Of the $27,620,462 of net unproved property costs (primarily seismic and lease acquisition cost) at December 31, 1996, being excluded from the amortizable base, $13,678,675 was incurred in 1996, $6,901,011 was incurred in 1995, $4,071,345 was incurred in 1994, and $2,969,431 was incurred in prior years. The Company expects it will complete its evaluation of the properties representing the majority of these costs within 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 1996, 1995, and 1994 include expenditures of $2,712,278, $2,814,395, and $2,973,971, respectively, relating to the Company’s initiatives in Russia; 1996, 1995, and 1994 expenditures of $487,597, $304,610, and $356,136, respectively, relating to initiatives in Venezuela; and 1996 and 1995 expenditures of $545,980 and $202,206, respectively, relating to initiatives in New Zealand.

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 1996, 1995, and 1994, respectively, were $9,458,016, $3,895,871, and $3,032,315.

³Includes capitalized general and administrative costs directly associated with the acquisition, development, and exploration efforts of approximately $7,400,000, $7,100,000, and $5,800,000 in 1996, 1995, and 1994, respectively. In addition, total includes $1,549,575, $1,442,022, and $766,572 in 1996, 1995, and 1994, 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 providing the Company with 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, under which, in return for undertaking to obtain financing for development of these fields, Swift is entitled to receive a 49% interest in production income derived by Senega from this project after repayment of costs.

On July 12, 1996, the Company entered into a partnership agreement which provides for the Company to contribute its rights under the Participation and Management Agreement to the partnership and for the partners to share equally revenues and costs of developing the Samburg Field and funding and management of the license areas, all in conjunction with Senega. The partnership is to be funded by the partners upon fulfillment of certain conditions and completion of certain further arrangements with Senega. It is currently anticipated that these activities would be funded principally through project financing. At December 31, 1996, the Company’s investment in Russia was approximately $9,530,000 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. Although the Company did not win the bids, it continued to pursue cooperative ventures involving other fields and opportunities in Venezuela. Currently, the Company is evaluating a number of Blocks being offered by Petroleos de Venezuela, S.A. under the Third Operating Agreement Round. At December 31, 1996, the Company’s investment in Venezuela was approximately $1,610,000 and is included in the unproved properties portion of oil and gas properties net of impairments of $45,668.

Since October 1995, the Company has been issued two Petroleum Exploration Permits by the New Zealand Minister of Energy. The first permit covers approximately 65,000 acres in the Onshore Taranaki Basin of New Zealand’s North Island, and the second covers approximately 69,300 adjacent acres. Under the terms of these permits, the Company is obligated to analyze and interpret certain seismic data, acquire certain new seismic data, and drill one exploratory well, to be followed by a development well or additional seismic work, all of which is to be performed on a staged basis in order to maintain the permits over periods extending through July 2000 for the first permit and August 1999 for the second permit. At December 31, 1996, the Company’s investment in New Zealand was approximately $750,000 and is included in the unproved properties portion of oil and gas properties.

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 7, 1997, is set forth as an exhibit to the Form 10-K Report for the year ended December 31, 1996, 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 exclude quantities 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, 1996, were based upon prices of $4.47 per Mcf of natural gas and $23.75 per barrel of oil, compared to $2.41 per Mcf and $18.07 per barrel as of December 31, 1995.

(3)Natural gas production for 1994, 1995, and 1996 excludes 1,358,375, 1,211,255, and 1,156,361 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.

Natural gas prices have declined significantly since December 31, 1996. Accordingly, the discounted future net cash flows shown above would be reduced if the standardized measure were calculated in the first quarter of 1997.

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 07:46:28 PM.

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