SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED March 31, 2004
INDEX

SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS

	March 31, 2004	December 31, 2003
ASSETS
Current Assets:
Cash and cash equivalents	$ 4,398,581	$ 1,066,280
Accounts receivable --
Oil and gas sales	27,201,434	26,082,650
Joint interest owners	1,942,313	1,350,707
Other current assets	6,959,951	4,957,647
	----------------------	----------------------
Total Current Assets	40,502,279	33,457,284
	----------------------	----------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized	1,341,732,893	1,305,763,355
Unproved properties not being amortized	67,625,981	67,557,969
	----------------------	----------------------
	1,409,358,874	1,373,321,324
Furniture, fixtures and other equipment	10,936,689	10,602,786
	----------------------	----------------------
	1,420,295,563	1,383,924,110
Less--Accumulated depreciation, depletion,
and amortization	(585,839,389)	(567,464,334)
	----------------------	----------------------
	834,456,174	816,459,776
	----------------------	----------------------
Other Assets:
Deferred income taxes	3,663,957	1,905,909
Debt issuance costs	7,746,868	8,015,575
	----------------------	----------------------
	11,410,825	9,921,484
	----------------------	----------------------
	$886,369,278	$859,838,544
	===========	===========

Liabilities and Stockholders' Equity

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

					Accumu-
					lated
		Additional			Other Com-
	Common	Paid-In	Treasury	Retained	prehensive
	Stock (1)	Capital	Stock	Earnings	Loss	Total
	-------------	---------------	------------	-----------------	-----------------	---------------
Balance, December 31, 2002	$ 278,116	$ 333,543,471	$(8,749,922)	$40,179,572	$(178,053)	$ 365,073,184
Stock issued for benefit plans (83,201 shares)	1	(408,178)	1,191,829	--	--	783,652
Stock options exercised (142,807 shares)	1,428	1,315,964	--	--	--	1,317,392
Employee stock purchase plan (56,574 shares)	566	413,947	--	--	--	414,513
Comprehensive income:
Net income	--	--	--	29,893,812	--	29,893,812
Change in fair value of cash flow hedges,
net of income tax	--	--	--	--	(91,289)	(91,289)
						---------------
Total comprehensive income	--	--	--	--	--	29,802,523
	-------------	---------------	------------	-----------------	-----------------	---------------
Balance, December 31, 2003	$ 280,111	$ 334,865,204	$(7,558,093)	$70,073,384	$(269,342)	$ 397,391,264
	=========	=========	=========	==========	==========	=========
Stock issued for benefit plans (46,150 shares)	--	166,298	661,848	--	--	828,146
Stock options exercised (91,215 shares)	912	1,018,865	--	--	--	1,019,777
Comprehensive income:
Net income	--	--	--	14,587,854	--	14,587,854
Change in fair value of cash flow hedges,
net of income tax	--	--	--	--	(94)	(94)
						---------------
Total comprehensive income	--	--	--	--	--	14,587,760
	-------------	---------------	------------	-----------------	-----------------	---------------
Balance, March 31, 2004	$ 281,023	$ 336,050,367	$(6,896,245)	$84,661,238	$(269,436)	$ 413,826,947
	=========	=========	=========	==========	==========	=========

(1) $.01 Par Value


See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) GENERAL INFORMATION

 

The consolidated financial statements included herein have been prepared by Swift Energy Company and are unaudited, except for the consolidated balance sheet at December 31, 2003 and consolidated statement of stockholders’ equity for the year ended December 31, 2003, 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. Certain reclassifications have been made to prior period financial information to conform to the current period presentation. 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 and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended March 31, 2004 and 2003, such internal costs capitalized totaled $2.9 million and $3.0 million, respectively. Interest costs are also capitalized to unproved oil and gas properties. For the three months ended March 31, 2004 and 2003, capitalized interest on our unproved properties totaled $1.6 million and $1.8 million, respectively. 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 or where the proceeds from the sale of oil and gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.

Future development costs 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.

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 costs, gas processing facilities and capitalized asset retirement obligations, 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 at the beginning of the period. This calculation is done on a country-by-country basis. Furniture, fixtures, and other equipment are 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.

Geological and geophysical (G&G) costs incurred on developed properties are recorded in Proved Property and therefore subject to amortization. In exploration areas, G&G costs are capitalized in Unproved Property and evaluated as part of the total capitalized costs associated with a prospect.

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 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 expense.

Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and gas properties, including gas processing facilities and capitalized asset retirement obligations, net of related salvage values and deferred income taxes, and excluding the asset retirement obligation liability is limited to the sum of the estimated future net revenues from proved properties, excluding cash outflows from asset retirement obligations, using period-end prices, adjusted for the effects of hedging, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“Ceiling Test”). Our hedges at March 31, 2004 consisted of natural gas price floors with strike prices lower than the period end price and thus did not affect prices used in this calculation. 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.

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 our period-end prices used in the Ceiling Test, even if only for a short period, it is possible that additional non-cash write-downs of oil and gas properties could occur in the future.

Principles of Consolidation

 

The accompanying consolidated financial statements include the accounts of Swift Energy Company 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 and inland waters oil and natural gas reserves in Texas and Louisiana, as well as onshore oil and natural gas reserves in New Zealand. Our investments in affiliated oil and gas partnerships and other 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.

Accounts Receivable

 

Included in the total “Accounts receivable” balance, which totaled $29.1 million and $27.4 million at March 31, 2004 and December 31, 2003, respectively, on the accompanying consolidated balance sheet, is approximately $2.3 million of receivables related to hydrocarbon volumes produced during 2001 and 2002 that have been disputed since early 2003. Accordingly, we did not record a receivable with regard to 2003 volumes. We continually assess the collectibility of trade and other receivables, and based on our judgment, we establish a reserve when we believe a receivable may not be collected. At both March 31, 2004 and December 31, 2003, we had an allowance for doubtful accounts of $0.8 million. These allowances for doubtful accounts have been deducted from the total “Accounts receivable” balances on the accompanying consolidated balance sheets.

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. Significant estimates include proved reserve volumes, DD&A, and deferred income taxes.

Income Taxes

 

Income tax expense in the first quarter of 2004 includes a reduction from the U.S. statutory rate, primarily from the result of the currency exchange rate effect on the New Zealand deferred tax, along with a reduction in tax expense primarily attributable to an adjustment of the tax basis of the TAWN properties acquired in 2002.

Earnings Per Share

 

Basic earnings per share (“Basic EPS”) have been computed using the weighted average number of common shares outstanding during the respective periods. Diluted earnings per share (“Diluted EPS”) for all periods also assume, as of the beginning of the period, exercise of stock options using the treasury stock method. Certain of our stock options that would potentially dilute Basic EPS in the future were antidilutive for the three months ended March 31, 2004 and 2003. 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 periods ended March 31, 2004 and 2003:

Three Months Ended March 31,
	2004								2003
	Net Income		Shares		Per Share Amount				Net Income		Shares		Per Share Amount
	----------		---------		--------				---------		---------		--------
Basic EPS:
Net Income Before Cumulative Effect     of Change in Accounting Principle     and Share Amounts	$14,587,854		27,552,827		$.53				$10,484,937		27,243,142		$.38
Stock Options	---		546,460						---		66,734
	-----------------		------------						-----------------		------------
Diluted EPS:
Net Income Before Cumulative Effect     of Change in Accounting Principle     and Assumed Share Conversions	$14,587,854		28,099,287		$.52				$10,484,937		27,309,876		$.38
	=========		========						========		========

 

Options to purchase approximately 3.2 million shares of common stock, at an average exercise price of $16.58 were outstanding at March 31, 2004, and 3.0 million shares of common stock, at an average price of $16.59 were outstanding at March 31, 2003. Approximately 0.9 million and 1.7 million options to purchase shares were not included in the computation of Diluted EPS for the three-month periods ended March 31, 2004 and 2003, respectively, because the options were antidilutive, given that the option price was greater than the average closing market price of the common shares during those periods.

Other Comprehensive Loss

 

We follow the provisions of SFAS No. 130 “Reporting Comprehensive Income,” which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income or loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company. At March 31, 2004, we recorded $269,436, net of taxes of $151,558, of derivative losses in “Other comprehensive loss” on the accompanying balance sheet. The components of accumulated other comprehensive loss and related tax effects for the three-month period ended March 31, 2004 were as follows:

 

	Gross Value		Tax Effect		Net of Tax Value
Balance at December 31, 2003	$  420,847		$ 151,505		$  269,342
Change in fair value of cash flow hedges	634,987		228,595		406,392
Effect of cash flow hedges settled during the period	(634,840)		(228,542)		(406,298)
	--------------		--------------		--------------
Balance at March 31, 2004	$  420,994		$ 151,558		$  269,436
	--------------		--------------		--------------

 

For the three-month periods ended March 31, 2004 and 2003, total comprehensive income was $14.6 million and $6.0 million, respectively.

Stock Based Compensation

 

We account for three stock-based compensation plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. No stock-based employee compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of the grant; or in the case of the employee stock purchase plan, the purchase price is 85% of the lower of the closing price of our common stock as quoted on the New York Stock Exchange at the beginning or end of the plan year or a date during the year chosen by the participant. Had compensation expense for these plans been determined based on the fair value of the options consistent with SFAS No. 123, “Accounting for Stock-Based Compensation,” our net income and earnings per share would have been adjusted to the following pro forma amounts:

					Three Months Ended March 31,
				2004			2003
Net Income:		As Reported		$14,587,854			$6,108,085
		Stock-based employee compensation expense determined under fair value method for all awards, net of tax		(1,022,306)			(981,942)
				-------------------			-------------------
		Pro Forma		$13,565,548			$5,126,143