SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002
INDEX

SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS

Liabilities and Stockholders' Equity

See accompanying notes to consolidated financial statements.

SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS

See accompanying notes to consolidated financial statements.

SWIFT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three months ended			Nine months ended
	09/30/02	09/30/01		09/30/02	09/30/01
	------------------	------------------		------------------	------------------
Revenues:
Oil and gas sales	$     36,592,329	$    39,346,270		$      101,536,512	$   153,154,895
Fees from limited partnerships and joint ventures	5,830	19,196		59,953	212,184
Interest income	158,664	15,935		190,957	39,788
Gain on asset disposition	---	---		7,332,668	---
Price-risk management and other, net	(186,014)	1,863,182		375,065	2,532,995
	------------------	------------------		------------------	----------------
	36,570,809	41,244,583		109,495,155	155,939,862
	------------------	------------------		------------------	------------------
Costs and Expenses:
General and administrative, net	2,497,413	2,099,533		7,368,989	5,991,518
Depreciation, depletion, and amortization	13,487,437	14,857,858		41,789,711	42,963,556
Oil and gas production	11,004,641	9,285,213		30,602,493	27,222,789
Interest expense, net	6,647,968	3,394,416		16,607,651	9,232,406
	------------------	------------------		------------------	----------------
	33,637,459	29,637,020		96,368,844	85,410,269
	------------------	------------------		------------------	------------------
Income Before Income Taxes and Cumulative Effect         of Change in Accounting Principle	2,933,350	11,607,563		13,126,311	70,529,593
Provision for Income Taxes	986,344	4,187,473		4,575,403	25,416,904
	------------------	------------------		------------------	------------------
Income Before Cumulative Effect of Change          in Accounting Principle	1,947,006	7,420,090		8,550,908	45,112,689
Cumulative Effect of Change in Accounting Principle         (net of taxes)	---	---		---	392,868
	------------------	------------------		------------------	------------------
Net Income	$     1,947,006	$     7,420,090		$     8,550,908	$     44,719,821
	===========	===========		===========	===========
Per Share Amounts-
Basic:  Income Before Cumulative Effect of Change                  in Accounting Principle	$               0.07	$               0.30		$               0.33	$               1.83
Cumulative Effect of Change                  in Accounting Principle	---	---		---	(0.02)
	------------------	------------------		------------------	------------------
Net Income	$               0.07	$               0.30		$               0.33	$               1.81
	===========	===========		===========	===========
Diluted:  Income Before Cumulative Effect of Change                  in Accounting Principle	$               0.07	$               0.29		$               0.32	$               1.77
Cumulative Effect of Change                  in Accounting Principle	---	---		---	(0.02)
	------------------	------------------		------------------	------------------
Net Income	$               0.07	$               0.29		$               0.32	$               1.75
	===========	===========		===========	===========
Weighted Average Shares Outstanding	26,889,186	24,760,352		26,112,382	24,716,411
	===========	===========		===========	===========

See accompanying notes to consolidated financial statements.

SWIFT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(1) $.01 Par Value
(2) Unaudited

See accompanying notes to consolidated financial statements.

SWIFT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

See accompanying notes to consolidated financial statements.

SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2002 (UNAUDITED) AND DECEMBER 31, 2001

(1) GENERAL INFORMATION

 

The consolidated financial statements included herein have been prepared by Swift Energy Company and are unaudited, except for the balance sheet at December 31, 2001, which has been prepared from the audited financial statements at that date. The financial statements reflect necessary adjustments, all of which were of a recurring nature, and are in the opinion of our management necessary for a fair presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in the latest Form 10-K and Annual Report.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Oil and Gas Properties

 

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. Interest not capitalized and 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, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.

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 the salvage value of the tangible equipment should offset 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, net of salvage value, 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 the fourth quarter of 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.

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 period-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.

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.

Earnings Per Share

 

Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during the respective periods. Diluted EPS for all periods also assumes, as of the beginning of the period, exercise of stock options using the treasury stock method. The following is a reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS (before cumulative effect of change in accounting principle) for the three-month and nine-month periods ended September 30, 2002 and 2001:

 

Options to purchase 2.8 million shares of common stock, at an average exercise price of $17.62 were outstanding at September 30, 2002. Approximately 1.4 million and 1.2 million options to purchase shares were not included in the computation of diluted EPS, for the three months and nine months ended September 30, 2002, respectively, because the option price was greater than the average closing market price of the common shares during those periods.

Price Risk Management Activities

 

Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be reported 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 hedge accounting for qualifying hedges would allow the gains and losses on derivatives to offset related results on the hedged item in the income statements and would require that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

We have a risk management policy to use derivative instruments to protect against declines in oil and gas prices. Mainly, the purchase of protection price floors and collars. We adopted SFAS No. 133 effective January 1, 2001. Accordingly, we marked our open contracts at December 31, 2000 to fair value at that date resulting in a one-time net of taxes charge of $392,868, which was recorded as a Cumulative Effect of Change in Accounting Principle. During the first nine months of 2002 and 2001, we recognized net losses of $201,474 and net gains of $1,924,931 respectively, relating to our derivative activities. Approximately $162,727 of the losses recognized in 2002 were unrealized as the contracts were still open, while $775,056 of the gains recognized in the comparative 2001 period were unrealized. This activity is recorded in “Price Risk Management and Other, net” on the accompanying statements of income. At September 30, 2002 the Company had recorded $116,230, net of taxes of $65,380, of derivative losses in “Other comprehensive loss” on the accompanying balance sheet. This amount represents the change in fair value for the effective portion of our derivative transactions that were qualified as cash flow hedges. The Company expects to reclassify all amounts held in “Other comprehensive loss” into the income statement within the next six months.

As of September 30, 2002, the Company had entered into the commodity derivative instruments set forth in the table below as cash flow hedges of its Domestic Oil and Natural Gas production for the remainder of 2002 and part of 2003. When the Company entered into the following transactions they were designated as a hedge of the variability in cash flows associated with the forecasted sale of its oil and natural gas production. Changes in the fair value of a hedge that is highly effective, and is designated and qualifies as a cash flow hedge, to the extent that the hedge is effective, are initially recorded in Other Comprehensive Income (Loss). When the hedged transactions are recorded upon the actual sale of oil and natural gas, then these gains or losses are transferred from Other Comprehensive Income (Loss) and recorded in Price-risk management and other, net on the statement of income. The fair value of these instruments is recognized on the balance sheet, in “Other current assets”, at September 30, 2002.

Crude Oil – Cash Flow Hedges				Collars
				-------------------------------
Period and Type of Contract		Volume in Bbls (000s)		Floors Weighted Average		Ceilings Weighted Average		Price Floor Contracts Weighted Average		September 30, 2002 Fair Value (000s)
October 2002 - December 2002
Floor Contracts		195						$  21.00		$     2
January 2003 - March 2003
Collar Contracts		90		$ 21.00						$  &