The 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 $3.5 million, $2.1 million and $1.7 million in 2006, 2005 and 2004 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 2006, 2005 and 2004 was $2.61, $2.22 and $1.86 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 limited to a “ceiling test” based on the estimated future reserves, discounted at a 10% per annum, from proved oil and natural gas 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 2006 ceiling test computation, a price sensitivity study also indicated that a 10 percent increase or decrease in commodity prices at December 31, 2006 would have increased or decreased the Full Cost Ceiling test cushion by approximately $40 million. The aforementioned price sensitivity is as of December 31, 2006 and, accordingly, does not include any potential changes in reserves due to first quarter 2007 performance, such as commodity prices, reserve revisions and drilling results.

The Full Cost Ceiling cushion at the end of 2006 of approximately $40.2 million was based upon average realized oil and natural gas prices of $54.73 per Bbl and $5.77 per Mcf, respectively, or a volume weighted average price of $38.75 per BOE. This cushion, however, would have been zero on such date at an estimated volume weighted average price of $34.91 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. We had 126.2 Bcfe, 97.9 Bcfe, and 72.5 Bcfe of proved undeveloped reserves, representing 60%, 65% and 66% of our total proved reserves at December 31, 2006, 2005 and 2004, respectively. As of December 31, 2006, 2005 and 2004, a portion of these proved undeveloped reserves, or approximately, 32.8 Bcfe, 38.1 Bcfe and 45.7 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 depletable life of