Chesapeake Energy (CHK)

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

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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.

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