MANAGING GROWTH IN A VOLATILE ENVIRONMENT
	1998 ANNUAL REPORT
Supplemental Information (Unaudited) Swift Energy Company and Subsidiaries

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

Of the $51,040,378 of domestic unproved property costs (primarily seismic and lease acquisition costs) at December 31, 1998, excluded from the amortizable base, $33,360,518 was incurred in 1998, $11,966,626 was incurred in 1997, $3,260,112 was incurred in 1996, and $2,953,122 was incurred in prior years. When the Company is in an active drilling mode, it has evaluated the majority of these unproved costs within a two to three year time frame. In response to current market conditions, the Company has decreased its planned 1999 drilling expenditures when compared to recent years, which when coupled with the $15.2 million of leasehold properties acquired in the Toledo Bend Properties acquisition may extend the evaluation timeframe of such costs.

Of the $5,001,508 of net foreign unproved property costs at December 31, 1998, being excluded from the amortizable base, $2,521,761 was incurred in 1998, $1,731,561 was incurred in 1997, $545,980 was incurred in 1996, and $202,206 was incurred in 1995. All of these costs are costs incurred in New Zealand, as the costs incurred in Russia and Venezuela were impaired in the third quarter of 1998 (see Note 1 to the Company’s financial statements). The Company expects it will complete its evaluation of the New Zealand properties as wells are drilled over the next two to three years.

Capital Expenditures. The following table sets forth capital expenditures related to the Company’s oil and gas operations:

¹Lease acquisitions for 1998, 1997, and 1996 include expenditures of: $2,521,761, $1,731,561, and $545,980, respectively, relating to the Company’s initiatives in New Zealand; $421,602, $828,133, and $487,597, respectively, relating to initiatives in Venezuela; and $592,841, $658,145, and $2,712,278, respectively, relating to initiatives in Russia.

²These 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 (being amortized) for 1998, 1997, and 1996, were $13,853,129, $7,384,385, and $9,458,016, respectively.

3Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $12,300,000, $11,700,000, and $7,400,000 in 1998, 1997, and 1996, respectively. In addition, total includes $3,849,665, $2,326,691, and $1,549,575 in 1998, 1997, and 1996, respectively, of capitalized interest on unproved properties.

 

Results of Operations. The following table sets forth results of the Company's oil and gas operations:

Supplemental Reserve Information. The following information presents estimates of the Company’s proved oil and gas reserves, which are all located onshore in the United States. All of the Company’s reserves were determined by the Company and audited by H. J. Gruy and Associates, Inc. ("Gruy"), independent petroleum consultants. Gruy’s summary report dated January 27, 1999, is set forth as an exhibit to the Form 10-K Report for the year ended December 31, 1998, and includes definitions and assumptions that served as the basis for the estimates 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 the Company’s volumetric production payment agreement.

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, 1998, were based upon prices of $2.23 per Mcf of natural gas and $11.23 per barrel of oil, compared to $2.78 per Mcf and $15.76 per barrel as of December 31, 1997.

³Natural gas production for 1996, 1997, and 1998 excludes 1,156,361, 1,015,226, and 866,232 Mcf, respectively, delivered under the Company’s volumetric production payment agreement.

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 the Company reasonably expects 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. 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). 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 the Company’s 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 reserve 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, 1997 and 1998:

1Amounts prior to the fourth quarter of 1997 have been retroactively restated to give recognition to: (a) an equivalent change in capital structure as a result of a 10% stock dividend in October 1997 (see Note 2 to the Company's financial statements); and (b) the adoption of Statement of Financial Accounting Standards No. 128, "Earnings per Share." See Note 2 to the Company’s financial statements.

²The loss in the third quarter of 1998 was the result of a pre-tax write-down of oil and gas properties of $90.8 million ($59.9 million after tax). See Note 1 to the Company’s financial statements.

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