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

	Three months ended			Nine months ended
	09/30/00	09/30/99		09/30/00	09/30/99
	----------------	----------------		----------------	----------------
Revenues:
Oil and gas sales	$      48,716,637	$      30,737,150		$     131,403,301	$     75,405,571
Fees from limited partnerships and joint ventures	138,487	92,737		257,653	192,386
Interest income	445,396	243,998		1,084,038	267,280
Other, net	224,646	205,410		655,194	830,879
	----------------	----------------		----------------	----------------
	49,525,166	31,279,295		133,400,186	76,696,116
	----------------	----------------		----------------	----------------
Costs and Expenses:
General and administrative, net	1,649,354	1,053,655		4,256,879	3,347,941
Depreciation, depletion, and amortization	11,589,279	10,403,262		34,610,907	31,630,013
Oil and gas production	7,568,686	5,138,138		20,600,827	13,689,086
Interest expense, net	3,969,684	3,749,414		12,046,008	10,402,426
	----------------	----------------		----------------	----------------
	24,777,003	20,344,469		71,514,621	59,069,466
	----------------	----------------		----------------	----------------
Income Before Income Taxes	24,748,163	10,934,826		61,885,565	17,626,650
Provision for Income Taxes	8,915,815	3,827,189		22,250,115	6,085,231
	----------------	----------------		----------------	----------------
Net Income	$     15,832,348	$      7,107,637		$     39,635,450	$     11,541,419
	===========	===========		===========	===========
Per share amounts-
Basic:	$               0.74	$               0.37		$               1.88	$               0.67
	===========	===========		===========	===========
Diluted:	$               0.66	$               0.36		$               1.71	$               0.67
	===========	===========		===========	===========
Weighted Average Shares Outstanding	21,347,883	19,069,848		21,068,015	17,125,937
	===========	===========		===========	===========

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, 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 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 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 to present value at 10% per annum, 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 countries that do not have 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, 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.

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. Such estimates are based on management’s best information at the time and accordingly, actual results in the subsequent reporting period 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”) 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 nine-month 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 and nine-month periods ended September 30, 2000 and 1999:

	Three Months Ended September 30,
	2000								1999
	Net Income		Shares		Per Share Amount				Net Income		Shares		Per Share Amount
	----------		---------		--------				---------		---------		--------
Basic EPS:
Net Income and Share Amounts	$15,832,348		21,347,883		$.74				$7,107,637		19,069,848		$.37
Dilutive Securities:
6.25% Convertible Notes	1,214,904		3,646,847						1,230,527		3,646,847
Stock Options	---		817,361						---		222,286
	----------------		----------						---------------		----------		---------
Diluted EPS:
Net Income and Assumed Share   Conversions	$17,047,252		25,812,091		$.66				$8,338,164		22,938,981		$.36
	=======		=======		======				======		======		======

 

	Nine Months Ended September 30,
	2000								1999
	Net Income		Shares		Per Share Amount				Net Income		Shares		Per Share Amount
	----------		---------		--------				---------		---------		--------
Basic EPS:
Net Income and Share Amounts	$39,635,450		21,068,015		$1.88				$11,541,419		17,125,937		$.67
Dilutive Securities:
6.25% Convertible Notes	3,646,962		3,646,847						---		---
Stock Options	---		648,323						---		222,286
	----------------		----------						---------------		----------		---------
Diluted EPS:
Net Income and Assumed Share   Conversions	$43,282,412		25,363,185		$1.71				$11,541,419		17,348,223		$.67
	=======		=======		======				======		======		======

 

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” and as amended by SFAS No. 138 “Accounting for Certain Derivative Instruments and Certain Hedging Activities - an Amendment of FASB Statement No. 133”,” is effective for fiscal years beginning after June 15, 2000.

We have a policy to use derivative instruments, mainly the buying of protection price floors, to protect against price declines in oil and gas prices. We currently believe that such derivatives would qualify for hedge accounting under SFAS No.133. At September 30, 2000, our derivative contracts accounted for as hedges will expire on or before December 31, 2000. Accordingly, we currently do not expect the initial adoption of SFAS No. 133 to have a material effect on our results of operations. However, we may enter into derivative contracts in the future, primarily purchased options serving as protection price floors, to mitigate our exposure to commodity prices, which may result in increased earnings volatility under SFAS No. 133.

LONG-TERM DEBT

 

Our long-term debt as of September 30, 2000 and December 31, 1999, is as follows (in thousands):

		September 30, 2000		December 31, 1999
Bank Borrowings		$        ---		$        ---
Convertible Notes		115,000		115,000
Senior Notes		124,114		124,068
		----------		----------
Long-Term Debt		$239,114		$239,068
		=======		=======

 

Under our restated $250.0 million revolving credit facility with a syndicate of nine banks, at September 30, 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 September 30, 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 (9.5% at September 30, 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 November 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 September 30, 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 10% stock dividend in October 1997. Interest on the notes is payable semiannually on May 15 and November 15. The Convertible Notes are redeemable for cash at the option of Swift, with certain restrictions, at 103.75% of principal commencing November 16, 2000 and for a year thereafter, then declining ratably each year 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 September 30, 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 by 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.

In late 1999, our first exploratory well on this permit, the Rimu-A1 was completed, and a ten-day production draw-down/build-up test was performed. Our portion of the drilling, completion, and testing costs incurred on the Rimu-A1 through September 30, 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.

We commenced drilling the first delineation well, the Rimu-B1, on July 18, 2000. In mid-October 2000, we completed the preliminary testing phase which exclusively tested the Lower Tariki sandstone and produced at daily equivalent rates up to 1,086 barrels of oil and 1,432 thousand cubic feet of natural gas. However, due to either formation damage incurred while drilling or lower than expected permeability, the production declined over the 108 hour test period. We are considering a stimulation treatment of the Lower Tariki sandstone, a sidetrack of the well in order to achieve a more advantageous geological position in both the Upper and Lower Tariki sandstones, and/or testing other potential intervals in the well bore. Future activities will be determined subsequent to drilling and evaluation of the next delineation well, the Rimu-B2 well which commenced drilling October 24, 2000. The drilling of the first Kauri Prospect well is scheduled to begin, if consenting permits, upon the completion of drilling of the Rimu-B2 well or the Rimu-A2. Our portion of the drilling, completion, and testing costs incurred through September 30, 2000 on Rimu-B1 was approximately $4.6 million.

Additionally, we have entered into agreements with Fletcher Challenge Energy Limited whereby we will earn a 20% participating interest in permit 38718 containing approximately 57,400 acres and a 25% participating interest in permit 38730 with approximately 48,900 acres. The operator commenced drilling the Tuihu Prospect well on October 28, 2000 on permit 38718 which should take from 45 to 60 days to complete.

As of September 30, 2000, our investment in New Zealand totaled approximately $22.2 million comprised of drilling costs, seismic costs, and other such prospect generation costs. Approximately $0.7 million of such costs have been impaired, while the remaining $21.5 million is included in the unproved properties portion of oil and gas properties. All other obligations under the permit have been fulfilled.

We expect that at year-end we will record some level of reserves on our New Zealand activities based on the wells that have been drilled and the wells currently drilling. Recording of reserves will result in the reclassification of a portion of the costs associated with those booked reserves from the unproved properties portion of our oil and gas properties to the proved properties portion of our oil and gas properties. We are currently in discussions with New Zealand purchasers of oil and gas, with the intent of having marketing arrangements in place, and production on line for oil and gas sales in New Zealand on or around July 1, 2001.

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 Areas 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. Oil and gas sales attributable to properties in which we own a direct or indirect interest comprise virtually all of our revenues.

LIQUIDITY AND CAPITAL RESOURCES

 

During the first nine months of 2000, we principally relied upon our internally generated cash flows of $87.8 million to fund capital expenditures of $102.1 million. We expect that internally generated cash flows, cash on hand of $32.3 million at September 30, 2000, and a limited amount of bank debt if needed, will provide all necessary funds for capital costs and working capital for the remainder of 2000. We believe that these same sources will also provide adequate funds for currently planned capital expenditures and working capital needs in 2001.

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 nine months of 2000, net cash provided by our operating activities increased by 81% to $87.8 million, as compared to $48.6 million during the first nine months a year earlier. The increase of $39.2 million was primarily due to $56.0 million of additional oil and gas sales during the 2000 period due to commodity prices. However, this increase was partially offset by a $6.9 million increase in oil and gas production costs and a $1.6 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 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 September 30, 2000 and at December 31, 1999, we had no outstanding borrowings under our credit facility. At September 30, 2000, our credit facility was a $250.0 million revolving line of credit with a $100.0 million borrowing base. Effective October 24, 2000, our borrowing base was increased to $150.0 million. Our 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 decreased from $16.5 million at December 31, 1999, to $3.9 million at September 30, 2000, primarily due to our capital expenditures exceeding our internally generated cash flows.

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. In May 2000, we contributed 15,652 shares of common stock held as treasury stock to our Employee Stock Ownership Plan.

Capital Expenditures. During the first nine months of 2000, we used $102.1 million to fund capital expenditures for property, plant, and equipment. These capital expenditures included:

• $66.6 million for drilling costs, both development and exploratory;
• $13.0 million of domestic prospect costs, principally prospect leasehold, seismic and geological costs of unproved prospects;
• $17.1 million of producing property acquisitions, mainly additional interests in the AWP Olmos Area purchased from partnerships managed by us;
• $4.0 million invested in New Zealand;
• $0.7 million on property, plant and equipment; and
• $0.7 million spent primarily for computer equipment, software and furniture and fixtures.

In the remaining three months of 2000, we expect to make capital expenditures of approximately $50.0 to $60.0 million, including investments in all areas in which they were made during the first nine months of the year as described above. These amounts include approximately $17.0 million for property acquisitions in the Texas Gulf Coast area from a third party already underway in the fourth quarter, including both onshore properties and smaller offshore interests.

We drilled or participated in the drilling of 52 wells in the first nine months of 2000, and 44 were successful. Development wells had a success rate of 41 out of 46, while three out of six exploratory wells drilled were successful. For the remaining three months of 2000 we anticipate drilling or participating in the drilling of an additional 21 wells, made up of 16 domestic development wells and two domestic exploratory wells, one exploratory New Zealand well on the Tuihu Prospect, and two New Zealand delineation wells, the first of which was the recently completed Rimu B-1 well and the other the Rimu B-2 well that recently commenced drilling. We estimate capital expenditures for 2000 to be approximately $150.0 to $160.0 million, an increase from 1999 capital expenditures of $78.0 million. This upward adjustment in the 2000 capital expenditures budget is in response to increased cash flows resulting from the improvement in commodity prices. We believe that 2000’s anticipated internally generated cash flows, together with cash on hand, and limited bank borrowings if needed will be sufficient to finance the costs associated with our currently budgeted remaining 2000 capital expenditures.

RESULTS OF OPERATIONS -- Three Months Ended September 30, 2000 and 1999

 

Revenues. Our revenues increased 58% during the third 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 66% increase in oil prices received and the 54% increase in gas prices received.

Oil and Gas Sales. Our oil and gas sales increased 58% to $48.7 million in the third quarter of 2000, compared to $30.7 million for the comparable period in 1999. Our natural gas production increased 2% while our oil production decreased 3% resulting in a slight increase in equivalent volumes produced compared to production in the same period in 1999.

Our $18.0 million increase in oil and gas sales during the third quarter of 2000 resulted from:

• Price increases which solely attributed to the favorable increase in sales of $18.0 million, with $7.2 million of the increase coming from the increase in average oil prices received and $10.8 million coming from the increase in average gas prices received; and
• Volume increases which had no impact on sales, with $0.4 million of an increase coming from the 0.1 Bcf increase in gas sales volumes and $0.4 million of a decrease coming from the 20,789 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 third quarter periods of 2000 and 1999.

		Three Months Ended September 30,
Area		Revenues (In Millions)								N