Chesapeake Energy (CHK)

Oil and Gas Properties

Chesapeake follows the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities (see Note 11). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and gas reserves. As of December 31, 2005, approximately 78% of our proved reserves were evaluated by independent petroleum engineers, with the balance evaluated by our internal reservoir engineers. In addition, our internal engineers evaluate all properties on an annual basis. The average composite rates used for depreciation, depletion and amortization were $1.91 per equivalent mcfe in 2005, $1.61 per equivalent mcfe in 2004, and $1.38 per equivalent mcfe in 2003.

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Table of Contents

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in the relationship between costs and the value of proved reserves or the underlying value of unproved properties, in which case a gain or loss is recognized. No income is recognized in connection with contractual services provided by Chesapeake to other interest owners on properties in which we hold an economic interest.

The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unevaluated properties are grouped by major prospect area where individual property costs are not significant and are assessed individually when individual costs are significant.

We review the carrying value of our oil and gas properties under the full-cost accounting rules of the Securities and Exchange Commission on a quarterly basis. Under these rules, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects.

We account for seismic costs in accordance with Rule 4-10 of Regulation S-X. Specifically, rule 4-10 requires that all companies that use the full cost method capitalize exploration costs as part of their oil and gas properties (i.e., full cost pool). Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geographical and geophysical studies and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Such costs are capitalized as incurred.

Seismic costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization computation until it is determined whether or not proved reserves can be assigned to the properties. The company reviews its unproved properties and associated seismic costs quarterly in order to ascertain whether impairment has incurred. To the extent that seismic costs cannot be directly associated with specific unevaluated properties, they are included in the amortization base as incurred.

Oil and Gas Properties

The accounting for oil and gas producing activities requires the Company’s management to choose between generally acceptable accounting alternatives and to make judgments about estimates of future uncertainties.

The Company uses the “successful efforts” method of accounting for oil and gas production activities as opposed to the alternate acceptable “full cost” method. Under the successful efforts method, the cost of productive wells, including mineral interests, wells and related equipment, interest during construction, and development dry holes are capitalized. Nonproductive exploration cost, which include certain geological and geophysical costs, exploratory dry holes, delay rentals, and other property carrying costs are charged to expense.

Capitalized oil and gas properties are depleted on the unit-of-production method. Depletion expense on evaluated properties is calculated on a field-by-field basis, based upon production multiplied by the depletion rate per unit that is derived by allocating the lease, well equipment, and intangible drilling costs capitalized, as well as the future abandonment costs, net of salvage, in that field over the number of units expected to be extracted over the life of the proved developed reserves. Unevaluated costs are excluded from the depletion calculation. As of December 31, 2004 and 2003, accumulated depletion associated with these assets totaled $46.3 million and $12.8 million respectively.

The majority of the Company’s oil and gas properties are classified as proved properties. Proved properties including developed and undeveloped costs associated with probable reserves are assessed for impairment using estimated future cash flows. Estimating future cash flows involves the use of complex judgments such as the estimation of proved and probable gas reserve

11

Columbia Energy Resources, LLC (a wholly owned

subsidiary of Triana Energy Holdings, LLC)

Notes to Consolidated Financial Statements (continued)

2. Critical Accounting Policies and Estimates (continued)

quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. Information relating to the Company’s estimates of natural gas and oil reserves and future net cash flows is provided in Note 13 (unaudited) of the consolidated financial statements. The Company’s proved reserve information is based on estimates prepared by independent petroleum engineers. Estimates prepared by others may be higher or lower than these estimates. The carrying values of the Company’s proved gas properties are reviewed on a field-by-field basis for indications of impairment on an annual basis, or whenever events or circumstances indicate that the remaining carrying values may not be recoverable. Proved gas properties that have carrying amounts in excess of estimated undiscounted future cash flows are deemed impaired. Those properties are then written down to fair value. For the periods ended December 31, 2004 and 2003, the Company incurred no impairment charges on gas properties. The costs of unproved gas properties (mineral interests) are periodically assessed on a field-by-field basis. If unproved properties are determined to be productive, the related costs are transferred to proved gas properties. If unproved properties are determined not to be productive or if the value has been otherwise impaired, the excess of carrying value over the estimated fair value is charged to expense. Unproved properties are impaired at 10.5% annually. The unimpaired balance of leases surrendered is charged to expense.

On the sale or retirement of a complete unit (group of properties in a geographical area) of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized in income.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.