.13

  Revisions - price                             ---     (88,217)       ---
  Acquisition of unproved properties        545,738         ---        ---
  Leasehold acquisition costs               172,553         ---        ---
      Adjusted subtotal                   1,814,105     427,340       4.25

  Tax basis step-up                          81,145         ---        ---
  Asset retirement obligation and other       5,694         ---        ---
      Total                              $1,900,944     427,340      $4.45

   (A)  Includes positive performance revisions of 76 bcfe and excludes
        downward revisions of 88 bcfe resulting from oil and natural gas
        prices declines between December 31, 2005 and March 31, 2006.



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

                                                   Mmcfe

  Beginning balance, 12/31/05                   7,520,690
  Extensions and discoveries                      196,769
  Acquisitions                                    243,080
  Divestitures                                        (67)
  Revisions - performance                          75,775
  Revisions - price                               (88,217)
  Production                                     (136,752)
  Ending balance, 3/31/06                       7,811,278

  Reserve replacement                             427,340
  Reserve replacement rate                            312%



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

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

  Oil and Natural Gas Sales ($ in thousands):
      Oil sales                                        $124,667    $79,944
      Oil derivatives - realized gains (losses)          (3,808)    (7,067)
      Oil derivatives - unrealized gains (losses)        (1,335)   (12,842)

          Total Oil Sales                               119,524     60,035

      Natural gas sales                                 940,318    535,777
      Natural gas derivatives - realized
       gains (losses)                                   252,029     47,415
      Natural gas derivatives - unrealized
       gains (losses)                                   198,950   (104,285)

          Total Natural Gas Sales                     1,391,297    478,907

          Total Oil and Natural Gas Sales            $1,510,821   $538,942

  Average Sales Price (excluding gains (losses)
   on derivatives):
      Oil ($ per bbl)                                    $58.92     $45.79
      Natural gas ($ per mcf)                            $ 7.58     $ 5.69
      Natural gas equivalent ($ per mcfe)                $ 7.79     $ 5.89

  Average Sales Price (excluding unrealized gains
   (losses) on derivatives):
      Oil ($ per bbl)                                    $57.12     $41.74
      Natural gas ($ per mcf)                            $ 9.61     $ 6.20
      Natural gas equivalent ($ per mcfe)                $ 9.60     $ 6.27

  Interest Expense ($ in thousands)
      Interest                                          $72,898    $47,293
      Derivatives - realized (gains) losses              (1,244)    (1,121)
      Derivatives - unrealized (gains) losses             1,004     (3,044)
          Total Interest Expense                        $72,658    $43,128



                        CHESAPEAKE ENERGY CORPORATION
                    CONDENSED CONSOLIDATED CASH FLOW DATA
                                  (in 000's)
                                 (unaudited)
  THREE MONTHS ENDED:                                  March 31,   March 31,
                                                         2006        2005

  Cash provided by operating activities                $967,458    $512,685

  Cash (used in) investing activities                (1,960,061) (1,173,937)

  Cash provided by financing activities                 970,862     654,356



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

  THREE MONTHS ENDED:                      March 31,   Dec. 31,    March 31,
                                             2006        2005        2005

  CASH PROVIDED BY OPERATING ACTIVITIES    $967,458    $829,543    $512,685

  Adjustments:
    Changes in assets and liabilities        79,405       3,250      (8,063)

  OPERATING CASH FLOW*                   $1,046,863    $832,793    $504,622

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



  THREE MONTHS ENDED:                      March 31,    Dec. 31,   March 31,
                                             2006        2005        2005

  NET INCOME                               $623,723    $452,525    $125,010

  Income tax expense                        382,283     260,114      71,856
  Interest expense                           72,658      64,177      43,128
  Depreciation and amortization
   of other assets                           23,872      16,175      10,082
  Oil and natural gas depreciation,
   depletion and amortization               304,957     272,551     180,968

  EBITDA**                               $1,407,493  $1,065,542    $431,044

   **  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:                      March 31,   Dec. 31,    March 31,
                                             2006        2005        2005

  CASH PROVIDED BY OPERATING ACTIVITIES    $967,458    $829,543    $512,685

  Changes in assets and liabilities          79,405       3,250      (8,063)
  Interest expense                           72,658      64,177      43,128
  Unrealized gains (losses) on oil
   and natural gas derivatives              197,615     178,259    (117,127)
  Other non-cash items                       90,357      (9,687)        421

  EBITDA                                 $1,407,493  $1,065,542    $431,044



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

                                           March 31,    Dec. 31,   March 31,
  THREE MONTHS ENDED:                        2006        2005        2005

  Net income available to common
   shareholders                            $603,902    $431,832    $119,547

  Adjustments:
    Loss on conversion/exchange
     of preferred stock                       1,009       4,406         ---
  Net Income                               $604,911    $436,238    $119,547

  Adjustments, net of tax:
    Unrealized (gains) losses
     on derivatives                        (121,899)   (112,965)     72,443
    Loss on repurchases or exchanges of debt    ---         236         572
    Early retirement expense                 33,947         ---         ---
    Gain on sale of investment              (72,786)        ---         ---

  Adjusted net income available to
   common shareholders*                    $444,173    $323,509    $192,562

  Adjusted earnings per share
   assuming dilution**                        $1.07       $0.84       $0.56

   *  Adjusted net income available to common and adjusted earnings per
      share assuming dilution exclude certain items that management believes
      affect the comparability of operating results.  The company discloses
      these non-GAAP financial measures as a useful adjunct to GAAP earnings
      because:
      a.  Management uses adjusted net income available to common to
          evaluate the company's operational trends and performance relative
          to other oil and natural gas producing companies.
      b.  Adjusted net income available to common are more comparable to
          earnings estimates provided by securities analysts.
      c.  Items excluded generally are one-time items, or items whose timing
          or amount cannot be reasonably estimated.  Accordingly, any
          guidance provided by the company generally excludes information
          regarding these types of items.

   ** For purposes of calculating fully diluted shares and earnings per
      share assuming dilution for the three months ended March 31, 2006 and
      December 31, 2005, accounting rules prohibit the company from assuming
      the conversion of the 5.0% (Series 2003) and the 4.125% preferred
      stock for common shares prior to conversion or exchange 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 431.7 million and 404.8 million for the three months
      ended March 31, 2006 and December 31, 2005, respectively).



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

                                       March 31,     Dec. 31,     March 31,
  THREE MONTHS ENDED:                    2006          2005         2005

  EBITDA                              $1,407,493    $1,065,542    $431,044

  Adjustments, before tax:
    Unrealized (gains) losses on oil
     and natural gas derivatives        (197,615)     (178,259)    117,127
    Loss on repurchases or exchanges
     of debt                                 ---           372         900
    Early retirement expense              54,753           ---         ---
    Gain on sale of investment          (117,396)          ---         ---

  Adjusted EBITDA*                    $1,147,235      $887,655    $549,071

   *  Adjusted EBITDA excludes certain items that management believes affect
      the comparability of operating results.  The company discloses these
      non-GAAP financial measures as a useful adjunct to EBITDA because:
      a. Management uses adjusted EBITDA to evaluate the company's
         operational trends and performance relative to other oil and
         natural gas producing companies.
      b. Adjusted EBITDA is more comparable to earnings estimates provided
         by securities analysts.
      c. Items excluded generally are one-time items, or items whose timing
         or amount cannot be reasonably estimated.  Accordingly, any
         guidance provided by the company generally excludes information
         regarding these types of items.



                               SCHEDULE "A"

                  CHESAPEAKE'S OUTLOOK AS OF MAY 1, 2006

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

We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of May 1, 2006, we are using the following key assumptions in our projections for the second quarter of 2006, the full-year 2006 and the full-year 2007.

The primary changes from our February 23, 2006 Outlook are in italicized bold in the table and are explained as follows:

   1)  We have updated the projected effect of changes in our hedging
       positions since our February 23, 2006 Outlook.
   2)  We have updated our expectations for future NYMEX oil and natural gas
       prices based on current market conditions in order to illustrate
       hedging effects only.
   3)  We have updated certain of our cost assumptions.
   4)  We have shown our projections for the quarter ending June 30, 2006
       for the first time.



                                 Quarter Ending  Year Ending    Year Ending
                                   6/30/2006     12/31/2006     12/31/2007
  Estimated Production:
    Oil - mbbls                      2,000         8,000           8,000
    Natural gas - bcf              127 - 132     528 - 538       571 - 581
    Natural gas equivalent - bcfe  139 - 144     576 - 586       619 - 629
    Daily natural gas equivalent
     midpoint - in mmcfe             1,555         1,592           1,710
  NYMEX Prices (A) (for calculation
   of realized hedging effects only):
    Oil - $/bbl                     $60.00        $60.87          $50.00
    Natural gas - $/mcf              $7.08         $7.52           $7.00
  Estimated Realized Hedging Effects
   (based on assumed NYMEX
   prices above):
    Oil - $/bbl                      $1.33         $1.43           $7.83
    Natural gas - $/mcf              $1.67         $2.02           $2.00
  Estimated Differentials
   to NYMEX Prices:
    Oil - $/bbl                      6 - 8%        6 - 8%          6 - 8%
    Natural gas - $/mcf              8 - 12%       8 - 12%         8 - 12%

  Operating Costs per Mcfe of
   Projected Production:
    Production expense           $0.85 - 0.95  $0.85 - 0.95    $0.90 - 1.00
    Production taxes (generally
     6.0% of O&G revenues) (B)   $0.48 - 0.53  $0.41 - 0.46    $0.36 - 0.41
    General and administrative   $0.15 - 0.20  $0.15 - 0.20    $0.15 - 0.20
    Stock-based compensation
     (non-cash)                  $0.05 - 0.07  $0.06 - 0.08    $0.08 - 0.10
    DD&A of oil and natural
     gas assets                  $2.25 - 2.35  $2.30 - 2.35    $2.35 - 2.45
    Depreciation of other assets $0.16 - 0.20  $0.16 - 0.20    $0.20 - 0.25
    Interest expense (C)         $0.52 - 0.57  $0.52 - 0.57    $0.53 - 0.58
  Other Income per Mcfe:
    Marketing and other income   $0.02 - 0.04  $0.02 - 0.04    $0.02 - 0.04
    Service operations income    $0.10 - 0.15  $0.10 - 0.15    $0.10 - 0.15

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

  Equivalent Shares Outstanding:
    Basic                           377 mm        376 mm          387 mm
    Diluted                         436 mm        436 mm          441 mm
  Capital Expenditures:
    Drilling, leasehold
     and seismic                  $700 - 750  $3,200 - 3,500  $3,400 - 3,600
                                      mm            mm              mm

   (A)  Oil NYMEX prices have been updated for actual contract prices
        through March 2006 and natural gas NYMEX prices have been updated
        for actual contract prices through April 2006.
   (B)  Severance tax per mcfe is based on NYMEX prices of $60.00 per bbl
        and natural gas prices ranging from $8.75 to $9.75 per mcf during Q2
        2006, $7.35 to $8.35 per mcf during calendar 2006 and $50.00 per bbl
        and $6.50 to $7.50 per mcf during calendar 2007.
   (C)  Does not include gains or losses on interest rate derivatives (SFAS
        133).


  Commodity Hedging Activities

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

   (i)   For swap instruments, we receive a fixed price for the hedged
         commodity and pay a floating market price, as defined in each
         instrument, to the counterparty.  The fixed-price payment and the
         floating-price payment are netted, resulting in a net amount due to
         or from the counterparty.
   (ii)  For cap-swaps, Chesapeake receives a fixed price and pays a
         floating market price.  The fixed price received by Chesapeake
         includes a premium in exchange for a "cap" limiting the
         counterparty's exposure.  In other words, there is no limit to
         Chesapeake's exposure but there is a limit to the downside exposure
         of the counterparty.
   (iii) Basis protection swaps are arrangements that guarantee a price
         differential of oil or natural gas from a specified delivery point.
         Chesapeake receives a payment from the counterparty if the price
         differential is greater than the stated terms of the contract and
         pays the counterparty if the price differential is less than the
         stated terms of the contract.

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

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

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

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

                                                            % Hedged
                                                                  Open Swap
                                                                  Positions
                                             Avg. NYMEX Assuming  as a % of
                           Avg. NYMEX  Gain     Price    Natural  Estimated
                             Strike   (Loss)  Including    Gas      Total
                             Price     from    Open &  Production  Natural
                Open Swaps  Of Open   Locked   Locked      in        Gas
                 in Bcf's    Swaps     Swaps  Positions Bcf's of: Production
  2006:
  Q1               93.8     $10.81    -$0.09   $10.72     124.1      76%
  Q2              101.4      $8.82    -$0.05    $8.77     129.5      78%
  Q3              117.9      $8.80    -$0.05    $8.75     137.0      86%
  Q4              114.9      $9.46    -$0.04    $9.42     142.4      81%
  Total 2006(A)   428.0      $9.42    -$0.05    $9.37     533.0      80%

  Total 2007      330.0      $9.94    -$0.04    $9.90     576.0      57%

  Total 2008      248.9      $9.22       ---    $9.22     604.0      41%

  Total 2009        3.7      $9.02       ---    $9.02     634.0       1%

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

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

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

                      Mid-Continent                     Appalachia
             Volume in Bcf's   NYMEX less*:   Volume in Bcf's   NYMEX plus*:
  2006            130.1           $ 0.32            ---           $  ---
  2007            137.2             0.33           32.9             0.34
  2008            118.6             0.27           25.6             0.34
  2009             86.6             0.29           18.2             0.31
  Totals          472.5           $ 0.30           76.7           $ 0.33
   * weighted average


We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($523 million as of March 31, 2006). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and natural gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR.

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

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

                                                              % Hedged
                                                                   Open Swap
                                                                   Positions
                         Avg. NYMEX  Avg. Fair           Assuming  as a % of
                           Strike   Value Upon           Natural   Estimated
                           Price   Acquisition Initial     Gas       Total
                          Of Open    of Open  Liability Production  Natural
              Open Swaps   Swaps      Swaps    Acquired    in         Gas
               in Bcf's  (per Mcf)  (per Mcf) (per Mcf) Bcf's of: Production
  2006:
  Q1             7.9       $4.91     $12.14    ($7.23)    124.1       6%
  Q2            10.5       $4.86      $9.97    ($5.11)    129.5       8%
  Q3            10.6       $4.86      $9.95    ($5.09)    137.0       8%
  Q4            10.6       $4.86     $10.38    ($5.52)    142.4       7%
  Total 2006    39.6       $4.87     $10.51    ($5.64)    533.0       7%

  Total 2007    42.0       $4.82      $9.18    ($4.36)    576.0       7%

  Total 2008    38.4       $4.67      $8.01    ($3.34)    604.0       6%

  Total 2009    18.3       $5.18      $7.28    ($2.10)    634.0       3%

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

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

                                                      % Hedged
                                                              Open Swap
                                Avg.       Assuming Oil       Positions
               Open Swaps      NYMEX        Production      as % of Total
                in mbbls    Strike Price   in mbbls of: Estimated Production
  2006:
  Q1            1,109.5       $60.03          2,116              52%
  Q2            1,379.5       $61.85          2,000              69%
  Q3            1,625.0       $63.90          1,942              84%
  Q4            1,656.0       $63.76          1,942              85%
  Total 2006(A) 5,770.0       $62.63          8,000              72%
  Total 2007    3,555.0       $67.07          8,000              44%
  Total 2008    2,928.0       $68.20          8,000              37%
  Total 2009      182.5       $66.26          8,000               2%

   (A)  Certain hedging arrangements include swaps with knockout prices
        ranging from $40.00 to $42.00 covering 501.5 mbbls in 2006.



                               SCHEDULE "B"

          CHESAPEAKE'S PREVIOUS OUTLOOK AS OF FEBRUARY 23, 2006
                      (PROVIDED FOR REFERENCE ONLY)

               NOW SUPERSEDED BY OUTLOOK AS OF MAY 1, 2006

Quarter Ending March 31, 2006; Year Ending December 31, 2006; Year Ending December 31, 2007.

We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of February 23, 2006, we are using the following key assumptions in our projections for the first quarter of 2006, the full-year 2006 and the full- year 2007.

The primary changes from our January 17, 2006 Outlook are in italicized bold in the table and are explained as follows:

   1)  We have updated the projected effect of changes in our hedging
       positions since our January 17, 2006 Outlook.
   2)  We have updated our expectations for future NYMEX oil and gas prices
       based on current market conditions in order to illustrate hedging
       effects only.
   3)  We have updated the share count for the effect of accelerating the
       stock-based awards to our former Chief Operating Officer; however, we
       have not reflected the impact to stock-based compensation that will
       occur in the 2006 first quarter or full year.
   4)  We have not reflected the gain related to the sale of our investment
       in Pioneer Drilling Company in other income for the 2006 first
       quarter or full year.
   5)  We have updated the book tax rate for 2006 and 2007 primarily to
       account for the impact of state income taxes associated with our
       newly acquired Appalachian operations.



                               Quarter Ending Year Ending      Year Ending
                                 3/31/2006    12/31/2006       12/31/2007
  Estimated Production:
    Oil - Mbbl                     1,900         7,700           7,750
    Gas - Bcf                    121 - 131     530 - 540       572 - 582
    Gas Equivalent - Bcfe        132 - 142     576 - 586       619 - 629
    Daily gas equivalent midpoint
     - in Mmcfe                    1,522         1,593           1,709
  NYMEX Prices (for calculation
   of realized hedging
   effects only):
    Oil - $/Bbl                   $58.51        $54.00          $50.00
    Gas - $/Mcf                    $9.47         $7.99           $7.00
  Estimated Realized Hedging Effects
   (based on assumed NYMEX prices
   above):
    Oil - $/Bbl                    $0.96         $4.51           $2.77
    Gas - $/Mcf                    $1.54         $1.40           $1.34
  Estimated Differentials
   to NYMEX Prices:
    Oil - $/Bbl                     6-8%          6-8%            6-8%
    Gas - $/Mcf                   10 - 15%       8 - 12%         8 - 12%
  Operating Costs per Mcfe of
   Projected Production:
    Production expense         $0.77 - 0.82  $0.77 - 0.82    $0.80 - 0.85
    Production taxes (generally
     6.0% of O&G revenues) (A) $0.48 - 0.53  $0.41 - 0.46    $0.36 - 0.41
    General and administrative $0.15 - 0.17  $0.14 - 0.16    $0.14 - 0.15
    Stock-based compensation
     (non-cash)                $0.07 - 0.09  $0.08 - 0.10    $0.10 - 0.12
    DD&A - oil and gas         $2.12 - 2.18  $2.15 - 2.20    $2.25 - 2.30
    Depreciation of other
     assets                    $0.14 - 0.16  $0.14 - 0.16    $0.14 - 0.16
    Interest expense (B)       $0.52 - 0.57  $0.52 - 0.57    $0.53 - 0.58
  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 (approximately
   equal to 95% deferred)           38%           38%             38%

  Equivalent Shares Outstanding:
    Basic                         368 mm        374 mm          381 mm
    Diluted                       431 mm        435 mm          440 mm
  Capital Expenditures:
    Drilling, leasehold
     and seismic                $650 - 700  $3,000 - 3,200  $3,300 - 3,500
                                    mm            mm              mm

   (A)  Severance tax per mcfe is based on NYMEX prices of $58.51 per bbl
        and natural gas prices ranging from $9.00 to $10.00 per mcf during
        Q1 2006, $54.00 per bbl and $7.50 to $8.50 per mcf during calendar
        2006 and $50.00 per bbl and $6.50 to $7.50 per mcf during calendar
        2007.
   (B)  Does not include gains or losses on interest rate derivatives (SFAS
        133).


  Commodity Hedging Activities

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

   (i)    For swap instruments, we receive a fixed price for the hedged
          commodity and pay a floating market price, as defined in each
          instrument, to the counterparty.  The fixed-price payment and the
          floating-price payment are netted, resulting in a net amount due
          to or from the counterparty.
   (ii)   For cap-swaps, Chesapeake receives a fixed price and pays a
          floating market price.  The fixed price received by Chesapeake
          includes a premium in exchange for a "cap" limiting the
          counterparty's exposure.  In other words, there is no limit to
          Chesapeake's exposure but there is a limit to the downside
          exposure of the counterparty.
   (iii)  Basis protection swaps are arrangements that guarantee a price
          differential of oil or gas from a specified delivery point.
          Chesapeake receives a payment from the counterparty if the price
          differential is greater than the stated terms of the contract and
          pays the counterparty if the price differential is less than the
          stated terms of the contract.

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

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

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

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

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

  2006:
  Q1               93.8     $10.81    -$0.09   $10.72     126.0      74%
  Q2               96.9      $8.88    -$0.06    $8.82     132.0      73%
  Q3              101.7      $8.93    -$0.06    $8.87     137.0      74%
  Q4               90.0      $9.41    -$0.05    $9.36     140.0      64%
  Total 2006(A)   382.4      $9.49    -$0.06    $9.43     535.0      71%

  Total 2007      206.9      $9.91    -$0.06    $9.85     577.0      36%

  Total 2008      131.8      $9.10       ---    $9.10     604.0      22%

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

Note: Not shown above are collars covering 0.2 bcf of production in 2006 at a weighted average floor and ceiling of $6.00 and $9.70 and call options covering 7.3 bcf of production in 2006 at a weighted average price of $12.50, 25.6 bcf of production in 2007 at a weighted average price of $10.57 and 7.3 bcf of production in 2008 at a weighed average price of $12.50.

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

                                                   Assuming Gas
                           Volume        NYMEX      Production
                          in Bcf's       less*:    in Bcf's of:    % Hedged
  2006                     130.1         $0.32          535           24%
  2007                     137.2          0.33          577           24%
  2008                     118.6          0.27          604           20%
  2009                      86.6          0.29          634           14%

  Totals                   472.5         $0.30        2,350           20%
   * weighted average



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

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

  2006:
  Q1                    1,109.5        $60.03        1,900.0         58%
  Q2                    1,289.5        $61.13        1,920.0         67%
  Q3                    1,242.0        $61.50        1,940.0         64%
  Q4                    1,196.0        $61.33        1,940.0         62%
  Total 2006(A)         4,837.0        $61.02        7,700.0         63%
  Total 2007            1,730.0        $62.42        7,750.0         22%
  Total 2008            1,098.0        $65.48        7,800.0         14%

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


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

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

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

                                                            % Hedged
                      Avg.
                     NYMEX    Avg. Fair                           Open Swap
                    Strike   Value Upon                           Positions
                     Price   Acquisition  Initial     Assuming    as a % of
           Open     Of Open    of Open   Liability      Gas       Estimated
          Swaps      Swaps      Swaps     Acquired   Production   Total Gas
         in Bcf's  (per Mcf)  (per Mcf)  (per Mcf)  in Bcf's of:  Production

  2006:
  Q1        7.9      $4.91     $12.14     ($7.23)       126.0         6%
  Q2       10.5      $4.86      $9.97     ($5.11)       132.0         8%
  Q3       10.6      $4.86      $9.95     ($5.09)       137.0         8%
  Q4       10.6      $4.86     $10.38     ($5.52)       140.0         8%
  Total
   2006    39.6      $4.87     $10.51     ($5.64)       535.0         7%

  Total
   2007    42.0      $4.82      $9.18     ($4.36)       577.0         7%

  Total
   2008    38.4      $4.67      $8.01     ($3.34)       604.0         6%

  Total
   2009    18.3      $5.18      $7.28     ($2.10)       634.0         3%

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

SOURCE: Chesapeake Energy Corporation

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