Chesapeake Energy 2013 Annual Report Download - page 66

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method since we generally reflect a higher level of capitalized costs as well as a higher natural gas and oil depreciation,
depletion and amortization rate, and we do not have exploration expenses that successful efforts companies frequently
have.
Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on
proved natural gas and oil reserves. If we maintain the same level of production year over year, the depreciation,
depletion and amortization expense may be significantly different if our estimate of remaining reserves or future
development costs changes significantly. Proceeds from the sale of properties are accounted for as reductions of
capitalized costs unless such sales involve a significant change in proved reserves and significantly alter the relationship
between costs and proved reserves, in which case a gain or loss is recognized. 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 producing area where individual property
costs are not significant.
We review the carrying value of our natural gas and oil properties under the SEC's full cost accounting rules on
a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, 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 (adjusted for natural gas and oil cash flow hedges) less estimated future
expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In
calculating estimated future net revenues, current prices are calculated as the unweighted arithmetic average of natural
gas and oil prices on the first day of each month within the 12-month period prior to the ending date of the quarterly
period. Costs used are those as of the end of the applicable quarterly period. Such prices are utilized except where
different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including
the effects of derivatives designated as cash flow hedges.
Two primary factors impacting this test are reserve levels and natural gas and oil prices, and their associated
impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves
and/or an increase or decrease in prices can have a material impact on the present value of estimated future net
revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. See
Natural Gas and Oil Properties in Note 1 of the notes to our consolidated financial statements included in Item 8 of
this report for further information on the full cost method of accounting.
Derivatives. Chesapeake uses commodity price and financial risk management instruments to mitigate a portion
of our exposure to price fluctuations in natural gas and oil prices, changes in interest rates and foreign exchange rates.
Gains and losses on derivative contracts are reported as a component of the related transaction. Results of commodity
derivative contracts are reflected in natural gas, oil and NGL sales, and results of interest rate and foreign exchange
rate derivative contracts are reflected in interest expense. The changes in the fair value of derivative instruments not
qualifying, or not elected, for designation as either cash flow or fair value hedges that occur prior to maturity are reported
currently in the consolidated statement of operations as unrealized gains (losses) within natural gas, oil and NGL sales
or interest expense. Cash settlements of our derivative arrangements are generally classified as operating cash flows
unless the derivative is deemed to contain, for accounting purposes, a significant financing element at contract inception,
in which case these cash settlements are classified as financing cash flows in the accompanying consolidated
statements of cash flows.
Accounting guidance for derivative instruments and hedging activities establishes accounting and reporting
standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts)
be recorded at fair value and included in the consolidated balance sheets as assets or liabilities. The accounting for
changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting
designation, which is established at the inception of a derivative. For derivative instruments designated as natural gas,
oil and NGL cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other
comprehensive income until the hedged item is recognized in earnings as natural gas, oil and NGL sales. Any change
in the fair value resulting from ineffectiveness is recognized immediately in natural gas, oil and NGL sales. For interest
rate derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes
in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings as
interest expense. Differences between the changes in the fair values of the hedged item and the derivative instrument,
if any, represent gains or losses on ineffectiveness and are reflected currently in interest expense. Hedge effectiveness
is measured at least quarterly based on the relative changes in fair value between the derivative contract and the
hedged item over time. Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges