FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 1998

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 exploration, development, acquisition, and operation of oil and natural gas properties, with particular emphasis on U.S. onshore natural gas reserves. The Company also has oil and gas activities in New Zealand, Venezuela, and Russia. 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. In the second quarter of 1998, the Company began netting supervision fees against general and administrative expenses and oil and gas production costs. This reclassification has been made for all periods presented. Certain other 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. Under the full-cost method of accounting, such costs may be incurred both prior to or after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, equipment, and certain general and administrative costs directly associated with acquisition, exploration, and development activities. Interest costs related to unproved properties are also capitalized to unproved oil and gas properties. The Company’s management believes this capitalization of such costs is appropriate under full-cost accounting rules. 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 that this relationship will continue in the future.

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. 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.

The cost of unproved properties not being amortized is assessed quarterly, on a country-by-country basis, to determine whether such properties have been impaired. Domestically, any impairment assessed is added to the cost of proved properties being amortized. To the extent costs accumulated in the Company’s international initiatives are determined by management to be costs that will not result in the addition of proved reserves, any impairment is charged to income. In determining whether such costs should be impaired, the Company’s management evaluates, among other factors, current oil and gas industry conditions, international economic conditions, capital availability, foreign currency exchange rates, the political stability in the countries in which the Company has an investment, and available geological and geophysical information.

Domestic Properties. 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 period-end prices, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects ("Ceiling Test"). 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 Test 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.

As a result of low oil and gas prices at September 30, 1998, the Company reported a non-cash write-down on a before-tax basis of $77.2 million ($50.9 million after tax) on its domestic properties.

Foreign Properties. In addition, during the third quarter of 1998, as it does every reporting period, the Company evaluated all of its foreign unevaluated properties (a detailed description of which is included in Note 8 to the Company’s financial statements), especially in light of the then increased volatility in the oil and gas markets, international uncertainty, and turmoil in the world capital markets.

The increased volatility in the oil and gas markets affected the Company’s cash flows available for further exploration and forced the Company to scale back its capital expenditures budget. All of this was further accentuated in Venezuela by the economic crisis there, the results of which were to diminish the availability of financing in international markets for Venezuelan projects and to worsen Venezuelan currency problems. Petroleos de Venezuela, S.A. layoffs, threatened oil worker strikes, reduced OPEC production allocations, and other third quarter 1998 events highlight the problems that the oil and gas industry is encountering in Venezuela. As a result of these and other factors, in the third quarter of 1998, the Company decided to impair all $2.8 million of costs related to its Venezuelan oil and gas exploration activities.

In addition, in the third quarter of 1998, the Company impaired all $10.8 million of costs relating to its Russian activities. This impairment is attributed not only to the volatility in the oil and gas markets and the severe tightening of international credit markets discussed above, but also to the increased political instability in Russia and the August 1998 collapse of the Russian currency. The Company believed that the economic and political situation would result in the lack of capital to develop these reserves underlying the Company’s net profits interest in the near term. Although the Company continues to believe that its net profits interest is legally enforceable under international law, for all these reasons the Company does not believe that realistically it will be able to recover its investment in Russia in the foreseeable future. Because of this, the Company determined that it no longer had a reasonable basis to continue capitalization of the costs in its Russia cost center.

The combination of the third-quarter domestic full-cost ceiling write-down and foreign activities impairment charges reduced before-tax earnings by $90.8 million ($59.9 million after tax). Since such impairment, any costs incurred in Venezuela and Russia have been charged to income.

Also, during the fourth quarter of 1998, the Company’s $0.4 million portion of drilling costs associated with an unsuccessful exploratory well drilled by another operator in New Zealand was charged to income as depreciation, depletion, and amortization costs.

Oil and Gas Revenues. Gas revenues are reported using the entitlement method in which the Company recognizes its ownership interest in natural gas production as revenue. If the Company’s sales exceed its ownership share of production, the differences are reported as deferred revenue. Natural gas balancing receivables are reported when the Company’s ownership share of production exceeds sales. As of December 31, 1998, the Company did not have any material natural gas imbalances.

Deferred Charges. Legal and accounting fees, underwriting fees, printing costs, and other direct expenses 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, 1998 was $3,826,864, net of accumulated amortization of $723,136. The issuance costs associated with its new $250.0 million revolving credit facility (the "New Credit Facility"), which closed in August 1998, have been capitalized and are being amortized over the life of the facility, which will extend until August 2002. The balance of these issuance costs at December 31, 1998, was $507,094, net of accumulated amortization of $51,600.

Limited Partnerships and Joint Ventures. Between 1984 and 1995, 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.

The Company acquired producing oil and gas properties and transferred those properties to the partnership entities which invested in producing oil and gas properties. These transfers were 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 and $300,000 in 1997 and 1996, respectively. With the acquisitions made in 1997, the Company fulfilled its responsibility of acquiring properties for such partnerships, as these partnerships are fully invested in properties.

Commencing in September 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, 1998, approximately $66.1 million had been raised in thirteen partnerships, one each formed in 1993 and 1994; three each in 1995, 1996, and 1997; and two in 1998. In June and October 1998, the Company closed the twelfth and thirteenth partnerships with total subscriptions of approximately $3.2 million and $4.3 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 between 1984 and 1986. In early 1997, eight private drilling partnerships formed between 1979 and 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 occurred in June 1998.

In October 1998, the Company notified investors in 63 Company-managed partnerships, formed between 1986 and 1994, that it had delayed calling investor meetings to consider its purchase of all of the oil and gas properties owned by these partnerships, which was proposed in March 1998. This decision principally reflected significant market changes that had occurred during the long period necessary for regulatory review of soliciting materials, the age of the third- party appraisals of these partnership properties, and the much publicized weakness in both the equity and debt markets for energy companies. During the last six months, the weakness in oil and natural gas prices has deepened, creating concern over the appropriateness of selling properties at this time. The Company expects to continue to re-evaluate the status and operation of these partnerships, whether to propose some form of liquidating transaction and, if so, when and in what form.

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 engages 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 natural gas production. Costs and any benefits derived from these price floors are accordingly recorded as a reduction or an 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 1998 hedging activities totaled approximately $377,000 with benefits of approximately $101,000 being received, resulting in a net cash outlay of approximately $276,000 or $0.007 per Mcfe. The costs related to the open contracts as of December 31, 1998, totaled approximately $252,000 and had a fair market value of $267,000.

Income Taxes. The Company accounts for income taxes using 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 to Enron. 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 receives all proceeds from sale of 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 were approximately 1.1 Bcf at December 31, 1998, and were 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.

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 1998, oil and gas sales to subsidiaries of PG&E Energy Trading Corporation and Aquila Southwest Pipeline Corporation were $13.0 million (16.2% of oil and gas sales) and $8.0 million (10.0%), respectively. In 1997, oil and gas sales to PG&E Energy Trading Corporation, Aquila Southwest Pipeline Corporation, and Koch Oil Company were $13.5 million (19.5%), $8.1 million (11.7%), and $7.1 million (10.3%), respectively. In 1996, oil and gas sales to TECO Gas Marketing Company were $6.9 million (13.0%).

Fair Value of Financial Instruments. The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and convertible notes. 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 values of the bank borrowings approximate the carrying amounts as of December 31, 1998 and 1997 and were determined based upon interest rates currently available to the Company for borrowings with similar terms. The fair values of the convertible notes were $81.4 million and $113.6 million at December 31, 1998 and 1997, respectively, and were based on quoted markets prices as of the respective dates.

New Accounting Pronouncements. In the first quarter of 1998, the Company adopted the Statement of Financial Accounting Standards ("SFAS") No. 130, "Reporting Comprehensive Income," which requires the display of comprehensive income and its components in the financial statements. Comprehensive income represents all changes in equity during the reporting period, including net income and charges directly to equity, which are excluded from net income. The adoption of this statement does not have a material impact on the Company or its financial disclosures, as the Company has not historically and currently does not enter into transactions that result in charges (or credits) directly to equity (such as additional minimum pension liability changes, currency translation adjustments, and unrealized gains and losses on available-for-sale securities).

In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Statement establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows the gains and losses on derivatives to offset related results on the hedged item in the income statements and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133 is effective for fiscal years beginning after June 15, 1999. The Company is currently evaluating the new standard, but has not yet determined the impact it will have on its financial position and results of operations.

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