FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 2000

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 our wholly owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and natural gas properties, with a focus on U.S. onshore natural gas reserves as well as onshore oil and natural gas reserves in New Zealand. Our investments in associated oil and gas partnerships and joint ventures are accounted for using the proportionate consolidation method, whereby our proportionate share of each entity’s assets, liabilities, revenues, and expenses are 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 current year presentation.

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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. We follow 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. 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 involving 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 our capitalized oil and gas property costs are amortized. The vast majority of our properties are onshore, and historically the salvage value of the tangible equipment offsets our site restoration and dismantlement and abandonment costs. We expect that this relationship will continue in the future.

We compute the provision for depreciation, depletion, and amortization of oil and gas properties on the unit-of-production method. Under this method, we compute 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. We currently have 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. In determining whether such costs should be impaired, our 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 we have an investment, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized, if any. To the extent costs accumulated in countries where there are no proved reserves, any costs determined by management to be impaired are charged to income.

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 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.

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.

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

Russia and Venezuela Write-downs. During the third quarter of 1998, as we do every reporting period, we evaluated all of our foreign unevaluated properties (a detailed description of which is included in Note 8 to the Consolidated 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 our cash flows available for further exploration and forced us to scale back our 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 highlighted the problems that the oil and gas industry was encountering in Venezuela. As a result of these and other factors, in the third quarter of 1998 we charged to income all $2.8 million of costs related to our Venezuelan oil and gas exploration activities.

In addition, in the third quarter of 1998, we charged to income all $10.8 million of costs relating to our Russian activities. This impairment was 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. We believed that the economic and political situation would result in the lack of capital to develop the reserves underlying our net profits interest in the near term. Although we continue to believe that our net profits interest is legally enforceable under international law, for all these reasons we did not believe that realistically we would be able to recover our investment in Russia in the foreseeable future. Because of this, we determined that we no longer had a reasonable basis to continue capitalization of the costs in our Russia cost center.

The combination of the third-quarter 1998 domestic full-cost ceiling write-down and foreign activities impairment charges reduced before-tax earnings by $90.8 million ($59.9 million after tax).

New Zealand. During the fourth quarter of 1998 and the second quarter of 1999, we charged to income as additional depreciation, depletion, and amortization costs our portion of drilling costs associated with an unsuccessful exploratory well in each quarter drilled by other operators in New Zealand. These costs were $400,000 in 1998 and $290,000 in 1999.

Because of the delineation of our 1999 Rimu discovery with two successful delineation wells drilled in 2000, proved reserves have been recognized in New Zealand at December 31, 2000. Commencing in the fourth quarter of 2000, at the end of each quarterly reporting period, a separate calculation of the Ceiling Test will be made for New Zealand in the same manner as the calculation for domestic properties as described above. Once production is established in New Zealand, the provision for depreciation, depletion, and amortization of oil and gas properties will be calculated on the unit-of-production method as described above.

Oil and Gas Revenues. Gas revenues are reported using the entitlement method in which we recognize our ownership interest in natural gas production as revenue. If our sales exceed our ownership share of production, the differences are reported as deferred revenues. Natural gas balancing receivables are reported when our ownership share of production exceeds sales. As of December 31, 2000, we 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 our 6.25% Convertible Subordinated Notes (the "Convertible Notes") and with the public offering in August 1999 of our 10.25% Senior Subordinated Notes (the "Senior Notes") were capitalized and are amortized over the life of each of the respective note offerings. The Convertible Notes were called for redemption effective December 26, 2000, and the balance of their unamortized issuance costs at that time of $3,046,181 was either transferred to the common stock equity accounts ($2,643,476) for the portion of the Convertible Notes converted into common stock at the election of those note holders, or recorded, net of taxes, as Extraordinary Loss on Early Extinguishment of Debt ($402,705) for the portion of the Convertible Notes redeemed for cash. The Senior Notes mature on August 1, 2009, and the balance of their issuance costs at December 31, 2000, was $3,199,214, net of accumulated amortization of $302,227. The issuance costs associated with our revolving 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, 2000, was $227,758, net of accumulated amortization of $330,936.

Limited Partnerships and Joint Ventures. We formed 88 limited partnerships between 1984 and 1995 to acquire interests in producing oil and gas properties and 13 partnerships between 1993 and 1998 to drill for oil and gas. In all of these partnerships, Swift paid for varying percentages of the capital or front-end costs and continuing costs of the partnerships and, in return, received differing percentage ownership interests in the partnerships, along with reimbursement of costs and/or payment of certain fees. At year-end 2000, we continue to serve as managing general partner of 80 of these various partnerships, and during fiscal 2000 approximately 4.7% of our total oil and gas sales was attributable to our interests in those partnerships.

During 1997 and 1998, eight drilling partnerships formed between 1979 and 1985 and 21 of the production purchase partnerships sold their properties and were dissolved, in each case following a vote of the investors in the particular partnerships approving such liquidations. Between 1999 and 2001, the investors in all but six of the remaining partnerships voted to sell the properties or their interests in the partnership and dissolve. We anticipate that the liquidation and dissolution of these 74 partnerships should be substantially completed by the end of 2001. The remaining six partnerships will continue to operate.

Price Risk Management Activities. Our revenues are derived from sales of our 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, we do engage periodically in certain limited hedging activities, which include buying protection price floors and entering into participating collars for portions of our oil and natural gas production. These derivative financial instruments are placed with major financial institutions that we believe present minimum credit risk. Costs and any benefits derived from the price floors were recorded as a reduction or an increase, as applicable, in oil and gas sales revenues. The costs to purchase put options were amortized over the option period. The participating collars were designated as hedges and realized gains or losses were recognized in oil and gas revenues when the associated production occurred.

The costs relating to 2000 hedging activities on the price floors totaled approximately $1,083,000 with benefits of approximately $579,000 being received, resulting in a net cash outflow of $504,000, or $0.012 per Mcfe produced. Participating collars covering oil for the first six months of 2000 closed with a loss of approximately $610,000, or $0.014 per Mcfe produced.

The costs related to open price floor contracts as of December 31, 2000, totaled approximately $823,000, which is our maximum exposure under these contracts. These open contracts, covering 2001 production, had a fair market value of approximately $209,000 at that date. These contracts expire on or before March 31, 2001. There are no open participating collars at this time. Beginning January 1, 2001, our adoption of SFAS No. 133, as amended, is described below.

Income Taxes. 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, we purchased interests in certain wells using funds provided by our sale of a volumetric production payment in these properties to Enron. We delivered the last remaining volumes under this arrangement in October 2000. Under the production payment agreement, we were required to deliver to Enron approximately 9.5 Bcf at an average price of $1.115 per MMBtu. We received all proceeds from the sale of excess gas at current market prices plus all proceeds from the sale of oil or condensate. In fiscal periods where volumes remained to be delivered under this arrangement, those volumes were not included in our proved reserves. Net proceeds from the sale of the production payment were recorded as deferred revenues. Deliveries under the production payment agreement were recorded as oil and gas sales revenues with a corresponding reduction of deferred revenues.

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

Credit Risk Due to Certain Concentrations. We extend 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 our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. During 2000, oil and gas sales to subsidiaries of Eastex Crude Company were $47.4 million, or 25.7% of our oil and gas sales, while sales to subsidiaries of PG&E Energy Trading Corporation were $21.2 million, or 11.5% of oil and gas sales. During 1999, oil and gas sales to subsidiaries of Eastex Crude Company were $21.7 million, or 19.4% of our oil and gas sales. During 1998, oil and gas sales to subsidiaries of PG&E Energy Trading Corporation were $13.0 million, or 16.2% of oil and gas sales, and to Aquila Southwest Pipeline Corporation were $8.0 million, or 10.0% of sales. Beginning in December 2000, the subsidiaries of PG&E Energy Trading Corporation to which we make sales were sold to subsidiaries of El Paso Corporation. All receivables from PG&E have been collected.

Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and 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, 2000 and 1999, and were determined based upon interest rates currently available to us for borrowings with similar terms. Based on quoted market prices as of the respective dates, the fair values of our Senior Notes were $115.1 million and $117.9 million at December 31, 2000 and 1999, respectively, and the fair value of our Convertible Notes was $89.7 million at December 31, 1999. The carrying value of our Senior Notes was $124.1 million at both December 31, 2000 and 1999, and the carrying value of our Convertible Notes was $115.0 million at December 31, 1999.

New Accounting Pronouncements. 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, as amended by SFAS No. 137 and SFAS No. 138, is effective for fiscal years beginning after June 15, 2000.

We have a policy to use derivative instruments, mainly the buying of protection price floors, to protect against price declines in oil and gas prices. We currently believe that such derivatives would qualify for hedge accounting under SFAS No.133, as amended. We do not plan to designate our open contracts at December 31, 2000, for special hedge accounting treatment, and instead plan to mark them to market through earnings. The adoption of this standard beginning January 1, 2001, will result in a Cumulative Effect of a Change in Accounting Principle of approximately $0.4 million, net of taxes, in the first quarter of 2001. This results from the change between the costs of those contracts when purchased and their fair market value at December 31, 2000. We feel that there will not be a material change in our financial position and results of operations as a result of this new standard, since the costs to purchase such floors are our maximum loss exposure. However, the market value and timing of accounting for such costs under SFAS No. 133, as amended, may result in increased earnings volatility between interim reporting periods.

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