SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED June 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			Six months ended
	06/30/02	06/30/01		06/30/02	06/30/01
	------------------	------------------		------------------	------------------
Revenues:
Oil and gas sales	$     38,331,342	$      51,113,100		$      64,944,183	$      113,808,625
Fees from limited partnerships and joint ventures	49,498	130,432		54,123	192,988
Interest income	26,531	11,514		32,293	23,853
Gain on asset disposition	---	---		7,332,668	---
Price-risk management and other, net	162,898	1,048,219		561,079	669,813
	------------------	------------------		------------------	------------------
	38,570,269	52,303,265		72,924,346	114,695,279
	------------------	------------------		------------------	------------------
Costs and Expenses:
General and administrative, net	2,597,549	2,007,754		4,871,576	3,891,985
Depreciation, depletion, and amortization	14,341,510	14,718,912		28,302,274	28,105,698
Oil and gas production	10,032,445	8,979,457		19,597,852	17,937,576
Interest expense, net	6,079,879	3,188,242		9,959,683	5,837,990
	------------------	------------------		------------------	------------------
	33,051,383	28,894,365		62,731,385	55,773,249
	------------------	------------------		------------------	------------------
Income Before Income Taxes and Cumulative Effect         of Change in Accounting Principle	5,518,886	23,408,900		10,192,961	58,922,030
Provision for Income Taxes	1,934,794	8,435,954		3,589,059	21,229,431
	------------------	------------------		------------------	------------------
Income Before Cumulative Effect of Change          in Accounting Principle	3,584,092	14,972,946		6,603,902	37,692,599
Cumulative Effect of Change in Accounting Principle         (net of taxes)	---	---		---	392,868
	------------------	------------------		------------------	------------------
Net Income	$     3,584,092	$     14,972,946		$     6,603,902	$     37,299,731
	===========	===========		===========	===========
Per Share Amounts-
Basic:  Income Before Cumulative Effect of Change                  in Accounting Principle	$               0.13	$               0.61		$               0.26	$               1.53
Cumulative Effect of Change                  in Accounting Principle	---	---		---	(0.02)
	------------------	------------------		------------------	------------------
Net Income	$                0.13	$               0.61		$               0.26	$               1.51
	===========	===========		===========	===========
Diluted:  Income Before Cumulative Effect of Change                  in Accounting Principle	$                0.13	$               0.59		$               0.25	$               1.48
Cumulative Effect of Change                  in Accounting Principle	---	---		---	(0.02)
	------------------	------------------		------------------	------------------
Net Income	$                0.13	$               0.59		$               0.25	$               1.46
	===========	===========		===========	===========
Weighted Average Shares Outstanding	26,566,357	24,722,727		25,723,981	24,694,441
	===========	===========		===========	===========

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
JUNE 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 six-month periods ended June 30, 2002 and 2001:

 

Options to purchase 2.7 million shares of common stock, at an average exercise price of $17.64 were outstanding at June 30, 2002. Approximately 1.2 million and 1.0 million options to purchase shares were not included in the computation of diluted EPS, for the three months and six months ended June 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 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 did not elect to designate our derivatives for special hedge accounting treatment and instead are using mark-to-market accounting treatment. 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 six months of 2002 and 2001, we recognized net losses of $19,879 and net gains of $293,774 respectively, relating to our derivative activities. Approximately $105,597 of the losses recognized in 2002 were unrealized as the contracts were still open, while $195,419 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 June 30, 2002, we had in place certain “costless collar” financial transactions in effect through the December 2002 contract month. Such derivatives qualify for cash flow hedge accounting under SFAS No.133, as amended. We did not elect to designate our derivatives for special hedge accounting treatment. The crude oil collars cover notional volumes of 45,000 barrels of oil per month, with floor prices ranging from $20.00 to $21.00 per barrel and ceiling prices ranging from $27.52 to $27.65 per barrel, plus 60% participation by the Company in prices realized above these ceilings. The natural gas collars cover notional volumes of 280,000 MMBtu per month, with floor prices ranging from $2.50 to $2.75 per MMBtu and ceiling prices ranging from $4.21 to $4.55 per MMBtu, also with 60% participation by the Company in prices realized above these ceilings. The fair value of our “costless collar” transactions was a liability of $79,440 for the crude oil collars and a liability of $26,157 for the natural gas collars at June 30, 2002.

New Accounting Principle

 

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” The statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. This standard will require us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company is currently evaluating the effect of adopting Statement No. 143 on its financial statements and will adopt the statement on January 1, 2003.

(3) LONG-TERM DEBT

 

Our long-term debt as of June 30, 2002 and December 31, 2001, is as follows (in thousands):

		June 30, 2002		December 31, 2001
Bank Borrowings		$        ---		$134,000
Senior Notes due 2009		124,234		124,197
Senior Notes due 2012		200,000		---
		----------		----------
Long-Term Debt		$324,234		$258,197
		=======		=======

 

The unamortized discount on the Senior Notes due 2009 was approximately $766 and $803 thousand at June 30, 2002 and December 31, 2001 respectively.

Bank Borrowings

 

Under our $300.0 million credit facility with a syndicate of nine banks, at June 30, 2002 we had no outstanding borrowings and at year-end 2001 outstanding borrowings of $134.0 million. At June 30, 2002, the credit facility consisted of a $300.0 million secured revolving line of credit with a $195.0 million borrowing base. The interest rate is either (a) the lead bank’s prime rate (4.75 % at June 30, 2002) or (b) the adjusted London Interbank Offered Rate (“LIBOR”) plus the applicable margin depending on the level of outstanding debt. The applicable margin is based on the ratio of the outstanding balance to the last calculated borrowing base. Our credit facility extends until October 1, 2005.

The terms of our credit facility include, among other restrictions, a limitation on the level of cash dividends (not to exceed $5.0 million in any fiscal year), a remaining aggregate limitation on purchases of Company stock of $15.0 million, requirements as to maintenance of certain minimum financial ratios (principally pertaining to working capital, debt, and equity ratios), and limitations on incurring other debt. Since inception, no cash dividends have been declared on our common stock. We are currently in compliance with the provisions of this agreement. The credit facility is secured by our domestic oil and gas properties. We have also pledged 65% of the stock in our two active New Zealand subsidiaries as collateral for this credit facility. The borrowing base is re-determined at least every six months and was reconfirmed on April 5, 2002 with the same $275.0 million borrowing base. The next scheduled borrowing base review is November 2002. Upon closing of our $200.0 million senior subordinated notes offering, on April 12, 2002, our borrowing base was reduced by $80.0 million, or 40% of the notes offering, to $195.0 million.

Senior Notes Due 2009

 

Our Senior Notes due 2009 at June 30, 2002, consist of $125,000,000 of 10.25% Senior Subordinated Notes due 2009. The Senior Notes were issued at 99.236% of the principal amount on August 4, 1999, and will mature on August 1, 2009. The notes are unsecured senior subordinated obligations and are subordinated in right of payment to all our existing and future senior debt, including our bank debt. Interest on the Senior Notes is payable semiannually on February 1 and August 1. On or after August 1, 2004, the Senior Notes are redeemable for cash at the option of Swift, with certain restrictions, at 105.125% of principal, declining to 100% in 2007. Upon certain changes in control of Swift, each holder of Senior Notes will have the right to require us to repurchase the Senior Notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. We are currently in compliance with the provisions of the indenture governing the Senior Notes.

Senior Notes Due 2012

 

Our Senior Notes due 2012 at June 30, 2002, consist of $200,000,000 of 9.375 % Senior Subordinated Notes due 2012. The Senior Notes were issued on April 11, 2002 and will mature on May 1, 2012. The notes are unsecured senior subordinated obligations and are subordinated in right of payment to all our existing and future senior debt, including our bank debt. Interest on the Senior Notes is payable semiannually on May 1 and November 1, with the first interest payment on November 1, 2002. On or after May 1, 2007, the Senior Notes are redeemable for cash at the option of Swift, with certain restrictions, at 104.688% of principal, declining to 100% in 2010. In addition, prior to May 1, 2005, we may redeem up to 33.33% of the Senior Notes with the proceeds of qualified offerings of our equity at 109.375% of the principal amount of the Senior Notes, together with accrued and unpaid interest. Upon certain changes in control of Swift, each holder of Senior Notes will have the right to require us to repurchase the Senior Notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. We are currently in compliance with the provisions of the indenture governing the Senior Notes.

(4) STOCKHOLDERS' EQUITY

 

In March 2002, we issued 220,000 shares of our common stock, along with cash consideration as a closing date adjustment, to acquire all of the New Zealand assets of Antrim Oil and Gas Limited (“Antrim”). These 220,000 shares, with a fair market value of $4.2 million, were issued from our treasury shares, and resulted in an increase to paid-in capital of $1.0 million and a decrease in the value of our treasury stock of $3.2 million. In April 2002, we issued 1,725,000 shares of common stock in a public offering, at a price of $18.25 per share. Gross proceeds from this offering were $31,481,250, with issuance costs of $994,906.