Chesapeake Energy 1998 Annual Report Download - page 50

1996. The gross profit margin derived from these operations is a function of drilling activities in the period, costs of
materials and supplies and the mix of operations between lower margin trucking operations versus higher margin
labor oriented service operations.
Production Expenses and Taxes. Production expenses and taxes, which include lifting costs, production taxes
and excise taxes, increased to $15.1 million in fiscal 1997, compared to $8.3 million in fiscal 1996. This increase
was primarily the result of increased production. On a unit production basis, production expenses and taxes
increased to $0.19 per Mcfe, compared to $0.14 per Mcfe in fiscal 1996. During fiscal 1996, a high proportion of
the Company's production was from the Giddings Field, much of which qualified for Texas severance tax
exemptions.
Impairment of Oil and Gas Properties. Prior to January 1997, the Company had completed operations on one
exploratory well in each of three separate areas outside Masters Creek in the Louisiana Trend. Between April 1997
and July 1997, the Company completed operations on 10 Company operated exploratory wells located outside
Masters Creek in the Louisiana Trend that resulted in the addition of only 0.5 Bcfe of proved reserves. Cumulative
well costs on these non-Masters Creek properties were approximately $43 million as of June 30, 1997. Of the 10
wells, one was completed on April 15, 1997, one on May 3, 1997 and eight after June 1, 1997. Based upon this
information and similar data which had become available from outside operated properties in these non-Masters
Creek areas of the Louisiana Trend, management determined that a significant portion of its leasehold in the
Louisiana Trend outside of Masters Creek was impaired. During the quarters ended March 31, 1997 and June 30,
1997, the Company transferred $7 6 million and $86 3 million, respectively, of non-Masters Creek Louisiana Trend
leasehold costs to the amortization base of the full-cost pool.
The weighted average oil and gas prices used to value the Company's proved reserves declined from $20.90 per
Bbl and $2.41 per Mcf at June 30, 1996 to $18.38 per Bbl and $2.12 per Mcf at June 30, 1997. Drilling and
equipment costs escalated rapidly in the fourth quarter of fiscal 1997 due primarily to higher day rates for drilling
rigs, thus increasing the estimated future capital expenditures to be incurred to develop the Company's proved
undeveloped reserves. The oil and gas price declines and the increased costs to drill and equip wells caused the
Company to eliminate 35 gross proved undeveloped locations in the Knox Field which contained an estimated 45
net Bcfe of proved undeveloped reserves. Similar factors, combined with unfavorable drilling and production
results, eliminated approximately 93 Bcfe of proved reserves in the Giddings and Louisiana Trend areas.
In the Independence area of the Giddings Field of Texas, a single well completed in late March 1997, which the
Company had estimated to contain 15.7 Bcfe of Company reserves at March 31, 1997, was significantly and
adversely affected by another operator's offset well which damaged the reservoir and reduced the Company's
estimated ultimate recovery to 8.0 Bcfe of reserves.
In late June 1997, management reviewed its March 31, 1997 internal estimates of proved reserves and related
present value and, after giving effect to the fourth quarter 1997 drilling and production results, oil and gas prices,
higher drilling and completion costs, and additional leasehold acquisition costs and delay rentals, determined that
the Company had less reserve potential than had previously been estimated. As a result, management estimated that
at June 30, 1997 the Company would have capitalized costs of oil and gas properties which would exceed its full-
cost ceiling by approximately $150 million to $200 million On June 27, 1997, the Company issued a press release
which included this estimate. Subsequently, based on the Company's fmal year-end estimates of its proved reserves
and related estimated future net revenues, which took into account additional drilling and production results,
management determined that as of June 30, 1997, its capitalized costs exceeded its full-cost ceiling by
approximately $236 million No such writedown was experienced by the Company in fiscal 1996.
Oil and Gas Depreciation, Depletion and Amortization. DD&A of oil and gas properties for fiscal 1997 was
$103.3 million, $52.4 million higher than fiscal 1996's expense of $50.9 million The expense in fiscal 1997
excluded the effects of the asset writedown. The average DD&A rate per Mcfe, which is a function of capitalized
costs, future development costs, and the related underlying reserves in the periods presented, increased to $1.31 in
fiscal 1997 compared to $0.85 in fiscal 1996.
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