SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED March 31, 2001
INDEX

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

Liabilities and Stockholders' Equity

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(1) $.01 Par Value
(2) Unaudited

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2001 (UNAUDITED) AND DECEMBER 31, 2000

(1) GENERAL INFORMATION

 

The condensed consolidated financial statements included herein have been prepared by Swift Energy Company and are unaudited, except for the balance sheet at December 31, 2000, which has been prepared from the audited financial statements at that date. The financial statements reflect necessary adjustments, all of which were of a recurring nature, and are in the opinion of our management necessary for a fair presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in the latest Form 10-K and Annual Report.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Oil and Gas Properties

 

We follow the "full-cost" method of accounting for oil and gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the acquisition, exploration, and development of oil and gas reserves are capitalized. Under the full-cost method of accounting, such costs may be incurred both prior to or after the acquisition of a property and include 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 our capitalized oil and gas property costs are amortized. The vast majority of our properties are all onshore, and historically the salvage value of the tangible equipment offsets our site restoration and dismantlement and abandonment costs. We expect that this relationship will continue in the future.

We compute the provision for depreciation, depletion, and amortization of oil and gas properties 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. In determining whether such costs should be impaired, our management evaluates, among other factors, current oil and gas industry conditions, international economic conditions, capital availability, foreign currency exchange rates, the political stability in the countries in which we have an investment, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized, if any. To the extent costs accumulated in countries where there are no proved reserves, any costs determined by management to be impaired are charged to income.

Domestic Properties. At the end of each quarterly reporting period, the unamortized cost of oil and gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using current period-end prices, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“Ceiling Test”). This calculation is done on a country-by-country basis for those countries with proved reserves.

The calculation of the Ceiling Test and provision for depreciation, depletion, and amortization is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered.

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

Use of Estimates

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates.

Earnings Per Share

 

Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during the respective periods. The calculation of diluted earnings per share (“Diluted EPS”) for the 2000 period assumed conversion of our Convertible Notes as of the beginning of 2000, which occurred in December 2000, and the elimination of the related after-tax interest expense. Diluted EPS for all periods also assumes, as of the beginning of the period, exercise of stock options and warrants using the treasury stock method. The following is a reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS (before cumulative effect of change in accounting principle) for the three-month periods ended March 31, 2001 and 2000:

Three Months Ended March 31,
	2001								2000
	Net Income		Shares		Per Share Amount				Net Income		Shares		Per Share Amount
	----------		---------		--------				---------		---------		--------
Basic EPS:
Net Income Before Cumulative Effect     of Change in Accounting Principle     and Share Amounts	$22,719,653		24,666,155		$.92				$9,589,828		20,848,617		$.46
Dilutive Securities:
6.25% Convertible Notes	---		---						1,218,984		3,646,847
Stock Options	---		822,409						---		388,706
	----------------		----------						----------------		----------
Diluted EPS:
Net Income Before Cumulative Effect     of Change in Accounting Principle     and Assumed Share Conversions	$22,719,653		25,488,564		$.89				$10,808,812		24,884,170		$.43
	=======		=======		======				======		======		======

 

Price Risk Management Activities

 

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.

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. Such derivatives qualify for hedge accounting under SFAS No.133, as amended. We did not elect to designate our open contracts at December 31, 2000, for special hedge accounting treatment. We adopted SFAS No. 133 effective January 1, 2001. Accordingly, we marked our open contracts at December 31, 2000 to fair value at that date resulting in a one-time net of taxes charge of $392,868 which is recorded as a Cumulative Effect of Change in Accounting Principle. In addition, the premium of $209,007 related to such open contracts at December 31, 2000 was also charged to earnings during the first quarter. Price floor contracts entered into in February and March 2001, for portions of May through October 2001 production which were designated as cash flow hedges, resulted in another $384,655 being charged to earnings as the ineffective amount on such hedges. Together these resulted in a total $593,662 charge to earnings in the first quarter of 2001 and is recorded in Price Risk Management and Other, net on the accompanying statements of income.

The fair value of our open price floor contracts at March 31, 2001 totaled $456,963 and is included in the Other Current Assets account. We are currently monitoring proposed changes being considered by the Financial Accounting Standards Board as they relate to accounting for options that are designated for cash flow hedges, and will account for our price floors under the proposed changes on a prospective basis. We do not believe that any changes made in the accounting for our price floors will have a material affect on our financial position and results of operations.

(3) LONG-TERM DEBT

 

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

		March 31, 2001		December 31, 2000
Bank Borrowings		$   65,200		$    10,600
Senior Notes		124,146		124,129
		----------		----------
Long-Term Debt		$189,346		$134,729
		=======		=======

Bank Borrowings

 

Under our $250.0 million credit facility with a syndicate of eight banks, at March 31, 2001 and at December 31, 2000 we had outstanding borrowings of $65.2 million and $10.6 million, respectively. At March 31, 2001, the credit facility consisted of a $250.0 million secured revolving line of credit with a $200 million borrowing base. The interest rate is either (a) the lead bank’s prime rate (8.0% at March 31, 2001) or (b) the adjusted London Interbank Offered Rate (“LIBOR”) plus the applicable margin depending on the level of outstanding debt. The applicable margin is based on the ratio of the outstanding balance to the last calculated borrowing base. Of the $65.2 million borrowed at March 31, 2001, $20.0 million was borrowed at the LIBOR rate plus applicable margin that ranged from 6.21% to 6.53% at March 31, 2001.

The terms of our 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 re-determined at least every six months and was approved under its May 2001 review with the same $200 million borrowing base. By its terms, the credit facility extends until August 2002.

Senior Notes

 

Our Senior Notes at March 31, 2001, consist of $125,000,000 of 10.25% Senior Subordinated Notes due 2009. The Senior Notes were issued at 99.236% of the principal amount on August 4, 1999, and will mature on August 1, 2009. The notes are unsecured senior subordinated obligations and are subordinated in right of payment to all our existing and future senior debt, including our bank debt. Interest on the Senior Notes is payable semiannually on February 1 and August 1, 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.

(4) STOCKHOLDERS' EQUITY

 

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

(5) NEW ZEALAND ACTIVITIES

 

Swift Operated Permit. Our activity in New Zealand began in 1995 with the issuance of the first of two petroleum exploration permits. After a 1998 surrender of a portion of our permit acreage, a combining of the two permits, and a 1999 expansion of the permit, as of March 31, 2001 our permit 38719 covers approximately 100,700 acres in the Taranaki Basin of New Zealand’s North Island, with all but 12,800 acres onshore. We have a 90% working interest in this permit and have fulfilled all current obligations under this permit.

In late 1999, we completed our first exploratory well on this permit, the Rimu-A1, and a production test was performed. During the second half of 2000, we drilled and successfully tested two delineation wells, the Rimu-B1 and the Rimu-B2. In 2001, we have drilled two more delineation wells, the Rimu-A2 and Rimu-A3, which have been logged and have encountered and have pipe set over both the Upper Tariki sandstone and Upper Rimu limestone. The drilling rig moved to the Kauri prospect and commenced drilling the Kauri-A1 exploratory well in early May, which is expected to take 60 days to drill and evaluate. The completion rig was on the Rimu-B pad in April and limited production testing is underway on the Rimu-B1 and Rimu-B2. The completion rig was moved in May to the Rimu-A pad for completion of the Rimu-A1, the Rimu-A3, followed by the Rimu-A2. Production testing will follow completion activities.

We have begun construction of production and gas processing facilities, which are initially designed to handle 3,500 barrels of oil per day and 10 million cubic feet of processed natural gas per day. We recently entered into an agreement with Genesis Power Limited, a New Zealand electricity generator, for the sale to Genesis of 40 petajoules (approximately 38 billion cubic feet) of natural gas over a 10 year period. Natural gas deliveries from our Rimu discovery will begin under this contract once production and gas processing facilities are completed, which is expected by the end of this year.

Non-Operated Permits. In 1998, we entered into agreements for a 25% working interest in an exploration permit held by Marabella Enterprises Ltd., a subsidiary of Bligh Oil & Minerals, an Australian company, and a 7.5% working interest held by Antrim Oil and Gas Limited, a Canadian company in a second permit operated by Marabella. In turn, Bligh and Antrim each became 5% working interest owners in our permit 38719. Unsuccessful exploratory wells were drilled on these two permits, and we charged $400,000 against earnings in 1998 and $290,000 in 1999. All of the acreage on the permit we had a 25% working interest in was surrendered in 2000. The exploratory well on the 7.5% working interest permit has been temporarily abandoned pending further evaluation.

In 2000, we entered into agreements with Fletcher Challenge Energy Limited whereby we will earn a 20% participating interest in petroleum exploration permit 38718 containing approximately 57,400 acres and a 25% participating interest in permit 38730 with approximately 48,900 acres. In January 2001, the operator temporarily abandoned the Tuihu #1 exploratory well on permit 38718 pending further analysis. The permit now contains approximately 28,700 acres after a scheduled surrender during December 2000.

Costs Incurred. As of March 31, 2001, our investment in New Zealand totaled approximately $41.1 million. Approximately $30.0 million of our investment costs have been included in the proved properties portion of our oil and gas properties and $11.1 million is included as unproved 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 Brookeland and Masters Creek areas. We have used this flexible strategy of employing both drilling and acquisitions to add more reserves than we depleted through production.

LIQUIDITY AND CAPITAL RESOURCES

 

During the first three months of 2001, we principally relied upon our internally generated cash flows of $48.2 million and bank borrowings of $54.6 million to fund capital expenditures of $100.0 million. We expect that internally generated cash flows and a limited amount of bank debt if needed, will provide all necessary funds for capital costs and working capital for the remainder of 2001 as our capital expenditures budget called for a greater proportion of expenditures to be made in the first part of the year.

During 2000, we primarily relied upon internally generated cash flows of $128.2 million to fund capital expenditures of $173.3 million, plus use of a portion of the remaining net proceeds from our third quarter 1999 issuance of Senior Notes and common stock.

Net Cash Provided by Operating Activities. For the first three months of 2001, net cash provided by our operating activities increased by 105% to $48.2 million, as compared to $23.5 million during the first quarter of 2000. The increase of $24.7 million was primarily due to $25.5 million of additional oil and gas sales during the 2001 period due to commodity prices and a $1.4 million decrease in interest expense. However, this increase was slightly offset by a $2.8 million increase in oil and gas production costs and a $0.7 million increase in general and administrative expense.

Existing Credit Facility. At March 31, 2001 and at December 31, 2000, we had $65.2 million and $10.6 million in outstanding borrowings under our credit facility. At March 31, 2001, our credit facility consists of a $250.0 million revolving line of credit with a $200.0 million borrowing base. The borrowing base is re-determined at least every six months. 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 in compliance with the provisions of this agreement.

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

Working Capital. Our working capital decreased slightly from a working capital deficit of $22.5 million at December 31, 2000, to a working capital deficit of $23.1 million at March 31, 2001, primarily due to our capital expenditures exceeding our internally generated cash flows.

Capital Expenditures. Due to front-loading our 2001 capital expenditures budget, during the first three months of 2001, we used $100.0 million to fund capital expenditures for property, plant, and equipment. These capital expenditures included:

Domestic Activities:

• $42.0 million for drilling costs, both development and exploratory;

• $39.3 million of producing property acquisitions comprised of approximately $31.7 million on the Lake Washington Acquisition and approximately $7.6 for the purchase of additional interests in properties we operate from partnerships managed by us;

• $7.0 million of domestic prospect costs, principally prospect leasehold, seismic and geological costs of unproved prospects;

• $0.3 million on property, plant and equipment; and

• $0.2 million spent primarily for computer equipment, software and furniture and fixtures.

New Zealand Activities:

• $8.7 million on development drilling to further delineate the Rimu area;

• $1.7 million on initial stages of production facilities

• $0.7 million on prospect costs, principally seismic and geological costs; and

• $0.1 million for fixed assets.

In the remaining nine months of 2001, we expect to make capital expenditures of approximately $75.0 to $85.0 million, including investments in all areas in which they were made during the first three months of the year as described above. For the remainder of the year, our quarterly domestic drilling will decrease over the first quarter levels while in New Zealand the remainder of the year will see increased expenditures on the production facilities.

We drilled or participated in the drilling of 14 domestic wells in the first three months of 2001, and all were successful. Thirteen development wells and one exploratory well were drilled. In New Zealand the Rimu-A2 completed drilling while the Rimu-A3 commenced drilling. As of the filing of this report, the Rimu-A3 has completed drilling while the Kauri-A1 has commenced drilling. For the remaining nine months of 2001 we anticipate drilling or participating in the drilling of an additional 42 domestic wells, made up of 31 domestic development wells and 11 domestic exploratory wells. In New Zealand, current plans for the remainder of 2001 are to drill the Kauri-A1 exploratory well and another Rimu delineation well. We estimate capital expenditures for 2001 to be approximately $175.0 to $185.0 million, an increase from 2000 capital expenditures which totaled $173.0 million. We believe that 2001’s anticipated internally generated cash flows, together with our available bank borrowings will be sufficient to finance the costs associated with our currently budgeted remaining 2001 capital expenditures.

RESULTS OF OPERATIONS -- Three Months Ended March 31, 2001 and 2000

 

Revenues. Our revenues increased 65% to $62.4 million during the first quarter of 2001 as compared to revenues of $37.7 million for the same period in 2000. This increase was caused substantially by growth in our oil and gas sales that resulted from the 134% increase in gas prices received and the slight increase in oil prices received.

Oil and Gas Sales. Our oil and gas sales increased 69% to $62.7 million in the first quarter of 2001, compared to $37.2 million for the comparable period in 2000. Our natural gas production increased 2% while our oil production decreased 8% resulting in a slight decrease in equivalent volumes produced compared to production in the same period in 2000.

Our $25.5 million increase in oil and gas sales during the first quarter of 2001 resulted solely from price variances. The components of our sales increase were:

• Price variances led to an increase in sales of $26.6 million, with $26.4 million of the increase coming from the increase in average gas prices received and $0.2 million coming from the increase in average oil prices received; and

• Volume variances had a $1.1 million unfavorable impact on sales, with $1.4 million of the decrease coming from the 49,527 barrel decrease in oil sales volumes, slightly offset by an increase of $0.3 million from the 0.1 Bcfe increase in gas sales volumes.

The following table provides additional information regarding the changes in the sources of our domestic oil and gas sales and volumes from our four core areas and in total for the first quarter periods of 2001 and 2000.

		Three Months Ended March 31,
Area		Revenues (In Millions)								Net Sales Volumes (Bcfe)
----------------		------------------------								---------------------------
		2001		2000						2001		2000
		------------		-----------						---------		---------
AWP Olmos		$22.6		$10.2						3.4		3.3
Brookeland		$  6.9		$  3.1						1.1		0.9
Giddings		$  4.1		$  2.4						0.6		0.8
Masters Creek		$20.1		$20.3						3.6		5.0
Other		$  9.0		$  1.2						1.6		0.5
		------------		------------						---------		---------
Total		$62.7		$37.2						10.3		10.5

 

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 2001 increased $736,000, or 64%, when compared to the same period in 2000. Our general and administrative expenses per Mcfe produced also increased to $0.18 per Mcfe from $0.11 per Mcfe for the comparable period in 2000. Such increases are reflective of additional staffing costs as our activities increased. Supervision fees netted from general and administrative expenses were $0.8 million and $0.9 million for the three-month periods ended March 31, 2001 and 2000, respectively.

Depreciation, depletion and amortization of our assets, or DD&A, increased approximately $1.9 million, or 17%, for the first quarter of 2001. This was primarily due to additions to our reserves and increased associated costs in this three month period. Our DD&A rate per Mcfe of production increased to $1.30 per Mcfe in the first quarter of 2001 from $1.09 per Mcfe in the same 2000 period.

Our production costs increased by $2.8 million to $0.87 per Mcfe in the first quarter of 2001 from $0.58 per Mcfe in the same 2000 period. Of the $2.8 million increase, $0.8 million related to the increase in severance and ad valorem taxes, which are commodity price sensitive. Severance taxes increased primarily from the higher gas prices received and from the expiration of certain specific well severance tax exemptions. The remainder of the $2.8 million increase reflects costs associated with new wells drilled and acquired, and the related increase in costs in procuring such services in an environment where demand for such services is increasing. Supervision fees netted from production costs were $0.8 million and $0.9 million for the three-month periods ended March 31, 2001 and 2000, respectively.

Interest expense on our convertible notes due 2006, including amortization of debt issuance costs, was eliminated in the first quarter of 2001 as this debt was converted to equity and extinguished in December 2000, while in the first quarter of 2000 it totaled $1.9 million. Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $0.8 million in the first quarter