SUSTAINED GROWTH THROUGH 
STRATEGIC MANAGEMENT

                                           1997 ANNUAL REPORT

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies


Principles of Consolidation. The accompanying consolidated financial statements include the accounts of Swift Energy Company (Swift) and its wholly owned subsidiaries (collectively referred to as the "Company"), which are engaged in the acquisition, development, operation, and exploration of oil and natural gas properties, with particular emphasis on U.S. onshore natural gas reserves. The Company also has oil and gas investments in Russia, Venezuela, and New Zealand. The Company’s investments in associated oil and gas partnerships and its joint ventures are accounted for using the proportionate consolidation method, whereby the Company’s proportionate share of each entity’s assets, liabilities, revenues, and expenses is included in the appropriate classifications in the consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the consolidated statements. Certain reclassifications have been made to prior year amounts to conform to the current year presentation.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates.

Property and Equipment. The Company follows the "full-cost" method of accounting for oil and gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the acquisition, exploration, and development of oil and gas reserves are capitalized. Such costs include lease acquisitions, geological and geophysical services, drilling, completion, equipment, and certain general and administrative costs directly associated with acquisition, exploration, and development activities. General and administrative costs related to production and general overhead are expensed as incurred. No gains or losses are recognized upon the sale or disposition of oil and gas properties, except in transactions that involve a significant amount of reserves. The proceeds from the sale of oil and gas properties are generally treated as a reduction of oil and gas property costs. Fees from associated oil and gas exploration and development limited partnerships are credited to oil and gas property costs to the extent they do not represent reimbursement of general and administrative expenses currently charged to expense.

Future development, site restoration, and dismantlement and abandonment costs, net of salvage values, are estimated on a property-by-property basis based on current economic conditions and are amortized to expense as the Company’s capitalized oil and gas property costs are amortized. The Company’s properties are all onshore and historically the salvage value of the tangible equipment offsets the Company’s site restoration and dismantlement and abandonment costs. The Company expects this relationship will continue.

The Company computes the provision for depreciation, depletion, and amortization of oil and gas properties on the unit-of-production method. Under this method, the Company computes the provision by multiplying the total unamortized costs of oil and gas properties—including future development, site restoration, and dismantlement and abandonment costs but excluding costs of unproved properties—by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves. This calculation is done on a country by country basis for those countries with oil and gas production. The Company currently has production in the United States only. The cost of unproved properties not being amortized is assessed quarterly to determine whether the value has been impaired below the capitalized cost. Any impairment assessed is added to the cost of proved properties being amortized. To the extent costs accumulated in the Company’s international initiatives will not result in the addition of proved reserves, an impairment would be charged to income upon such determination.

At the end of each quarterly reporting period, the unamortized cost of oil and gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using current prices, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects ("Ceiling Limitation"). This calculation is done on a country by country basis for those countries with proved reserves. Currently, the Company has proved reserves in the United States only.

The calculation of the Ceiling Limitation and provision for depreciation, depletion, and amortization is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered.

All other equipment is depreciated by the straight-line method at rates based on the estimated useful lives of the property. Repairs and maintenance are charged to expense as incurred. Renewals and betterments are capitalized.

Deferred Charges. Legal and accounting fees, underwriting fees, printing costs, and other direct expenses associated with the issuance of the Company’s 6.5% Convertible Subordinated Debentures due 2003 ("Debentures") were capitalized in June 1993 and through June 1996 were being amortized over the life of the Debentures. Due to the conversion of all outstanding Debentures into common stock in August 1996, the related unamortized costs ($1,097,551) were transferred to the Company’s appropriate capital accounts in the third quarter of 1996. The issuance costs associated with the public offering in November 1996 of the Company’s 6.25% Convertible Subordinated Notes (the "Notes") have been capitalized and are being amortized over the life of the Notes, which mature on November 15, 2006. The balance of these issuance costs at December 31, 1997, ($4,184,014) is net of accumulated amortization of $365,986.

Limited Partnerships and Joint Ventures. Between 1991 and 1995 (and for prior periods), the Company formed limited partnerships and joint ventures for the purpose of acquiring interests in producing oil and gas properties and, since 1993, partnerships engaged in drilling for oil and gas reserves. The Company serves as managing general partner or manager of these entities. Because the Company serves as the general partner of these entities, under state partnership law it is contingently liable for the liabilities of these partnerships, virtually all of which are owed to the Company and are not material for any of the periods presented in relation to the partnerships’ respective assets.

The Company acquired producing oil and gas properties and transferred those properties to the partnership entities which invested in producing oil and gas properties at cost, including interest, other carrying costs, closing costs, and screening and evaluation costs of properties not acquired, or in certain instances at fair market value based upon the opinion of an independent expert. These costs were reduced by net operating revenues from the effective date of the acquisition to the date of transfer to these entities. Such net operating revenue amounts totaled approximately $100,000, $300,000, and $600,000 in 1997, 1996, and 1995, respectively. The Company, with the acquisitions made in 1997, has fulfilled its responsibility of acquiring properties for such partnerships, as these partnerships are fully invested in properties.

Commencing September 15, 1993, the Company began offering, on a private placement basis, general and limited partnership interests in limited partnerships to be formed to drill for oil and gas. As managing general partner, the Company pays for all front-end costs incurred in connection with these offerings, for which the Company receives an interest in the partnerships. Through December 31, 1997, approximately $58.6 million had been raised in eleven partnerships, one formed in each of 1993 and 1994 and three in each of 1995, 1996, and 1997. In May, July, and September 1997, the Company closed the ninth, tenth, and eleventh partnerships with total subscriptions of approximately $4.4 million, $3.0 million, and $9.4 million, respectively. Costs of syndication and qualification of these limited partnerships incurred by the Company have been deferred. Under the current private limited partnership offerings, selling and formation costs borne by the Company serve as the Company’s general partner contribution to such partnerships.

During 1996, the limited partners in 18 partnerships, which had been in operation over nine years and had produced a substantial majority of their reserves, voted to sell their remaining properties and liquidate the limited partnerships. Of these partnerships, 10 were the earliest public income partnerships (formed in 1984 to 1986) and were liquidated in 1996, and in early 1997 eight private drilling partnerships (formed in 1979 to 1985) were liquidated. During 1997, the limited partners in an additional 11 partnerships, formed in 1990 and 1991, voted to sell their properties and liquidate the limited partnerships, which liquidation is expected in early 1998. As the public income partnerships formed since 1986 grow older, it is anticipated that proposals will continue to be made to the investors in those partnerships to sell their properties and liquidate the partnerships.

Hedging Activities. The Company’s revenues are primarily the result of sales of its oil and natural gas production. Market prices of oil and natural gas may fluctuate and adversely affect operating results. To mitigate some of this risk, the Company does engage periodically in certain limited hedging activities, but only to the extent of buying protection price floors for portions of its and the limited partnerships’ oil and gas production. Costs and any benefits derived from these price floors are accordingly recorded as a reduction or increase, as applicable, in oil and gas sales revenue and were not significant for any year presented. The costs to purchase put options are amortized over the option period. The costs related to the open contracts totaled approximately $95,308 and had a market value of $121,600 as of December 31, 1997.

Income Taxes. The Company accounts for income taxes using Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes." SFAS No. 109 utilizes the liability method, and deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax bases of assets and liabilities given the provisions of the enacted tax laws.

Deferred Revenues. In May 1992, the Company purchased interests in certain wells using funds provided by the Company’s sale of a volumetric production payment in these properties. Under the production payment agreement, the Company 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. Volumes remaining to be delivered through October 2000 under the volumetric production payment (approximately 2.0 Bcf at December 31, 1997) are not included in the Company’s proved reserves. Net proceeds from the sale of the production payment were recorded as deferred revenues. Deliveries under the production payment agreement are recorded as oil and gas sales revenues and a corresponding reduction of deferred revenues. Hydrocarbons produced in excess of the amount required to be delivered are sold by the Company for its own account.

Cash and Cash Equivalents. The Company considers all highly liquid debt instruments with an initial maturity of three months or less to be cash equivalents.

Credit Risk Due to Certain Concentrations. The Company extends credit, primarily in the form of monthly oil and gas sales and joint interest owners receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions and may accordingly impact the Company’s overall credit risk. However, the Company believes that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which the Company extends credit.

During the year ended December 31, 1997, three oil or gas purchasers each accounted for 10% or more of the Company’s revenues, with those purchasers together accounting for approximately 42%. Three oil or gas purchasers accounted for 10% or more of the Company’s revenues during the year ended December 31, 1996, with those purchasers together accounting for approximately 51%. Because of the availability of other purchasers, the Company does not believe that the loss of any single oil or gas purchaser or contract would materially affect its sales.

Fair Value of Financial Instruments. The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, and long-term debt. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The fair value of long-term debt was determined based upon interest rates currently available to the Company for borrowings with similar terms. The fair value of long-term debt approximates the carrying amount as of December 31, 1997.

New Accounting Standard. In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive Income," which established standards for reporting and displaying comprehensive income and its components in the financial statements. SFAS No. 130 is effective for fiscal years beginning after December 15, 1997. The adoption of this statement requires incremental financial statement disclosure only, and thus will have no effect on the Company’s financial position or results of operations.

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