SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED March 31, 2000
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, 2000 (UNAUDITED) AND DECEMBER 31, 1999

(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, 1999, 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 generally accepted accounting principles 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 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.

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, we have proved reserves in the United States only.

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 our capitalized oil and gas property costs are amortized. Our properties are all onshore, and historically the salvage value of the tangible equipment offsets our site restoration and dismantlement and abandonment costs, which we expect to continue in the future.

We compute the provision for depreciation, depletion, and amortization of oil and gas properties on 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 for those countries with oil and gas production.

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. Any impairment assessed is added to the cost of proved properties being amortized and is therefore subject to the Ceiling Test. To the extent costs accumulated in our 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, our management evaluates, among other factors, the results of drilling, 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.

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

 

Our revenues are primarily the result of sales of our 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, we do engage periodically in certain limited hedging activities, which includes buying protection price floors and entering into participation collars for portions of our and our managed limited partnerships’ oil and natural gas production. These derivative financial instruments are placed with major financial institutions that we believe present minimum credit risk. Costs and any benefits derived from the price floors are recorded as a reduction or increase, as applicable, in oil and gas sales revenue. The costs to purchase put options are amortized over the option period. The participation collars are designated as hedges and realized gains or losses are recognized in oil and gas revenues when the associated production occurs.

The costs related to 2000 hedging activities through March 31, 2000 on both the price floors and the participating collars totaled $432,084, or $0.041 per Mcfe produced.

The costs related to 2000 hedging activities through March 31, 2000 on the price floors totaled $173,364 with no benefits having been received, resulting in a net cash outflow of $173,364, or $0.016 per Mcfe produced. The costs related to open price floor contracts as of March 31, 2000 totaled $128,250, which is our maximum exposure under these contracts. These open contracts had a fair market value of $47,500 at March 31, 2000.

At March 31, 2000, three months of participating collars had closed with our recording a loss of $258,720, or $0.025 per Mcfe produced.

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”) assumes conversion of our 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. The assumed conversion of our convertible notes has been excluded from the calculation of Diluted EPS for the 1999 period as they would have been antidilutive for that period. The following is a reconciliation of the calculation of Basic and Diluted EPS for the three-month periods ended March 31, 2000 and 1999:

	Net Income		Shares		Per Share Amount				Net Income		Shares		Per Share Amount
	----------		---------		--------				---------		---------		--------
Basic EPS:
Net Income and Share Amounts	$9,589,828		20,848,617		$.46				$1,281,755		16,156,449		$.08
Dilutive Securities:
6.25% Convertible Notes	1,218,984		3,646,847						---		---
Stock Options	---		388,706						---		---
	----------------		----------						---------------		----------		---------
Diluted EPS:
Net Income and Assumed Share   Conversions	$10,808,812		24,884,170		$.43				$1,281,755		16,156,449		$.08
	=======		=======		======				======		======		======

 

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, as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133” is effective for fiscal years beginning after June 15, 2000. We are currently evaluating the new standard, but have not yet determined the impact it will have on our financial position and results of operations.

LONG-TERM DEBT

 

Our long-term debt as of March 31, 2000 and December 31, 1999, is as follows (in thousands):

		2000		1999
Bank Borrowings		$        ---		$        ---
Convertible Notes		115,000		115,000
Senior Notes		124,083		124,068
		----------		----------
Long-Term Debt		$239,083		$239,068
		=======		=======

 

Under our restated $250.0 million revolving credit facility with a syndicate of nine banks, at March 31, 2000 and at December 31, 1999 we had no outstanding borrowings, as previous borrowings were paid in full during August 1999 with proceeds from our third quarter concurrent public offerings of senior subordinated notes and common stock. At March 31, 2000, the credit facility consisted of a $250.0 million secured revolving line of credit with a $100 million borrowing base. The interest rate is either (a) the lead bank’s prime rate (9% at March 31, 2000) 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 our outstanding balance on the credit facility to the last calculated borrowing base.

The terms of the 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 our common stock. We are 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 which had not been completed as of the date of this report. By its terms, the credit facility extends until August 2002.

Our Convertible Notes at March 31, 2000, consist of $115,000,000 of 6.25% Convertible Subordinated Notes due 2006. The Convertible Notes were issued on November 25, 1996, and will mature on November 15, 2006. The Convertible Notes are unsecured and convertible into common stock of Swift at the option of the holders at any time prior to maturity at an adjusted conversion price of $31.534 per share, subject to adjustment upon the occurrence of certain events. The original conversion price of $34.6875 was adjusted downward to reflect the October 1997 10% stock dividend. Interest on the notes is payable semiannually on May 15 and November 15, and commenced with the first payment on May 15, 1997. The Convertible Notes are redeemable for cash at the option of Swift, with certain restrictions, at 104.375% of principal, declining to 100.625% in 2005. Upon certain changes in control of Swift, if the price of our common stock is not above certain levels, each holder of Convertible Notes will have the right to require us to repurchase the Convertible Notes at 101% of the principal amount thereof, together with accrued and unpaid interest to the date of repurchase, but after the repayment of any Senior Indebtedness, as defined.

Our Senior Notes at March 31, 2000, 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, and commenced with the first payment on February 1, 2000. 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.

(3) STOCKHOLDERS' EQUITY

 

In August of 1999, we sold 4.6 million shares of common stock in a public offering for $9.75 per share, with net proceeds of approximately $42.1 million.

(4) FOREIGN ACTIVITIES

 

New Zealand. We own a petroleum exploration permit in New Zealand. 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. In March 1998, we 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, leaving us with only one expanded permit. On October 18, 1999, this expanded permit was again extended to include approximately 12,800 adjacent offshore acres. This permit now contains approximately 100,700 acres.

Our first exploratory well on this permit, the Rimu-A1 well has been completed, and a ten-day production draw-down/build-up test has been performed. Our portion of the drilling, completion, and testing costs incurred through March 31, 2000 was approximately $7.0 million. We are performing additional seismic acquisition and analysis on the permit area and are analyzing further delineation activities on the Rimu block which we expect to begin in the third quarter. All other obligations under the permit have been fulfilled.

As of March 31, 2000, our investment in New Zealand totaled approximately $13.9 million. Approximately $0.7 million of such costs have been impaired, while the remaining $13.2 million 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

 

Over the last several years, we have emphasized adding reserves through drilling activity. We also add reserves through strategic purchases of producing properties when oil and gas prices are lower and other market conditions are appropriate, as we did in the third quarter of 1998 with the purchase of the Masters Creek and Brookeland Fields from Sonat Exploration Company. In 1997, 1998, and 1999, we used this flexible strategy of employing both drilling and acquisitions to add more reserves than we depleted through production. Our revenues are primarily from oil and gas sales attributable to properties in which we own a direct or indirect interest.

LIQUIDITY AND CAPITAL RESOURCES

 

During the first three months of 2000, we relied upon our internally generated cash flows of $23.5 million to fund capital expenditures of $24.4 million. We expect internally generated cash flows, together with cash on hand, to provide funds for capital costs and working capital through the remainder of 2000.

During 1999, we primarily relied upon internally generated cash flows of $73.6 million to fund capital expenditures of $78.1 million. Capital expenditures were also partially funded with the remaining proceeds, after repayment of our bank borrowings, from our public sale of senior notes and common stock in August 1999.

Net Cash Provided by Operating Activities. For the first three months of 2000, net cash provided by our operating activities increased by 58% to $23.5 million, as compared to $14.8 million during the first three months a year earlier. The 2000 increase of $8.7 million was primarily due to $16.1 million of additional oil and gas sales. However, this increase was offset by the $1.7 million increase in oil and gas production costs and the $0.8 million increase in interest expense.

Financing Activities. In August 1999, in two concurrent public offerings, we sold $125.0 million of 10.25% Senior Subordinated Notes and 4.6 million shares of common stock for $44.9 million. The notes were issued at 99.236% of the principal amount and will mature on August 1, 2009. Proceeds from the two offerings were used to repay all of our bank borrowings of $136.0 million. The remaining proceeds were used, together with internally generated cash flows, to fund capital expenditures and working capital needs. The principal terms of these notes are more fully described in Note 3 to our condensed consolidated financial statements.

Credit Facility. At March 31, 2000 and at December 31,1999, we had no outstanding borrowings under our credit facility. At March 31, 2000, our credit facility consists of a $250.0 million revolving line of credit with a $100.0 borrowing base. Our $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. We are currently in compliance with the provisions of this agreement.

Debt Maturities. The credit facility extends until August 18, 2002. Our $115.0 million convertible notes mature November 15, 2006. Our $125.0 million senior notes mature August 1, 2009.

Working Capital. Our working capital increased from $16.5 million at December 31, 1999, to $19.4 million at March 31, 2000, primarily due to increased oil and gas sales receivables, which reflect the increase in commodity prices.

Common Stock Repurchase Program. In March 1997, we commenced a common stock repurchase program that terminated pursuant to its terms as of June 30, 1999. We spent $13.3 million to acquire 927,774 shares at an average cost of $14.34 per share. In March 1999, we used 68,318 shares of common stock held as treasury stock to fund our employer contribution in the 401(k) program for our employees.

Capital Expenditures. During the first three months of 2000, we used $24.4 million to fund capital expenditures for property, plant, and equipment. These capital expenditures included:

• $18.6 million for drilling costs, both development and exploratory;
• $3.9 million of domestic prospect costs, principally prospect leasehold, seismic and geological costs of unproved prospects for our account;
• $1.3 million invested in New Zealand;
• $0.4 million on property, plant and equipment; and
• $0.2 million spent primarily for computer equipment, software and furniture and fixtures.

In the remaining nine months of 2000, we expect to spend approximately $108.0 million on capital expenditures, including investments in all areas in which investments were made during the first three months of the year as described above. Sixteen wells were drilled in the first three months of 2000, and fourteen were successful. Twelve of the successful wells were development wells. For the remaining nine months of 2000 we anticipate drilling an additional 29 wells made up of 22 development wells, seven exploratory wells, and two delineation wells to our New Zealand Rimu well, the first of which is expected to commence drilling in the third quarter. We estimate capital expenditures for 2000 to be approximately $132 million, an increase from 1999 capital expenditures of $78 million. This upward adjustment in the 2000 capital expenditures budget is in response to the recent improvement in commodity prices. We believe that 2000’s anticipated internally generated cash flows, together with cash on hand, will be sufficient to finance the costs associated with our currently budgeted remaining 2000 capital expenditures. We also have access to bank borrowings, should they become necessary.

RESULTS OF OPERATIONS -- Three Months Ended March 31, 2000 and 1999

 

Revenues. Our revenues increased 76% during the first quarter of 2000 as compared to the same period in 1999. This increase was caused by growth in our oil and gas sales which resulted from the 151% increase in oil prices received and the 60% increase in gas prices received.

Oil and Gas Sales. Our oil and gas sales increased 76% to $37.2 million in the first quarter of 2000, compared to $21.1 million for the comparable period in 1999. Our natural gas production decreased 9% and oil production decreased 10% resulting in a 9%, or 1.1 Bcfe, decrease in volumes produced compared to production in the same period in 1999. These volume decreases were more than offset by the increased prices received. The decrease in production volumes resulted primarily from our decision to reduce development drilling during 1999 due to low oil and gas prices. Additionally, several new Masters Creek wells, with their high initial rates of production, were placed into production in late 1998 and produced strongly in the first quarter of 1999, and with drilling curtailed in 1999, not enough new production was placed online to offset the normal production decline. With the level of drilling in late 1999 and that planned for 2000, we expect that beginning in the second quarter, production quantities will be higher than production during the comparable quarters in 1999. The first quarter 2000 production of 10.5 Bcfe did represent a 3% increase over the 10.2 Bcfe produced in the fourth quarter of 1999.

Our $16.1 million increase in oil and gas sales during the first quarter of 2000 resulted from:

• Price increases which had a favorable impact on sales of $18.0 million, with $10.7 million of the increase coming from the increase in average oil prices received and $7.3 million coming from the increase in average gas prices received; offset by
• Volume decreases which had an unfavorable impact on sales of $1.9 million, with $1.1 million of the decrease coming from the 0.6 Bcf decrease in gas sales volumes and $0.8 million of the decrease coming from the 75,000 barrel decrease in oil sales volumes.

The following table provides additional information regarding the changes in the sources of our oil and gas sales and volumes from our four core areas in the first quarter periods of 2000 and 1999.

Area		Revenues (In Millions)								Net Sales Volumes (Bcfe)
----------------		------------------------								---------------------------
		2000		1999						2000		1999
		------------		-----------						---------		---------
AWP Olmos		$10.2		$6.8						3.3		3.7
Brookeland		$  3.1		$2.3						0.9		1.2
Giddings		$  2.4		$1.5						0.8		0.9
Masters Creek		$20.3		$9.9						5.0		5.3

 

Due to the decrease in the 1999 capital expenditures budget, and the resulting curtailment of drilling, the natural production decline in these fields was not offset by newly developed production. In response to improving commodity prices, drilling is on the increase and 2000 production volumes are projected to increase in subsequent quarters.

The following table provides additional information regarding our oil and gas sales:

Costs and Expenses. Our general and administrative expenses for the first quarter of 2000 increased slightly when compared to the same period in 1999. Our general and administrative expenses per Mcfe produced also increased from $0.10 per Mcfe for the first quarter of 1999 to $0.11 per Mcfe for the comparable period in 2000 as production volumes decreased as described above. Supervision fees netted from general and administrative expenses for the first quarter of 2000 were $0.9 million and for the same period of 1999 were $0.7 million.

Depreciation, depletion and amortization of our assets, or DD&A, increased 7% or approximately $0.7 million for the first quarter of 2000. This was primarily due to additions to our reserves and associated costs and to the related 9% decrease in production volumes. Our DD&A rate per Mcfe of production increased from $0.93 per Mcfe in the first quarter of 1999 to $1.09 per Mcfe in the same 2000 period.

Our production costs per Mcfe increased by $1.7 million or to $0.58 per Mcfe in the first quarter of 2000 from $0.38 per Mcfe in the same 1999 period. This rate increase was due to the 9% decrease in production volumes and the $1.7 million increase in production costs. This increase of $1.7 million primarily related to the $1.2 million increase in severance and ad valorem taxes. Severance taxes increased resulting from higher commodity prices and the expiration of certain specific well severance tax exemptions, while ad valorem taxes also increased in response to higher commodity prices. Supervision fees netted from production costs for the first quarter of 2000 were $0.9 million and for the same period of 1999 were $0.7 million.

Interest expense on our convertible notes due 2006, including amortization of debt issuance costs, was the same in the first quarter of 2000 and 1999, totaling $1.9 million. Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $0.1 million in the first quarter of 2000, compared to $2.4 million in the same 1999 period. Interest expense and discount on our newly issued senior notes due 2009, including amortization of debt issuance costs, totaled $3.3 million in 2000 only. Thus, total interest charges for the first quarter of 2000 were $5.3 million, of which $1.2 million was capitalized. In the first quarter of 1999, these charges totaled $4.3 million, of which $1.0 million was capitalized. The increase in interest expense in 2000 is attributable to the higher interest rate on our new senior notes. The capitalized portion of interest is related to our exploration, partnership and foreign business development activities.

Net Income. Our net income for the first quarter of 2000 of $9.6 million and Basic EPS of $0.46 were 648% and 475% higher than net income of $1.3 million and Basic EPS of $0.08 in the first quarter of 1999. This increase primarily reflected the effect of the increased oil and gas prices received in the 2000 period, as discussed above. The lower percentage increase in Basic EPS as compared to net income resulted from the public sale of 4.6 million shares of common stock in the third quarter of 1999.

Forward Looking Statements

 

The statements contained in this 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 our 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 us, including those regarding our 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 our 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 herein, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our 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 -- N/A

Item 2. Changes in Securities and Use of Proceeds -- N/A

Item 3. Defaults Upon Senior Securities -- N/A

Item 4. Submission of Matters to a Vote of Security Holders -- N/A

Item 5. Other Information -- N/A

Item 6. Exhibits & Reports on Form 8-K --

            (a) Documents filed as part of the report

                    (3) Exhibits

                            12    Swift Energy Company Ratio of Earnings to Fixed Charges

            (b) Reports on Form 8-K filed during the quarter ended March 31, 2000 -- N/A

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.

SWIFT ENERGY COMPANY
RATIO OF EARNINGS TO FIXED CHARGES