Chesapeake Energy 2000 Annual Report Download - page 84

During 1999, Chesapeake acquired approximately 101 bcfe of proved reserves through purchases of oil and gas
properties for consideration of $52 million. We also sold 59 bcfe of proved reserves for consideration of
approximately $46 million. During 1999, we recorded upward revisions of 80 bcfe to the December 31, 1998
estimates of our U.S. reserves, and downward revisions of 99 bcfe to the December 31, 1998 estimates of our
Canadian reserves, for a total revision of 19 bcfe, or approximately 1.7%. The upward revisions to our U.S. reserves
were caused by higher oil and gas prices at December 31, 1999, and actual performance in excess of predicted
performance. Higher prices extend the economic lives of the underlying oil and gas properties and thereby increase
the estimated future reserves. The downward revisions to our Canadian reserves were caused by a reduction of our
proved undeveloped locations and an increase in projected transportation and operating costs in Canada, which
decreased the economic lives of the underlying properties.
During 2000, Chesapeake acquired 107.9 bcfe of proved reserves for consideration of $75.3 million. Also during
2000, we recorded downward revisions to our U.S. oil reserves of 3.2 million barrels and upward revisions to our U.S.
natural gas reserves of 25.7 bcf. The downward revisions to our U.S. oil reserves were related to lower estimates
primarily in the Knox, Permian and Williston areas. The upward revisions to our U.S. gas reserves were due
primarily to additional reserves added as a result of the signfficant increase in natural gas prices as of December 31,
2000, which had the effect of extending the economic life of our properties. These upward revisions were partially
offset by the elimination of proved undeveloped locations primarily in the Knox, Independence and Sahara fields, as
well as lower estimates in various areas located primarily in the Mid-Continent area. During 2000, we also had
negative revisions to our Canadian gas reserves of 28.0 bcf. This decrease was primarily due to the increase in crown
royalties resulting from higher natural gas prices at December 31, 2000, as well as lower estimates on various
properties in the Helmet field.
Standardized Measure of Discounted Future Net Cash Flows (unaudited)
Statement of Financial Accounting Standards No. 69 prescribes guidelines for computing a standardized
measure of future net cash flows and changes therein relating to estimated proved reserves. Chesapeake has followed
these guidelines which are briefly discussed below.
Future cash inflows and future production and development costs are determined by applying year-end prices
and costs to the estimated quantities of oil and gas to be produced. Estimates are made of quantities of proved
reserves and the future periods during which they are expected to be produced based on year-end economic
conditions. Estimated future income taxes are computed using current statutory income tax rates including
consideration for the current tax basis of the properties and related carryforwards, giving effect to permanent
differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a
10% annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting
Standards Board and, as such, do not necessarily reflect our expectations of actual revenue to be derived from those
reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed
previously, are equally applicable to the standardized measure computations since these estimates are the basis for
the valuation process.
The following summary sets forth our future net cash flows relating to proved oil and gas reserves based on the
standardized measure prescribed in SFAS 69:
December 31, 1998
-73-
U.S. Canada Combined
($ in thousands)
Future cash inflows(a)
Future production costs $ 1,374,280
(432,876) $ 474,143
(52,493) $ 1,848,423
(485,369)
Future development costs (124,717) (29,634) (154,351)
Future income tax provision (6,464) (143,747) (150,211)
Net future cash flows 810,223 248,269 1,058,492
Less effect of a 10% discount factor (303,096) (132,281) (435,377)
Standardized measure of discounted future net cash flows $507,127 $115,988 $623,115
Discounted (at 10%) future net cash flows before income taxes $504,148 $156,843 $660,991