After discovering this computational error, the ceiling tests for all quarters since 1997 were recomputed and it was determined that no write-down of our oil and gas assets was necessary in any of the years from 1997 to 2003. However, based upon the oil and natural gas prices in effect on March 31, 2003 and September 30, 2003, the unamortized cost of oil and natural gas properties exceeded the cost center ceiling. As permitted by full cost accounting rules, improvements in pricing and/or the addition of proved reserves subsequent to those dates sufficiently increased the present value of our oil and natural gas assets and removed the necessity to record a write-down in these periods. Using the prices in effect and estimated proved reserves existing on March 31, 2003 and September 30, 2003, the after-tax write-down would have been approximately $1.0 million, and $6.3 million, respectively, had we not taken into account these subsequent improvements. These improvements at September 30, 2003 included estimated proved reserves attributable to our Shady Side #1 well, which we have since sold in February 2005. Because of the volatility of oil and gas prices, no assurance can be given that we will not experience a write-down in future periods.

In connection with our year-end 2004 ceiling test computation, a price sensitivity study also indicated that a 20 percent increase in commodity prices at December 31, 2004 would have increased the pre-tax present value of future net revenues ("NPV") by approximately $56.5 million. Conversely, a 20 percent decrease in commodity prices at December 31, 2004 would have reduced our NPV by approximately $56.5 million. This would have caused our unamortized cost of proved oil and gas properties to exceed the cost pool ceiling, resulting in an after-tax write-down of approximately $2.7 million. The aforementioned price sensitivity and NPV is as of December 31, 2004 and, accordingly, does not include any potential changes in reserves due to first quarter 2005 performance, such as commodity prices, reserve revisions and drilling results.

The Full Cost Ceiling cushion at the end of 2004 of approximately $32.5 million was based upon average realized oil and natural gas prices of $41.18 per Bbl and $5.68 per Mcf, respectively, or a volume weighted average price of $37.63 per BOE. This cushion, however, would have been zero on such date at an estimated volume weighted average price of $31.50 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.

We have a significant amount of proved undeveloped reserves, which are primarily oil reserves. We had 44.9 Bcfe and 72.5 Bcfe of proved undeveloped reserves, representing 64% and 66% of our total proved reserves at December 31, 2003 and 2004, respectively. As of December 31, 2003 and 2004, a portion of these proved undeveloped reserves, or approximately 43.9 Bcfe and 45.7, 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 of our Camp Hill properties is considerably longer, or approximately 15 years, when compared to the depletable life of our remaining oil and natural gas properties of approximately 2.25 years. Accordingly, the combination of a relatively low ratio of future development costs and a relatively long depletable life on our Camp Hill properties has resulted in a relatively low overall historical depletion rate and DD&A expense. This has resulted in a capitalized cost basis associated with producing properties being depleted over a longer period than the associated production and revenue stream. It has also resulted in the build-up of nondepleted capitalized costs associated with properties that have been completely depleted. We expect our relatively low historical depletion rate to continue until the high level of nonproducing reserves to total proved reserves is reduced and the life of our proved developed reserves is extended through development drilling and/or the significant addition of new proved producing reserves through acquisition or exploration. If our level of total proved reserves, finding cost and current prices were all to remain constant, this continued build-up of capitalized costs increases the probability of a ceiling test write-down.

We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years.

Oil and Natural Gas Reserve Estimates

The reserve data included in this document are estimates prepared by Ryder Scott Company, DeGolyer and MacNaughton, and Fairchild & Wells, Inc., Independent Petroleum Engineers. Reserve engineering is a subjective process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact manner. The process relies on judgment and the interpretation of

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