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 onshore oil and natural gas reserves in Texas and Louisiana, 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 financial 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 exploration, development and acquisition 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 property by property 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 compute the provision for depreciation, depletion, and amortization of oil and gas properties by 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. 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, we evaluate, among other factors, current drilling results, lease expiration dates, 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. To the extent costs accumulate in countries where there are no proved reserves, any costs determined by management to be impaired are charged to income.

Full Cost Ceiling Test. 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 2001, as a result of low oil and gas prices at December 31, 2001, we reported a non-cash write-down on a before-tax basis of $98.9 million ($63.5 million after tax) on our domestic properties. We had no write-down on our New Zealand properties.

In addition, any unsuccessful exploratory well costs in countries in which there are no proved reserves are charged to expense as incurred. During 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 drilled by another operator in New Zealand. This charge was $290,000.

Because of the delineation of our 1999 Rimu discovery with two successful delineation wells drilled in 2000, proved reserves were recognized in New Zealand as of December 31, 2000.

Given the volatility of oil and gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline from the Company’s year-end prices used in the Ceiling Test, even if only for a short period, it is possible that additional write-downs of oil and gas properties could occur in the future.

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"), with the public offering in August 1999 of our 10.25% Senior Subordinated Notes (the "Senior Notes"), and with our September 2001 extension of our bank credit facility were capitalized and are amortized over the life of each of the respective note offerings and credit facility. 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 was 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, 2001, was $2,956,306, net of accumulated amortization of $545,135. The issuance costs associated with our revolving credit facility, which closed in September 2001, have been capitalized and are being amortized over the original life of the facility. The balance of revolving credit facility issuance costs at December 31, 2001, was $766,876, net of accumulated amortization of $513,573. 

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 partnerships and dissolve. During 2001, seven drilling partnerships and two production purchase partnerships were dissolved. We anticipate that the liquidation and dissolution of the additional 65 partnerships will be completed by the end of 2002. The remaining six partnerships will continue to operate until their limited partners vote otherwise.

Price-Risk Management Activities. 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 a 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, was adopted by us on January 1, 2001.

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 elected not to designate our price floors for special hedge accounting treatment under SFAS No. 133, as amended. However, we have elected to use mark-to-market accounting treatment for our derivative contracts. Upon adoption of SFAS No. 133 on January 1, 2001, we recorded a net of taxes charge of $392,868, which is recorded as a Cumulative Effect of Change in Accounting Principle. During 2001 we recognized net gains of $1,173,094 relating to our derivative activities, with $16,784 in unrealized losses at year-end 2001. This activity is recorded in Price-risk management and other, net on the accompanying statements of income.

At December 31, 2001, we had open price floor contracts covering notional volumes of 2.0 million MMBtu of natural gas. These natural gas price floor contracts relate to the NYMEX contract months of February and March 2002 at an average price of $2.33 per MMBtu. The fair value of our open price floor contracts at December 31, 2001, totaled $296,000 and is included in Other current assets on the accompanying balance sheets.

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 2001, oil and gas sales to subsidiaries of Eastex Crude Company were $31.6 million, or 18.1% of oil and gas sales, while sales to subsidiaries of Enron were $18.2 million, or 10.4% of oil and gas sales. 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. Beginning in December 2000, the subsidiaries of PG&E Energy Trading Corporation to which we made sales were sold to subsidiaries of El Paso Corporation. All receivables from PG&E were collected. During the fourth quarter of 2001, we wrote off $1.4 million due to uncollected receivables related to gas sold to Enron in November 2001. This amount is included in Other expenses on the Consolidated Statement of Income. We have discontinued sales of oil and gas to Enron and are selling that production to other purchasers.

Risk Factors. Our revenues, profitability and cash flow are substantially dependent upon the price of and demand for oil and gas. Prices for oil and gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty, and a variety of additional factors beyond our control. We are also dependent upon the continued success of our domestic and New Zealand exploration and development programs. Other factors that could affect revenues, profitability, and cash flow include the inherent uncertainty in reserves estimates, our price-risk management activities, and the ability to replace reserves and finance our growth.

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, 2001 and 2000, 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 $126.5 million and $115.1 million at December 31, 2001 and 2000, respectively. The carrying value of our Senior Notes was $124.2 million and $124.1 million at December 31, 2001 and 2000, respectively.