This excerpt taken from the CHK 8-K filed May 2, 2006.
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, Chesapeakes 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 companys 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, Chesapeakes 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 companys 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, Chesapeakes 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 companys 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.
Chesapeakes 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.