Chesapeake Energy 2012 Annual Report Download - page 103

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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Natural Gas and Oil Properties
Chesapeake follows the full cost method of accounting under which all costs associated with natural gas and oil
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 10). Capitalized costs are amortized on a
composite unit-of-production method based on proved natural gas and oil reserves. Estimates of our proved reserves
as of December 31, 2012 were prepared by both third-party engineering firms and Chesapeake's internal staff.
Approximately 89% of these proved reserves estimates (by volume) as of December 31, 2012 were prepared by
independent engineering firms. In addition, our internal engineers review and update our reserves on a quarterly basis.
The average composite rates used for depreciation, depletion and amortization of natural gas and oil properties were
$1.76 per mcfe in 2012, $1.37 per mcfe in 2011 and $1.35 per mcfe in 2010.
Proceeds from the sale of natural gas and oil 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
prospect area where individual property costs are not significant. In addition, we analyze our unevaluated leasehold
and transfer to evaluated properties leasehold that can be associated with reserves, leasehold that expired in the
quarter or leasehold that is not a part of our development strategy and will be abandoned. As our strategic focus is
shifting from a natural gas asset base to a more balanced natural gas and liquids asset base, and as our budgeted
capital expenditures were being reduced in 2012, we identified undeveloped leasehold having a cost of $1.684 billion
that would not be a part of our development strategy going forward. The acreage was primarily located in the Williston
and DJ Basins, as well as other non-core leasehold located throughout our operating areas.
The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31,
2012 and notes the year in which the associated costs were incurred.
Year of Acquisition
2012 2011 2010 Prior Total
($ in millions)
Leasehold acquisition cost .......................... $ 1,826 $ 2,732 $ 3,519 $ 3,325 $ 11,402
Exploration cost ........................................... 1,213 176 42 — 1,431
Capitalized interest ...................................... 810 424 312 376 1,922
Total ...................................................... $ 3,849 $ 3,332 $ 3,873 $ 3,701 $ 14,755
We also review, on a quarterly basis, the carrying value of our natural gas and oil properties under the full cost
accounting rules of the SEC. 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 2012, capitalized costs of natural gas and oil properties exceeded the estimated present value calculation of future
net revenues from our proved reserves, net of related income tax considerations, resulting in an impairment in the
carrying value of natural gas and oil properties in the 2012 third quarter of $3.315 billion. For the ceiling test calculation,
costs used are those as of the end of the appropriate quarterly period. 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. 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. Cash flow hedges locked in prior to September 30, 2012
relating to future production periods increased the 2012 third quarter ceiling test impairment by $279 million. As of
December 31, 2012, none of our open derivative instruments were designated as cash flow hedges. Our natural gas
and oil hedging activities are discussed in Note 9 of these consolidated financial statements. See Risks and Uncertainties
above for a discussion of the reduction in our estimated proved reserves in 2012 and factors that could impact a future
ceiling test impairment.