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

(1)There are no earned interests in 1995 or in 1994. Earned interests amounts included in 1993 are $3,308,623.

(2)Lease acquisitions for 1995, 1994, and 1993 include expenditures of $2,814,395, $2,973,971, and $1,032,656, respectively, relating to the Company's initiatives in Russia; 1995, 1994, and 1993 expenditures of $304,610, $356,136, and $456,681, respectively, relating to initiatives in Venezuela; and include 1995 expenditures of $202,206 relating to initiatives in New Zealand.

(3)These 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 1995, 1994, and 1993, respectively, were $3,895,871, $3,032,315, $4,198,429.

(4) Includes capitalized general and administrative costs directly associated with the acquisition, development, and exploration efforts of approximately $7,100,000, $5,800,000, and $8,300,000 in 1995, 1994, and 1993. In addition, total includes $1,442,022, $766,572, and $389,352 in 1995, 1994, and 1993, respectively, of capitalized interest on unproved properties.

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

Property Purchase and Production Payment Agreement. In May 1992, the Company purchased from a subsidiary of Manville Corporation ("Manville") additional interests in certain wells in McMullen County, Texas, in which the Company had owned interests for over three years. The funds for this purchase were provided by the Company's sale of a volumetric production payment in the Manville properties to Enron Reserve Acquisition Corp. ("Enron") for net proceeds of $13,790,000. These proceeds were recorded as deferred revenues and are amortized as the required deliveries are made. Under the production payment agreement, the Company continues to own the properties purchased from Manville, but is required to deliver to Enron approximately 9.5 Bcf over an eight-year period, or for such longer period as is necessary to deliver a specified heating equivalent quantity at an average price of $1.115 per MMBtu. The Company is responsible for all production related costs associated with operating these properties. The amount to be delivered varies from month to month in generally decreasing quantities. To the extent monthly gas production from the properties exceeds the agreed upon deliverable quantities (as it has in every year since the purchase date), the Company receives all proceeds from sale of such excess gas at current market prices, plus the proceeds from sale of oil or condensate. Since entering into the volumetric production payment, the Company has met all scheduled deliveries to Enron under this agreement.

Foreign Activities. On September 3, 1993, the Company signed a Participation Agreement with Senega, a Russian Federation joint stock company (in which the Company has an indirect interest of less than 1%), to assist in the development and production of reserves from two fields in Western Siberia. Under the terms of the Participation Agreement, the Company will receive a minimum 5% net profits interest from the sale of hydrocarbon products from the fields for providing managerial, technical and financial support to Senega. Additionally, the Company purchased a 1% net profits interest from Senega for $300,000. In May 1995, the Company executed a Management Agreement with Senega. In return for obtaining financing for development of these fields, Swift was given certain rights by Senega, including a 49% interest in production income derived by Senega from this project after repayment of costs. At December 31, 1995, the Company's investment in Russia was approximately $6,820,000 and is included in the unproved properties portion of oil and gas properties.

The Company formed a wholly owned subsidiary, Swift Energy de Venezuela, C.A., for the purpose of submitting a bid on August 5, 1993, under the Venezuelan Marginal Oil Field Reactivation Program on the Quiriquire Unit located in Northeastern Venezuela. Swift (together with a minority interest holder) was one of six bidders on the Quiriquire Unit. The Company did not win the bid for the Quiriquire Unit; however, other fields and opportunities are continuing to be evaluated in Venezuela. At December 31, 1995, the Company's investment in Venezuela was approximately $1,120,000 and is included in the unproved properties portion of oil and gas properties net of impairments of $45,668.

On October 12, 1995, the Company was approved for the grant of Petroleum Exploration Permit by the New Zealand Minister of Energy and the acceptance of which was approved by the Company's board of directors on November 7, 1995. This permit (PEP 38717) covers approximately 65,000 acres in the Onshore Taranaki Basin region. This permit primarily requires the Company to: (a) post a $175,000 bond (which was done by the Company on December 22, 1995) before January 11, 1996; (b) before December 31, 1997, analyze and interpret approximately 460 kilometers of existing seismic data and acquire approximately 100 kilometers of new seismic data; (c) commence drilling one well prior to July 31, 1998; (d) review results prior to July 31, 1999, and (e) prior to July 31, 2000, drill a development well or acquire additional seismic data. At December 31, 1995, the Company's investment in New Zealand was approximately $200,000 and is included in the unproved properties portion of oil and gas properties.

Acquisition of Properties by Swift. During the second quarter of 1994, the Company acquired approximately $18,100,000 of producing oil and gas properties in a single acquisition transaction. Approximately $3,500,000 and $12,700,000 of the properties were transferred to affiliated partnerships formed under the Company's SDI offering in 1995 and 1994, respectively. Approximately $1,900,000 of the properties were retained by the Company for its own account.

Supplemental Reserve Information (Unaudited). 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 company personnel and audited by H. J. Gruy and Associates, Inc. ("Gruy"), independent petroleum consultants. Gruy's summary report dated February 19, 1996, is set forth as an exhibit to the Form 10-K Report for the year ended December 31, 1995, 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:

(1) Proved reserves for these periods exclude quantitites subject to the Company's volumetric production payment agreement.

(2)Revisions of previous quantity 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, 1995, were based upon $2.41 per Mcf of natural gas and $18.07 per barrel of oil, compared to $1.85 per Mcf and $15.09 per barrel as of December 31, 1994.

(3) Natural gas production for 1993, 1994, and 1995 excludes 1,581,206, 1,358,375, and 1,211,255 Mcf, respectively, delivered under the Company's volumetric production payment agreement.

Standardized Measure of Discounted Future Net Cash Flows (Unaudited). 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 carryforwards.

The estimates of cash flows and reserves quantities shown above are based on year-end oil and gas prices. Under Securities and Exchange Commission rules, companies that follow the full-cost accounting method are required to make quarterly Ceiling Limitation 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:

This page was last updated on Saturday, February 08, 2003 , at 07:46:26 PM .

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