Chesapeake Energy 2010 Annual Report Download - page 100

costs, and the related underlying reserves in the periods presented, was $1.35, $1.51 and $2.34 in 2010, 2009
and 2008, respectively. The decrease in the average rate from $2.34 in 2008 to $1.35 in 2010 is due primarily
to reductions of our natural gas and oil full-cost pool resulting from our divestitures in 2008, 2009 and 2010,
impairments of our full-cost pool in 2008 and 2009 as well as the addition of reserves through our drilling
activities.
Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $220
million in 2010, compared to $244 million in 2009 and $174 million in 2008. The average DD&A rate per mcfe
was $0.21, $0.27 and $0.21 in 2010, 2009 and 2008, respectively. The decrease from 2009 to 2010 was
primarily due to certain of our midstream assets that were contributed to our midstream joint venture on
September 30, 2009 and subsequently deconsolidated on January 1, 2010, offset by additional depreciation
expense associated with the assets acquired over the past year. Property and equipment costs are depreciated
on a straight-line basis. Buildings are depreciated over 10 to 39 years, gathering facilities are depreciated over
20 years, drilling rigs are depreciated over 15 years and all other property and equipment are depreciated over
the estimated useful lives of the assets, which range from two to twenty years. To the extent company-owned
drilling rigs are used to drill our wells, a substantial portion of the depreciation is capitalized in natural gas and
oil properties as exploration or development costs.
Impairment of Natural Gas and Oil Properties. Due to lower commodity prices in the second half of 2008
and throughout 2009, we reported a non-cash impairment charge on our natural gas and oil properties of $11.0
billion in 2009 and $2.8 billion in 2008. We account for our natural gas and oil properties using the full-cost
method of accounting, which limits the amount of costs we can capitalize and requires us to write off these
costs if the carrying value of natural gas and oil assets in the evaluated portion of our full-cost pool exceeds the
sum of the present value of expected future net cash flows of proved reserves using a 10% pre-tax discount
rate based on pricing and cost assumptions prescribed by the SEC and the present value of certain natural gas
and oil hedges.
(Gains) Losses on Sales of Other Property and Equipment. In 2010, we recorded a ($137) million gain
associated with sales of other property and equipment which consisted of a ($157) million gain on the sale of
our Springridge gas gathering system to our affiliate, CHKM, and a net $20 million loss related to various sales
of other property and equipment, including the sale of pipe, gas gathering systems and other miscellaneous
assets. In 2009, we recorded a $38 million loss on the sale of two gathering systems. There were nominal
amounts of gains and losses on the sales of other property and equipment in 2008.
Other Impairments. In 2010, we recorded a $21 million impairment to natural gas gathering systems
primarily related to the obsolescence of certain pipe inventory. In 2009, we recorded a $130 million impairment
of other property and equipment and other assets. An $86 million impairment was associated with certain of
our midstream assets contributed to our midstream joint venture in September 2009, as well as a $4 million
impairment of debt issuance costs associated with the portion of our $460 million midstream revolving bank
credit facility that was reduced to $250 million as a result of the joint venture. Also in 2009, we recognized a
$27 million charge associated with certain of our service operations assets and $13 million of bad debt
expense related to potentially uncollectible receivables. In 2008, we recorded a $30 million impairment
associated with certain of our midstream assets.
Restructuring Costs. In 2009, we recorded $34 million of restructuring and relocation costs in our Eastern
Division and certain other workforce reduction costs. We reorganized our Charleston, West Virginia-based
Eastern Division from a regional corporate headquarters to a regional field office consistent with the business
model we use elsewhere in the country. As a result, we consolidated the management of our Eastern Division
land, legal, accounting, information technology, geoscience and engineering departments into our corporate
offices in Oklahoma City. The costs of the restructuring included termination benefits, consolidating or closing
facilities and relocating employees. The discussion of restructuring costs in Note 13 of our consolidated
financial statements included in Item 8 of this report provides additional detail on the accounting for and
reporting of these costs.
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