SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED March 31, 1999
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, 1999 (UNAUDITED) AND DECEMBER 31, 1998

(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, 1998, 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

 

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. 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 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 in the future.

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 such properties have been impaired. 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.

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.

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 and the limited partnerships’ oil and natural 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 1999 hedging activities through March 31, totaled approximately $344,600 with benefits of approximately $348,400 being received, resulting in a net cash inflow of approximately $3,800. The costs related to open contracts as of March 31, 1999 totaled approximately $261,900 and had a fair market value of $35,000.

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. Basic EPS has been retroactively restated in all periods presented to give recognition to the 10% stock dividend declared in October 1997 that resulted in an additional 1,494,622 shares being issued.

The calculation of diluted earnings per share ("Diluted EPS") 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). Certain of the Company’s stock options that would potentially dilute Basic EPS in the future were not included in the computation of Diluted EPS because to do so would have been antidilutive for the periods presented. Diluted EPS has also been retroactively restated for all periods presented to give effect to the 10% stock dividend. The original conversion price of the Convertible Notes of $34.6875 has been revised to $31.534 to reflect the October 1997 stock dividend declared.

New Accounting Pronouncement

 

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 allows 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. The Company is currently evaluating the new standard, but has not yet determined the impact it will have on its financial position and results of operations.

(3) BANK BORROWINGS

 

Under its new $250.0 million revolving credit facility with a syndicate of ten banks (the "New Credit Facility"), at March 31, 1999, the Company had outstanding borrowings of $141.8 million. At December 31, 1998, the Company had outstanding borrowings of $146.2 million under its borrowing arrangements. At March 31, 1999, 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 (a) the lead bank’s prime rate (7.75% at March 31, 1999) or (b) the adjusted London Interbank Offered Rate ("LIBOR") plus the applicable margin depending on the level of outstanding debt (a weighted average of 6.38% at March 31, 1999). 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 $141.8 million borrowed at March 31, 1999, $140.0 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 borrowing base is redetermined at least every six months and is currently under its May review but had not been determined as of the date of the filing of this report. The New Credit Facility will extend until August 2002.

(4) ACQUISITION OF PROPERTIES

 

In the third quarter of 1998, the Company purchased from Sonat Exploration Company ("Sonat"), a subsidiary of Sonat Inc., the Toledo Bend Properties located in Texas and Louisiana in the vicinity of Toledo Bend Lake for approximately $84.5 million in cash, with approximately $54.2 million of the total spent for producing properties, approximately $15.0 million to purchase an interest in two gas processing plants, and approximately $15.3 million to acquire leasehold properties.

As of December 31, 1998, estimated proved reserves for the Toledo Bend Properties were 130.5 Bcfe, of which approximately 58% was natural gas, and 59% was proved undeveloped. At such date the properties include 162 producing oil and natural gas wells in the Brookeland Field in Southeast Texas and the Masters Creek Field in Western Louisiana, 23 saltwater disposal wells, a 20% interest in two natural gas plants, associated production facilities, working interests in approximately 200,875 gross undeveloped (125,378 net undeveloped) acres, and approximately 114,000 undeveloped fee mineral acres. The Company has become operator of 115 of the 162 wells. The Company’s production on these properties amounted to approximately 11.6 Bcfe in 1998 and 6.4 Bcfe in the first quarter of 1999, of which 44% was natural gas in each of these periods. The two gas plants are operated by a third party and have combined capacity of 250 MMcfe per day.

This acquisition was accounted for by the purchase method and was incorporated into the Company’s results of operations in the third quarter of 1998. The following unaudited pro forma supplemental information presents consolidated results of operations as if this acquisition had occurred on January 1, 1998:

		Three months ended March 31, 1998
(Thousands, except per share amounts)		(Unaudited)
Revenue		$36,700
Net Income Before Income Taxes		$12,680
Net Income		$8,407
Per Share Amounts--
Basic		$0.51
Diluted		$0.46

(5) FOREIGN ACTIVITIES

 

New Zealand. 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. A wholly-owned subsidiary, Swift Energy New Zealand Limited, formed in late 1997, conducts the Company’s New Zealand activities and owns the interest in the permits. 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 expanded permit, the Company is obligated to and expects to drill one exploratory well prior to August 12, 1999. All other obligations under the permit have been fulfilled, including the reinterpretation of existing seismic data and the acquisition and processing of new seismic data.

On October 23, 1998, the Company entered into separate agreements with Marabella Enterprises Ltd. ("Marabella"), a subsidiary of Bligh Oil & Minerals N.L., an Australian company, to obtain from Marabella a 25% working interest in another New Zealand Petroleum Exploration Permit and for Marabella to become a 5% participant in the Company’s Permit. An exploration well on the Marabella permit commenced drilling on October 16, 1998, the results of which were unsuccessful. Accordingly, the $0.4 million costs of such well were charged against earnings in the fourth quarter of 1998. The Company has also agreed in principle to participate with Marabella in an additional permit as a 17.5% working interest owner.

At March 31, 1999, the Company’s investment in New Zealand was approximately $5.2 million and is included in the unproved properties portion of oil and gas properties.

SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

GENERAL

 

The Company’s principal corporate objectives are the accumulation of crude oil and natural gas reserves for production and sale and the enhancement of the net present value of those reserves. The Company was formed in 1979 and, commencing in 1991, the Company began to emphasize the addition of reserves through increased development and exploration drilling activity. The Company also adds reserves through strategic property acquisitions when conditions warrant such activity, as it did in the third quarter of 1998 with the purchase of the Toledo Bend Properties. This flexible strategy using both drilling and acquisitions has led to additions of reserves in excess of the Company’s production in each of the years 1996, 1997, and 1998. The Company’s revenues are primarily comprised of oil and gas sales attributable to properties in which the Company owns a direct or indirect interest.

LIQUIDITY AND CAPITAL RESOURCES

 

During the first three months of 1999, the Company relied upon its internally generated cash flows of $14.8 million to fund its capital expenditures of $13.2 million. Cash and working capital for the remainder of 1999 are expected to be provided through internally generated cash flows. During 1998, the Company relied upon $138.3 million of bank borrowings, along with its internally generated cash flows of $54.2 million, to fund capital expenditures of $183.8 million.

Net Cash Provided by Operating Activities

 

For the three month period ended March 31, 1999, net cash provided by operating activities increased by 14% to $14.8 million, as compared to $13.0 million during the first three months of 1998. The 1999 increase of $1.8 million was primarily due to the $5.3 million increase in oil and gas sales, partially offset by the $1.9 million increase in oil and gas production costs and the $1.9 million increase in interest expense.

Existing Credit Facilities

 

At March 31, 1999, the Company had outstanding borrowings of $141.8 million under its new credit facility syndicated in August 1998. At December 31, 1998, the Company had outstanding borrowings of $146.2 million under such borrowing arrangements. Currently, the new credit facility consists of a $250.0 million revolving line of credit with a $170.0 million borrowing base. The Company’s $250.0 million revolving credit facility includes, among other restrictions, requirements as to maintenance of certain minimum financial ratios (principally pertaining to working capital, debt, and equity ratios), and limitations on incurring other debt. The Company is currently in compliance with the provisions of this agreement. The new credit facility will extend until August 2002.

Working Capital

 

The Company's working capital decreased over the last three months from $3.8 million at December 31, 1998, to $1.6 million at March 31, 1999. This decrease is primarily the result of a decrease in joint interest owners receivables resulting from the Company’s decrease in drilling activity in response to the decrease in commodity prices and a capital expenditures budget based on internally generated cash flows.

Due to the nature of the Company's business highlighted above, the individual components of its working capital fluctuate considerably from period to period. The Company incurs significant working capital requirements in connection with its role as operator of approximately 836 wells and its drilling and acquisition activities. In this capacity, the Company is responsible for certain day-to-day cash management, including the collection and disbursement of oil and gas revenues and related expenses.

Common Stock Repurchase Program

 

In March 1997, the Company’s commenced a common stock repurchase program under which $13.3 million had been spent through March 31, 1999 to acquire 927,774 shares at an average cost of $14.34 per share. In March 1999, the Company used 68,318 shares of its treasury stock to fund its employer match in the 401-K. Under the current repurchase program for up to $10.0 million of the Company’s common stock which extends until June 30, 1999, the Company has used approximately $4.0 million of working capital since July 1998 to acquire 492,500 shares for an average cost of $8.04 per share.

Capital Expenditures

 

Capital expenditures for property, plant, and equipment during the first three months of 1999 were $13.2 million. These capital expenditures included: (a) $7.4 million of drilling costs, both development and exploratory, (b) $4.0 million of domestic prospect costs (principally prospect leasehold, seismic and geological costs of unproved prospects for the Company's account), (c) $1.4 million spent on field facilities and production equipment, (d) $0.2 million invested in New Zealand, with the remaining $0.2 million spent primarily for computer equipment and software and furniture and fixtures.

In the remaining nine months of 1999, the Company expects capital expenditures to be approximately $41.0 million, including investments in all areas in which investments were made during the first three months of the year as described above. Of the wells drilling in the first three months of 1999, two were completed, both as successful development wells. The Company anticipates drilling a total of 20 wells (15 development and five exploratory) in 1999.

The Company believes that 1999’s anticipated internally generated cash flows will be sufficient to finance the costs associated with its currently budgeted remaining 1999 capital expenditures.

RESULTS OF OPERATIONS – Comparison of Three Months Ended March 31, 1999 and 1998

Revenues

 

The Company’s revenues increased 30% during the first three months of 1999 as compared to the same period in 1998, due primarily to the increase in oil and gas sales, a result of the increase in production volumes, offset somewhat by the lower commodity prices.

Oil and Gas Sales

 

Oil and gas sales increased 34% to $21.1 million in the first three months of 1999, compared to $15.8 million for the comparable period in 1998. The 23% increase in natural gas production and the 273% increase in oil production were primarily the result of production from the recent Toledo Bend Properties acquisition. The Company's net sales volume in the first three months of 1999 increased by 65% or 4.6 Bcfe (billion cubic feet equivalent) over volumes in the comparable 1998 period. The increases in volume were significantly offset by a 20% decrease in natural gas prices and a 14% decrease in oil prices received between the two periods, as highlighted in the table below.

The elements of the Company’s $5.3 million increase in oil and gas sales during the first three months of 1999 included: (1) volume increases that added $9.8 million of sales from the 1.4 Bcf increase in gas sales volumes ($3.1 million) and from the 532,696 barrel increase in oil sales volumes ($6.7 million) and (2) price variances that had a $4.5 million unfavorable impact on sales due to the decrease in average gas prices received ($3.3 million), and a decrease in average oil prices received ($1.2 million). Oil and gas sales during the first three months of 1999 from the Toledo Bend Properties were $12.2 million (none in 1998) from 6.4 Bcfe of net sales volume, while sales from the AWP Olmos Field were $6.9 million ($8.3 million in 1998) from 3.7 Bcfe of net sales volumes (4.0 Bcfe in 1998) for a decrease of 0.3 Bcfe, while the Austin Chalk trend generated oil and gas sales of $1.5 million ($4.2 million in 1998) from 0.9 Bcfe of net sales volume (1.8 Bcfe in 1998) for a decrease of 0.9 Bcfe.

Revenues from oil and gas sales comprised 98% and 96%, respectively, of total revenues for the first three months of 1999 and 1998. The majority (62% and 84%, respectively) of these revenues were derived from the sale of the Company's gas production. The acquisition of the Toledo Bend Properties, which has a higher percentage of its production from oil, has decreased somewhat the Company’s predominate gas production mix. Even though the Company has scaled back its 1999 capital expenditures budget, the Company expects oil and gas sales volumes to increase in 1999 when compared to 1998, primarily due to the full year of production from the Toledo Bend Properties.

 The following table provides additional information regarding the Company's oil and gas sales.

Costs and Expenses

 

General and administrative expenses for the first three months of 1999 increased by approximately $0.1 million, or 11%, when compared to the same period in 1998. This increase in costs reflects the increase in the Company’s activities. However, the Company's general and administrative expenses per Mcfe produced decreased by 33% from $0.14 per Mcfe produced for the first three months of 1998 to $0.10 per Mcfe produced for the comparable period in 1999. Supervision fees netted from general and administrative expenses for the first three months of 1999 and 1998 were $0.7 million and $0.6 million, respectively.

Depreciation, depletion, and amortization ("DD&A") increased 60% (approximately $4.0 million) for the first three months of 1999, primarily due to the Company's reserves additions and associated costs and to the related sale of increased quantities (65%) of oil and gas produced therefrom. The Company's DD&A rate per Mcfe of production has decreased from $0.96 per Mcfe produced in the 1998 period to $0.93 per Mcfe produced in the 1999 period.

Production costs per Mcfe increased to $0.38 per Mcfe produced in the 1999 period from $0.36 per Mcfe produced in the 1998 period. Primarily due to the 65% increase in production volumes, oil and gas production costs increased by 75% (approximately $1.9 million) in the first three months of 1999 when compared to the first three months of 1998. Supervision fees netted from production costs for the first three months of 1999 and 1998 were $0.7 million and $0.6 million, respectively.

Interest expense on the Convertible Notes, including amortization of debt issuance costs, were the same in the first three months of 1999 and 1998, totaling $1.9 million, while interest expense on the existing credit facilities, including commitment fees and amortization of debt issuance costs, totaled $2.4 million in the 1999 period ($0.3 million in the 1998 period) for total interest charges of $4.3 million (of which $1.0 million was capitalized). In the first three months of 1998, these charges totaled $2.2 million (of which $0.8 million was capitalized). The Company capitalizes that portion of interest related to its exploration, partnership, and foreign business development activities. The increase in interest expense in 1999 is attributable to the increase in interest incurred on the amounts outstanding on its existing credit facilities.

Net Income

 

Net income of $1.3 million and Basic EPS of $0.08 for the first three months of 1999 were both 60% lower than net income of $3.2 million and Basic EPS of $0.20 in the same period for 1998. This decrease primarily reflected the effect of the 20% and 14% decrease in natural gas and oil prices while costs and expenses increased 68% in relation to the 65% increase in production volumes discussed above.

Year 2000

 

The Year 2000 issue results from computer programs and embedded computer chips with date fields that cannot distinguish between the years 1900 and 2000. The Company is currently implementing the steps necessary to make the Company’s operations capable of addressing the Year 2000. These steps include upgrading, testing, and certifying its computer systems and field operation services and obtaining Year 2000 compliance certification from the Company’s critical business suppliers, customers, venders, and other service providers. The Company formed a task force during 1998 to address the Year 2000 issue and prepare the Company’s business systems for the Year 2000. By mid-1999 the Company expects the mission critical systems to be either replaced or updated and testing to be virtually completed.

The Company’s business systems are almost entirely comprised of off-the-shelf software. Most of the necessary changes in computer instructional code can be made by upgrading such software. The Company is currently in the process of either upgrading the off-the-shelf software or receiving certification as to Year 2000 compliance from vendors or third-party consultants. A testing phase is being conducted as the software is updated or certified and is expected to be completed by mid-1999.

The Company does not believe that costs incurred to address the Year 2000 issue with respect to its business systems will have a material effect on the Company’s results of operations or its liquidity and financial condition. The estimated total cost to address Year 2000 issues is projected to be less than $150,000, most of which will be spent during the testing phase.

The failure to correct a material Year 2000 problem could result in an interruption or failure of certain normal business activities or operations. Based on activities to date, the Company believes that it will be able to resolve any Year 2000 problems concerning its financial and administrative systems. It is undeterminable how all the aspects of the Year 2000 issue will impact the Company; however, field operations and the myriad of peripheral technical applications which perform the Company’s core business functions of oil and gas exploration are primarily non-information technology systems which are not date specific and are predicted to perform correctly. The most reasonably likely worst case scenario, therefore, would involve a prolonged disruption of external power sources upon which core equipment relies, resulting in a substantial decrease in the Company’s oil and gas production activities. Although the Company maintains limited on-site secondary power supplies such as generators, it is not economically feasible to maintain a secondary power supply to fully replace primary power; therefore, a prolonged interruption could materially affect the Company’s operations, liquidity or capital resources. In addition, pipeline operators to whom the Company sells natural gas, as well as other customers and suppliers, could be prone to Year 2000 problems that could not be assessed or detected by the Company. The Company is contacting its major purchasers, customers, suppliers, financial institutions and others with whom it conducts business to determine whether they will be able to resolve in a timely manner any Year 2000 problems directly affecting the Company and to inform them of the Company’s internal assessment of its Year 2000 review. There can be no assurance that such third parties will not fail to appropriately address their Year 2000 issues or will not themselves suffer a Year 2000 disruption that could have a material adverse effect on the Company’s business, financial condition, or operating results. Based upon these responses and any problems that arise during the testing phase, contingency plans or back-up systems would be determined and addressed. The Company has utilized, and will continue to utilize, both internal and external resources to complete tasks and perform testing necessary to address the Year 2000 problem.

Forward Looking Statements

 

The statements contained in this Quarterly Report on Form 10-Q ("Quarterly Report") that are not historical facts are forward-looking statements as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, and therefore involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, capital expenditures, drilling activity, development activities, cost savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory matters and competition. Such forward-looking statements generally are accompanied by words such as "plan," "estimate," "expect," "predict," "anticipate," "projected," "should," "believe" or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and the Company’s financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by or on behalf of the Company, including those regarding the Company's financial results, levels of oil and gas production or revenues, capital expenditures, and capital resource activities. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for the Company’s oil and natural gas, the uncertainty of drilling results and reserve estimates, operating hazards, requirements for capital, general economic conditions, competition and government regulations, as well as the risks and uncertainties discussed in this Quarterly Report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in the Company’s other public reports, filings and public statements. Also, because of the volatility in oil and gas prices and other factors, interim results are not necessarily indicative of those for a full year.

SWIFT ENERGY COMPANY
PART II. - OTHER INFORMATION

Item 1. Legal Proceedings --

 

The description contained under "Item3. – Legal Proceedings" in the Company’s Form 10-K Report for the year ended December 31, 1998 is incorporated by reference herein.

Item 2. Changes in Securities and Use of Proceeds --

 

(a) Effective March 31, 1999, Swift Energy Company and American Stock Transfer & Trust Company (the "Rights Agent") amended Sections 1(b) and 1(c)(ii) of the Rights Agreement, originally dated as of August 1, 1997 (the "Rights Agreement"), and executed the Rights Agreement (as Amended and Restated as of March 31, 1999) on April 16, 1999.

Under the original Rights Agreement, the terms "Affiliate" and "Associate" are defined in Section 1(b) in the same way those terms are defined in Rule 12b-2 under the Securities Exchange Act of 1934 (the "Exchange Act"), which includes as an Associate any entity of which a person beneficially owns 10% or more of a class of the entity’s equity securities. The first change modifies this Rule 12b-2 definition as it applies to any investment adviser to only apply when a person beneficially owns 20% or more of the equity securities of an entity.

The second change to the Rights Agreement in certain circumstances excepts from the definition of "Beneficial Owner" in Section 1(c)(ii) common stock acquirable under convertible securities of the Company. Presently this definition includes, for purposes of determining whether a person owns 15% of the Company’s common stock then outstanding, any securities acquirable upon exercising conversion rights. The modification excludes from the definition of securities which are beneficially owned those acquirable under conversion rights if the market price for the Company’s common stock is not more than 50% of the conversion price of such convertible securities.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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