SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2005
INDEX

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2005	December 31, 2004
ASSETS
Current Assets:
Cash and cash equivalents	$ 9,714,592	$ 4,920,118
Accounts receivable --
Oil and gas sales	39,651,825	38,029,409
Joint interest owners	780,972	1,013,938
Other current assets	12,919,971	10,422,531
	----------------------	----------------------
Total Current Assets	63,067,360	54,385,996
	----------------------	----------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized	1,526,524,713	1,479,681,903
Unproved properties not being amortized	78,598,390	80,121,509
	----------------------	----------------------
	1,605,123,103	1,559,803,412
Furniture, fixtures and other equipment	13,508,448	12,820,622
	----------------------	----------------------
	1,618,631,551	1,572,624,034
Less--Accumulated depreciation, depletion,
and amortization	(673,288,705)	(649,185,874)
	----------------------	----------------------
	945,342,846	923,438,160
	----------------------	----------------------
Other Assets:
Deferred income taxes	---	1,666,058
Debt issuance costs	8,873,058	9,148,977
Restricted assets	1,982,124	1,933,956
	----------------------	----------------------
	10,855,182	12,748,991
	----------------------	----------------------
	$1,019,265,388	$990,573,147
	===========	===========

Liabilities and Stockholders' Equity

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

						Other Com-
		Additional		Unearned		prehensive
	Common	Paid-In	Treasury	Compen-	Retained	Income
	Stock (1)	Capital	Stock	sation	Earnings	(Loss)	Total
	-------------	---------------	------------	---------------	-----------------	-----------------	---------------
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 (509,105 shares)	5,091	4,260,882	--	--	--	--	4,265,973
Tax benefits from exercise of stock options	--	1,956,555	--	--	--	--	1,956,555
Employee stock purchase plan (50,418 shares)	504	502,097	--	--	--	--	502,601
Issuance of restricted stock	--	1,785,262	--	(1,785,262)	--	--	--
Amortization of restricted stock	--	--	--	56,677	--	--	56,677
Net income	--	--	--	--	68,450,917	--	68,450,917
Other comprehensive income	--	--	--	--	--	720,007	720,007
							---------------
Total comprehensive income	--	--	--	--	--	--	69,170,924
	-------------	---------------	------------	---------------	-----------------	-----------------	---------------
Balance, March 31, 2004	$ 285,706	$ 343,536,298	$(6,896,245)	$(1,728,585)	$138,524,301	$450,665	$ 474,172,140
	=========	=========	=========	==========	==========	==========	=========
Stock issued for benefit plans (31,424 shares)	--	435,134	450,659	--	--	--	885,793
Stock options exercised (111,904 shares)	1,119	851,103	--	--	--	--	852,222
Tax benefits from exercise of stock options	--	552,778	--	--	--	--	552,778
Issuance of restricted stock	--	104,150	--	--	--	--	104,150
Amortization of restricted stock	--	--	--	85,008	--	--	85,008
Net income	--	--	--	--	25,689,152	--	25,689,152
Other comprehensive loss	--	--	--	--	--	(1,007,042)	(1,007,042)
							---------------
Total comprehensive income	--	--	--	--	--	--	24,682,110
	-------------	---------------	------------	---------------	-----------------	-----------------	---------------
Balance, March 31, 2005	$ 286,825	$ 345,479,463	$(6,445,586)	$(1,643,577)	$164,213,453	$(556,377)	$ 501,334,201
	=========	=========	=========	==========	==========	==========	=========

(1) $.01 Par Value


See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) GENERAL INFORMATION

 

The condensed consolidated financial statements included herein have been prepared by Swift Energy Company and 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 condensed 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

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. 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, 2005 and 2004, such internal costs capitalized totaled $4.1 million and $2.9 million, respectively. Interest costs are also capitalized to unproved oil and gas properties. For the three months ended March 31, 2005 and 2004, capitalized interest on unproved properties totaled $1.8 million, and $1.6 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 both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, 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, and the period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures, and other equipment, held at cost, are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between three and 20 years. 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 Properties” and therefore subject to amortization. G&G costs incurred that are directly associated with specific unproved properties are capitalized in “Unproved properties” 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, capitalized asset retirement obligations, net of related salvage values and deferred income taxes, and excluding the recognized asset retirement obligation liability is limited to the sum of the estimated future net revenues from proved properties, excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, 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, 2005 consisted mainly of natural gas and crude oil price floors with strike prices lower than the period end price and thus did not materially affect prices used in this calculation. This calculation is done on a country-by-country basis.

The calculation of the Ceiling Test and provision for depreciation, depletion, and amortization (“DD&A) 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 estimates. 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 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 inland waters and onshore oil and natural gas reserves in Louisiana and Texas, as well as oil and natural gas reserves in New Zealand. Our undivided interests in gas processing plants, and investments in oil and gas limited partnerships where we are the general partner 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 accompanying consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements.

Revenue Recognition

 

Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Processing costs for natural gas and natural gas liquids (NGLs) that are paid in-kind are deducted from revenues. The Company uses the entitlement method of accounting in which the Company recognizes its ownership interest in production as revenue. If our sales exceed our ownership share of production, the natural gas balancing payables are reported in “Accounts payable and accrued liabilities” on the accompanying balance sheet. Natural gas balancing receivables are reported in “Other current assets” on the accompanying balance sheet when our ownership share of production exceeds sales. As of March 31, 2005, we did not have any material natural gas imbalances.

Accounts Receivable

 

Included in the “Accounts receivable” balance, which totaled $40.4 million and $39.0 million at March 31, 2005 and December 31, 2004, respectively, on the accompanying balance sheets, is approximately $2.3 million of receivables related to hydrocarbon volumes produced from 2001 and 2002 that have been disputed since early 2003. As a result of the dispute, we did not record a receivable with regard to any 2003 disputed volumes and our contract governing these sales expired in 2003.

We assess the collectibility of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both March 31, 2005 and December 31, 2004, we had an allowance for doubtful accounts of $0.5 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balances on the accompanying balance sheets.

Inventories

 

We value inventories at the lower of cost or market value. Cost of crude oil inventory is determined using the weighted average method and all other inventory is accounted for using the first in, first out method (“FIFO”). The major categories of inventories, which are included in “Other current assets” on the accompanying balance sheets, are shown as follows:

 

	Balance at March 31, 2005 (000’s)		Balance at December 31, 2004 (000’s)
	-----------------------------		-----------------------------
Materials, Supplies and Tubulars	$10,196		$6,417
Crude Oil	559		770
	-----------------------------		-----------------------------
Total	$10,755		$7,187
	===================		===================

 

Use of Estimates

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires us to make estimates and assumptions that affect the reported amount of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates underlying these financial statements include:

• the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties and the related present value of estimated future net cash flows there from,
• accruals related to oil and gas revenues, capital expenditures and lease operating expenses,
• the estimated future cost and timing of asset retirement obligations, and
• estimates made in our income tax calculations.

While we are not aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period during which the adjustment occurs.

Income Taxes

 

Under SFAS No. 109, “Accounting for Income Taxes,” deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. The effective tax rates for both the first quarter of 2005 and 2004 were lower than the statutory tax rates primarily due to reductions from the New Zealand statutory rate attributable to the currency effect on the New Zealand deferred tax calculation. In the first quarter of 2005, these amounts were partially offset by higher deferred state income taxes. The first quarter of 2004 included favorable corrections to tax basis amounts discovered while preparing the prior year’s tax returns. The tax laws in the jurisdictions we operate in are continuously changing and professional judgments regarding such laws can differ. The Company is currently evaluating the impact of the recently enacted American Jobs Creation Act of 2004. We do not believe this act will have a material impact in the near-term on our financial position or cash flow from operations.

Accounts Payable and Accrued Liabilities

 

Included in “Accounts payable and accrued liabilities,” on the accompanying balance sheets, at March 31, 2005 and December 31, 2004 are liabilities of approximately $4.9 million and $6.9 million, respectively, representing the amount by which checks issued, but not presented to the Company’s banks for collection, exceeded balances in the applicable disbursement bank accounts.

Accumulated Other Comprehensive Income (Loss), Net of Income Tax

 

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, 2005, we recorded $0.6 million, net of taxes of $0.3 million, of derivative losses in “Accumulated other comprehensive income (loss), net of income tax” on the accompanying balance sheet. The components of accumulated other comprehensive Income (loss) and related tax effects for the period ending March 31, 2005 were as follows:

	Gross Value			Tax Effect					Net of Tax Value
Other comprehensive income at December 31, 2004	$710,828			$(260,163)					$450,665
Change in fair value of cash flow hedges	(1,508,366)			551,264					(957,102)
Effect of cash flow hedges settled during the period	(78,646)			28,706				(49,940)
	---------------			--------------------				-------------------
Other comprehensive loss at March 31, 2005	$(876,184)			$319,807				$(556,377)
	=============			=============				=============

 

Total comprehensive income was $24.7 million and $14.6 million for the first quarter of 2005 and 2004, respectively.

Stock Based Compensation

 

We account for two stock-based compensation plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. We issued restricted stock to employees for the first time in the fourth quarter of 2004 and for the period ended March 31, 2005 we recorded expense related to these shares of $0.1 million in “General and administrative, net” on the accompanying statements of income. No stock-based employee compensation cost is reflected in net income for employee stock options, as all options granted under our plan 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, as 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,
				2005		2004
Net Income:		As Reported		$25,689,152		$14,587,854
		Stock-based employee compensation expense determined under fair value method for all awards, net of tax		(859,151)		(1,022,306)
		Pro Forma		$24,830,001		$13,565,548
Basic EPS:		As Reported		$.91		$.53
		Pro Forma