SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1998
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)

	Three months ended September 30,			Nine months ended September 30,
	1998	1997		1998	1997
	----------------	----------------		----------------	----------------
Revenues:
Oil and gas sales	$      23,859,065	$      16,411,619		$     55,341,980	$     48,852,796
Fees from limited partnerships and joint ventures	93,062	379,340		297,941	643,443
Interest income	32,636	414,698		95,511	2,164,874
Other, net	572,790	690,322		1,638,080	1,885,446
	----------------	----------------		----------------	----------------
	24,557,553	17,895,979		57,373,512	53,546,559
	----------------	----------------		----------------	----------------
Costs and Expenses:
General and administrative, net of reimbursement	1,058,652	932,734		2,939,076	2,741,164
Depreciation, depletion, and amortization	13,347,786	6,386,620		27,333,026	17,495,161
Oil and gas production	4,045,160	2,190,174		8,920,157	6,361,956
Interest expense, net	2,385,626	1,361,927		5,355,269	3,755,235
Write down of oil and gas properties	90,772,628	---		90,772,628	---
	----------------	----------------		----------------	----------------
	111,609,852	10,871,455		135,320,156	30,353,516
	----------------	---------------		----------------	----------------
Income Before Income Taxes	(87,052,299)	7,024,524		(77,946,644)	23,193,043
Provision (Benefit) for Income Taxes	(29,621,284)	2,338,835		(26,641,714)	7,624,402
	----------------	----------------		----------------	----------------
Net Income (Loss)	$     (57,431,015)	$      4,685,689		$     (51,304,930)	$     15,568,641
	===========	===========		===========	===========
Per share amounts-
Basic:	$               (3.50)	$               0.29		$                (3.11)	$               0.94
	===========	===========		===========	===========
Diluted:	$                (3.50)	$               0.27		$                (3.11)	$               0.88
	===========	===========		===========	===========
Weighted Average Shares Outstanding	16,419,022	16,418,385		16,481,382	16,507,694
	===========	===========		===========	===========

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, 1998 (UNAUDITED) AND DECEMBER 31, 1997

(1) GENERAL INFORMATION

 

The condensed consolidated financial statements included herein have been prepared by Swift Energy Company (the "Company") and are unaudited, except for the balance sheet at December 31, 1997, 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 management, necessary for a fair presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). The Company believes 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.

In the second quarter of 1998, the Company began netting supervision fees against general and administrative expenses and oil and gas production costs. This reclassification has been made to all periods presented. Certain other reclassifications have also been made to prior year amounts to conform to current year presentation.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Oil and Gas Properties

 

For financial reporting purposes, the Company follows 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 lease acquisitions, geological and geophysical services, drilling, completion, equipment, and certain general and administrative costs directly associated with acquisition, exploration, and development activities. The Company’s management believes this capitalization of such costs is appropriate under full-cost accounting rules. 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 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. 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 the Company's capitalized oil and gas property costs are amortized. The Company's properties are all onshore and historically the salvage value of the tangible equipment offsets the Company's site restoration and dismantlement and abandonment costs. The Company expects this relationship will continue.

The Company computes the provision for depreciation, depletion, and amortization of oil and gas properties on the unit-of-production method. Under this method, the Company computes 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 for those countries with oil and gas production. The Company currently has production in the United States only.

The cost of unproved properties not being amortized is assessed quarterly, on a country by country basis, to determine whether the value has been impaired below the capitalized cost. Domestically, any impairment assessed is added to the cost of proved properties being amortized. To the extent costs accumulated in the Company’s international initiatives are determined by management to be costs that will not result in the addition of proved reserves, any impairment is charged to income. In determining whether such costs should be impaired, the Company’s 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 the Company has an investment, and available geological and geophysical information.

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. Currently the Company has proved reserves in the United States only.

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.

As a result of low oil and gas prices at the end of September 1998, the Company reported a non-cash write down on a before-tax basis of $77.2 million ($50.9 million after tax) of its domestic properties. This is the first time in the Company’s history that a full-cost ceiling write down was necessitated.

International Properties. In addition, during the third quarter of 1998, as it does every reporting period, the Company evaluated all of its foreign unevaluated properties (a detailed description of which is included in Note 6 to the Company’s condensed consolidated financial statements), especially in light of the increased volatility in the oil and gas markets, international economic uncertainty, and turmoil in the world capital markets. Based on a detailed evaluation of foreign activities, the Company impaired the entire balance of accumulated unevaluated costs in both Venezuela and Russia.

The increased volatility in the oil and gas markets has affected the Company’s cash flows available for further exploration and has forced the Company to scale back its capital expenditures budget. All of this has been further accentuated in Venezuela by the economic crisis there, the results of which have been to diminish the availability of financing in international markets for Venezuelan projects and to worsen Venezuelan currency problems. Petroleos de Venezuela, S.A. layoffs, threatened oil worker strikes, reduced OPEC production allocations and other third quarter 1998 events highlight the problems that the oil and gas industry is encountering in Venezuela. As a result of all these and other factors, the Company decided to impair in the third quarter of 1998 all $2.8 million of costs related to its Venezuelan oil and gas exploration activities.

In addition, the Company determined, in the third quarter of 1998 to impair all $10.8 million of costs relating to its Russian activities. This impairment is attributed to not only the volatility in the oil and gas markets and the severe tightening of international credit markets as discussed above, but also to the increased political instability in Russia and the August 1998 collapse of the Russian currency. The Company believes that the economic and political situation will result in a lack of capital necessary to develop these reserves underlying the Company’s net profits interest in the near term. Although the Company continues to believe that its net profits interest is legally enforceable under international law, for all of these reasons the Company currently does not believe that realistically it will be able to recover its investment in Russia in the foreseeable future. Because of this, the Company believes that it currently does not have a reasonable basis to continue capitalization of the costs in its Russia cost center.

The combination of the full-cost ceiling test and foreign activities impairment charges reduced before-tax earnings by $90.8 million ($59.9 million after tax).

Hedging Activities

 

The Company’s revenues are primarily the result of sales of its oil and natural gas production. Market prices of oil and natural gas may fluctuate and adversely affect operating results. To mitigate some of this risk, the Company does engage periodically in certain limited hedging activities, but only to the extent of buying protection price floors for portions of its own and its limited partnerships’ oil and gas production. Costs and any benefits derived from these price floors are accordingly recorded as a reduction or increase, as applicable, in oil and gas sales revenue and were not significant for any period presented. The costs to purchase put options are amortized over the option period. The costs related to 1998 hedging activities through September 30, totaled approximately $377,000 with benefits of approximately $101,000 being received, resulting in a net cash outlay of approximately $276,000 or $0.019 per Mcfe. The Company had no open contracts at September 30, 1998.

Income Per Share

 

The Company has adopted Statement of Financial Accounting Standards (SFAS) No. 128, "Earnings per Share," which establishes new standards for computing and presenting earnings per share. Basic income per share has been computed using the weighted average number of common shares outstanding during the respective periods. Basic income per share has been retroactively restated in all periods presented to give recognition to the adoption of SFAS No. 128, as well as to give recognition to an equivalent change in capital structure as a result of a 10% stock dividend declared in October 1997 that resulted in an additional 1,494,622 shares being issued.

The calculation of diluted income per share assumes conversion of the Company’s Convertible Notes as of the beginning of the respective periods and the elimination of the related after-tax interest expense and assumes, as of the beginning of the period, exercise of stock options and warrants (using the treasury stock method). Diluted income per share has also been retroactively restated for all periods presented to give effect to the adoption of SFAS No. 128 and the 10% stock dividend. The original conversion price of the Convertible Notes of $34.6875 was revised to $31.534 to reflect the October 1997 stock dividend declared.

The following is a reconciliation of the calculation of basic and diluted earnings per share for the nine months ended September 30, 1998, and 1997:

	Three Months Ended September 30,
		1998					1997
		Net				Per Share		Net				Per Share
		Income		Shares		Amount		Income		Shares		Amount
		-----------		------------		----------		-----------		-----------		----------
Basic EPS:
Net Income (Loss) and Share
Amounts		$(57,431,015)		16,419,022		$ (3.50)		$4,685,689		16,418,385		$ 0.29
Dilutive Securities:
Convertible Notes (1)		---		---				846,005		3,646,847
Stock Options (1)		---		---				---		475,479
		-----------		-----------				-----------		-----------
Diluted EPS:
Net Income (Loss) and Assumed
Share Conversions		$(57,431,015)		16,419,022		$ (3.50)		$5,531,694		20,540,711		$ 0.27
		========		========		=======		========		========		=======

 

	Nine Months Ended September 30,
		1998					1997
		Net				Per Share		Net				Per Share
		Income		Shares		Amount		Income		Shares		Amount
		-----------		------------		----------		-----------		-----------		----------
Basic EPS:
Net Income (Loss) and Share
Amounts		$(51,304,930)		16,481,382		$ (3.11)		$15,568,641		16,507,694		$ 0.94
Dilutive Securities:
Convertible Notes (1)		---		---				2,665,253		3,646,847
Stock Options (1)		---		---				---		475,479
		-----------		-----------				-----------		-----------
Diluted EPS:
Net Income (Loss) and Assumed
Share Conversions		$(51,304,930)		16,481,382		$ (3.11)		$18,233,894		20,630,020		$ 0.88
		========		========		=======		========		========		=======

(1) The Convertible Notes and the stock options are antidilutive in the 1998 periods.

(3) BANK BORROWINGS

 

In August 1998, the Company closed its new $250.0 million revolving credit facility with a syndicate of ten banks (the "New Credit Facility"). At September 30, 1998, the Company had outstanding borrowings of $151.5 million under its New Credit Facility. At December 31, 1997, the Company had outstanding borrowings of $7.9 million under its borrowing arrangements. At September 30, 1998, the New Credit Facility consisted of a $250.0 million revolving line of credit with a $170.0 million borrowing base. The interest rate is either (i) the lead bank’s prime rate (8.5% at September 30, 1998) or (ii) adjusted LIBOR (a weighted average of 6.96% at September 30, 1998) plus the applicable margin depending on the level of outstanding debt. The applicable margin is based on the Company’s ratio of outstanding balance on the New Credit Facility to the last calculated borrowing base. Of the $151.5 million borrowed at September 30, 1998, $147.0 million was borrowed at the LIBOR rate.

The terms of the New Credit Facility include, among other restrictions, a limitation on the level of cash dividends (not to exceed $2.0 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 the Company’s common stock. The Company is currently in compliance with the provisions of this agreement. The New Credit Facility will extend until August 2002.

Previously, the Company’s credit facilities consisted of a $100.0 million revolving line of credit with a $80.0 million borrowing base and a $7.0 million revolving line of credit with a $5.1 million borrowing base. These facilities were with a two bank-group. Depending on the level of outstanding debt, the interest rate on the $100.0 million revolving line of credit was (i) either the bank’s base rate or the bank’s base rate plus 0.25% or (ii) the LIBOR rate plus 1% to plus 1.5%. The interest rate on the $7.0 million revolving line of credit was the bank’s base rate less 0.25%.

(4) NEW ACCOUNTING PRONOUNCEMENTS

 

In the first quarter of 1998, the Company adopted SFAS No. 130, "Reporting Comprehensive Income," which requires the display of comprehensive income and its components in the financial statements. Comprehensive income represents all changes in equity during the reporting period, including net income and charges directly to equity which are excluded from net income. The adoption of this statement does not have a material impact on the Company or its financial disclosures, as the Company has not historically and currently does not enter into transactions which result in charges (or credits) directly to equity (such as additional minimum pension liability changes, currency translation adjustments, and unrealized gains and losses on available for sale securities).

In April 1998, the American Institute of Certified Public Accountants issued Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities," which requires costs of start-up activities to be expensed as incurred. The statement is effective for financial statements beginning after December 15, 1998. The adoption of this standard is not expected to have a significant effect on the Company’s financial position or results of operations.

In June 1998, the Financial Accounting Standards Board issued 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) be recorded 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 allow the gains and losses on derivatives to offset related results on the hedged item in the income statements, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

SFAS No. 133 is effective for fiscal years beginning after June 15, 1999. A company may also implement SFAS No. 133 as of the beginning of any fiscal quarter after issuance (that is, fiscal quarters beginning June 16, 1998 and thereafter). SFAS No. 133 cannot be applied retroactively. SFAS No. 133 must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997 (and, at a company’s election, before January 1, 1998).

The Company has not yet quantified the impacts of adopting SFAS No. 133 on its financial statements and has not determined the timing of or method of its adoption of SFAS No.133.

(5) ACQUISITION OF PROPERTIES

 

On July 2, 1998, the Company entered into a purchase agreement to acquire from Sonat Exploration Company ("Sonat"), a subsidiary of Sonat Inc., effective April 1, 1998, certain producing oil and gas properties (the "Toledo Bend Properties") located in Texas and Louisiana in the vicinity of Toledo Bend Lake for approximately $86.1 million in cash, with a majority ($70.8 million) of the estimated purchase price at closing being allocated to proved properties, with the remaining ($15.3 million) being allocated to unproved properties. Post-closing purchase price adjustments are still being determined, but management does not expect that these adjustments will be material to the Company’s financial statements. The acquisition closed August 26, 1998.

As of April 1, 1998, estimated proved reserves for the Toledo Bend Properties were 91.1 Bcfe, of which approximately 56% was natural gas, with 1997 production of 22.0 Bcfe, of which approximately 51% was natural gas. The properties include 156 producing oil and natural gas wells in the Brookeland Field in Southeast Texas and the Masters Creek Field in Western Louisiana, 21 saltwater disposal wells, a 20% interest in two natural gas plants, associated production facilities and working interests in approximately 200,000 undeveloped net acres containing more than 50 drilling locations. The Company has become operator of 113 of the 156 wells. The two gas plants are operated by a third party and have combined capacity of 250 Mmcfe per day, and in 1997 had operating cash flow of $2.8 million.

The Toledo Bend Properties extend one of the Company’s core areas by adding producing reserves that the Company believes will significantly increase its production on a short-term basis. Furthermore, as a result of the Company’s extensive experience in other parts of the Austin Chalk trend, the Company believes that it can successfully exploit incremental drilling opportunities in the future.

This acquisition was accounted for by the purchase method and was incorporated into the Company’s results of operations during the third quarter. The following unaudited pro forma supplemental information presents consolidated results of operations as if this acquisition had occurred on January 1, 1997 (in thousands, except per share amounts):

	Nine months ended September 30,
	1998	1997
	(unaudited)
Revenue	$ 90,299	$ 96,649
Net Income Before Non-Cash Charge	$ 16,017	$ 24,758
Net Income (Loss)	$   (43,893)	$ 24,758
Per Share Amounts-
Basic	$ (2.66)	$ 1.50
Diluted	$ (2.66)	$ 1.32

 

(6) FOREIGN ACTIVITIES

 

Since October 1995, the Company has been issued two Petroleum Exploration Permits by the New Zealand Minister of Energy. The first permit covered approximately 65,000 acres in the Onshore Taranaki Basin of New Zealand’s North Island, and the second covered approximately 69,300 adjacent acres. The Company formed a wholly-owned subsidiary, Swift Energy New Zealand Limited, for the purpose of conducting its New Zealand activities and assigned its interest in the permits to that subsidiary during the third quarter of 1997. In March 1998, the Company surrendered approximately 46,400 acres covered in the first permit and the remaining acreage has been included as an extension of the area covered in the second permit. Under the terms of the