SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED March 31, 2002
INDEX

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

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

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

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

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

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

(1) GENERAL INFORMATION

 

The condensed 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 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

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. 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. Fees from associated oil and gas exploration and development limited partnerships are credited to oil and gas property costs to the extent they do not represent reimbursement of general and administrative expenses currently charged to expense.

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 historically the salvage value of the tangible equipment offsets 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 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 periods ended March 31, 2002 and 2001:

Three Months Ended March 31,
	2002								2001
	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	$3,019,810		24,881,604		$.12				$22,719,653		24,666,155		$.92
Stock Options	---		465,061						---		822,409
	----------------		----------						----------------		----------
Diluted EPS:
Net Income Before Cumulative Effect     of Change in Accounting Principle     and Assumed Share Conversions	$3,019,810		25,346,665		$.12				$22,719,653		25,488,564		$.89
	=======		=======		======				======		======		======

 

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, mainly the purchase of protection price floors and collars, to protect against declines in oil and gas prices. 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 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 three months of 2002 and 2001, we recognized net gains of $85,718 and net losses of $593,662 respectively, relating to our derivative activities. All of the net gains recognized in 2002 were realized because the contracts had expired, while $234,654 of the losses recognized in the comparative 2001 period were unrealized as the contracts were still open. This activity is recorded in “Price Risk Management and Other, net” on the accompanying statements of income.

At March 31, 2002, we had in place certain “costless collar” financial transactions beginning in the May 2002 contract month and in effect through the December 2002 contract month. Such derivatives qualify for cash flow hedge accounting under SFAS No.133, as amended. The crude oil collars cover notional volumes of 25,000 barrels of oil per month, with a floor price of $20.00 per barrel and a ceiling price of $27.52 per barrel, plus 60% participation by the Company in prices realized above the ceiling. The natural gas collars cover notional volumes of 200,000 MMBtu per month, with a floor price of $2.50 per MMBtu and a ceiling price of $4.21 per MMBtu, also with 60% participation by the Company in prices realized above the ceiling. The fair value of our “costless collar” transactions was zero at the transaction date and zero at March 31, 2002, as they were entered into on the last trading day of March. Since the value of the collars had not changed from inception to the end of the first quarter of 2002, no gain or loss was recognized on these transactions.

Subsequently, on April 2, 2002 we entered into additional “costless collar” transactions also beginning in the May 2002 contract month and in effect through the December 2002 contract month. The additional crude oil collars cover notional volumes of 20,000 barrels of oil per month, with a price floor of $21.00 per barrel and a ceiling price of $27.65 per barrel, plus 60% participation by the Company in prices realized above the ceiling. The additional natural gas collars cover notional volumes of 80,000 MMBtu per month, with a floor price of $2.75 per MMBtu and a ceiling price of $4.55 per MMBtu, plus 60% participation by the Company in prices realized above the ceiling.

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. We currently do not include dismantlement and abandonment costs in our depletion calculation as the vast majority of our properties are onshore and the salvage value of the tangible equipment offsets our dismantlement and abandonment costs. 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 March 31, 2002 and December 31, 2001, is as follows (in thousands):

		March 31, 2002		December 31, 2001
Bank Borrowings		$231,000		$134,000
Senior Notes		124,215		124,197
		----------		----------
Long-Term Debt		$355,215		$258,197
		=======		=======

Bank Borrowings

 

Under our $300.0 million credit facility with a syndicate of nine banks, at March 31, 2002 we had outstanding borrowings of $231.0 million and at year-end 2001 outstanding borrowings of $134.0 million. At March 31, 2002, the credit facility consisted of a $300.0 million secured revolving line of credit with a $275.0 million borrowing base. The interest rate is either (a) the lead bank’s prime rate (4.75 % at March 31, 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. Of the $231.0 million borrowed at March 31, 2002, $230.0 million was borrowed at the LIBOR rate plus applicable margin, or a total which averaged 3.53% at March 31, 2002.

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), 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. 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. Upon closing of our $200.0 million senior subordinated notes offering, on April 12, 2002, our borrowing base was reduced by $80.0 million to $195.0 million. As of April 30, 2002, our borrowings under this credit facility were $5.8 million.

Senior Notes Due 2009

 

Our Senior Notes due 2009 at March 31, 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. In addition, prior to August 1, 2002, we may redeem up to 33.33% of the Senior Notes with the proceeds of qualified offerings of our equity at 110.25% 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.

Senior Notes Due 2012

 

As described in Note 8 (“Subsequent Events”), in April 2002 we issued $200 million of Senior Subordinated Notes due 2012. The Senior Notes carry an interest rate of 9.375% and mature on May 1, 2012.

(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 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. As described in Note 8 (“Subsequent Events”), we also completed a 1,725,000 share offering of common stock in April 2002.