SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2001
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
SEPTEMBER 30, 2001 (UNAUDITED) AND DECEMBER 31, 2000

(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, 2000, 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 acquisition, exploration, and development 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 acquisition of leases, 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 as part of 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 that involve a significant quantity of reserves. The proceeds from the sale of oil and gas properties are generally treated as a reduction of oil and gas property costs. 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 on a property-by-property basis, 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 all onshore, and historically the salvage value of the tangible equipment offsets our site restoration and dismantlement and abandonment costs. We expect that this relationship will continue in the future.

We compute the provision for depreciation, depletion, and amortization of oil and gas properties using the unit-of-production method on a country-by-country basis for those countries with oil and gas production. 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.

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, our management evaluates, among other factors, 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, if any. To the extent costs accumulated in countries where there are no proved reserves, any costs determined by management to be impaired are charged to income.

Domestic Properties. 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 current 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.

New Zealand. Because of the delineation of our 1999 Rimu discovery with successful wells drilled in 2000, proved reserves were recognized in New Zealand as of December 31, 2000. Commencing in the fourth quarter of 2000, at the end of each quarterly reporting period a separate calculation of the Ceiling Test is made for New Zealand in the same manner as the calculation for domestic properties as described above. Given the commencement of production in New Zealand during the first nine months of 2001, the provision for depreciation, depletion, and amortization of oil and gas properties pertaining to the first nine months of 2001 has been calculated on the unit-of-production method.

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. The calculation of diluted earnings per share (“Diluted EPS”) for the 2000 period assumed conversion of our Convertible Notes as of the beginning of 2000, which conversion actually occurred in December 2000, and the elimination of the related after-tax interest expense. 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 nine-month periods ended September 30, 2001 and 2000:

Price Risk Management Activities

 

In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The Statement establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) to 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, 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 open contracts at December 31, 2000 and September 30, 2001, 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 is recorded as a Cumulative Effect of Change in Accounting Principle. During the first nine months of 2001 we recognized net gains of $1,924,931 relating to our derivative activities, of which $775,056 was unrealized. This activity is recorded in Price Risk Management and Other, net on the accompanying statements of income.

At September 30, 2001, we had open price floor contracts covering notional volumes of 3.0 million MMBtu of natural gas and 0.4 million barrels of crude oil. Natural gas price floor contracts relate to the NYMEX contract months of November and December 2001, at an average price of $2.45 per MMBtu. Crude oil price floor contracts relate to the NYMEX contract months of November and December 2001, at an average price of $21.00 per barrel. The fair value of our open price floor contracts at September 30, 2001 totaled $1,015,628 and is included in Other Current Assets on the accompanying balance sheet.

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. 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 expects to adopt the statement January 1, 2003.

(3) LONG-TERM DEBT

 

Our long-term debt as of September 30, 2001 and December 31, 2000, is as follows (in thousands):

		September 30, 2001		December 31, 2000
Bank Borrowings		$   126,300		$    10,600
Senior Notes		124,180		124,129
		----------		----------
Long-Term Debt		$250,480		$134,729
		=======		=======

 

Bank Borrowings

 

Under our $250.0 million credit facility with a syndicate of seven banks, at September 30, 2001 we had outstanding borrowings of $126.3 million and at year-end 2000 outstanding borrowings of $10.6 million. At September 30, 2001, the credit facility consisted of a $250.0 million secured revolving line of credit with a $200 million borrowing base. The interest rate is either (a) the lead bank’s prime rate (6.00% at September 30, 2001) 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 $126.3 million borrowed at September 30, 2001, $30.0 million was borrowed at the LIBOR rate plus applicable margin that equaled 4.96% at September 30, 2001.

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. The borrowing base is re-determined at least every six months and was reconfirmed in September 2001 with the same $200 million borrowing base. Effective September 28, 2001, the credit facility was extended until October 1, 2005. The credit facility syndicate was expanded to nine banks in October 2001.

Senior Notes

 

Our Senior Notes at September 30, 2001, 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.

(4) STOCKHOLDERS' EQUITY

 

In December 2000, the holders of approximately $100.0 million of our Convertible Notes converted such notes into 3,164,644 shares of our common stock, which resulted in an increase in our stockholders’ equity of approximately $97.4 million. 

(5) NEW ZEALAND ACTIVITIES

 

Swift Operated Permits. In 1996 we were issued two petroleum exploration permits in New Zealand. After a 1998 surrender of a portion of our permit acreage while combining the two permits and a 1999 expansion of the permit acreage, our permit 38719 covered approximately 100,700 acres in the Taranaki Basin of New Zealand’s North Island as of June 30, 2001, with all but 12,800 acres onshore. We have a 90% working interest in this permit and have fulfilled all current obligations. The initial five year term of the permit ended on August 12, 2001, however, under the terms of the Crown Minerals Act of 1991, we have extended our petroleum exploration permit an additional five years, by relinquishing 50% of the acreage within the permit. We have chosen to relinquish acreage on the western and eastern portions of our permit which we feel is not prospective. The acreage that we retain includes all the acreage we feel is prospective and includes our Rimu and Kauri areas as well as our Tawa and Matai prospects.

In late 1999, we completed our first exploratory well, the Rimu-A1, and a production test was performed. During the second half of 2000, we drilled and successfully tested two delineation wells, the Rimu-B1 and the Rimu-B2. In 2001, we have drilled and tested two more Rimu delineation wells, the Rimu-A2 and Rimu-A3. The Rimu-B3 well is currently drilling. Initially missing its target of the upper Tariki sands, this well did encounter hydrocarbon shows in some shallow Urenui sands as well as deeper Eocene sands. The Rimu-B3 well is being sidetracked to target the upper and lower Tariki sands. We also drilled the Kauri-A1 exploratory well and have encountered and set production casing over the Manutahi sand, the Kauri sands, the Upper Tariki sand and the Upper Rimu limestone. Initial testing of the Kauri-A1 well in the upper Tariki sand has been completed and testing of the Kauri sands will begin. The Kauri-A2 well was drilled and tested hydrocarbons in the shallow Manutahi sand. Additional testing of this well is continuing. Preparations are underway to implement sand control measures and install artificial lift equipment to allow for additional testing. Currently, the Rimu-A1, A2, A3, Rimu-B1 and B2 wells are shut in awaiting the completion of the production and gas processing facilities.

Construction continues on the production and gas processing facilities, which are initially designed to handle 3,500 barrels of oil per day and 10 million cubic feet of processed natural gas per day. The facility is expected to be operational during the first quarter of next year. We recently entered into an agreement with Genesis Power Limited (Genesis), a New Zealand state-owned enterprise, for the sale to Genesis of 40 petajoules (approximately 38 billion cubic feet) of natural gas over a 10 year period. Natural gas deliveries from our Rimu discovery will begin under this contract once the production and gas processing facilities are completed. During the first nine months of 2001 we produced and sold 81,957 barrels of oil from our New Zealand properties while we conducted production testing at the Rimu A and B pads.

In 2000, we entered into an agreement with Fletcher Challenge Energy Limited whereby we would earn a 25% participating interest in petroleum exploration permit 38730 containing approximately 48,900 acres. In May 2001, Fletcher relinquished their interest in the permit, and we then assumed 100% working interest in such permit by means of committing to an acceptable work plan. Such plan requires us to acquire a minimum of 30 kilometers of new 2D seismic data, which was shot and is being processed, and then by February 15, 2002 commit to drill a well or surrender the permit.

Non-Operated Permits. In 1998, we entered into agreements for a 25% working interest in an exploration permit, permit 38712, held by Marabella Enterprises Ltd., a subsidiary of Bligh Oil & Minerals, an Australian company, and a 7.5% working interest held by Antrim Oil and Gas Limited, a Canadian company in a second permit, permit 38716, operated by Marabella. In turn, Bligh and Antrim each became 5% working interest owners in our permit 38719. Unsuccessful exploratory wells were drilled on these two permits, and we charged $400,000 against earnings in 1998 and $290,000 in 1999. All of the acreage in permit 38712 was surrendered in 2000. The exploratory well on permit 38716 has been temporarily abandoned pending further evaluation. It is currently anticipated that this well will be re-entered and sidetracked to target a location to the west of the initial well. A five year extension was granted on permit 38716 in 2001 upon the surrender of 50% of the acreage.

In 2000, we entered into an agreement with Fletcher Challenge Energy Limited whereby we earned a 20% participating interest in petroleum exploration permit 38718 containing approximately 57,400 acres. In January 2001, the operator temporarily abandoned the Tuihu #1 exploratory well pending further analysis. The permit now contains approximately 28,700 acres after a scheduled acreage surrender during December 2000.

Costs Incurred. As of September 30, 2001, our investment in New Zealand totaled approximately $65.5 million. Approximately $34.7 million of our investment costs have been included in the proved properties portion of our oil and gas properties and $30.8 million is included as unproved properties.

(6) SEGMENT INFORMATION

 

Below is a summary of financial information by geographic area. No comparable information is presented for 2000 as we did not have oil and gas production in New Zealand during 2000.

		Domestic		New Zealand		Total
		--------------		-------------		-------------
Three months ended September 30, 2001:
Oil and gas sales		$38,387,134		$959,136		$39,346,270