Supplemental Information (Unaudited)

Capitalized Costs. The following table presents our aggregate capitalized costs relating to oil and gas producing activities and the related depreciation, depletion, and amortization:

Of the $57,096,694 of domestic unproved property costs (primarily seismic and lease acquisition costs) at December 31, 2001, excluded from the amortizable base, $26,707,313 was incurred in 2001, $9,545,964 was incurred in 2000, $5,640,587 was incurred in 1999, and $15,202,830 was incurred in prior years. When we are in an active drilling mode, we evaluate the majority of these unproved costs within a two to four year time frame. In response to market conditions in 1998, we decreased our 1999 drilling expenditures when compared to prior years, which, when coupled with the $15.3 million of leasehold properties acquired in the Brookeland and Masters Creek areas in 1998, may extend the evaluation time frame of such costs. Consequently, in response to market conditions, we have decreased our 2002 drilling expenditures as well.

Of the $38,846,469 of net New Zealand unproved property costs at December 31, 2001, excluded from the amortizable base, $30,383,713 was incurred in 2001, $5,013,539 was incurred in 2000, $907,972 was incurred in 1999, and $2,541,245 was incurred in prior years. We expect to continue drilling in New Zealand to delineate our prospects there, with seven wells planned for drilling in 2002. We expect to complete our evaluation of current unevaluated costs over the next two to three years. Upon the startup of the Rimu Production Station near the end of the first quarter of 2002, $23.6 million of these unproved property costs will be moved to the proved properties classification and will begin being depreciated.

Costs Incurred. The following table sets forth costs incurred related to our oil and gas operations:

¹These are actual amounts as incurred by year, including both proved and unproved lease costs. The annual lease acquisition amounts added to proved oil and gas properties in 2001, 2000, and 1999 were $13,308,843, $16,791,834, and $14,389,680, respectively.

²Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $11,600,000, $10,300,000, and $8,500,000 in 2001, 2000, and 1999, respectively. In addition, total includes $6,256,222, $5,043,206, and $4,142,098 in 2001, 2000, and 1999, respectively, of capitalized interest on unproved properties.

Results of Operations. New Zealand operations began in 2001 while all our oil and gas operations in 2000 and 1999 were domestic. The following table sets forth results of our oil and gas operations:

Supplemental Reserve Information. The following information presents estimates of our proved oil and gas reserves. Reserves were determined by us and audited by H. J. Gruy and Associates, Inc. ("Gruy"), independent petroleum consultants. Gruy’s summary report dated February 14, 2002, is set forth as an exhibit to the Form 10-K Report for the year ended December 31, 2001, and includes definitions and assumptions that served as the basis for the audit of proved reserves and future net cash flows. Such definitions and assumptions should be referred to in connection with the following information:

¹Proved reserves exclude quantities subject to our volumetric production payment agreement, which expired with the last required delivery of volumes in October 2000.

²Revisions of previous estimates are related to upward or downward variations based on current engineering information for production rates, volumetrics, and reservoir pressure. Additionally, changes in quantity estimates are affected by the increase or decrease in crude oil and natural gas prices at each year-end. Proved reserves, as of December 31, 2001, were based upon prices in effect at year-end. The weighted average of such year-end prices for total, domestic, and New Zealand were $2.51, $2.68, and $1.18 per Mcf of natural gas and $18.45, $18.51, and $18.25 per barrel of oil, respectively. This compares to $9.86, $11.25, and $0.71 per Mcf and $24.62, $25.50, and $22.30 per barrel as of December 31, 2000, for total, domestic, and New Zealand, respectively.

³Natural gas production for 1999 and 2000 excludes 728,235 and 405,130 Mcf, respectively, delivered under our volumetric production payment agreement.

⁴We acquired 62.1 Bcfe and 5.7 Bcfe from the TAWN and Antrim acquisitions, respectively, in New Zealand. These reserves estimates at December 31, 2001, are not included in the above table. The TAWN reserves were all proved developed while the Antrim reserves were 34% proved developed.

Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

1. 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.

2. The estimated future gross revenues of proved reserves are priced on the basis of year-end prices, except in those instances where fixed and determinable gas price escalations are covered by contracts limited to the price we reasonably expect to receive.

3. The future gross revenue streams are reduced by estimated future costs to develop and to produce the proved reserves, as well as certain abandonment costs based on year-end cost estimates and the estimated effect of future income taxes.

4. Future income taxes are computed by applying the statutory tax rate to future net cash flows reduced by the tax basis of the properties, the estimated permanent differences applicable to future oil and gas producing activities, and tax carry forwards.

The estimates of cash flows and reserves quantities shown above are based on year-end oil and gas prices for each period. Subsequent changes to such year-end oil and gas prices could have a significant impact on discounted future net cash flows. Under Securities and Exchange Commission rules, companies that follow the full-cost accounting method are required to make quarterly Ceiling Test calculations, using prices in effect as of the period end date presented (see Note 1 to the Consolidated Financial Statements). Application of these rules during periods of relatively low oil and gas prices, even if of short-term seasonal duration, may result in write-downs.

The standardized measure of discounted future net cash flows is not intended to present the fair market value of our oil and gas property reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment, and the risks inherent in reserves estimates.

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

Quarterly Results. The following table presents summarized quarterly financial information for the years ended December 31, 2000 and 2001: