SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2006
INDEX

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2006	December 31, 2005
ASSETS
Current Assets:
Cash and cash equivalents	$55,227,167	$53,004,562
Accounts receivable --
Oil and gas sales	51,633,643	45,518,260
Joint interest owners	4,765,417	1,082,187
Other receivables	9,850,320	3,795,080
Deferred tax asset	22,130,793	---
Other current assets	18,578,260	11,655,046
	----------------------	----------------------
Total Current Assets	162,185,600	115,055,135
	----------------------	----------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties	1,802,196,935	1,731,866,298
Unproved properties	100,954,114	87,553,220
	----------------------	----------------------
	1,903,151,049	1,819,419,518
Furniture, fixtures and other equipment	20,673,961	15,313,277
	----------------------	----------------------
	1,923,825,010	1,834,732,795
Less--Accumulated depreciation, depletion,
and amortization	(791,057,946)	(755,699,056)
	----------------------	----------------------
	1,132,767,064	1,079,033,739
	----------------------	----------------------
Other Assets:
Debt issuance costs	7,733,329	8,026,780
Restricted assets	2,219,173	2,296,968
	----------------------	----------------------
	9,952,502	10,323,748
	----------------------	----------------------
	$1,304,905,166	$1,204,412,622
	===========	===========

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

			Additional								Other
	Common		Paid-in		Treasury		Unearned		Retained		Comprehensive
	Stock (1)		Capital		Stock		Compensation		Earnings		Income (Loss)		Total
	-----------------		-----------------		-----------------		-----------------		-----------------		-----------------		-----------------
Balance, December 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 (840,847 shares)	8,409		9,804,555		----		----		----		----		9,812,964
Tax benefits from exercise of stock options	----		4,366,236		----		----		----		----		4,366,236
Employee stock purchase plan (32,495 shares)	325		642,354		----		----		----		----		642,679
Issuance of restricted stock (15,000 shares)	150		----		----		----		----		----		150
Grants of restricted stock (158,500 shares)	----		6,668,608		----		(6,072,008)		----		----		596,600
Forfeitures of restricted stock	----		(367,490)		----		367,490		----		----		----
Amortization of restricted stock compensation	----		----		----		1,583,283		----		----		1,583,283
Comprehensive income:
Net income	----		----		----		----		115,778,456		----		115,778,456
Other comprehensive income	----		----		----		----		----		(520,134)		(520,134)
													-----------------
Total comprehensive income	----		----		----		----		----		----		115,258,322
	-----------------		-----------------		-----------------		-----------------		-----------------		-----------------		-----------------
Balance, December 31, 2005	$294,590		$365,085,695		$(6,445,586)		$(5,849,820)		$254,302,757		$(69,469)		$607,318,167
	===========		===========		===========		===========		===========		===========		===========
Stock issued for benefit plans (22,358 shares)	----		714,049		320,642		----		----		----		1,034,691
Stock options exercised (68,372 shares)	683		984,297		----		----		----		----		984,980
Adoption of SFAS No. 123R	----		(5,875,280)		----		5,849,820		----		----		(25,460)
Excess tax benefits from stock-based awards	-----		550,218		----		----		----		----		550,218
Issuance of restricted stock (14,180 shares)	142		(142)		----		----		----		----		---
Amortization of stock compensation	----		2,487,073		----		----		----		----		2,487,073
Comprehensive income:
Net income	----		----		----		----		37,314,506		----		37,314,506
Other comprehensive income	----		----		----		----		----		497,752		497,752
													-----------------
Total comprehensive income	----		----		----		----		----		----		37,812,258
	-----------------		-----------------		-----------------		-----------------		-----------------		-----------------		-----------------
Balance, December 31, 2006	$295,415		$363,945,910		$(6,124,944)		$              ----		$291,617,263		$428,283		$650,161,927
	===========		===========		===========		===========		===========		===========		===========

(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 Annual Report on Form 10-K as filed with the Securities and Exchange Commission.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Holding Company Structure

 

In December 2005, we implemented a holding company structure pursuant to Texas and federal law in a manner designed to be a non-taxable transaction. The new parent holding company assumed the Swift Energy Company name and its common stock and continued to trade on the New York and Pacific Stock Exchanges. The purposes of this new holding company structure are to separate Swift Energy’s domestic and international operations to better reflect management practices, to improve our economics, and to provide greater administrative and organizational flexibility. Under the new organizational structure, four new subsidiaries were formed with the Texas parent holding company wholly owning three Delaware subsidiaries, which in turn wholly own Swift Energy's operating subsidiaries. Swift Energy Operating, LLC is the operator of record for Swift Energy's domestic properties. Swift Energy's name, charter, bylaws, officers, board of directors, authorized shares and shares outstanding remain substantially identical. The Company's international operations continue to be conducted through Swift Energy International, Inc. Swift Energy amended its bank credit agreement, debt indentures and various other plans and documents to accommodate the internal reorganization, but the Company's day-to-day conduct of business was not impacted. Accordingly, there was no impact on our financial position or results of operations.

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, 2006 and 2005, such internal costs capitalized totaled $6.0 million and $4.1 million, respectively. Interest costs are also capitalized to unproved oil and gas properties. For the three months ended March 31, 2006 and 2005, capitalized interest on unproved properties totaled $2.1 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 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, 2006 consisted of natural gas and crude oil price floors with strike prices higher than the period end price but 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 its 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 onshore 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, 2006, we did not have any material natural gas imbalances.

Accounts Receivable

 

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, 2006 and December 31, 2005, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balances on the accompanying balance sheets. Receivables related to insurance reimbursement are computed in accordance with applicable accounting guidance; and we monitor our costs incurred and their collectibility under our insurance policies and believe all amounts recorded are recoverable.

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, 2006 (000’s)		Balance at December 31, 2005 (000’s)
	-----------------------------		-----------------------------
Materials, Supplies and Tubulars	$12,428		$8,494
Crude Oil	772		916
	-----------------------------		-----------------------------
Total	$13,200		$9,410
	===================		===================

 

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,
• estimates of insurance recoveries related to property damage,
• estimates of stock compensation expense,
• 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 rate for the three months ended March 31, 2006 and 2005 was higher than the U.S. Federal statutory tax rate primarily due to state income taxes, partially offset by reductions from the New Zealand statutory rate attributable to the currency effect on the New Zealand deferred tax calculation. As of March 31, 2006, we believe we will utilize all of our domestic operating loss carryforwards during the 2006 tax year, and these amounts are classified as current in the “Deferred tax asset” account on the accompanying balance sheet

Accounts Payable and Accrued Liabilities

 

Included in “Accounts payable and accrued liabilities,” on the accompanying balance sheets, at March 31, 2006 and December 31, 2005 are liabilities of approximately $12.1 million and $9.9 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, 2006, we recorded $0.4 million, net of taxes of $0.2 million, of derivative gains 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 2006 were as follows:

	Gross Value			Tax Effect					Net of Tax Value
Other comprehensive income at December 31, 2005	$(110,094)			$40,625					$(69,469)
Change in fair value of cash flow hedges	(104,721)			38,642					(66,079)
Effect of cash flow hedges settled during the period	889,687			(325,856)				563,831
	---------------			--------------------				-------------------
Other comprehensive loss at March 31, 2006	$674,872			$(246,589)