Chesapeake Energy Corporation Reports Strong Results for the 2006 Second Quarter
Net Income Available to Common Shareholders Reaches $332 Million on Revenue of $1.6 Billion and Production of 143 Bcfe; Net Income Per Fully Diluted Common Share Increases 58% Over the 2005 Second Quarter
Total Production Growth Should Reach at Least 25% in 2006 and 11% in 2007, Including 10% Organic Production Growth in Each Year
Proved Reserves Reach Record Level of 8.1 Tcfe; Company Delivers First Half 2006 Reserve Replacement Rate of 308% From 860 Bcfe of Additions at a Drilling and Acquisition Cost of $1.80 per Mcfe
Company Provides Detailed Review of Its 14.0 Tcfe of Unproved Reserves Located on Its 9.7 Million Net Acre U.S. Onshore Leasehold Position
PRNewswire-FirstCall
OKLAHOMA CITY

Chesapeake Energy Corporation today reported financial and operating results for the second quarter of 2006. For the quarter, Chesapeake generated net income available to common shareholders of $332.1 million ($0.82 per fully diluted common share), operating cash flow of $914.2 million (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $1.029 billion (defined as net income before income taxes, interest expense, and depreciation, depletion and amortization expense) on revenue of $1.584 billion and production of 142.7 billion cubic feet of natural gas equivalent (bcfe). For the quarter, ebitda and net income per fully diluted common share increased 77% and 58% over the 2005 second quarter, respectively.

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

   *  an unrealized mark-to-market gain of $9.7 million resulting from the
      company's oil and natural gas and interest rate hedging programs;
   *  a reversal of an accrual of $7.2 million for production taxes as the
      result of the dismissal of certain severance tax claims;
   *  a $15.0 million income tax accrual related to the recently adopted
      "margin" tax in Texas; and
   *  a reduction of net income available to common shareholders of
      $9.5 million resulting from the exchange of two series of the
      company's preferred stock for common stock pursuant to tender offers
      made during the quarter.

Excluding the above-mentioned items and giving effect to common shares issued for preferred shares during the quarter, Chesapeake's net income to common shareholders in the second quarter of 2006 would have been $339.8 million ($0.82 per fully diluted common share) and ebitda would have been $1.001 billion. The foregoing items do not affect the calculation of operating cash flow. For the quarter, adjusted ebitda and adjusted net income per fully diluted common share increased 77% and 64% over the 2005 second quarter. 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 18-21 of this release.

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

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

                                                   Three Months Ended:
                                                6/30/06   3/31/06   6/30/05

   Average daily production (in mmcfe)            1,568     1,519     1,244
   Natural gas as % of total production              91        91        89
   Natural gas production (in bcf)                129.8     124.1     101.1
   Average realized natural gas price ($/mcf)(A)   8.04      9.61      5.95
   Oil production (in mbbls)                      2,143     2,116     2,012
   Average realized oil price ($/bbl)(A)          58.80     57.12     42.82
   Natural gas equivalent production (in bcfe)    142.7     136.8     113.2
   Natural gas equivalent realized
    price ($/mcfe)(A)                              8.20      9.60      6.08
   Marketing income ($/mcfe)                        .08       .10       .05
   Service operations income ($/mcfe)               .10       .11       ---
   Production expenses ($/mcfe)                    (.85)     (.87)     (.64)
   Production taxes ($/mcfe)(B)                    (.24)     (.40)     (.42)
   General and administrative costs ($/mcfe)(C)    (.19)     (.17)     (.08)
   Stock-based compensation ($/mcfe)               (.05)     (.05)     (.02)
   DD&A of oil and natural
    gas properties ($/mcfe)                       (2.30)    (2.23)    (1.85)
   D&A of other assets ($/mcfe)                    (.16)     (.17)     (.10)
   Interest expense ($/mcfe)(A)                    (.51)     (.52)     (.48)
   Operating cash flow ($ in millions)(D)         914.2   1,046.9     453.7
   Operating cash flow ($/mcfe)                    6.41      7.66      4.01
   Adjusted ebitda ($ in millions)(E)           1,001.4   1,147.2     564.6
   Adjusted ebitda ($/mcfe)                        7.02      8.39      4.99
   Net income to common shareholders
    ($ in millions)                               332.1     603.9     179.2
   Earnings per share - assuming dilution ($)      0.82      1.44      0.52
   Adjusted net income to common
    shareholders ($ in millions)(F)               339.8     444.2     173.9
   Adjusted earnings per share
    - assuming dilution ($)                        0.82      1.07      0.50

   (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)  current quarter includes an $11.6 million reversal of an Oklahoma
        severance tax accrual
   (C)  excludes expenses associated with non-cash stock-based compensation
   (D)  defined as cash flow provided by operating activities before changes
        in assets and liabilities
   (E)  defined as net income before income taxes, interest expense, and
        depreciation, depletion and amortization expense, as adjusted to
        remove the effects of certain items detailed on page 20.
   (F)  defined as net income as adjusted to remove the effects of certain
        items detailed on page 20.



 Oil and Natural Gas Production Sets Record for 20th Consecutive Quarter;
    2006 Second Quarter Average Daily Production Increases 26% and 3%
  Over Production in the 2005 Second Quarter and the 2006 First Quarter

Daily production for the 2006 second quarter averaged 1.568 bcfe, an increase of 324 million cubic feet of natural gas equivalent (mmcfe), or 26%, over the 1.244 bcfe of daily production in the 2005 second quarter and an increase of 49 mmcfe, or 3.2%, over the 1.519 bcfe produced per day in the 2006 first quarter. Of the 324 mmcfe increase in daily production from the year ago quarter, 45% was generated from organic drillbit growth and 55% was generated from acquisitions, with the company's trailing 12-month organic production growth rate calculated as 12.0%.

Of the 49 mmcfe daily increase in sequential quarterly production, 95% was generated from organic drillbit growth and 5% was generated from acquisitions, with the company's sequential quarterly organic production growth rate calculated as 3.1%. Chesapeake is anticipating total production growth of at least 25% in 2006 and 11% in 2007, including organic growth rates of at least 10% each year. Please note that the company's production forecast for 2006 excludes any provision for possible production curtailments that the industry and Chesapeake may experience as a result of high pipeline pressures and/or early filling of U.S. natural gas storage facilities.

Chesapeake's 2006 second quarter production of 142.7 bcfe was comprised of 129.8 billion cubic feet of natural gas (bcf) (91% on a natural gas equivalent basis) and 2.14 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 1.568 bcfe consisted of 1.427 bcf of natural gas and 23,549 barrels (bbls) of oil. The 2006 second quarter was Chesapeake's 20th consecutive quarter of sequential U.S. production growth. Over these 20 quarters, Chesapeake's U.S. production has increased 296%, for an average compound quarterly growth rate of 7.1% and an average compound annual growth rate of 31.7%.

Chesapeake Continues Industry's Most Active Drilling Program With Drilling
                          Success Rate Over 97%

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 half, Chesapeake continued the industry's most active drilling program and drilled 613 gross (496 net) operated wells and participated in another 801 gross (88 net) wells operated by other companies. The company's drilling success rate was 97% for company-operated wells and 99% for non-operated wells. During the 2006 first half, Chesapeake invested $1.097 billion in operated wells (using an average of 82 operated rigs), $241 million in non-operated wells (using an average of 75 non-operated rigs), $324 million to acquire new leasehold (exclusive of leases acquired through acquisitions) and $72 million to acquire new 3-D seismic data.

 During the First Half of 2006, Oil and Natural Gas Proved Reserves Reach
Record Level of 8.1 Tcfe; Drilling and Acquisition Costs Average $1.80 per
   Mcfe as Company Adds 860 Bcfe for a Reserve Replacement Rate of 308%

Chesapeake began 2006 with estimated proved reserves of 7.521 trillion cubic feet of natural gas equivalent (tcfe) and ended the second quarter with 8.101 tcfe, an increase of 580 bcfe, or 7.7%. During the 2006 first half, Chesapeake replaced its 279 bcfe of production with an estimated 860 bcfe of new proved reserves, for a reserve replacement rate of 308%. Reserve replacement through the drillbit was 590 bcfe, or 211% of production (including 352 bcfe of positive performance revisions and 196 bcfe of downward revisions resulting from natural gas price declines between December 31, 2005 and June 30, 2006) and 69% of the total increase. Reserve replacement through the acquisition of proved reserves was 269 bcfe, or 97% of production and 31% of the total increase.

Total costs incurred during the 2006 first half, 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 $3.6 billion. The company's total drilling and acquisition costs were $1.80 per thousand cubic feet of natural gas equivalent (mcfe), excluding costs of $1.6 billion for leasehold and unproved properties acquired during the period and $93 million relating primarily to tax basis step-up and asset retirement obligations, as well as downward revisions of proved reserves from lower natural gas prices. Excluding the same costs as described above, Chesapeake's exploration and development costs through the drillbit were $1.70 per mcfe during the 2006 first half while reserve replacement costs through acquisitions of proved reserves were $1.84 per mcfe. A complete reconciliation of finding and acquisition costs and a roll-forward of proved reserves is presented on page 16 of this release.

As of June 30, 2006, the estimated future net cash flows of Chesapeake's proved reserves, before income taxes and discounted at 10% (PV-10), were $15.0 billion using field differential adjusted prices of $69.10 per barrel of oil (bbl) (based on a NYMEX quarter-ending price of $73.86 per bbl) and $5.72 per thousand cubic feet of natural gas (mcf) (based on a NYMEX quarter- ending price of $6.09 per mcf). In addition to the PV-10 value of its proved reserves, the net book value of the company's other assets (including drilling rigs, land and buildings, investments in securities and other non-current assets) was $1.8 billion as of June 30, 2006.

Chesapeake's PV-10 changes by approximately $310 million for every $0.10 per mcf change in natural gas prices and approximately $49 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 June 30, 2006 PV-10 value to the standardized measure at such date. 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.

Average Prices Realized, Hedging Results and Hedging Positions Detailed

Average prices realized during the 2006 second quarter (including realized gains or losses from oil and natural gas derivatives, but excluding unrealized gains or losses on such derivatives) were $58.80 per bbl and $8.04 per mcf, for a realized natural gas equivalent price of $8.20 per mcfe. Chesapeake's average realized pricing differentials to NYMEX during the second quarter were a negative $6.19 per bbl and a negative $0.84 per mcf. Realized gains and losses from oil and natural gas hedging activities during the quarter generated a $5.71 loss per bbl and a $2.08 gain per mcf, for a 2006 second quarter realized hedging gain of $257.4 million, or $1.80 per mcfe. Chesapeake's total realized hedging gains in the first half of 2006 were $505.6 million, or $1.81 per mcfe.

Chesapeake has hedged a substantial level of its production through 2008 in order to capture attractive returns from recent acquisitions and to help secure strong margins and profitability on the company's drilling program. The following tables compare Chesapeake's hedged production volumes (including only swaps and also including the hedges assumed in the CNR acquisition) as of July 27, 2006 to those as of June 5, 2006.

                    Swap Positions as of July 27, 2006

                                  Natural Gas                   Oil
   Quarter or Year        % Hedged        $ NYMEX    % Hedged        $ NYMEX
   2006 3Q                   93%            $8.85       87%           $64.83
   2006 4Q                   87%            $9.50       86%           $65.64
   2006 Total Remaining      90%            $9.17       87%           $65.25
   2007 Total                72%            $9.88       73%           $71.42
   2008 Total                57%            $9.37       63%           $71.45



                      Swap Positions as of June 5, 2006

                                 Natural Gas                    Oil
   Quarter or Year        % Hedged        $ NYMEX    % Hedged        $ NYMEX
   2006 3Q                   93%            $8.85       84%           $63.90
   2006 4Q                   86%            $9.50       85%           $63.76
   2006 Total Remaining      89%            $9.17       84%           $63.83
   2007 Total                69%            $9.86       56%           $68.79
   2008 Total                55%            $9.34       48%           $69.50

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 July 27, 2006 labeled as Schedule "A", which begins on page 22. This Outlook has been changed from the Outlook dated June 5, 2006 (attached as Schedule "B", which begins on page 26) to reflect various updated information.

Chesapeake Increases Cost Inflation Hedges through Additional Oilfield Service

Investments

Chesapeake recently agreed to purchase one of the leading drilling contractors in the Appalachian Basin. The company is currently utilizing two of the contractor's 15 rigs and through this acquisition will gain enhanced operational flexibility in expanding activity levels in the basin. This acquisition bolsters the scale and operating capabilities of the company's 100% owned drilling rig subsidiary, Nomac Drilling Corporation. To date, Chesapeake has invested approximately $400 million to build or acquire 57 drilling rigs (including the pending acquisition of the Appalachian Basin drilling contractor) and is building 22 additional rigs. In total, Chesapeake's drilling rig fleet should reach 79 rigs by the end of the 2007 first quarter, which would rank Nomac as one of the six largest drilling rig contractors in the U.S.

Chesapeake's direct rig ownership is complemented by its $63 million in investments in two private drilling rig contractors, DHS Drilling Company and Mountain Drilling Company, in which Chesapeake owns approximately 45% and 49%, respectively. DHS owns 16 rigs and Mountain owns four rigs and has ordered another six 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.

Chesapeake's Leasehold and 3-D Seismic Inventories Now 9.7 Million Net Acres

and 12.9 Million Acres; Risked Unproved Reserves in the Company's Inventory

Now 14.0 Tcfe, Bringing Total Reserve Base to 22.1 Tcfe

Chesapeake attributes its strong drilling results and organic growth rates during 2006 (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 science. During the past five years, Chesapeake has significantly strengthened its technical capabilities by increasing its land, geoscience and engineering staff by over 450% to nearly 800 employees. Today, the company has more than 4,100 employees, of which approximately 70% work in the company's E&P operations and approximately 30% work in the company's oilfield service operations.

Since 2000, Chesapeake has invested $4.7 billion in new leasehold and 3-D seismic acquisitions and now owns what it believes to be one of the largest inventories of onshore leasehold (9.7 million net acres) and 3-D seismic (12.9 million acres) in the U.S. On this leasehold, the company has an estimated 24,000 net drilling locations, representing an approximate 10-year inventory of drilling projects, on which it believes it can develop approximately 3.3 tcfe of proved undeveloped reserves and approximately 14.0 tcfe of unproved reserves. Adding the company's total proved reserves of 8.1 tcfe to its estimated 14.0 tcfe of unproved reserves brings Chesapeake's estimated total reserves to approximately 22.1 tcfe.

Company Provides Detailed Information on Its Four Gas Resource Play Types

Chesapeake characterizes its drilling activity by one of four play types: conventional gas resource, unconventional gas resource, emerging unconventional 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 unproved reserves associated with such drillsites. The following summarizes Chesapeake's position and activity in each gas resource play type and highlights notable projects in each play.

Conventional Gas Resource Plays - In its traditional conventional areas (i.e., portions of the Mid-Continent, Permian, Gulf Coast, South Texas regions), where exploration targets are typically deep and defined using 3-D seismic data, Chesapeake believes it has a meaningful competitive advantage due to its operating scale, deep drilling expertise and over 10.0 million acres of 3-D seismic data. In these plays, Chesapeake owns 3.0 million net acres on which it has an estimated 1.0 tcfe of proved undeveloped reserves, an estimated 2.4 tcfe of risked unproved reserves and is currently utilizing 31 operated drilling rigs (up to 32 by year-end) to further develop its inventory of approximately 2,800 drillsites. Two of Chesapeake's most important conventional gas resource plays are described below.

   *  South Texas:  Located primarily in Zapata County, Texas, Chesapeake's
      South Texas assets are currently producing approximately 145 mmcfe per
      day and the company is currently utilizing six rigs (up to seven by
      year-end) to develop its 140,000 net acres of leasehold.  Chesapeake's
      proved undeveloped reserves in South Texas are an estimated 211 bcfe
      and its risked unproved reserves are an estimated 300 bcfe after
      applying a 75% risk factor and assuming an additional 325 net wells
      are drilled in the years ahead.  The company's expected economics for
      vertical South Texas wells are $3.0 million to develop 2.0 bcfe on
      80 acre spacing.

   *  Mountain Front (Primarily Morrow and Springer formations in Western
      Oklahoma):  From these prolific formations located in the Anadarko
      Basin, the company is currently producing approximately 80 mmcfe per
      day from the Mountain Front area and is currently utilizing four rigs
      (four at year-end also) to develop its 120,000 net acres of leasehold.
      Chesapeake's proved undeveloped reserves in the Mountain Front are an
      estimated 65 bcfe and its risked unproved reserves are an estimated
      200 bcfe after applying a 70% risk factor and assuming an additional
      80 net wells are drilled in the years ahead.  The company's expected
      economics for vertical Mountain Front wells are $8.0 million to
      develop 4.0 bcfe on 320 acre spacing.

Unconventional Gas Resource Plays - In its unconventional gas resource areas, Chesapeake owns 1.1 million net acres on which it has an estimated 1.7 tcfe of proved undeveloped reserves, an estimated 6.0 tcfe of risked unproved reserves and is currently utilizing 51 operated drilling rigs (up to 69 by year-end) to further develop its inventory of approximately 9,000 net drillsites. Four of Chesapeake's most important unconventional gas resource plays are described below.

   *  Fort Worth Barnett Shale (North Texas):  This play is the largest
      unconventional gas resource play in the U.S. and Chesapeake believes
      it is the third largest producer of natural gas and the third most
      active driller as well as the second largest leasehold owner in
      Tarrant and Johnson Counties (the sweet spot of the horizontally
      developed "Tier 1" area).  Chesapeake is currently producing
      approximately 130 mmcfe per day from the Fort Worth Barnett Shale and
      is currently utilizing 15 rigs (up to 25 by year-end) to develop its
      165,000 net acres of leasehold located primarily in the Tier 1 area.
      Chesapeake's proved undeveloped reserves in the Fort Worth Barnett are
      an estimated 594 bcfe and its risked unproved reserves are an
      estimated 3.4 tcfe after applying a 25% risk factor and assuming an
      additional 2,200 net wells are drilled in the years ahead.  The
      company's expected economics for horizontal Barnett Shale wells are
      $2.7 million to develop 2.4 bcfe on 55 acre spacing.

   *  Sahara (Primarily Mississippi, Chester, Hunton formations in Northwest
      Oklahoma):  In this vast play that extends across five counties in
      northwestern Oklahoma, Chesapeake believes it is the largest producer
      of natural gas, the most active driller and the largest leasehold
      owner in the area.  Chesapeake is currently producing approximately
      130 mmcfe per day in the Sahara area and is currently utilizing
      12 rigs (up to 16 by year-end) to develop its 500,000 net acres of
      leasehold.  Chesapeake's proved undeveloped reserves in Sahara are an
      estimated 397 bcfe and its risked unproved reserves are an estimated
      1.8 tcfe after applying a 25% risk factor and assuming an additional
      4,900 net wells are drilled in the years ahead.  The company's
      expected economics for vertical Sahara wells are $0.9 million to
      develop 0.6 bcfe on approximately 65 acre spacing.

   *  Ark-La-Tex Tight Gas Sands (Primarily Travis Peak, Cotton Valley,
      Pettit and Bossier formations):  In this large region covering most of
      East Texas and Northern Louisiana, Chesapeake has assembled a strong
      portfolio of unconventional gas resource plays.  Chesapeake believes
      it is one of the 10 largest producers of natural gas, the third most
      active driller and one of the largest leasehold owners in the area.
      Chesapeake is currently producing approximately 100 mmcfe per day in
      the Ark-La-Tex area and is currently utilizing 14 rigs (up to 17 by
      year-end) to further develop its 125,000 net acres of leasehold.
      Chesapeake's unconventional proved undeveloped reserves in the Ark-La-
      Tex region are an estimated 369 bcfe and its unconventional risked
      unproved reserves are an estimated 425 bcfe after applying a 40% risk
      factor and assuming an additional 1,100 net wells are drilled in the
      years ahead.  The company's expected economics for medium-depth
      vertical unconventional Ark-La-Tex wells are $1.6 million to develop
      1.0 bcfe on approximately 60 acre spacing.

   *  Granite, Atoka and Cherokee Washes (Western Oklahoma and Texas
      Panhandle):  Chesapeake believes it is the largest producer of natural
      gas, the most active driller and the largest leasehold owner in the
      Wash plays.  Chesapeake is currently producing approximately 110 mmcfe
      per day from these plays and is currently utilizing 10 rigs (up to 11
      by year-end) to further develop its 115,000 net acres of leasehold.
      Chesapeake's proved undeveloped reserves in the Wash plays are an
      estimated 304 bcfe and its risked unproved reserves are an estimated
      300 bcfe after applying a 50% risk factor and assuming an additional
      525 net wells are drilled in the years ahead.  The company's expected
      economics for vertical Wash wells are $2.8 million to develop 1.4 bcfe
      on 80 acre spacing.


Emerging Unconventional Gas Resource Plays - In its emerging unconventional gas resource areas where commercial production has only recently been established but the future reserve potential could be substantial, Chesapeake owns 2.2 million net acres on which it has an estimated 100 bcfe of proved undeveloped reserves, an estimated 3.8 tcfe of risked unproved reserves and is currently utilizing 10 operated drilling rigs (up to 23 rigs by year-end) to further develop its inventory of approximately 2,600 net drillsites. Five of Chesapeake's most important emerging unconventional gas resource plays are described below.

   *  Fayetteville Shale (Arkansas):  In this region of rapidly growing
      importance to Chesapeake, the company believes it is now the largest
      leasehold owner in the play (second largest in the most currently
      prospective area of the play).  Chesapeake is currently producing
      approximately 2.0 mmcfe per day from the Fayetteville Shale and is
      currently utilizing two rigs (up to eight by year-end) to further
      develop its 1.0 million net acres of leasehold (300,000 net acres in
      the most currently prospective area of the play to date).
      Chesapeake's proved undeveloped reserves in the Fayetteville are an
      estimated 18 bcfe and its risked unproved reserves are an estimated
      2.0 tcfe after applying an 85% risk factor and assuming an additional
      2,000 net wells are drilled in the years ahead.  The company's
      expected economics for horizontal Fayetteville Shale wells are
      $2.5 million to develop 1.2 bcfe on 80 acre spacing.

   *  Deep Haley (Primarily Strawn, Atoka, Morrow formations in West Texas):
      In this West Texas Delaware Basin area of increasing value to
      Chesapeake, the company believes it is now the second largest
      leasehold owner.  Chesapeake is currently producing approximately
      30 mmcfe per day from the Deep Haley area and is currently utilizing
      four rigs (up to eight by year-end) to further develop its 225,000 net
      acres of leasehold.  Chesapeake's proved undeveloped reserves in Deep
      Haley are an estimated 59 bcfe and its risked unproved reserves are an
      estimated 650 bcfe after applying an 80% risk factor and assuming an
      additional 140 net wells are drilled in the years ahead.  The
      company's expected economics for vertical Deep Haley wells are
      $10.5 million to develop 7.0 bcfe on 320 acre spacing.

   *  Delaware Basin Shales (Primarily Barnett and Woodford formations in
      West Texas):  Chesapeake's most significant land acquisition
      activities during the 2006 second quarter took place in the Delaware
      Basin Barnett and Woodford Shale play in far West Texas.  In this
      promising play, Chesapeake believes it has become the second largest
      leasehold owner (and the largest in what it believes is the most
      prospective area of the play).  Chesapeake is currently producing
      approximately 1.0 mmcfe per day from the Delaware Basin Barnett and
      Woodford Shales and is currently utilizing two rigs (up to four by
      year-end) to further develop its 385,000 net acres of leasehold.
      Chesapeake has not yet booked any proved reserves in the Delaware
      Basin shales plays and its risked unproved reserves are an estimated
      600 bcfe after applying a 90% risk factor and assuming an additional
      240 net wells are drilled in the years ahead.  The company's expected
      economics for Delaware Basin vertical Barnett and Woodford Shale wells
      are $4.5 million to develop 3.0 bcfe on 160 acre spacing.

   *  Caney and Woodford Shales (Oklahoma Arkoma Basin):  Chesapeake
      believes it is now the third largest leasehold owner in the Caney and
      Woodford Shale play, one of the most promising unconventional gas
      plays in the Oklahoma portion of the Arkoma Basin.  The company is
      currently producing approximately 7.0 mmcfe per day from the Caney and
      Woodford Shales and is currently utilizing one rig to drill its first
      operated horizontal Woodford Shale well on its 100,000 net acres of
      leasehold.  Chesapeake's proved undeveloped reserves in the play are
      an estimated 10 bcfe and its risked unproved reserves are an estimated
      300 bcfe after applying a 70% risk factor and assuming an additional
      170 net wells are drilled in the years ahead.  The company's expected
      economics for horizontal Woodford Shale wells are $4.0 million to
      develop 2.2 bcfe on 160 acre spacing.

   *  Deep Bossier (East Texas and Northern Louisiana):  Chesapeake believes
      it has become one of the top three leasehold owners in the emerging
      Deep Bossier play.  The company is currently producing approximately
      1.0 mmcfe per day in the Deep Bossier play and is currently utilizing
      one rig (one or two by year-end) to further develop its 190,000 net
      acres of leasehold.  Chesapeake's proved undeveloped reserves in the
      Deep Bossier play are an estimated 6.0 bcfe and its risked unproved
      reserves are an estimated 200 bcfe after applying a 90% risk factor
      and assuming an additional 60 net wells are drilled in the years
      ahead.  The company's expected economics for Deep Bossier wells are
      $10.0 million to develop 5.0 bcfe on 320 acre spacing.

Appalachian Basin Gas Resource Plays - In this core area of the company's operations, play types range from conventional to unconventional to emerging gas resource in various Devonian Shale and other formations. Chesapeake is the largest leasehold owner in the region with 3.4 million net acres that were primarily acquired from CNR in November 2005. The company is currently producing approximately 120 mmcfe per day and is currently utilizing nine rigs (up to 11 rigs by year-end) to further develop its extensive leasehold position. In Appalachia, Chesapeake has an estimated 468 bcfe of proved undeveloped reserves and its risked unproved reserves are an estimated 1.8 tcfe after applying a 35% risk factor and assuming an additional 9,100 net wells are drilled in the years ahead. The company's expected economics for vertical Devonian Shale wells are $0.425 million to develop 0.3 bcfe on 160 acre spacing.

In addition, Chesapeake continues to actively develop various conventional, unconventional and emerging unconventional plays not described above. These areas are located throughout the company's operations and in which the company continues to actively generate new prospects and acquire additional leasehold.

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 second quarter. The company delivered top-tier organic production growth and impressive profit margins as strong oil and natural gas price realizations far exceeded modest cost inflation. We have also opportunistically hedged service costs and a substantial portion of our anticipated production through 2008 at exceptional prices in order to ensure strong profitability. This position differentiates Chesapeake among many companies in the industry that may face margin compression as natural gas markets digest short-term excess natural gas supplies caused in large part by limited storage capacity and exceptionally warm weather last winter.

"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 to accelerate development of our substantial unproved reserve base. We currently have 101 operated rigs working, up from an average of 73 operated rigs in 2005, and we anticipate increasing our drilling activity to approximately 135 operated rigs by year-end 2006. This increase in drilling activity creates the potential for increased proved reserves and production levels in 2006 and 2007.

"Our business strategy continues to feature 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 mitigating financial and operational risks through hedging. 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 to discuss this release has been scheduled for Friday morning, July 28, 2006 at 9:00 a.m. EDT. The telephone number to access the conference call is 913-981-5543 and the confirmation code is 4119635. 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 for audio playback from noon EDT, July 28, 2006 through midnight EDT on August 10, 2006. The number to access the conference call replay is 719-457-0820 and the passcode for the replay is 4119635. The conference call will also be webcast live on the Internet and can be accessed by going to Chesapeake's website at http://www.chkenergy.com/ and selecting the "News & Events" 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 the Prospectus dated June 27, 2006 for our offering of 7.625% Senior Notes due 2013 filed with the Securities and Exchange Commission on June 29, 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. Our production forecasts exclude provisions for possible production curtailments that the industry and Chesapeake may experience as a result of high pipeline pressures and/or early filling of U.S. natural gas storage facilities. 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/ .

FIRST ADD -- TABLES -- TO FOLLOW

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