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significant estimates are based on current assumptions that may be materially
effected by changes to future economic conditions such as the market prices received
for sales of volumes of oil and natural gas, interest rates, the market value
of our common stock and corresponding volatility and our ability to generate future
taxable income. Future changes to these assumptions may affect these significant
estimates materially in the near term. Oil and Natural
Gas Properties We account for investments in natural
gas and oil properties using the full-cost method of accounting. All costs directly
associated with the acquisition, exploration and development of natural gas and
oil properties are capitalized. These costs include lease acquisitions, seismic
surveys, and drilling and completion equipment. We proportionally consolidate
our interests in natural gas and oil properties. We capitalized compensation costs
for employees working directly on exploration activities of $1.4 million, $1.7
million and $2.1 million in 2003, 2004 and 2005 respectively. We expense maintenance
and repairs as they are incurred. We amortize natural
gas and oil properties based on the unit-of-production method using estimates
of proved reserve quantities. We do not amortize investments in unproved properties
until proved reserves associated with the projects can be determined or until
these investments are impaired. We periodically evaluate, on a property-by-property
basis, unevaluated properties for impairment. If the results of an assessment
indicate that the properties are impaired, we add the amount of impairment to
the proved natural gas and oil property costs to be amortized. The amortizable
base includes estimated future development costs and, where significant, dismantlement,
restoration and abandonment costs, net of estimated salvage values. The depletion
rate per Mcfe for 2003, 2004 and 2005 was $1.55, $1.86 and $2.22 respectively.
We account for dispositions of natural gas and oil
properties as adjustments to capitalized costs with no gain or loss recognized,
unless such adjustments would significantly alter the relationship between capitalized
costs and proved reserves. We have not had any transactions that significantly
alter that relationship. The net capitalized costs
of proved oil and natural gas properties are subject to a “ceiling test” which
limits such costs to the estimated present value, discounted at a 10% interest
rate, of future net revenues from proved reserves, based on current economic and
operating conditions (the “Full Cost Ceiling”). If net capitalized costs exceed
this limit, the excess is charged to operations through depreciation, depletion
and amortization. In connection with our year-end 2005
ceiling test computation, a price sensitivity study also indicated that a 20 percent
increase in commodity prices at December 31, 2005 would have increased the pre-tax
present value of future net revenues (“NPV”) by approximately $67.0 million. Conversely,
a 20 percent decrease in commodity prices at December 31, 2005 would have reduced
our NPV by approximately $68.0 million. The aforementioned price sensitivity and
NPV is as of December 31, 2005 and, accordingly, does not include any potential
changes in reserves due to first quarter 2006 performance, such as commodity prices,
reserve revisions and drilling results. The Full Cost
Ceiling cushion at the end of 2005 of approximately $103 million was based upon
average realized oil and natural gas prices of $57.17 per Bbl and $8.04 per Mcf,
respectively, or a volume weighted average price of $50.63 per BOE. This cushion,
however, would have been zero on such date at an estimated volume weighted average
price of $34.25 per BOE. A BOE means one barrel of oil equivalent, determined
using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural
gas liquids, which approximates the relative energy content of oil, condensate
and natural gas liquids as compared to natural gas. Prices have historically been
higher or substantially higher, more often for oil than natural gas on an energy
equivalent basis, although there have been periods in which they have been lower
or substantially lower. Under the full cost method
of accounting, the depletion rate is the current period production as a percentage
of the total proved reserves. Total proved reserves include both proved developed
and proved undeveloped reserves. The depletion rate is applied to the net book
value and estimated future development costs to calculate the depletion expense.
Proved reserves materially impact depletion expense. If the proved reserves decline,
then the depletion rate (the rate at which we record depletion expense) increases,
reducing net income. We have a significant amount of
proved undeveloped reserves, which are primarily oil reserves. We had 44.9 Bcfe,
72.5 Bcfe, and 97.9 Bcfe of proved undeveloped reserves, representing 64%, 66%
and 65% of our total proved reserves at December 31, 2003, 2004 and 2005, respectively.
As of December 31, 2003, 2004 and 2005, a portion of these proved undeveloped
reserves, or approximately, 43.9 Bcfe, 45.7 Bcfe and 38.1 Bcfe, respectively,
are attributable to our Camp Hill properties that we acquired in 1994. See “Business
and Properties - East Texas Area — Camp Hill Project” for further discussion of
the Camp Hill properties. The estimated future development costs to develop our
proved undeveloped reserves on our Camp Hill properties are relatively low, on
a per Mcfe basis, when compared to the estimated future development costs to develop
our proved undeveloped reserves on our other oil and natural gas properties. Furthermore,
the average depletable life (the estimated time that it will take to produce all
recoverable reserves) of our Camp Hill properties is considerably longer, or approximately
15 years, when compared to the | |
