This prospectus supplement relates to an effective registration statement under the Securities Act of 1933, but is not complete and may be changed. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Filed Pursuant to Rule 424(b)(2)

$150,000,000

% Senior Notes Due 2011

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          We will pay interest on the notes on each                     and                     . The first interest payment will be made on                     ,           . There is no sinking fund for the notes.

          Prior to                     , 2007, we may redeem up to 35% of the notes using proceeds from public offerings of our equity. We may redeem all of the notes prior to                     , 2008 at a price equal to 100% of the principal amount plus the applicable premium set forth in this prospectus supplement. In addition, we may redeem some or all of the notes after                     , 2008 at the redemption prices listed on page S- .

          Investing in the notes involves risks. See “Risk Factors” beginning on page S-11 of this prospectus supplement and on page 3 of the accompanying prospectus.

Underwriting

Proceeds to

Price to

Discounts and

Swift Energy

Public(1)

Commissions

Company(1)

Per Note

%

%

%

Total

$

$

$

(1)	Plus accrued interest, if any, from                 , 2004.

     Delivery of the notes, in book-entry form only, will be made on or about                     , 2004.

          Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement or the accompanying prospectus to which it relates is truthful or complete. Any representation to the contrary is a criminal offense.

Credit Suisse First Boston

Goldman, Sachs & Co.

	Jefferies & Company, Inc.

	Banc One Capital Markets, Inc.

	Deutsche Bank Securities

	CIBC World Markets

	BNP PARIBAS

The date of this prospectus supplement is                     , 2004

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[Insider Front Cover]

PICTURE

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      This document is in two parts. The first part is this prospectus supplement, which describes the terms of the notes. The second part is the accompanying prospectus, which gives more general information, some of which may not apply to the notes. In this prospectus supplement, “Swift,” “we,” “us,” and “our” refer to Swift Energy Company and its subsidiaries, unless otherwise indicated.

      If the description of the notes varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement.

      You should rely only on the information we have included or incorporated by reference in this prospectus supplement and the accompanying prospectus. We have not authorized anyone to provide you with additional or different information. If you receive any unauthorized information, you must not rely on it. We are offering to sell the notes only in states where sales are permitted. You should not assume that the information we have included in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the date of this prospectus supplement or the accompanying prospectus or that any information we have incorporated by reference is accurate as of any date other than the date of the document incorporated by reference.

      We expect that delivery of the notes will be made against payment therefor on or about                      , 2004, which will be the tenth business day following the date of pricing of the notes (such settlement code being herein referred to as “T+10”). You should recognize that trading of the notes on the date of pricing and the next seven succeeding business days may be affected by the T+10 settlement. See “Underwriting.”

      See the “Glossary of Terms” beginning on page S-99 for explanations of abbreviations and terms used in this prospectus supplement.

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TABLE OF CONTENTS

		Page
Prospectus Supplement
SUMMARY			S-1
RISK FACTORS			S-11
USE OF PROCEEDS			S-17
CAPITALIZATION			S-17
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA			S-18
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			S-21
BUSINESS AND PROPERTIES			S-31
MANAGEMENT			S-44
DESCRIPTION OF EXISTING INDEBTEDNESS			S-47
DESCRIPTION OF THE NOTES			S-49
CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS			S-90
UNDERWRITING			S-95
NOTICE TO CANADIAN RESIDENTS			S-97
LEGAL MATTERS			S-98
EXPERTS			S-98
GLOSSARY OF TERMS			S-99
CONSOLIDATED FINANCIAL STATEMENTS			F-1
Prospectus
ABOUT THIS PROSPECTUS			1
WHERE YOU CAN FIND MORE INFORMATION			1
RISK FACTORS			3
FORWARD-LOOKING STATEMENTS			4
THE COMPANY			5
RATIO OF EARNINGS TO FIXED CHARGES			6
USE OF PROCEEDS			6
DESCRIPTION OF DEBT SECURITIES			7
DESCRIPTION OF CAPITAL STOCK			15
DESCRIPTION OF DEPOSITARY SHARES			18
DESCRIPTION OF WARRANTS			19
PLAN OF DISTRIBUTION			21
LEGAL OPINIONS			22
EXPERTS			22

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INCORPORATION OF ADDITIONAL DOCUMENTS BY REFERENCE

      In addition to the documents referred to under “Where You Can Find More Information” in the accompanying prospectus, this prospectus supplement incorporates by reference our Annual Report on Form 10-K for the fiscal year ended December 31, 2003 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2004 filed by us with the Securities and Exchange Commission.

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S-8

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S-10

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RISK FACTORS

      An investment in our notes involves significant risks. You should carefully consider the following risk factors before you decide to purchase the notes. You should also carefully read and consider all of the information we have included, or incorporated by reference, in this prospectus supplement and the accompanying prospectus before you decide to purchase the notes.

Risks Relating to our Business

	Oil and natural gas prices are volatile. A substantial decrease in oil and natural gas prices would adversely affect our financial results.

      Our future financial condition, results of operations, and the value of our oil and natural gas properties depend primarily upon market prices for oil and natural gas. Oil and natural gas prices historically have been volatile and will likely continue to be volatile in the future. The recent record high oil and natural gas prices may not continue and could drop precipitously in a short period of time. The prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, worldwide economic conditions, weather conditions, import prices, political conditions in major oil producing regions, especially the Middle East, and actions taken by OPEC. A significant decrease in price levels for an extended period would negatively affect us in several ways:

	•	our cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves or increase production;
	•	certain reserves would no longer be economic to produce, leading to both lower proved reserves and cash flow;
	•	our lenders could reduce the borrowing base under our bank credit facility because of lower oil and natural gas reserve values, reducing our liquidity and possibly requiring mandatory loan repayments; and
	•	access to other sources of capital, such as equity or long term debt markets, could be severely limited or unavailable in a low price environment.

      Consequently, our revenues and profitability would suffer.

	Our level of debt could reduce our financial flexibility, and we currently have the ability to incur substantially more debt, including secured debt.

      As of March 31, 2004, after giving effect to this offering and the application of the net proceeds thereof, our total debt would have comprised approximately 47% of our total capitalization. Although our bank credit facility and indentures will limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness, we will be permitted to incur significant additional indebtedness, including secured indebtedness, in the future if specified conditions are satisfied. All borrowings under our bank credit facility will be effectively senior to the notes offered hereby to the extent of the value of the collateral securing those borrowings. Our current level of indebtedness:

	•	will require us to dedicate a substantial portion of our cash flow to the payment of interest;
	•	will subject us to a higher financial risk in an economic downturn due to substantial debt service costs;
	•	may limit our ability to obtain financing or raise equity capital in the future; and
	•	may place us at a competitive disadvantage to the extent that we are more highly leveraged than some of our peers.

      Higher levels of indebtedness would increase these risks.

S-11

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	Estimates of proved reserves are uncertain, and revenues from production may vary significantly from expectations.

      The quantities and values of our proved reserves included in this prospectus supplement and in the documents that we have incorporated by reference are only estimates and subject to numerous uncertainties. Estimates by other engineers might differ materially. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. These estimates depend on assumptions regarding quantities and production rates of recoverable oil and natural gas reserves, future prices for oil and natural gas, timing and amounts of development expenditures and operating expenses, all of which will vary from those assumed in our estimates. These variances may be significant.

      Any significant variance from the assumptions used could result in the actual amounts of oil and natural gas ultimately recovered and future net cash flows being materially different from the estimates in our reserve reports. In addition, results of drilling, testing, production, and changes in prices after the date of the estimates of our reserves may result in substantial downward revisions. These estimates may not accurately predict the present value of net cash flows from our oil and natural gas reserves.

      At December 31, 2003, approximately 41% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, which may not occur.

	If we cannot replace our reserves, our revenues and financial condition will suffer.

      Unless we successfully replace our reserves, our production will decline, resulting in lower revenues and cash flow. When oil and natural gas prices decrease, our cash flow decreases, resulting in less available cash to drill and replace our reserves and an increased need to draw on our bank credit facility.

	Drilling wells is speculative and capital intensive.

      Developing and exploring properties for oil and natural gas requires significant capital expenditures and involves a high degree of financial risk. The budgeted costs of drilling, completing, and operating wells are often exceeded and can increase significantly when drilling costs rise. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties. Moreover, the successful drilling or completion of an oil or gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.

	We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

      We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition, or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

	•	environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas, or other pollution into the environment, including groundwater and shoreline contamination;
	•	abnormally pressured formations;
	•	mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
	•	fires and explosions;

S-12

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	•	personal injuries and death; and
	•	natural disasters.

      Any of these risks could adversely affect our ability to conduct operations or result in substantial losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect our financial condition.

	We are exposed to the risk of fluctuations in foreign currencies, primarily the New Zealand dollar.

      Fluctuations in rates between the New Zealand dollar and U.S. dollar may impact our financial results from our New Zealand subsidiaries since we have receivables, liabilities, and natural gas and NGL sales contracts denominated in New Zealand dollars. We do not hedge against the risks associated with fluctuations in exchange rates. Although we may use hedging techniques in the future, we may not be able to eliminate or reduce the effects of currency fluctuations. As a result, exchange rate fluctuations could have an adverse impact on our operating results.

	We have incurred a write-down of the carrying values of our properties in the past and could incur additional write-downs in the future.

      Under the full cost method of accounting, SEC accounting rules require that on a quarterly basis we review the carrying value of our oil and gas properties on a country by country basis for possible write-down or impairment. Under these rules, capitalized costs of proved reserves may not exceed a ceiling calculated at the present value of estimated future net revenues from those proved reserves, determined using a 10% per year discount and unescalated prices in effect as of the end of each fiscal quarter. Capital costs in excess of the ceiling must be permanently written down.

      We recorded an after-tax, non-cash charge during the fourth quarter of 2001 of $63.5 million. This write-down resulted in a charge to earnings and a reduction of stockholders’ equity, but did not impact our cash flow from operating activities. If commodity prices decline or if we have downward reserve revisions, we could incur additional write-downs in the future.

	Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.

      To finance acquisitions, we may need to substantially alter or increase our capitalization through the use of our bank credit facility, the issuance of debt or equity securities, the sale of production payments, or by other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or other transactions can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. Furthermore, we may not be able to obtain external funding for any such acquisitions or other transactions or to obtain external funding on terms acceptable to us.

	Reserves on acquired properties may not meet our expectations, and we may be unable to identify liabilities associated with acquired properties or obtain protection from sellers against associated liabilities.

      Property acquisition decisions are based on various assumptions and subjective judgments that are speculative. Although available geological and geophysical information can provide information about the potential of a property, it is impossible to predict accurately a property’s production and profitability. In addition, we may have difficulty integrating future acquisitions into our operations, and they may not achieve our desired profitability objectives. Likewise, as is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except through the transferor. In many instances, title

S-13

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      In addition, our assessment of acquired properties may not reveal all existing or potential problems or liabilities, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. In the course of our due diligence, we may not inspect every well, platform, or pipeline. Inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination. We may not be able to obtain contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of acquired properties in addition to the risk that the properties may not perform in accordance with our expectations.

	Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

      We describe some of our current prospects and our plans to explore those prospects in this prospectus supplement. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities, if at all, to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects, or producing fields will be applicable to our drilling prospects.

	Our use of oil and natural gas price hedging contracts involves credit risk and may limit future revenues from price increases and expose us to risk of financial loss.

      We enter into hedging transactions for our oil and natural gas production to reduce exposure to fluctuations in the price of oil and natural gas, primarily to protect against declines in prices. Our hedges at year-end 2003 consisted of natural gas price floors with strike prices lower than the period end prices. Our hedging transactions have also consisted of financially settled crude oil and natural gas forward sales contracts with major financial institutions as well as crude oil price floors. We intend to continue to enter into these types of hedging transactions in the foreseeable future. Hedging transactions expose us to risk of financial loss in some circumstances, including if production is less than expected, the other party to the contract defaults on its obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. Hedging transactions other than floors may limit the benefit we would have otherwise received from increases in the price for oil and natural gas. Additionally, hedging transactions other than floors may expose us to cash margin requirements.

	We may have difficulty competing for oil and gas properties or supplies.

      We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and gas properties, as well as for the equipment, labor, and materials required to develop and operate such properties. Many of these competitors have financial and technological resources substantially greater than ours. The market for oil and gas properties is highly competitive and we may lack technological information or expertise available to other bidders. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition.

	Governmental laws and regulations are costly and stringent, especially those relating to environmental protection.

      Our domestic exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. These laws and regulations affect the costs, manner, and

S-14

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      Our operations outside of the United States could also be subject to similar foreign governmental controls and restrictions pertaining to protection of human health and the environment. These controls and restrictions may include the need to acquire permits, prohibitions on drilling in certain environmentally sensitive areas, performance of investigatory or remedial actions for any releases of petroleum hydrocarbons or other wastes caused by us or prior owners or operators, closure, and restoration of facility sites, and payment of penalties for violations of applicable laws and regulations.

Risks Relating to the Notes

	The notes are not secured by our assets and are effectively subordinated to all of our secured indebtedness to the extent of the value of assets securing such indebtedness.

      The notes will be our general unsecured obligations and will be effectively subordinated in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness. If we become insolvent or are liquidated, our assets that serve as collateral under our secured indebtedness would be made available to satisfy our obligations under any secured debt before any payments are made on the notes. Our obligations under our bank credit facility are secured by substantially all of our domestic assets and a majority of the capital stock of our New Zealand operating subsidiaries. As of March 31, 2004, after giving effect to this offering and the application of the net proceeds thereof, we would have $17.9 million of indebtedness outstanding under our bank credit facility with the ability to borrow up to $231.3 million of additional indebtedness under the facility. See “Description of Existing Indebtedness – Bank Credit Facility,” and “Description of the Notes – Certain Covenants – Limitation on Indebtedness.”

	Your right to receive payments on these notes is effectively subordinated to the rights of existing and future creditors of any subsidiaries that are not guarantors on the notes.

      Initially none of our subsidiaries are required to guarantee the notes offered by this prospectus supplement. In addition, we may be able to designate one or more subsidiaries in the future as unrestricted subsidiaries, which would not be required to guarantee the notes. As a result, holders of the notes will be effectively subordinated to the indebtedness and other liabilities of these subsidiaries, including trade creditors. Therefore, in the event of the insolvency or liquidation of a foreign or an unrestricted subsidiary, following payment by that subsidiary of its liabilities, such subsidiary may not have sufficient remaining assets to make payments to us as a shareholder or otherwise. In the event of a default by any such subsidiary under any credit arrangement or other indebtedness, its creditors could accelerate such debt, prior to such subsidiary distributing amounts to us that we could have used to make payments on the notes.

S-15

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	If we experience a change of control, we may be unable to repurchase the notes as required under the indenture.

      In the event of a change of control, you will have the right to require us, subject to various conditions, to repurchase the notes. We may not have sufficient financial resources to pay the repurchase price for the notes, or may be prohibited from doing so under our bank credit facility or other debt agreements.

      If a change of control occurs and we are prohibited from repurchasing the notes, our failure to do so would constitute a default under the indenture, which in turn is likely to be a default under our bank credit facility and our outstanding senior subordinated notes.

	The notes have no existing market, and a market may not develop.

      There is no existing market for the notes, and we are not applying to list the notes on any securities exchange. Therefore, no liquid market may exist for the notes at any time, which may depress the prices at which you will be able to sell your notes.

	Fraudulent conveyance considerations could avoid guarantees for the notes.

      Our domestic subsidiaries in the future may be required to guarantee our obligations under the notes if they incur indebtedness or issue preferred stock. The guarantees would be senior unsecured obligations of such subsidiaries. Under fraudulent conveyance laws, a court might subordinate or avoid any guarantees of the notes by our subsidiaries in favor of a subsidiary’s other debts or liabilities. To the extent a subsidiary’s guarantee of the notes is avoided as a result of fraudulent conveyance laws or held unenforceable for any other reason, you would receive no payments under that subsidiary’s guarantee and would be creditors solely of us and any subsidiaries whose guarantees were not avoided.

S-16

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USE OF PROCEEDS

      We will receive net proceeds from this offering of approximately $146.0 million, after deducting estimated expenses and the underwriters’ discounts. We intend to use approximately $131.4 million of the net proceeds to repurchase our outstanding 10 1/4% senior subordinated notes due 2009, either through a tender offer or redemption or combination thereof. We intend to use the remainder to repay indebtedness under our bank credit facility and for general corporate purposes. Prior to the repurchase of our 10 1/4% senior subordinated notes due 2009, we intend to use a portion of the net proceeds to repay all outstanding indebtedness under our bank credit facility.

      At May 31, 2004, the outstanding balance under our bank credit facility was approximately $31.9 million, excluding letters of credit, with an average interest rate of 2.45%, and we had approximately $217.3 million of borrowing capacity available. During the last year, funds were drawn on our bank credit facility to accelerate our drilling program and for general corporate purposes.

CAPITALIZATION

      The following table sets forth our consolidated cash and cash equivalents and capitalization as of March 31, 2004 on a historical basis and as adjusted to give effect to this offering and the application of the estimated net proceeds as described above under “Use of Proceeds.” You should read this table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Description of Existing Indebtedness,” and the consolidated financial statements and the notes thereto appearing elsewhere in this prospectus supplement.

				As of March 31, 2004
				Historical				As Adjusted(1)
				(In thousands)
Cash and cash equivalents				$	4,399			$	4,399
Debt:
	Bank borrowings				32,500				17,906
	10 1/4% senior subordinated notes due 2009				124,377				—
	9 3/8% senior subordinated notes due 2012				200,000				200,000
	% senior notes offered hereby				—				150,000
		Total debt		$	356,877			$	367,906
Total stockholders’ equity					413,827				407,861
		Total capitalization		$	770,704			$	775,768

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(1)		Assumes redemption of the outstanding principal amount of our 10 1/4% senior subordinated notes due 2009, plus a redemption premium of $6.4 million.

S-17

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

      The selected historical consolidated financial data presented below as of and for each of the five years ended December 31, 2003 has been derived from our audited consolidated financial statements. The selected historical consolidated financial data as of and for each of the three months ended March 31, 2004 and 2003 has been derived from our unaudited consolidated financial statements. For a discussion of our significant financial results and conditions during 2003, 2002, and 2001 and the three month periods ended March 31, 2004 and 2003, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this prospectus supplement.

				Three Months Ended
				March 31,								Year Ended December 31,
				2004				2003				2003				2002				2001				2000				1999
				(In thousands, except ratios)
Income Statement Data:
Revenues:
	Oil and gas sales			$	65,954			$	54,850			$	211,033			$	141,196			$	181,185			$	189,139			$	108,899
	Gain on asset disposition				—				—				—				7,333				—				—				—
	Price risk management and other, net				(598	)			(1,350	)			(2,132	)			1,441				2,622				2,486				1,772
		Total revenues			65,356				53,500				208,901				149,970				183,807				191,625				110,671
Costs and expenses:
	General and administrative, net of reimbursement				4,030				3,557				14,097				10,565				8,187				5,586				4,497
	Depreciation, depletion, and amortization				18,296				14,912				63,072				56,224				59,502				47,771				42,349
	Accretion of asset retirement obligation				170				215				857				—				—				—				—
	Lease operating costs				9,626				7,313				33,833				29,656				24,990				19,227				13,736
	Severance and other taxes				6,247				4,594				19,034				11,841				11,730				9,993				5,910
	Interest expense, net				6,901				6,685				27,269				23,275				12,627				15,968				14,443
	Other expenses				—				—				—				—				2,102				984				—
	Write-down of oil and gas properties(1)				—				—				—				—				98,862				—				—
		Total costs and expenses			45,270				37,276				158,162				131,562				218,000				99,530				80,935
Income (loss) before income taxes and change in accounting principle					20,086				16,224				50,739				18,408				(34,193	)			92,095				29,736
Provision (benefit) for income taxes					5,498				5,739				16,469				6,485				(12,238	)			32,911				10,450
Income (loss) before change in accounting principle					14,588				10,485				34,271				11,923				(21,955	)			59,184				19,286
Cumulative effect of change in accounting principle (net of taxes)(2)					—				4,377				4,377				—				393				—				—
Net income (loss)				$	14,588			$	6,108			$	29,894			$	11,923			$	(22,348	)		$	59,184			$	19,286
Other Financial Data:
EBITDA(3)				$	45,454			$	38,036			$	141,937			$	90,575			$	136,799			$	155,835			$	86,528
Net cash provided by operating activities					39,596				26,799				110,827				71,626				139,884				128,197				73,603
Capital expenditures					45,150				26,335				144,503				155,234				275,126				173,277				78,113
Ratio of earnings to fixed charges(4)					3.2	x			2.7	x			2.3	x			1.4	x			—				5.2	x			2.4	x
Ratio of EBITDA to cash interest(3)(5)					6.6	x			5.7	x			4.3	x			3.5	x			7.4	x			7.5	x			6.6	x
Balance Sheet Data (at end of period):
Working capital (deficit)				$	(15,370	)		$	(5,247	)		$	(35,099	)		$	(17,116	)		$	(36,492	)		$	(22,452	)		$	16,535
Total assets					886,369				786,549				859,839				767,006				671,683				572,387				454,299
Long term debt:
	Bank borrowings				32,500				5,700				15,900				—				134,000				10,600				—
	6 1/4% convertible subordinated notes				—				—				—				—				—				—				115,000
	10 1/4% senior subordinated notes				124,377				124,292				124,355				124,272				124,197				124,129				124,068
	9 3/8% senior subordinated notes				200,000				200,000				200,000				200,000				—				—				—
Stockholders’ equity					413,827				371,856				397,391				365,073				312,653				332,154				170,404

S-18

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(1)		Due primarily to a decline in prices for both oil and gas in the fourth quarter of 2001 a pre-tax domestic full cost ceiling write-down of oil and gas properties of $98.9 million, or $63.5 million after-tax, was necessary at December 31, 2001.
(2)		We adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” effective January 1, 2001 resulting in a one- time net of taxes charge of $0.4 million in the first quarter of 2001, which is recorded as a cumulative effect of change in accounting principle. We adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003. Our adoption of SFAS No. 143 resulted in a one-time net of taxes charge of $4.4 million in the first quarter of 2003, which is recorded as a cumulative effect of change in accounting principle.
(3)		EBITDA represents income before interest expense, income tax, depreciation, depletion, and amortization, write-down of oil and gas properties, accretion of asset retirement obligation, and gain on asset disposition. We have reported EBITDA because we believe EBITDA is a measure commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. We believe EBITDA assists such investors in comparing a company’s performance on a consistent basis without regard to depreciation, depletion and amortization, which can vary significantly depending upon accounting methods or nonoperating factors such as historical cost. EBITDA is not a calculation based on GAAP and should not be considered an alternative to net income in measuring our performance or used as an exclusive measure of cash flow. Investors should carefully consider the specific items included in our computation of EBITDA. While EBITDA has been disclosed herein to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, investors should be cautioned that EBITDA as reported by us may not be comparable in all instances to EBITDA as reported by other companies. EBITDA amounts may not be fully available for management’s discretionary use, due to certain requirements to conserve funds for capital expenditures, debt service and other commitments. The definition of EBITDA stated herein differs from the definition of EBITDA applicable to the covenants for the notes, in that the notes definition makes certain exclusions to net income, some of which would reduce EBITDA. See “Description of the Notes – Certain Definitions – Consolidated Net Income” and “– EBITDA.”
		EBITDA is not intended to represent net income as defined by GAAP and such information should not be considered as an alternative to net income, cash flow from operations or any other measure of performance prescribed by GAAP in the United States. The following table reconciles net income to EBITDA for the periods presented:

		Three Months
		Ended
		March 31,								Year Ended December 31,
		2004				2003				2003				2002				2001				2000				1999
		(In thousands)
Net income (loss)		$	14,588			$	6,108			$	29,894			$	11,923			$	(22,348	)		$	59,184			$	19,286
Provision (benefit) for income taxes			5,498				5,739				16,469				6,485				(12,238	)			32,911				10,450
Cumulative effect of change in accounting principle (net of taxes)			—				4,377				4,377				—				393				—				—
Interest expense, net			6,901				6,685				27,269				23,275				12,627				15,968				14,443
Depreciation, depletion, and amortization, and accretion of asset retirement obligation			18,466				15,127				63,929				56,224				59,502				47,771				42,349
Gain on asset disposition			—				—				—				(7,333	)			—				—				—
Write-down of oil and gas properties			—				—				—				—				98,862				—				—
EBITDA		$	45,454			$	38,036			$	141,937			$	90,575			$	136,799			$	155,835			$	86,528

(4)		For purposes of calculating the ratio of earnings to fixed charges, fixed charges include interest expense, capitalized interest, amortization of debt issuance costs and that portion of non-capitalized rental expense deemed to be the equivalent of interest. Earnings represents income before income taxes from continuing operations before fixed charges. Due to the $98.9 million charge incurred in 2001 resulting from a write-down in the carrying value of natural gas and oil properties, 2001 earnings were insufficient by $40.2 million to cover fixed charges in 2001. If this non-cash charge was excluded, the ratio of earnings to fixed charges would have been 4.1x for 2001.
(5)		Cash interest is the total amount of interest paid on our obligations, including capitalized amounts.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

      You should read the following discussion and analysis in conjunction with our financial information and our consolidated financial statements and notes thereto included or incorporated by reference in this prospectus supplement. The following information contains forward-looking statements. For a discussion of limitations inherent in forward-looking statements, see “Forward-Looking Information” in the accompanying prospectus on page 4.

Overview

      For the first three months of 2004, we had revenues of $65.4 million and production of 14.3 Bcfe. Our revenues were bolstered by strong oil and natural gas prices and a 35% increase in domestic production over production in the same period in 2003. We continued to focus our efforts and capital throughout the quarter on better infrastructure, increased production and the development of longer life oil reserves in the Lake Washington area. In the first quarter of 2004, we produced over 11,300 gross (9,300 net) BOE per day in Lake Washington, compared to approximately 4,500 gross (3,700 net) BOE per day in the same period of 2003. New Zealand accounted for 3.9 Bcfe of production in the first quarter of 2004, a 25% decrease from production in the same period in 2003. Natural gas production in New Zealand declined due to minimum takes from the gas purchaser at TAWN. Increased use of hydroelectricity in New Zealand has contributed to a short-term reduction in market demand, which is expected to continue at least through the second quarter of this year. While our fields at TAWN have been able to meet minimum contracted volumes to date, it is anticipated, due to accelerated production in 2002 and 2003 along with natural production declines, that these fields will not be able to meet the minimum contracted volumes beginning in the second half of this year without additional development. These minimum contracted volumes represent the volumes of gas that the purchasers under the contracts must take if the fields produce such volumes. There is no penalty if the fields are unable to produce these minimum contracted volumes. We are currently considering drilling a development well in the Tariki field in the second half of this year, but to some extent, our ongoing activity at TAWN is affected by discussions with the gas purchaser. New Zealand natural gas and NGL contracts are denominated in the New Zealand dollar, which has significantly strengthened during the last several years against the U.S. dollar. This has resulted in increased prices for natural gas and NGLs. We continue to see a tightening natural gas market and strengthening natural gas prices in New Zealand. For 2004, we believe we are positioned for production growth of 11% to 17% and proved reserve growth of 5% to 8%, and expect commodity prices to remain strong.

      Our production costs increased in the first quarter of 2004, predominately due to increased production in Lake Washington, increased severance taxes, currency exchange rates, and maintenance activities in New Zealand. Our general and administrative expenses increased in the first quarter of 2004, predominantly due to an increase in franchise tax expense, increased costs related to our corporate governance activities and compliance with the Sarbanes-Oxley Act, as well as higher costs in our New Zealand operations due to currency exchange rates. We are working to reduce our production and general and administrative costs on a per unit of production basis for the remainder of 2004.

      Our debt to PV-10 ratio has remained relatively steady at 22% at December 31, 2003 and 21% at March 31, 2004. Our debt to capitalization ratio was 46% at December 31, 2003 and March 31, 2004. We believe that our current cash flow is best utilized on capital projects rather than for other corporate purposes, such as reducing our debt. We will continue to look for opportunities in 2004 to improve our balance sheet and liquidity, but expect our capital expenditures to continue to equal or modestly exceed our cash flow for the near term.

Results of Operations – Three Months Ended March 31, 2004 and 2003

      Revenues. Our revenues in the first quarter of 2004 increased by 22% compared to revenues in the same period of 2003, due primarily to increases in oil prices and in production from our Lake Washington

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      The following table provides information regarding the changes in the sources of our oil and gas sales and volumes for the three months ended March 31, 2004 and 2003:

				Three Months Ended March 31,
				Oil and Gas								Oil and Gas
				Sales								Sales Volumes
Area				2004				2003				2004				2003
				(In millions)								(Bcfe)
AWP Olmos				$	11.7			$	12.5				2.6				2.0
Brookeland					4.6				4.3				1.0				0.8
Lake Washington					28.9				11.1				5.1				2.0
Masters Creek					5.1				9.4				1.0				1.7
Other					4.4				6.5				0.7				1.2
	Total Domestic			$	54.7			$	43.8				10.4				7.7
Rimu/ Kauri					4.3				1.5				1.1				0.5
TAWN					7.0				9.6				2.8				4.7
	Total New Zealand			$	11.3			$	11.1				3.9				5.2
		Total		$	66.0			$	54.9				14.3				12.9

We combine NGLs with oil for reporting purposes. Prior to 2002, we combined NGLs with natural gas for reporting purposes. The following table provides additional information regarding our oil, NGL, and natural gas sales:

				Sales Volume																Average Sales Price
				Oil				NGL				Gas				Combined				Oil				NGL				Gas
				(MBbl)				(MBbl)				(Bcf)				(Bcfe)				(Bbl)				(Bbl)				(Mcf)
Three Months Ended March 31, 2004:
	Domestic				1,018				211				3.1				10.4			$	33.95			$	24.31			$	4.90
	New Zealand				106				67				2.8				3.9			$	36.03			$	16.00			$	2.27
		Total			1,124				278				5.9				14.3			$	34.14			$	22.30			$	3.64
Three Months Ended March 31, 2003:
	Domestic				578				100				3.6				7.7			$	32.80			$	28.47			$	6.03
	New Zealand				112				73				4.1				5.2			$	32.36			$	12.89			$	1.62
		Total			690				173				7.7				12.9			$	32.73			$	21.90			$	3.71

      Oil and gas sales in the first quarter of 2004 increased by 20%, or $11.1 million, from the level of oil and gas sales for the same period in 2003. The increase in production volumes during the first quarter of 2004 was primarily due to increased production from our Lake Washington, AWP, and Brookeland areas domestically and the Rimu/ Kauri area in New Zealand.

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      In the first quarter of 2004, our $11.1 million increase in oil, NGL, and natural gas sales resulted from:

	•	Volume variances that had a $9.8 million favorable impact on sales, comprised of a $16.5 million increase attributable to a 539,000 Bbl increase in oil and NGL sales volumes, offset by a $6.7 million decrease associated with a 1.8 Bcf decrease in gas sales volumes; and
	•	Price variances that had a $1.3 million favorable impact on sales, of which $1.7 million was attributable to a 4% increase in average combined oil and NGL prices, partially offset by a $0.4 million decrease attributable to a 2% decrease in average natural gas prices.

      Costs and Expenses. Our total expenses in the first quarter of 2004 increased $8.0 million, or 21%, compared to expenses in the same period in 2003. The majority of the increase was due to a $3.4 million increase in depreciation, depletion, and amortization and a $2.3 million increase in lease operating costs, both of which increased as our production volumes increased in the 2004 period.

      Our first quarter of 2004 general and administrative expenses, net, increased $0.5 million, or 13%, from the level of such expenses in the same 2003 period. This increase was due primarily to an increase in franchise tax expense, increased costs related to our corporate governance activities and compliance with the Sarbanes-Oxley Act, as well as higher costs in our New Zealand operations due to the increase in the currency exchange rates between the New Zealand dollar and the U.S. dollar. Our general and administrative expenses per Mcfe produced were $0.28 per Mcfe in both the first quarter of 2004 and 2003. The portion of supervision fees recorded as a reduction of general and administrative expenses was $1.3 million for the first quarter of 2004 and $0.7 million for the same period in 2003.

      Depreciation, depletion, and amortization of our oil and gas properties, or DD&A, increased $3.4 million, or 23%, in the first quarter of 2004 from 2003 levels. Domestically, DD&A increased $4.7 million in the 2004 period, mainly due to higher production. In New Zealand, DD&A decreased by $1.3 million in the 2004 period due to decreased production. Our DD&A rate per Mcfe of production was $1.28 in the first quarter of 2004 and $1.16 in the comparable 2003 period.

      We recorded $0.2 million of accretion on our asset retirement obligation in both the first quarters of 2004 and 2003.

      Our lease operating costs in the first quarter of 2004 increased $2.3 million, or 32%, over the level of such expenses in the comparable 2003 period. Approximately $1.4 million of the increase in lease operating costs during the first quarter of 2004 was related to our domestic operations, which increased due to higher production from our Lake Washington, AWP, and Brookeland areas in that period. In New Zealand, production costs increased by $0.9 million in the first quarter of 2004 mainly due to the increase in currency exchange rates between the New Zealand dollar and the U.S. dollar, and scheduled maintenance activities in the first quarter of 2004. The portion of supervision fees recorded as a reduction to production costs was $0 for the 2004 period and $0.5 million for the 2003 period. Our lease operating costs per Mcfe produced were $0.67 in the first quarter of 2004 and $0.57 in the same period of 2003.

      Severance and other taxes in the first quarter of 2004 increased $1.7 million, or 36%, over the level of such expenses in the comparable 2003 period. The increase was due primarily to higher commodity prices and increased Lake Washington production. Severance and other taxes, as a percentage of oil and gas sales, were approximately 9% and 8% in the first quarters of 2004 and 2003, respectively.

      Interest expense on our 9 3/8% senior subordinated notes issued in April 2002, including amortization of debt issuance costs, totaled $4.8 million in both the first quarters of 2004 and 2003, respectively. Interest expense on our 10 1/4% senior subordinated notes issued in August 1999, including amortization of debt issuance costs, totaled $3.3 million in both the first quarters of 2004 and 2003. Interest expense on our bank credit facility, including commitment fees and amortization of debt issuance costs, totaled $0.4 million in both the first quarters of 2004 and 2003. The total interest cost in the first quarter of 2004 was $8.5 million, of which $1.6 million was capitalized. The total interest cost in the first quarter of 2003 was $8.5 million, of which $1.8 million was capitalized.

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      Income tax expense in the first quarter of 2004 includes a reduction from the U.S. statutory rate, primarily from the result of the currency exchange rate effect on the New Zealand deferred tax, along with a reduction in tax expense primarily attributable to an adjustment of the tax basis of the TAWN properties acquired in 2002.

      As discussed in Note 1 to the Consolidated Financial Statements, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” on January 1, 2003. Our adoption of SFAS No. 143 resulted in a one-time net of taxes charge of $4.4 million, which is recorded as a “Cumulative Effect of Change in Accounting Principle” in the 2003 consolidated statement of income.

      Net Income. Our net income in the first quarter of 2004 of $14.6 million was 139% higher than our first quarter of 2003 net income of $6.1 million due to higher commodity prices, increased domestic production, and the effect of the cumulative effect of change in accounting principle recognized in the first quarter of 2003.

Results of Operations – Years Ended 2003, 2002, and 2001

      Revenues. Our revenues in 2003 increased by 39% compared to revenues in 2002, due primarily to increases in oil and natural gas prices and production from our Lake Washington and New Zealand areas. Revenues in 2002 decreased by 18% compared to 2001 revenues primarily due to a drop in domestic natural gas prices in 2002. Revenues from our oil and gas sales comprised substantially all of net revenues for 2003, 94% of total revenues for 2002, and 99% of total revenues for 2001. Natural gas production comprised 53% of our production volumes in 2003, 55% in 2002, and 59% in 2001. Domestic natural gas production comprised 49% of our total natural gas production volumes in 2003, 58% in 2002, and 100% in 2001.

      The following table provides information regarding the changes in the sources of our oil and gas sales and volumes for the years ended December 31, 2003, 2002, and 2001.

																Oil and Gas
				Oil and Gas Sales												Sales Volume
Area				2003				2002				2001				2003				2002				2001
				(In millions)												(Bcfe)
AWP Olmos				$	43.7			$	33.1			$	56.1				8.4				10.9				13.0
Brookeland					16.4				11.9				25.1				3.9				4.1				6.5
Lake Washington					59.5				18.5				4.6				12.1				4.4				1.2
Masters Creek					25.7				32.3				62.3				5.7				9.7				15.3
Other					18.9				16.3				31.3				3.7				5.2				8.3
		Total Domestic		$	164.2			$	112.1			$	179.4				33.8				34.3				44.3
Rimu/ Kauri					11.6				4.0				1.8				3.3				1.5				0.5
TAWN					35.2				25.1				—				16.1				14.0				—
		Total New Zealand		$	46.8			$	29.1			$	1.8				19.4				15.5				0.5
	Total			$	211.0			$	141.2			$	181.2				53.2				49.8				44.8

      We combine NGLs with oil for reporting purposes. Prior to 2002, we combined NGLs with natural gas for reporting purposes.

      Oil and gas sales in 2003 increased by 49%, or $69.8 million, from the level of those revenues for 2002, and our net sales volumes in 2003 increased by 7%, or 3.4 Bcfe, over net sales volumes in 2002. Average prices for oil increased to $29.89 per Bbl in 2003 from $24.52 per Bbl in 2002. Average natural gas prices increased to $3.42 per Mcf in 2003 from $2.30 per Mcf in 2002. Average NGL prices increased to $17.60 per Bbl in 2003 from $12.82 per Bbl in 2002.

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      In 2003, our $69.8 million increase in oil, NGL, and natural gas sales resulted from:

	•	Price variances that had a $59.0 million favorable impact on sales, of which $31.4 million was attributable to the 49% increase in average natural gas prices and $27.6 million was attributable to the 32% increase in average combined oil and NGL prices; and
	•	Volume variances that had a $10.8 million favorable impact on sales, with $8.8 million of increases attributable to the 422,000 Bbl increase in oil and NGL sales volumes, and $2.0 million of the increases from the 0.9 Bcf increase in natural gas sales volumes.

      In 2002, oil and gas sales decreased by 22%, or $40.0 million, from the level of those revenues in 2001 even though our net sales volumes in 2002 increased by 11%, or 5.0 Bcfe, over net sales volumes in 2001. Average combined prices for oil and NGLs decreased to $20.88 per Bbl in 2002 from $22.64 per Bbl in 2001. Average natural gas prices decreased to $2.30 per Mcf in 2002 from $4.23 per Mcf in 2001. The increase in production during the 2002 period was primarily from our New Zealand and Lake Washington areas.

      In 2002, our $40.0 million decrease in oil, NGL, and natural gas sales resulted from:

	•	Price variances that had a $59.0 million unfavorable impact on sales, of which $6.6 million was attributable to the 8% decrease in average combined oil and NGL prices and $52.4 million was attributable to the 46% decrease in average natural gas prices; and
	•	Volume variances that had a $19.0 million favorable impact on sales, with $16.2 million of increases attributable to the 715,000 Bbl increase in oil and NGL sales volumes, and $2.8 million of the increases from the 0.7 Bcf increase in natural gas sales volumes.

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

															Average Sales Price
			Sales Volume
																			Natural
			Oil				Gas				Combined				Oil				Gas
			(MBbl)				(Bcf)				(Bcfe)				(Bbl)				(Mcf)
2001:
First				603				6.7				10.3			$	27.63			$	6.86
Second				691				7.1				11.3			$	26.05			$	4.66
Third				813				6.8				11.7			$	23.76			$	2.94
Fourth				948				5.9				11.5			$	16.02			$	2.21
	Total			3,055				26.5				44.8			$	22.64			$	4.23
2002:
First				944				6.6				12.3			$	16.10			$	1.72
Second				1,002				6.7				12.7			$	20.98			$	2.60
Third				908				6.7				12.2			$	23.05			$	2.32
Fourth				916				7.1				12.6			$	23.55			$	2.55
	Total			3,770				27.1				49.8			$	20.88			$	2.30
2003:
First				864				7.6				12.9			$	30.55			$	3.71
Second				1,033				7.1				13.3			$	25.48			$	3.47
Third				1,164				6.7				13.6			$	26.60			$	3.17
Fourth				1,132				6.6				13.4			$	27.84			$	3.29
	Total			4,193				28.0				53.2			$	27.47			$	3.42

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      We combine NGLs with oil for reporting purposes. Prior to 2002, we combined NGLs with natural gas for reporting purposes. For 2003 and 2002, NGL production was 823 MBbls and 1,174 MBbls, respectively, at an average price of $17.60 and $12.82 per barrel, respectively.

      Costs and Expenses. Our expenses in 2003 increased $26.6 million, or 20%, compared to 2002 expenses. The majority of the increase was due to a $11.4 million increase in oil and gas production costs and a $6.8 million increase in DD&A, both of which increased as our production volumes increased in 2003. Our expenses in 2002 decreased by $86.4 million, or 40%, compared to 2001 expenses. This decrease was due primarily to a $98.9 million non-cash write-down of domestic oil and gas properties in 2001.

      Our 2003 general and administrative expenses, net, increased $3.5 million, or 33%, from the level of such expenses in 2002, while 2002 general and administrative expenses increased $2.4 million, or 29%, over 2001 levels. These increases in 2002 and 2003 were due primarily to our increased activities in New Zealand and a reduction in reimbursements from partnerships that we managed as almost all of these partnerships have been liquidated. In addition, our 2003 expenses increased due to an increase in franchise tax expense and increased costs related to our corporate governance activities and compliance with the Sarbanes-Oxley Act. Our general and administrative expenses per Mcfe produced increased to $0.27 per Mcfe in 2003 from $0.21 per Mcfe in 2002 and $0.18 per Mcfe in 2001. The portion of supervision fees recorded as a reduction to general and administrative expenses was $3.6 million for 2003, $3.1 million for 2002, and $3.5 million for 2001.

      DD&A increased $6.8 million, or 12%, in 2003 from 2002 levels, while 2002 DD&A decreased $3.3 million, or 6%, from 2001 levels. Domestically, DD&A increased $1.0 million in 2003 due to increases in the depletable oil and gas property base, offset by slightly lower production in the 2003 period and higher reserve volumes that were added primarily through our Lake Washington activities. In New Zealand, DD&A increased by $5.8 million in 2003 due to increased production in the 2003 period. In 2002, our domestic DD&A decreased by $15.6 million due to lower production in the 2002 period and the domestic non-cash write-down of oil and gas properties in the fourth quarter of 2001 that decreased our depletable base, along with higher reserve volumes that were added primarily through our Lake Washington activities. In New Zealand, our 2002 DD&A increased $12.3 million as our production and depletable oil and gas property base both increased in the 2002 period due primarily to the TAWN acquisition. Our DD&A rate per Mcfe of production was $1.19 in 2003, $1.13 in 2002, and $1.33 in 2001, reflecting variations in per unit cost of reserves additions.

      We recorded $0.9 million of accretion on our asset retirement obligation in 2003 associated with the adoption of SFAS No. 143 implemented on January 1, 2003.

      Our production costs in 2003 increased $11.4 million, or 27%, over such expenses in 2002, while those expenses in 2002 increased $4.8 million, or 13%, over such expenses in 2001. Approximately $6.2 million of the increase in production costs during 2003 was related to domestic severance taxes, which increased along with commodity prices and higher production from our Lake Washington area in that period. In New Zealand, production costs increased by $5.2 million in 2003 mainly due to royalty payments made on higher production in the period. In 2002, production costs increased as our New Zealand activities increased, partially offsetting the domestic production costs decrease, which mainly was due to a decrease in production volumes. The portion of supervision fees recorded as a reduction to production costs was $1.5 million for 2003, $2.1 million for 2002, and $3.3 million for 2001. Our production costs per Mcfe produced were $0.99 in 2003, $0.83 in 2002, and $0.82 in 2001.

      Interest expense on our 9 3/8% senior subordinated notes issued in April 2002, including amortization of debt issuance costs, totaled $19.1 million in 2003 and $13.5 million in 2002. Interest expense on our 10 1/4% senior subordinated notes issued in August 1999, including amortization of debt issuance costs, totaled $13.2 million in both 2003 and 2002 and $13.1 million in 2001. Interest expense on our bank credit facility, including commitment fees and amortization of debt issuance costs, totaled $1.6 million in 2003, $3.6 million in 2002, and $5.8 million in 2001. Other interest cost was $0.3 million in 2003. Our total interest cost in 2003 was $34.2 million, of which $6.9 million was capitalized. Our total interest cost in 2002 was $30.3 million, of which $7.0 million was capitalized. Our 2001 total interest cost was

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      In the fourth quarter of 2001, we recognized a domestic non-cash write-down of oil and gas properties, as discussed in Note 1 to the Consolidated Financial Statements. Lower prices for both oil and natural gas at December 31, 2001, necessitated a pre-tax domestic full-cost ceiling write-down of $98.9 million, or $63.5 million after tax. In addition to this domestic ceiling write-down, we also expensed $2.1 million of charges in the fourth quarter of 2001 for certain delinquent accounts receivable, the majority of which were related to natural gas sold to Enron, and a write-off of debt issuance costs for a planned offering that was cancelled based upon market conditions following the events of September 11, 2001.

      Income tax expense in 2003 includes a reduction of approximately $1.3 million from the U.S. statutory rate, primarily from the result of the currency exchange rate effect on the New Zealand deferred tax. This amount was partially offset by higher deferred state taxes and other items.

      As discussed in Note 1 to the Consolidated Financial Statements, we adopted SFAS No. 143 on January 1, 2003. Our adoption of SFAS No. 143 resulted in a one-time net of taxes charge of $4.4 million, which was recorded as a cumulative effect of change in accounting principle in the 2003 consolidated statement of income. We adopted SFAS No. 133, as amended, on January 1, 2001. Our adoption of SFAS No. 133 resulted in a one-time net of taxes charge of $0.4 million, which was recorded as a cumulative effect of change in accounting principle in the 2001 consolidated statement of income.

      Net Income (Loss). Our net income in 2003 of $29.9 million was 151% higher than our 2002 net income of $11.9 million due to higher commodity prices and increased production.

      Our net income in 2002 of $11.9 million was 153% higher than our 2001 net loss of $(22.3) million due to overall lower costs, as a non-cash write-down of oil and gas properties occurred in 2001 and not in 2002, offset somewhat by lower revenue in 2002 due to lower commodity prices.

Contractual Commitments and Obligations

      Our contractual commitments for the next five years and thereafter as of December 31, 2003 are as follows:

			2004				2005				2006				2007				2008				Thereafter				Total
			(In thousands)
Non-cancelable operating leases			$	2,143			$	493			$	159			$	157			$	125			$	14			$	3,090
Capital commitments due to pipeline operators				96				—				—				—				—				—				96
Asset retirement obligation(1)				1,704				2,604				—				129				74				5,626				10,138
Drilling rigs and seismic				5,919				—				—				—				—				—				5,919
Senior subordinated notes due 2009(2)				—				—				—				—				—				125,000				125,000
Senior subordinated notes due 2012(2)				—				—				—				—				—				200,000				200,000
Credit facility(3)				—				15,900				—				—				—				—				15,900
	Total		$	9,862			$	18,996			$	159			$	286			$	199			$	330,640			$	360,143

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(1)	Amounts shown by year are the fair values at December 31, 2003.
(2)	Amounts do not include the interest obligation, which is paid semiannually.
(3)	Amounts exclude a $0.8 million standby letter of credit outstanding under this facility.

Commodity Price Trends and Uncertainties

      Oil and natural gas prices historically have been volatile and are expected to continue to be volatile in the future. The price of oil increased significantly in the first quarter of 2004 and is currently significantly higher when compared to longer-term historical prices. Factors such as actions taken by OPEC, worldwide

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Liquidity and Capital Resources

      During the first quarter of 2004, we largely relied upon our net cash provided by operating activities of $39.6 million and proceeds from bank borrowings of $16.6 million to fund capital expenditures of $45.1 million and for working capital. During the first quarter of 2003, we relied upon our net cash provided by operating activities of $26.8 million to fund capital expenditures of $26.3 million.

      Net Cash Provided by Operating Activities. For the first quarter of 2004, our net cash provided by operating activities was $39.6 million, representing a 48% increase as compared to $26.8 million generated during the first quarter of 2003. The $12.8 million increase was primarily due to an increase of $11.1 million in oil and gas sales for the 2004 period, attributable to higher commodity prices and production, offset in part by higher lease operating costs due to higher domestic production and severance taxes as a result of higher commodity prices in the first quarter of 2004.

      Accounts Receivable. Included in our accounts receivable balance, which totaled $29.1 million and $27.4 million at March 31, 2004 and December 31, 2003, respectively, is approximately $2.3 million of receivables related to hydrocarbon volumes produced from 2001 and 2002 that have been disputed since early 2003. We assess the collectibility of trade and other receivables and we accrue a reserve when we believe a receivable may not be collected. At March 31, 2004 and December 31, 2003, we had an allowance for doubtful accounts of $0.8 million. These allowances for doubtful accounts have been deducted from our accounts receivable balances.

      Existing Credit Facility. We had $32.5 million in outstanding borrowings under our bank credit facility at March 31, 2004, and $15.9 million in outstanding borrowings at December 31, 2003. Our bank credit facility at March 31, 2004 consisted of a $300.0 million revolving line of credit with a $250.0 million borrowing base. The borrowing base is re-determined at least every six months and was reaffirmed by our bank group at $250.0 million, effective May 1, 2004. At our request, the commitment amount was reduced to $150.0 million effective May 9, 2003. Under the terms of our bank credit facility, we can increase this commitment amount back to the total amount of the borrowing base at our discretion, subject to the terms of the credit agreement. Our revolving credit facility includes, among other restrictions, requirements to maintain certain minimum financial ratios (principally pertaining to working capital, debt, and equity ratios), and limitations on incurring other debt. We are in compliance in all material respects with the provisions of this agreement.

      We have signed a commitment letter and fee letter with the administrative agent of our bank group relating to the renewal and extension of our bank credit facility. We anticipate that the renewal and extension will be finalized in June 2004 on substantially the same terms as our existing facility except with a $400.0 million revolving line of credit and a maturity date of October 1, 2008.

      Working Capital. Our working capital improved from a deficit of $35.1 million at December 31, 2003, to a deficit of $15.4 million at March 31, 2004. The improvement was primarily due to a decrease in accounts payable and accrued capital costs due to a reduction in our drilling activities at March 31, 2004.

      Capital Expenditures. Domestic activities account for the majority of our 2004 capital expenditure budget with the largest allocation going to our Lake Washington area. In Lake Washington, the 2004 budget assumes drilling activity of 25 to 30 development wells and two to four exploratory wells, while we complete an extensive three-dimensional seismic survey and begin analysis of the resulting data to enhance our future drilling program in the area. We plan to drill 15 to 18 development wells in AWP Olmos with the objective of maintaining production levels in that area. Additionally, we expect to conduct ongoing

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      Domestic expenditures of $36.5 million as follows:

	•	$31.2 million for drilling and developmental activity costs;
	•	$4.7 million of domestic prospect costs, principally prospect leasehold, seismic, and geological costs of unproved prospects;
	•	$0.4 million relating to costs directly associated with evaluating potential producing property acquisitions; and
	•	$0.2 million primarily for computer equipment, software, furniture, and fixtures.

      New Zealand expenditures of $8.6 million as follows:

	•	$7.0 million for drilling costs and developmental activity costs;
	•	$1.5 million on prospect costs, principally seismic and geological costs; and
	•	$0.1 million for fixed assets.

      We have spent considerable time and capital in 2003 and the first quarter of 2004, on significant facility capacity upgrades in the Lake Washington field to increase facility capacity to more than 20,000 barrels per day for crude oil, up from 9,000 barrels per day capacity in the first quarter of 2003. Facility upgrades, most of which were completed in the fourth quarter of 2003, and the commissioning of these upgrades, led to numerous planned production shut-in periods during the third and fourth quarters of 2003. We have upgraded three production platforms, added new compression for the gas lift system, and installed a new oil delivery system and permanent barge loading facility.

      We drilled or participated in drilling 12 domestic development wells and two domestic exploratory wells in the first quarter of 2004. Seven of the development wells and one exploratory well were in the Lake Washington area. Four of the development wells were in the AWP area. One domestic exploratory well and 11 of the domestic development wells were completed. In New Zealand, the Kauri-E3 well was completed while the Kauri-E4 began completion procedures.

      For the remaining nine months of 2004, we expect to make capital expenditures of approximately $90.0 to $120.0 million. We currently estimate total capital expenditures for 2004 to be approximately $133.0 to $163.0 million, excluding acquisition costs. Approximately $3.0 to $13.0 million of this will be funded through non-core property dispositions. Capital expenditures for 2003 were $144.5 million. The budget for 2004, is dependent upon operational performance and commodity pricing levels during the year.

      We believe that the anticipated internally generated cash flows for 2004, together with borrowings under our bank credit facility, will be sufficient to finance the costs associated with our currently budgeted 2004 capital expenditures. If producing property acquisitions become attractive during 2004, we may access debt and/or equity markets to fund such activity.

      During the last nine months of 2004, we anticipate drilling or participating in the drilling of up to an additional 18 to 23 development wells and one to three exploratory wells in our Lake Washington area, an additional eleven to fourteen development wells in our AWP area, and up to five additional wells, with varying working interest percentages, mainly in our South Texas areas. In addition, we plan on drilling an additional two or three Kauri wells, a Tariki well, and four to six Manutahi wells.

      Our 2004 capital expenditures continue to be focused on developing and producing long-lived oil and natural gas reserves in our Lake Washington, AWP Olmos, and Rimu/ Kauri areas. This focus should help lessen our overall production decline curve, which would extend our average reserve life. We expect our 2004 total production to increase by 11% to 17% over 2003 levels, primarily from the Lake Washington

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	New Accounting Principles

      In March 2004, the FASB issued an exposure draft that would amend SFAS No. 123, “Accounting for Stock Based Compensation,” and SFAS No. 95, “Statement of Cash Flows.” This exposure draft was issued to improve existing accounting rules and provide more complete, higher quality information for investors on employee stock compensation matters. The comment period for the exposure draft ends June 30, 2004. The exposure draft covers a wide range of equity-based arrangements including stock options. Under the FASB’s proposal, share-based payments to employees, including stock options, would be treated the same as other forms of compensation by recognizing the related cost in the income statement. The expense of the award would generally be measured at fair value at the grant date. Current accounting guidance requires that the expense relating to employee stock options only be disclosed in the footnotes of the financial statements. We are evaluating the effects that will result from future adoption of this proposed statement or related accounting changes.

      In 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities,” which is an interpretation of Accounting Research Bulletin No. 51, “Consolidated Financial Statements.” The interpretation significantly changes whether entities included in its scope are consolidated by their sponsors, transferors, or investors. The interpretation introduces a new consolidation model, the variable interest model, which determines control (and consolidation) based on potential variability in gains and losses of the entity being evaluated for consolidation. The interpretation provides guidance for determining whether an entity lacks sufficient equity or its equity holders lack adequate decision-making ability. These variable interest entities, or VIEs, are covered by the interpretation and are to be evaluated for consolidation based on their variable interests. These provisions applied immediately to variable interests in VIEs created after January 31, 2003, and to variable interests in special purpose entities for periods ending after December 15, 2003. The provisions apply for all other types of variable interests in VIEs for periods ending after March 15, 2004. We have no variable interests in VIEs, nor do we have variable interests in special purpose entities. The adoption of this interpretation had no impact on our financial position or results of operations.

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BUSINESS AND PROPERTIES

General

      We are engaged in developing, exploring, acquiring, and operating oil and gas properties, with a focus on oil and natural gas reserves onshore and in the inland waters of Louisiana and Texas and onshore in New Zealand. We were founded in 1979 and are headquartered in Houston, Texas. At year-end 2003, we had estimated proved reserves of 820.4 Bcfe with a PV-10 Value of over $1.5 billion. Our proved reserves at year-end 2003 were comprised of approximately 47% crude oil, 41% natural gas, and 12% NGLs, of which 59% were proved developed. Our proved reserves are concentrated 40% in Louisiana, 37% in Texas, and 21% in New Zealand.

      We currently focus primarily on development and exploration in four domestic core areas and two core areas in New Zealand:

	•	AWP Olmos – South Texas
	•	Brookeland – East Texas
	•	Lake Washington – South Louisiana
	•	Masters Creek – Central Louisiana
	•	Rimu/ Kauri – New Zealand
	•	TAWN – New Zealand

Competitive Strengths and Business Strategy

      We believe that our competitive strengths, together with a balanced and comprehensive business strategy, provide us with the flexibility and capability to accomplish our goals. Our primary goals for the next five years are to increase proved oil and natural gas reserves at an average rate of 5% to 10% per year and to increase production at an average rate of 7% to 12% per year.

	Demonstrated Ability to Grow Reserves and Production

      We have grown our proved reserves from 436.1 Bcfe to 820.4 Bcfe over the five-year period ended December 31, 2003. Over the same period, our annual production has grown from 39.0 Bcfe to 53.2 Bcfe and our annual net cash provided by operations increased from $54.2 million to $110.8 million. Our growth in reserves and production has resulted primarily from drilling activities in our six core areas combined with producing property acquisitions. More recently in 2003, we increased our production by 7% in relation to 2002 production. During the same period, we also increased our proved reserves by 9.5%, which replaced 234% of our 2003 production. We believe that we have the opportunities, experience, and knowledge to continue growing our reserves and production.

	Balanced Approach to Growth

      Our strategy is to increase our reserves and production through both drilling and acquisitions, shifting the balance between the two activities in response to market conditions. In general, we focus on drilling in our core property and emerging growth areas when oil and natural gas prices are strong. When prices weaken and the per unit cost of acquisitions becomes more attractive, we shift our focus toward acquisitions. We believe this balanced approach has resulted in our ability to grow in a strategically cost effective manner. Over the five-year period ended December 31, 2003, we replaced 266% of our production at an average cost of $1.25 per Mcfe. In 2004, we believe we are positioned to grow our proved reserves 5% to 8% and our production 11% to 17%.

      In this current environment of stronger oil and natural gas prices, our 2004 capital expenditures are primarily focused on developing and producing reserves in our Lake Washington, AWP Olmos, and Rimu/ Kauri areas. With this focus, we expect 2004 total production to increase over 2003 production levels

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	Concentrated Focus on Core Areas with Operational Control

      The concentration of our operations in six core areas allows us to realize economies of scale in drilling and production by enabling us to manage larger producing fields with less personnel while minimizing incremental costs of increased drilling and completions. Our average lease operating costs, excluding taxes, were $0.64, $0.60, and $0.56 per Mcfe in 2003, 2002, and 2001, respectively. The value of this concentration is enhanced by our operating 95% of our proved oil and natural gas reserve base as of December 31, 2003. Retaining operational control allows us to more effectively manage production, control operating costs, allocate capital and time field development.

	Develop Under-Exploited Properties

      We are focused on applying modern technologies and recovery methods to areas with known hydrocarbon resources to optimize our exploration and exploitation of such properties. For example, the Lake Washington field was discovered in the 1930s. We acquired our properties in this area for $30.5 million in 2001. Since that time, we have increased our average daily production from less than 700 BOE to over 9,300 BOE for the quarter ended March 31, 2004. We have also increased our proved reserves in the area from 7.7 million BOE, or 46.2 Bcfe, to approximately 43.5 million BOE or 261.0 Bcfe, as of December 31, 2003. Additionally, on our original 100,000 acre New Zealand permit, only two wells had been drilled at the time that we acquired our interest. We have drilled 18 wells in New Zealand since 1999. When we first acquired our interests in AWP Olmos, Brookeland, and Masters Creek, these areas also had significant additional development potential. We intend to continue acquiring large acreage positions in under-explored and under-exploited areas, where we can apply modern technologies to grow production from developed fields.

	Capitalize on the Near Term Depletion of New Zealand’s Largest Gas Field

      The Maui field in New Zealand currently supplies over 70% of the natural gas produced in New Zealand. The Maui field is expected to be depleted by 2007, which has caused significant upward pressure on prices for natural gas in the country. Our average natural gas price in New Zealand has increased 40% from the first quarter of 2003 to the first quarter of 2004. We expect the prices we receive for our natural gas in New Zealand to continue to increase in the foreseeable future. Our New Zealand activities provide us with long term growth opportunities and significant potential reserves in a country with stable political and economic conditions, existing oil and gas infrastructure, and favorable tax and royalty regimes.

	Maintain Financial Flexibility and a Conservative Capital Structure

      We practice a disciplined approach to financial management and have historically maintained a strong capital structure to provide us with the ability to execute our business plan. As of March 31, 2004, our debt to capitalization was approximately 46% and our debt per proved reserves was $0.44 per mcfe. We plan to maintain a capital structure that provides financial flexibility through the prudent use of capital and an active hedging program. The combination of hedging with collars and floors and the sale of our New Zealand natural gas production under long term, fixed price contracts provides for a more stable cash flow.

	Experienced Technical Team

      We employ 43 oil and gas professionals, including geophysicists, petrophysicists, geologists, petroleum engineers, and production and reservoir engineers, who have an average of approximately 25 years of experience in their technical fields and have been employed by us for an average of over nine years. We

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      We have increasingly used seismic technology to enhance the results of our drilling and production efforts, including two and three-dimensional seismic analysis, amplitude versus offset studies, and detailed formation depletion studies.

      We have developed an expertise in drilling horizontal wells at vertical depths below 10,000 feet, often in a high-pressure environment, involving single or dual lateral legs of several thousand feet. This results in an integrated approach to exploration using multidisciplinary data analysis and interpretation that has helped us identify a number of exploration prospects.

      We use various recovery techniques, including water flooding and acid treatments, fracturing reservoir rock through the injection of high-pressure fluid, gravel packing, and inserting coiled tubing velocity strings to enhance and maintain gas flow. We believe that the application of fracturing technology and coiled tubing has resulted in significant increases in production and decreases in completion and operating costs, particularly in our AWP Olmos area.

      When appropriate, we develop new applications for existing technology. For example, in New Zealand we acquired seismic data by effectively combining marine data with the acquisition of land seismic data, an application we have not seen any other company use in New Zealand.

Operating Areas

      The following table sets forth information regarding our proved reserves and production in our six core areas:

				% of Year-End
				2003 Proved				% of 2003
Area		Location		Reserves				Production
AWP Olmos		South Texas			26%				16%
Brookeland		East Texas			5%				7%
Lake Washington		South Louisiana			32%				23%
Masters Creek		Central Louisiana			8%				11%
Rimu/ Kauri		New Zealand			15%				6%
TAWN		New Zealand			6%				30%
% of Total					92%				93%

	Domestic Core Operating Areas

      AWP Olmos Area. As of December 31, 2003, we owned 27,900 net acres in the AWP Olmos Area in South Texas. We have extensive experience with low-permeability, tight-sand formations typical of this area, having acquired our first acreage there in 1988. These reserves are approximately 66% natural gas. At year-end 2003, we owned interests in and operated 504 wells in this area producing natural gas from the Olmos sand formation at depths of approximately 9,000 to 11,500 feet. We own nearly 100% of the working interests in all our operated wells.

      In 2003, we completed eight development wells in this area, performed four fracture enhancements, and installed coiled tubing velocity strings in six wells. Also in 2003, we purchased interests in the AWP Olmos area from partnerships we managed. At year-end 2003, we had 124 proved undeveloped locations. Our planned 2004 capital expenditures in this area will focus on drilling 15 to 18 development wells.

      Brookeland Area. As of December 31, 2003, we owned drilling and production rights in 72,516 net acres and 3,500 fee mineral acres in the Brookeland area, which contains substantial proved undeveloped reserves. This area is located in East Texas near the border of Louisiana in Jasper and Newton counties. We primarily drill horizontal wells and produce from the Austin Chalk formation. The reserves are

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      Lake Washington Area. As of December 31, 2003, we owned drilling and production rights in 12,911 net acres in the Lake Washington area located in Plaquemines Parish in South Louisiana. Subsequent to December 31, 2003, we acquired interests in an additional 1,921 acres and obtained lease and seismic options covering another 9,182 acres. Approximately 94% of our proved reserves of 43.5 million BOE in this area at December 31, 2003 were oil and NGLs. We primarily produce from multiple Miocene sands ranging in depth from less than 1,700 feet to greater than 9,000 feet. The field is located on a salt dome and has produced over 300 million BOE since its inception in the 1930s. The area around the dome is heavily faulted, thereby creating a large number of potential traps. Oil and gas from approximately 77 producing wells is gathered from three platforms located in water depths from two to 12 feet, with drilling and workover operations performed with barge rigs.

      In 2003, we drilled 52 development wells and six exploratory wells, of which 42 development and five exploratory wells were completed. Our 2004 capital expenditure budget assumes reduced drilling activity from 2003 levels while we complete an extensive three-dimensional seismic survey and begin analysis of the resulting data to enhance our future drilling program in the area. At year-end 2003, we had
82 proved undeveloped locations in this field. Our planned 2004 budget includes drilling 25 to 30 development wells and two to four exploratory wells.

      We spent considerable time and capital in 2003 on significant facility capacity upgrades in the Lake Washington area to increase facility capacity to more than 20,000 barrels per day for crude oil up from 9,000 barrels per day capacity in the first quarter 2003. These facility upgrades, most of which were completed during the fourth quarter of 2003, include improvements to all three production platforms, new compression for the gas lift system, a new oil delivery system, additional crude oil storage, and a permanent barge loading facility. During 2004, we will continue to optimize the operating performance of all these facilities, which will include additions, adjustments, and refinements to existing facilities and may include the addition of a fourth field processing facility.

      Masters Creek Area. As of December 31, 2003, we owned drilling and production rights in 62,560 net acres and 91,994 fee mineral acres in the Masters Creek area, which contains substantial proved undeveloped reserves. This area is located in Central Louisiana near the Texas-Louisiana border in the two parishes of Vernon and Rapides. It contains horizontal wells producing both oil and gas from the Austin Chalk formation. The reserves are approximately 71% oil and NGLs. At year-end 2003, we had 12 proved undeveloped locations. Our planned 2004 capital expenditures include drilling one to two development wells.

     Domestic Emerging Growth Areas

      Garcia Ranch Area. We have been focusing on the deep sands of the Frio formation (10,000 to 16,000 feet) in an area known as Garcia Ranch, which straddles the border of Kenedy County and Willacy County in the southern tip of Texas. We have a 65% working interest in two wells in the area, one in the Rome prospect in Willacy County and one in the Siena prospect in Kenedy County. In addition, we have a 33% working interest in two wells in the Milan prospect in Kenedy County. Two exploratory wells drilled in this area during 2003 were not successful. We plan to participate in drilling two exploratory and four development wells in this area in 2004.

     New Zealand Core Operating Areas

      Our activity in New Zealand began in 1995. As of December 31, 2003, our exploration permit 38719, which we operate, included approximately 49,800 acres in the Taranaki Basin of New Zealand’s north island. In April 2004, two other permits (38756 and 38759) within the Taranaki Basin were consolidated with our permit 38719 to form one permit area of approximately 78,300 acres. This acreage represents our Kauri area and surrounds our Rimu area, and includes our Tawa and Matai prospects. We also hold a 50%

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      Rimu/ Kauri Area. Since 2002, we have held petroleum mining permit 38151 covering approximately 5,500 acres in the Rimu area for a primary term of 30 years. We began commercial production from the Rimu area in May 2002. During 2003, we completed three of four wells in the Kauri area. Two of these wells successfully targeted the Kauri Sand, the third was completed in the Manutahi Sand. We also fracture stimulated three Kauri Sand wells in 2003. Our natural gas production from this area is sold to Genesis Power Ltd. under a long term contract for use at its Huntly Power Station, New Zealand’s largest thermal power station.

      TAWN Area. Our interest in the TAWN consists of a 100% working interest in four petroleum mining permits, 38138 through 38141, covering producing oil and gas fields and extensive associated hydrocarbon-processing facilities and pipelines. The properties are collectively identified as the TAWN properties, an acronym derived from the first letters of the field names – the Tariki field, the Ahuroa field, the Waihapa field, and the Ngaere field. The four fields include 17 wells where the purchaser of gas, Contact Energy, has contracted to take minimum quantities and can call for higher production levels to meet electrical demand in New Zealand. Sales of gas to Contact Energy exceeded the contract minimum during all of 2003. The TAWN assets are located approximately 17 miles north of the Rimu/Kauri area.

      Our infrastructure at TAWN includes two hydrocarbon-processing plants with significant excess capacity. We also own the pipelines connecting the fields and facilities to export terminals and interior markets.

	New Zealand Emerging Growth Areas

      The Tawa prospect is located in permit 38719 northwest of the Rimu area. Its main targets are the Kauri, Tariki, and Kapuni sands. Consisting of a combination of structural and stratigraphic traps, this prospect was developed based upon our analysis of existing two and three-dimensional seismic data. The Tawa prospect may also include a shallower prospect located on the southeast flank of the Tawa prospect.

      Three prospects are located in our TAWN area and are identified as the Waihapa Deep prospect, the Toko Deep prospect, and the Ahuroa Flank prospect. All three prospects will have the Kapuni group sands (the major reservoir in the basin) as their main target, but as these wells are drilled they will also pass through the Tariki sandstone and other major producers in the basin.

Oil and Natural Gas Reserves

      The following table presents information regarding proved reserves of oil and natural gas attributable to our interests in producing properties as of December 31, 2003, 2002, and 2001. The information set forth in the table regarding reserves is based on proved reserves reports prepared by us and audited by H. J. Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers. Gruy’s audit was conducted according to standards approved by the Board of Directors of the Society of Petroleum Engineers, Inc. and included examination, on a test basis, of the evidence supporting our reserves. Gruy’s audit was based upon review of production histories and other geological, economic, and engineering data provided by us.

      Estimates of future net revenues from our proved reserves and the PV-10 Value are made using oil and gas sales prices in effect as of the dates of such estimates adjusted for the effects of hedging and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including, in the case of gas contracts, the use of fixed and determinable contractual price escalations. Our hedges at year-end 2003 consisted of natural gas price floors with strike prices lower than the period end price and thus did not affect prices used in these calculations. The weighted averages of such year-end prices domestically were $5.53 per Mcf of natural gas, $30.88 per barrel of oil, and $21.81 per barrel of NGL, compared to $4.23, $29.36, and $17.30 at year-end 2002 and $2.68, $18.51, and $11.00 at year-end 2001, respectively. The weighted averages of such year-end 2003 prices for New

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      The following tables set forth estimates of future net revenues presented on the basis of unescalated prices and costs in accordance with criteria prescribed by the SEC and its PV-10 Value as of December 31, 2003, 2002, and 2001. Operating costs, development costs, asset retirement obligation costs, and certain production-related taxes were deducted in arriving at the estimated future net revenues. No provision was made for income taxes. The estimates of future net revenues and their present value differ in this respect from the standardized measure of discounted future net cash flows set forth in supplemental information to our Consolidated Financial Statements, which is calculated after provision for future income taxes.

				As of December 31, 2003
				Total				Domestic				New Zealand
Estimated Proved Oil and Natural Gas Reserves
Natural gas reserves (MMcf):
	Proved developed				210,120				138,173				71,947
	Proved undeveloped				125,685				104,148				21,537
		Total			335,805				242,321				93,484
Oil reserves (MBbl):
	Proved developed				45,525				38,768				6,757
	Proved undeveloped				35,235				28,248				6,987
		Total			80,760				67,016				13,744
Estimated Present Value of Proved Reserves (In thousands)
	Proved developed			$	940,883			$	805,834			$	135,048
	Proved undeveloped				597,912				517,485				80,427
		PV-10 Value		$	1,538,795			$	1,323,319			$	215,476

				As of December 31, 2002
				Total				Domestic				New Zealand
Estimated Proved Oil and Natural Gas Reserves
Natural gas reserves (MMcf):
	Proved developed				233,515				149,732				83,783
	Proved undeveloped				93,217				90,093				3,125
		Total			326,732				239,824				86,908
Oil reserves (MBbl):
	Proved developed				35,928				26,530				9,398
	Proved undeveloped				34,511				32,500				2,011
		Total			70,439				59,030				11,409

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				As of December 31, 2002
				Total				Domestic				New Zealand
Estimated Present Value of Proved Reserves (In thousands)
	Proved developed			$	679,356			$	516,833			$	162,523
	Proved undeveloped				481,833				456,632				25,201
		PV-10 Value		$	1,161,189			$	973,465			$	187,724

				As of December 31, 2001
				Total				Domestic				New Zealand
Estimated Proved Oil and Natural Gas Reserves
Natural gas reserves (MMcf):
	Proved developed				181,652				167,402				14,250
	Proved undeveloped				143,261				121,088				22,173
		Total			324,912				288,490				36,423
Oil reserves (MBbl):
	Proved developed				23,760				20,393				3,366
	Proved undeveloped				29,723				22,172				7,551
		Total			53,483				42,565				10,918
Estimated Present Value of Proved Reserves (In thousands)
	Proved developed			$	344,479			$	306,095			$	38,383
	Proved undeveloped				258,507				186,012				72,495
		PV-10 Value		$	602,986			$	492,108			$	110,878

We combine NGLs with oil for reporting purposes. Prior to 2002, we combined NGLs with natural gas for reporting purposes.

      Proved reserves are estimates of hydrocarbons to be recovered in the future. Reservoir engineering is a subjective process of estimating the sizes of underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserves reports of other engineers might differ from the reports contained herein. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Future prices received for the sale of oil and gas may be different from those used in preparing these reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered. There can be no assurance that these estimates are accurate predictions of the present value of future net cash flows from oil and gas reserves.

Oil and Gas Wells

      As we continued to liquidate partnerships for those partnerships that voted to do so, our total gross well count decreased from 2001 levels. Acquisitions such as Lake Washington, where we own nearly a

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			Oil Wells				Gas Wells				Total Wells(1)
December 31, 2003:
	Gross			397				560				957
	Net			340.6				504.0				844.6
December 31, 2002:
	Gross			342				555				897
	Net			278.9				479.8				758.7
December 31, 2001:
	Gross			396				786				1,182
	Net			297.0				467.9				764.9

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(1)	Excludes 41 service wells in 2003, 35 service wells in 2002, and 48 service wells in 2001.

Oil and Gas Acreage

      As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except as to claims made by, through, or under the transferor. Although we have title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights. In many instances, title opinions may not be obtained if in our judgment it would be uneconomical or impractical to do so.

      The following table sets forth the developed and undeveloped leasehold acreage held by us at December 31, 2003:

				Developed(1)								Undeveloped(1)
				Gross				Net				Gross				Net
Alabama					9,686.01				2,859.10				644.22				183.99
Louisiana					82,257.09				65,415.99				16,637.34				10,296.57
Mississippi					630.03				163.32				60.00				15.80
Texas					166,636.81				113,555.70				31,284.03				19,017.64
Wyoming					681.07				151.06				67,698.95				66,078.96
All other states					320.00				266.66				400.00				257.32
Offshore Louisiana					4,609.37				276.56				5,000.00				258.34
Offshore Texas					2,880.00				74.39				—				—
	Total Domestic				267,700.38				182,762.78				121,724.54				96,108.62
New Zealand					7,600.00				7,181.70				162,422.37				124,766.10
		Total			275,300.38				189,944.48				284,146.91				220,874.72

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(1)	Fee mineral acres acquired in the Brookeland and Masters Creek areas acquisition are not included in the above leasehold acreage table. We have 26,345 developed fee mineral acres and 69,149 undeveloped fee mineral acres for a total of 95,494 fee mineral acres.

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Drilling Activities

      The following table sets forth the results of our drilling activities during the three years ended December 31, 2003:

						Gross Wells																Net Wells
																		Temporarily																Temporarily
Year				Type of Well		Total				Producing				Dry				Abandoned				Total				Producing				Dry				Abandoned
	2003			Exploratory – Domestic			8				5				3				—				7.3				5.0				2.3				—
				Development – Domestic			63				53				10				—				61.9				51.9				10.0				—
				Exploratory – New Zealand			1				—				1				—				0.5				—				0.5				—
				Development – New Zealand			3				3				—				—				3.0				3.0				—				—
	2002			Exploratory – Domestic			7				3				4				—				5.0				2.3				2.7				—
				Development – Domestic			23				17				6				—				23.0				17.0				6.0				—
				Exploratory – New Zealand			3				2				1				—				2.2				2.0				0.2				—
				Development – New Zealand			3				2				1				—				3.0				2.0				1.0				—
	2001			Exploratory – Domestic			11				6				5				—				6.2				4.0				2.2				—
				Development – Domestic			36				36				—				—				29.5				29.5				—				—
				Exploratory – New Zealand			2				—				1				1				1.1				—				0.9				0.2
				Development – New Zealand			4				2				2				—				3.6				1.8				1.8				—

Operations

      We generally seek to be operator in the wells in which we have a significant economic interest. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties we operate. Independent contractors supervised by us provide all the equipment and personnel. We employ drilling, production, and reservoir engineers, geologists, and other specialists who work to improve production rates, increase reserves, and lower the cost of operating our oil and gas properties.

      Oil and gas properties are customarily operated under the terms of a joint operating agreement. These agreements usually provide for reimbursement of the operator’s direct expenses and for payment of monthly per-well supervision fees. Supervision fees vary widely depending on the geographic location and depth of the well and whether the well produces oil or natural gas. The fees for these activities paid to us in 2003 totaled $5.1 million and ranged from $450 to $2,107 per well per month.

Marketing of Production

      Domestically, we typically sell our oil and natural gas production at market prices near the wellhead or at a central point after gathering and/or processing. We sell our natural gas in the spot market on a monthly basis, while we sell our oil at prevailing market prices. We do not refine any oil we produce. Shell, both domestically and in New Zealand, and Contact Energy in New Zealand each accounted for 10% or more of our total revenues during the year ended December 31, 2003, with those purchasers accounting for approximately 26% of revenues in the aggregate. For the year-ended December 31, 2002, Eastex Crude Company and Contact Energy in New Zealand accounted for approximately 28% of our total revenues. However, due to the availability of other purchasers, we do not believe that the loss of any single oil or gas purchaser or contract would materially affect our revenues.

      In 1998, we entered into gas processing and gas transportation agreements for our natural gas production in the AWP Olmos area with PG&E Energy Trading Corporation, which was assumed in December 2000 by El Paso Hydrocarbon, LP, and El Paso Industrial, LP, both affiliates of El Paso Merchant Energy, for up to 75,000 Mcf per day, which provided for a ten-year term with automatic one-year extensions unless earlier terminated. We believe that these arrangements adequately provide for our gas transportation and processing needs in the AWP Olmos area for the foreseeable future.

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      Our oil production from the Brookeland and Masters Creek areas is sold to various purchasers at prevailing market prices. Our natural gas production from these areas is processed under long term gas processing contracts with Duke Energy Field Services, Inc. The processed liquids and residue gas production are sold in the spot market at prevailing prices.

      Our oil production from the Lake Washington area is delivered into ExxonMobil’s crude oil pipeline system or barges for sales to various purchasers at prevailing market prices. Our natural gas production from this area is either consumed on the lease or is delivered into El Paso’s Tennessee Gas Pipeline system and then sold in the spot market at prevailing prices.

      Our oil production in New Zealand is sold to Shell Petroleum Mining at international prices tied to the Asia Petroleum Price Index (APPI) Tapis posting, less the cost of storage, trucking, and transportation.

      Our natural gas production from our TAWN fields is sold under a long term fixed price contract with Contact Energy. Our natural gas production from the Rimu field is sold to Genesis Power Ltd. under a long term fixed price contract that was modified in 2003 and covers approximately 7.2 Bcfe per year for a three-year period. During 2003, additional production volumes from our TAWN fields, over the contract maximum, were sold to Contact Energy or Genesis Power Ltd. at prevailing market rates.

      Production of NGLs in New Zealand is sold to Rockgas Ltd. under long term contracts tied to New Zealand’s domestic natural gas liquids market.

      The following table summarizes sales volumes, sales prices, and production cost information for our net oil and natural gas production for the three-year period ended December 31, 2003.

				Year Ended December 31,
				2003				2002				2001
Net Sales Volume:
	Oil (MBbls)(1)(2)				4,193				3,770				3,055
	Natural gas (MMcf)(3)				28,003				27,132				26,459
		Total (MMcfe)			53,158				49,752				44,791
Average Sales Price:
	Oil (Per Bbl)(1)(2)			$	27.47			$	20.88			$	22.64
	Natural gas (Per Mcf)(3)			$	3.42			$	2.30			$	4.23
Average Production Cost (Per Mcfe)				$	0.99			$	0.83			$	0.82

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(1)	Oil production for 2003, 2002, and 2001 includes New Zealand production of 855,910 barrels at an average price per barrel of $24.26, 695,454 barrels at an average price per barrel of $20.28, and 84,261 barrels at an average price per barrel of $21.64.
(2)	We combine NGLs with oil for reporting purposes. Prior to 2002, we combined NGLs with natural gas for reporting purposes. The NGLs production for 2003 was 823,214 barrels at an average price of $17.60 per barrel and for 2002 was 1,173,504 barrels at an average price of $12.82 per barrel.
(3)	Natural gas production for 2003 and 2002 includes New Zealand production of 14,258,679 Mcf with an average price of $1.83 per Mcf, and 11,351,518 Mcf with an average price of $1.32 per Mcf.

Risk Management

      Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including blowouts, cratering, pipe failure, casing collapse, and fires, each of which could result in severe damage to or destruction of oil and gas wells, production facilities or other property, or individual injuries. The oil and gas exploration business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharges of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental damage. Additionally, as managing general partner of six limited partnerships, we are solely responsible for the day-to-day conduct of those limited partnerships’ affairs and accordingly have liability for expenses and liabilities of the limited

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Commodity Risk

      The oil and gas industry is affected by the volatility of commodity prices. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. We have a price-risk management policy to use derivative instruments to protect against declines in oil and gas prices, mainly through the purchase of price floors and collars. As of the date of this prospectus supplement, we had in place natural gas price floors in effect for the June 2004 contract month through the December 2004 contract month. The natural gas price floors cover notional volumes of 2,760,000 Mmbtu with a weighted average floor price of $5.43 per Mmbtu. With these floors, approximately 50% to 60% of our domestic natural gas production is expected to be covered by hedges for the second and third quarters of 2004 and approximately 12% to 17% of our domestic natural gas production is expected to be covered by hedges for the fourth quarter of 2004. As of the date of this prospectus supplement, we also had crude oil price floors in effect for the July 2004 contract month through the September 2004 contract month. The crude oil price floors cover 225,000 barrels with a weighted average floor price of $31.40 per barrel. Additionally, we purchased a participating costless collar that covers 75,000 barrels for the September 2004 contract month with a weighted average floor price of $31.00 per barrel and a weighted average ceiling price of $42.50 per barrel. These crude oil hedges are expected to cover approximately 20% to 30% of our domestic crude oil production from July 2004 to September 2004.

Competition

      We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and gas properties, as well as for equipment, labor, and materials required to develop and operate such properties. Many of these competitors have financial and technological resources substantially greater than ours. The market for oil and gas properties is highly competitive and we may lack technological information or expertise available to other bidders. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition.

Regulations

	Environmental Regulations

      Our domestic exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas, wetlands, and other ecologically sensitive and protected areas, and impose substantial remedial liabilities for pollution resulting from drilling operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of significant investigatory or remedial obligations, and the imposition of injunctive relief that limits or prohibits our operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. While we believe that we are in substantial compliance with current environmental laws and regulations and have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.

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      We currently own or lease, and have in the past owned or leased, numerous properties in connection with our domestic operations that have been used for the exploration and production of oil and gas for many years. Although we have used operation and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or other wastes may have been disposed or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon or away from could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original conduct, including the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as “CERCLA” or the “Superfund” law, the federal Resource Conservation and Recovery Act or “RCRA,” the federal Clean Water Act, the federal Clean Air Act, the federal Oil Pollution Act or “OPA,” and analogous state laws. Under such laws and any implementing regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damages allegedly caused by the release of petroleum hydrocarbons or other wastes into the environment.

      Our domestic operations offshore in the Gulf of Mexico are subject to OPA, which imposes a variety of requirements related to the prevention of oil spills, and liability for damages resulting from such spills in United States waters. The OPA imposes strict, joint and several liability on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. Liability limits for offshore facilities require a responsible party to pay all removal costs, plus up to $75 million in other damages. These liability limits do not apply, however, if the spill was caused by gross negligence or willful misconduct of the party, if the spill resulted from violation of a federal safety, construction or operation regulation, or if the party fails to report the spill or cooperate fully in any resulting cleanup. The OPA also requires a responsible party at an offshore facility to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. We believe our operations are in substantial compliance with OPA requirements.

      Our operations outside of the United States, including especially in New Zealand, could also potentially be subject to similar foreign governmental controls and restrictions pertaining to protection of human health and the environment. These controls and restrictions may include the need to acquire permits, prohibitions on drilling in certain environmentally sensitive areas, performance of investigatory or remedial actions for any releases of petroleum hydrocarbons or other wastes caused by us or prior operators, closure and restoration of facility sites, and payment of penalties for violations of applicable laws and regulations. We believe that compliance with existing requirements of such governmental bodies has not had a material adverse effect on our results of operations.

	United States Federal, State and New Zealand Regulation of Oil and Natural Gas

      The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government and are affected by the availability, terms and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The Federal Energy Regulatory Commission (“FERC”) is continually proposing and implementing new rules and regulations affecting the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. Some recent FERC proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.

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      Our sales of crude oil, condensate and NGLs are not currently subject to FERC regulation. However, the ability to transport and sell such products is dependent on certain pipelines whose rates, terms and conditions of service are subject to FERC regulation.

      Production of any oil and gas by us will be affected to some degree by state regulations. Many states in which we operate have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. Such statutes, and the regulations promulgated in connection therewith, are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or proration unit, which could restrict the rate of production below the rate that a well would otherwise produce in the absence of such regulation. In addition, certain state regulatory authorities can limit the number of wells or the locations where wells may be drilled. Any of these actions could negatively affect the amount or timing of revenues. Likewise, the government of New Zealand regulates the exploration, production, sales, and transportation of oil and natural gas.

Federal Leases

      Some of our domestic properties are located on federal oil and gas leases administered by various federal agencies, including the Bureau of Land Management. Various regulations and administrative orders affect the terms of leases, and in turn may affect our exploration and development plans, methods of operation, and related matters.

Litigation

      In the ordinary course of business, we have been party to various legal actions, which arise primarily from our activities as operator of oil and gas wells. In our opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.

Employees

      At December 31, 2003, we employed 241 persons. Of these employees, 58 were in New Zealand, eight of whom are members of a union. None of our other employees are represented by a union. Relations with employees are considered to be good.

Facilities

      At December 31, 2004, we occupied approximately 93,000 square feet of office space at 16825 Northchase Drive, Houston, Texas, under a ten-year lease expiring in 2005. The lease requires payments of approximately $164,000 per month. In New Zealand we leased approximately 16,000 square feet of office space, under leases expiring in 2009. These New Zealand leases require payments of approximately $14,000 per month. We also have field offices in various locations from which our employees supervise local oil and gas operations.

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MANAGEMENT

Executive Officers and Directors

A. Earl Swift		Chairman of the Board
Terry E. Swift		President, Chief Executive Officer and Director
Virgil N. Swift		Vice Chairman of the Board
Joseph A. D’Amico		Executive Vice President and Chief Operating Officer
Bruce H. Vincent		Executive Vice President – Corporate Development and Secretary
Alton D. Heckaman, Jr.		Senior Vice President – Finance and Chief Financial Officer
James M. Kitterman		Senior Vice President – Operations
James P. Mitchell		Senior Vice President – Commercial Transactions and Land
Victor R. Moran		Senior Vice President – Energy Marketing and Business Development
David W. Wesson		Controller
Deanna L. Cannon		Director
G. Robert Evans		Director
Raymond E. Galvin		Director
Greg Matiuk		Director
Henry C. Montgomery		Director
Clyde W. Smith, Jr.		Director

      A. Earl Swift, 70, is Chairman of the Board and has served in such capacity since Swift’s founding in 1979. He previously served as President from 1979 to November 1997 and as Chief Executive Officer from 1979 until May 2001. For the 17 years prior to 1979, he was employed by affiliates of American Natural Resources Company. He currently serves on the board of directors of Excalibur Industries, Inc., a public company primarily involved in the machining and manufacturing of steel products for the energy field services market. Mr. Swift is a registered professional engineer and holds a degree in Petroleum Engineering, a Juris Doctorate degree, and a Master’s degree in Business Administration. He is the brother of Virgil N. Swift and the father of Terry E. Swift.

      Terry E. Swift, 48, has served as the Chief Executive Officer since May 2001, as a director since May 2000, and as President since November 1997. He served as Chief Operating Officer from 1991 to February 2000 and was Executive Vice President from 1991 to 1997. He served as Senior Vice President – Exploration and Joint Ventures from 1990 to 1991 and as Vice President – Exploration and Joint Ventures from 1988 to 1990. Mr. Swift has a Bachelor’s degree in Chemical Engineering and a Master’s degree in Business Administration. He is the son of A. Earl Swift and the nephew of Virgil N. Swift.

      Virgil N. Swift, 75, has been a director since 1981 and has acted as Vice Chairman of the Board since 1991. He acted as Executive Vice President – Business Development between November 1991 and June 2000. Mr. Swift previously served as Executive Vice President and Chief Operating Officer from 1982 to 1991. He joined Swift in 1981 as Vice President – Drilling and Production. For the preceding 28 years he held various production, drilling and engineering positions with Gulf Oil Corporation and its subsidiaries, last serving as General Manager – Drilling for Gulf Canada Resources, Inc. Mr. Swift is a registered professional engineer and holds a Bachelor’s degree in Petroleum Engineering. He is the brother of A. Earl Swift and the uncle of Terry E. Swift.

      Bruce H. Vincent, 56, was appointed Executive Vice President – Corporate Development and Secretary in August 2000. On January 23, 2004, Mr. Vincent was also appointed President of Swift Energy International, Inc., a wholly owned subsidiary of Swift. Previously he served as Senior Vice President – Funds Management since joining Swift in 1990. Mr. Vincent holds a Bachelor of Arts degree in Business Administration and a Master’s degree in Finance.

      Joseph A. D’Amico, 56, was appointed Executive Vice President in August 2000 and was appointed Chief Operating Officer in February 2000. He was Senior Vice President of Exploration and Development

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from February 1998 to February 2000. He served as Vice President of Exploration and Development from 1993 to 1998, Director of Exploration and Development from 1992 to 1993 and Funds Manager from 1988, when he joined Swift, until 1992. Mr. D’Amico holds Bachelor of Science and Master of Science degrees in Petroleum Engineering and a Master’s degree in Business Administration.

      Alton D. Heckaman, Jr., 47, was appointed Senior Vice President – Finance and Chief Financial Officer in August 2000. He had previously served as Vice President and Controller from May 1993 to August 2000 and Assistant Vice President – Finance from March 1986 to May 1993. Mr. Heckaman joined Swift in 1982. He is a Certified Public Accountant and holds a Bachelor’s degree in Accounting.

      James M. Kitterman, 60, was appointed Senior Vice President – Operations in May 1993. He had previously served as Vice President – Operations since joining Swift in 1983. Mr. Kitterman holds a Bachelor’s degree in Petroleum Engineering and a Master’s degree in Business Administration.

      James P. Mitchell, 50, was appointed Senior Vice President – Commercial Transactions and Land in February 2003. He previously served as Vice President – Land and Property Transactions from December 2001 to February 2003, Vice President – Land from 1996 to 2001 and Manager of Land from 1992 to 1996. Previously he had served as Director of Land Acquisitions and Joint Venture Negotiations and Coordinator of Land Acquisitions, having joined Swift in 1987. Mr. Mitchell holds a Bachelor’s degree in History and Business Law.

      Victor R. Moran, 48, was appointed Senior Vice President – Energy Marketing and Business Development in August 2000. From 1995 he served as Vice President – Natural Gas Marketing/ Business Development. He had previously served as Director of Business Development since January 1992, when he joined Swift. Mr. Moran holds a Bachelor’s degree in Government, a Master’s degree in Business Administration and a Juris Doctorate degree.

      David W. Wesson, 45, was appointed Controller in January 2001. He previously served as Assistant Controller – Reporting from April 1999 to January 2001, Manager, Reporting/ Budget from October 1995 to April 1999 and Manager, Corporate Accounting/ Budget from February 1990 to October 1995. He joined Swift as Senior Accountant in 1988. Mr. Wesson is a Certified Public Accountant and holds a Bachelor’s degree in Accounting.

      Deanna L. Cannon, 44, was elected as a director at the Annual Meeting of Shareholders held May 11, 2004. Ms. Cannon currently serves as President of Cannon & Company CPA’s PLC, a privately held consulting firm. Through December 2003, she served as Chief Financial Officer of Miller Exploration Company from November 2001 and Vice President – Finance and Corporate Secretary of Miller Exploration from June 1999. From May 1998 to June 1999, she served as Assistant Vice President – Finance of Miller Exploration. She also served as director of Miller Oil Corporation, a wholly owned subsidiary of Miller Exploration, from May 2001 to December 2003. Previously, Ms. Cannon was employed in public accounting for 16 years, initially for Arthur Andersen & Co. in Jacksonville, Florida and later for Plante & Moran, LLP in Traverse City, Michigan. Ms. Cannon holds a Bachelor of Science degree in Accounting and is a Certified Public Accountant. She is a member of the Michigan Oil and Gas Association, American Institute of Certified Public Accountants and Michigan Association of Certified Public Accountants.

      G. Robert Evans, 72, has been a director since 1994. Effective January 1, 1998, Mr. Evans retired as Chairman of Material Sciences Corporation, having held that position since 1991. Material Sciences Corporation is a public company that develops and commercializes continuously processed, coated materials technologies. He remains a director of Material Sciences Corporation. He also currently serves as a director of Consolidated Freightways Corporation, a public trucking company, since 1996. Mr. Evans was also Chief Executive Officer and Vice Chairman of Consolidated Freightways from January 24, 2000 through May 8, 2000. Mr. Evans has a Bachelor of Science degree in Economics.

      Raymond E. Galvin, 72, has served as a director since August 5, 2002. From 1992 until he retired in February 1997, he was the President of Chevron USA Production Company. He also served as a director of Chevron Corp. from 1995 to 1997 and as a Vice President of Chevron Corp. from 1988 to 1997.

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      Greg Matiuk, 59, was appointed to serve as a member of the Board of Directors on September 17, 2003. After 36 years of service, Mr. Matiuk retired from ChevronTexaco Corp. in May 2003 as Executive Vice President, Administrative and Corporate Services, a position he had held since 2001. From 1998 until 2001, he was Vice President, Human Resources and Quality, and from 1996 to 1998 he served as Vice President of Strategic Planning and Quality. Mr. Matiuk began his career at ChevronTexaco in 1967 as a production and reservoir engineer. Among a variety of positions, Mr. Matiuk also served as Manager of Drilling and Production in Australia, General Manager for Chevron U.K. Ltd. in Aberdeen, Scotland, and Vice President and General Manger of the Western Business Unit for Chevron U.S.A. Production Co., in Bakersfield, California. He holds a Bachelor of Science degree in Geological Engineering and a Master’s degree in Business Administration. Mr. Matiuk has also served as a board member for various other organizations including the National Council for Minorities in Engineering, United Way, the Bakersfield Symphony, Boy Scouts of America and INROADS.

      Henry C. Montgomery, 68, has served as a director since 1987. Since 1980, Mr. Montgomery has been and continues to serve as the Chairman of the Board of Montgomery Professional Services Corporation, a management consulting and financial services firm. Mr. Montgomery currently also serves as Chairman of the Board of Catalyst Semiconductor, Inc., a public company that designs, develops and markets programmable integrated circuit products and, since May 2003, he has also served as a director of QuickLogic Corporation, a public company that designs and markets field programmable gate arrays, embedded standard products, associated software and programming hardware. From January 2000 to March 2001, Mr. Montgomery served as Executive Vice President, Finance and Administration, and Chief Financial Officer of Indus International, Inc., a public company engaged in enterprise asset management systems. For eight months in 1999, he served as interim Executive Vice President of Finance and Administration of Spectrian Corporation, a publicly held wireless telecom infrastructure company. Mr. Montgomery holds a Bachelor of Arts degree in Economics.

      Clyde W. Smith, Jr., 55, has served as a director since 1984. Since January 2002, Mr. Smith has served as President of Ascentron, Inc., an electronics manufacturing services company that acquired the assets of D.W. Manufacturing, Inc. in January 2002. From May 1998 until January 2002, Mr. Smith served as General Manager of D.W. Manufacturing, Inc. d/b/a Millennium Technology Services, an electronics manufacturer. Mr. Smith is a Certified Public Accountant and holds a Bachelor of Business Administration degree.

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DESCRIPTION OF EXISTING INDEBTEDNESS

Bank Credit Facility

      Our $300.0 million credit facility with a ten bank syndicate, which is scheduled to mature on October 1, 2005, is secured by substantially all of our domestic oil and gas properties and a majority of the capital stock of our New Zealand operating subsidiaries. We have signed a commitment letter and fee letter with the administrative agent of our bank group relating to the renewal and extension of our bank credit facility. We anticipate that the renewal and extension will be finalized during June 2004 on substantially the same terms as our existing facility except with a $400.0 million revolving line of credit and a maturity date of October 1, 2008.

      The amount available for borrowing under our current bank credit facility is subject to a borrowing base determination that is re-calculated at least every six months. Our current borrowing base, as reconfirmed by the bank syndicate effective May 1, 2004, is $250.0 million. At our request, the commitment amount was reduced to $150.0 million effective May 9, 2003. Under the terms of our current bank credit facility, we can increase this commitment amount back to the total amount of the borrowing base at our discretion. At December 31, 2003 and March 31, 2004, we had $15.9 million and $32.5 million, respectively, in outstanding borrowings under our credit facility. Prior to the redemption date for our 10 1/4% senior subordinated notes due 2009, we intend to repay all outstanding indebtedness under our bank credit facility. The bank credit facility will then be available for future borrowings, including to redeem a portion of our 10 1/4% senior subordinated notes.

      Under our current credit facility and depending on the level of outstanding debt, the interest rate is either the lead bank’s base rate, 4.00% at March 31, 2004, or, at our option, LIBOR plus the applicable margin, which was 2.34% for our outstanding borrowings at March 31, 2004. The weighted average interest rate was 2.47% for our outstanding borrowings at March 31, 2004.

      The terms of the revolving line of credit include, among other restrictions, a limitation on cash dividends, requirements to maintain certain minimum financial ratios, including working capital and debt and equity ratios, and limitations on incurring other debt. Since inception, no cash dividends have been declared on our common stock. Our credit facility limits our repurchase of shares of common stock to $15.0 million from September 28, 2001. In addition, our bank credit facility contains certain covenants that limit, among other things, our ability to:

	•	incur debt;
	•	dispose of property and assets;
	•	enter into consolidation or merger transactions;
	•	enter into certain contracts or leases; and
	•	expand into other lines of business.

      For all periods presented in this prospectus supplement, we were in compliance in all material respects with the provisions of our credit facility. For a detailed description of this credit facility, see the credit agreement which is attached as Exhibit 10.16 of our Quarterly Report on Form 10-Q for the quarter ended September 30, 2001. The first and second amendments are attached as Exhibits 10.17 and 10.18 of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2002.

Senior Subordinated Notes Due 2009

      On August 4, 1999, we issued $125.0 million aggregate principal amount of 10 1/4% senior subordinated notes due August 1, 2009. In accordance with the terms of the indenture, we may redeem these senior subordinated notes on or after August 1, 2004 for cash at a redemption price equal to 105.125% of principal amount, plus accrued and unpaid interest, if any. We intend to repurchase our outstanding

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      For a detailed description of the senior subordinated notes due 2009 and their provisions, see the indenture and the first supplemental indenture filed as an exhibit to the senior subordinated notes registration statement on July 9, 1999 and to our Current Report on Form 8-K filed with the SEC on August 4, 1999.

Senior Subordinated Notes Due 2012

      On April 11, 2002, we issued $200.0 million aggregate principal amount of 9 3/8% senior subordinated notes due May 1, 2012. Payments of principal, interest and premium under the senior subordinated notes due 2012 are subordinated to payments on our existing and future senior debt, including our credit facility. On or after May 1, 2007, we may redeem our senior subordinated notes due 2012 for cash at a redemption price equal to 104.688% of principal amount, plus accrued and unpaid interest, if any, declining to 100% in 2010. In addition, before May 1, 2005, we may redeem up to 33.33% of our senior subordinated notes due 2012 with the proceeds of public offerings of our equity at a redemption price equal to 109.375% of their principal amount, plus accrued and unpaid interest, if any. If certain changes in control occur, each holder of the senior subordinated notes due 2012 will have the right to require us to repurchase their senior subordinated notes due 2012 at 101% of the notes’ principal amount, plus accrued and unpaid interest to the date of repurchase.

      For a detailed description of our senior subordinated notes due 2012 and their provisions, see the indenture and the first supplemental indenture filed as exhibits to our Current Report on Form 8-K filed with the SEC on April 16, 2002.

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DESCRIPTION OF THE NOTES

      You can find the definitions of certain terms used in this description under the subheading “– Certain Definitions,” beginning on page S-     . In this description, the words “Swift,” “we,” “us,” and “our” refer to Swift Energy Company and not to any of its subsidiaries.

      We will issue the notes under an indenture to be dated as of                     , 2004, which is to be supplemented by a first supplemental indenture to be dated as of                     , 2004, referred to as supplemented as the “Indenture,” between Swift and Wells Fargo Bank, National Association, as trustee (the “Trustee”). The Indenture is governed by the Trust Indenture Act of 1939 (the “Trust Indenture Act”). The terms of the notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act.

      We urge you to read the Indenture because it, and not this description, defines your rights as a holder of these notes. A copy of the form of indenture and the first supplemental indenture are incorporated by reference. The form of indenture is filed as an exhibit to our registration statement on Form S-3, filed with the Securities and Exchange Commission on January 21, 2004, of which this prospectus supplement forms a part, and the first supplemental indenture will be filed as an exhibit to a Current Report on Form 8-K.

      We are issuing $150.0 million of senior notes (the “Offered Notes”) now and, subject to our compliance with the covenant described under “– Certain Covenants – Limitation on Indebtedness,” we can issue an unlimited amount of additional notes at later dates under the same Indenture. Any additional notes that we issue in the future will be identical in all respects to the Offered Notes that we are issuing now, except that notes issued in the future will have different issuance prices and issuance dates. The Offered Notes and any additional notes issued under the Indenture are collectively referred to as the “Notes.” We will issue Notes only in fully registered form without coupons, in denominations of $1,000 and integral multiples of $1,000.

Principal, Maturity and Interest

      The Notes will mature on                     , 2011.

      Interest on the Notes will accrue at a rate of      % per annum and will be payable semi-annually in arrears on                     and                     , commencing on                     ,           , in the case of the Offered Notes. We will pay interest to those persons who were holders of record on and immediately preceding each interest payment date.

      Interest on the Notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

Subsidiary Guaranties

      Under the circumstances described below under “– Certain Covenants – Future Subsidiary Guarantors,” Swift’s payment obligations under the Notes may in the future be jointly and severally guaranteed by one or more Subsidiary Guarantors. The Subsidiary Guaranty of any Subsidiary Guarantor will be a senior unsecured obligation of such Subsidiary Guarantor.

      Upon the sale or other disposition of all the Capital Stock of a Subsidiary Guarantor (other than to Swift or an Affiliate of Swift) permitted by the Indenture, such Subsidiary Guarantor will be released from all its obligations under its Subsidiary Guaranty. For a more detailed description of these obligations, see “– Certain Covenants – Limitation on Issuance and Sale of Capital Stock of Restricted Subsidiaries,” and “– Certain Covenants – Limitation on Asset Sales”. In addition, any Subsidiary Guarantor that is designated an Unrestricted Subsidiary in accordance with the terms of the Indenture shall be released from and relieved of its obligations under its Subsidiary Guaranty upon execution and delivery of a supplemental indenture satisfactory to the Trustee. Any Subsidiary Guarantor may be released from its

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      Each of Swift and any Subsidiary Guarantor will agree to contribute to any other Subsidiary Guarantor that makes payments pursuant to its Subsidiary Guaranty an amount equal to Swift’s or such Subsidiary Guarantor’s proportionate share of such payment, based on the net worth of Swift or such Subsidiary Guarantor relative to the aggregate net worth of Swift and the Subsidiary Guarantors.

Optional Redemption

      Except as set forth below, we will not be entitled to redeem the Notes at our option prior to their Stated Maturity.

      On or after                     , 2008, we may redeem all or any portion of the Notes upon not less than 30 nor more than 60 days’ prior notice, at the redemption prices set forth below, plus accrued and unpaid interest, if any, to the redemption date subject to the right of Holders of record on the relevant record date to receive interest due on the relevant interest payment date. The following prices are for Notes redeemed during the 12-month period commencing on                     of the years set forth below, and are expressed as percentages of principal amount:

Year		Redemption Price
2008				%
2009				%
2010 and thereafter			100.000	%

      We may on any one or more occasions prior to                     , 2007, redeem up to 35% of the aggregate principal amount of the Notes originally issued with the net proceeds of one or more Equity Offerings at a redemption price of      % of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of redemption, subject to the right of Holders of record on the relevant record date to receive interest due on the relevant interest payment date, provided that at least 65% of the aggregate principal amount of the Notes originally issued remains outstanding after the occurrence of such redemption. Any such redemption shall occur not later than 90 days after the date of the closing of any such Equity Offering upon not less than 30 nor more than 60 days’ prior notice. The redemption shall be made in accordance with procedures set forth in the Indenture.

      At any time prior to                     , 2008, we will be entitled, at our option, to redeem all, but not less than all, of the Notes at a redemption price equal to 100% of the principal amount of the Notes plus the Applicable Premium as of, and accrued and unpaid interest to, the redemption date (subject to the right of Holders on the relevant record date to receive interest due on the relevant interest payment date). Notice of such redemption must be mailed by first-class mail to each Holder’s registered address, not less than 30 or more than 60 days prior to the redemption date.

      If less than all the Notes are to be redeemed at any time, selection of Notes for redemption will be made by the Trustee in compliance with the requirements of the principal national securities exchange, if any, on which the Notes are listed, or, if the Notes are not so listed, on a pro rata basis.

Sinking Fund

      There will be no mandatory sinking fund payments for the Notes.

Repurchase at the Option of Holders Upon a Change of Control

      Upon the occurrence of a Change of Control, each Holder of Notes shall have the right to require us to repurchase all or any part (equal to $1,000 in principal amount or an integral multiple thereof) of such Holder’s Notes pursuant to the offer described below (“Change of Control Offer”) at a purchase price in cash (a “Change of Control Payment”) equal to 101% of the principal amount of the Notes repurchased,

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      Within 30 days following any Change of Control, we shall:

	(a) cause a notice of the Change of Control Offer to be sent at least once to the Dow Jones News Service or similar business news service in the United States; and
	(b) send, by first-class mail, with a copy to the Trustee, to each Holder of Notes, at such Holder’s address appearing in the Security Register, a notice stating, among other things:

	(1) that a Change of Control has occurred and a Change of Control Offer is being made pursuant to the Indenture and that all Notes, or portions thereof, properly tendered will be accepted for payment,
	(2) the Change of Control Purchase Price and the purchase date, which shall be, subject to any contrary requirements of applicable law, a business day (a “Change of Control Payment Date”) no earlier than 30 days nor later than 60 days from the date we mail such notice,
	(3) that any Note, or portion thereof, accepted for payment, and duly paid on the Change of Control Payment Date, pursuant to the Change of Control Offer shall cease to accrue interest on the Change of Control Payment Date,
	(4) that any Notes, or portions thereof, not properly tendered will continue to accrue interest,
	(5) a description of the transaction or transactions constituting the Change of Control,
	(6) the procedures that the Holders of the Notes must follow in order to tender their Notes, or portions thereof, for payment and the procedures that Holders of Notes must follow in order to withdraw an election to tender Notes, or portions thereof, for payment, and
	(7) all other instructions and materials necessary to enable Holders to tender Notes pursuant to the Change of Control Offer.

      We will comply, to the extent applicable, with the requirements of Section 14(e) under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws and regulations are applicable in connection with the purchase of Notes pursuant to a Change of Control Offer. To the extent that the provisions of any securities laws or regulations conflict with the provisions relating to the Change of Control Offer, we will comply with the applicable securities laws and regulations and will not be deemed to have breached our obligations described above by virtue of such compliance.

      If a Change of Control were to occur, Swift and any Subsidiary Guarantors may not have sufficient financial resources, or may not be able to arrange financing, to pay the purchase price for all Notes tendered by the Holders thereof. In addition, as of the Issue Date, our existing credit facility does, and any future Bank Credit Facilities or other agreements relating to indebtedness to which Swift or any Subsidiary Guarantor becomes a party may, provide that certain events that would constitute a Change of Control are events of default thereunder or require such indebtedness to be repurchased upon a Change of Control. If a Change of Control occurs at a time when Swift and the Subsidiary Guarantors are unable to purchase the Notes (due to insufficient financial resources or otherwise), such failure to purchase tendered Notes would constitute an Event of Default under the Indenture, which would, in turn, constitute a default under our credit facility and may constitute a default under the terms of any other Bank Credit Facility or other Indebtedness of Swift or any Subsidiary Guarantors then outstanding. The provisions under the Indenture related to Swift’s obligation to make an offer to repurchase the Notes as a result of a Change of Control may be waived or modified, at any time prior to the occurrence of such Change of Control, with the written consent of the Holders of a majority in principal amount of the Notes.

      We will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the

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      A “Change of Control” shall be deemed to occur if:

	(a) any “person” or “group” (within the meaning of Section 13(d)(3) and 14(d)(2) of the Exchange Act or any successor provision to either of the foregoing, including any group acting for the purpose of acquiring, holding or disposing of securities within the meaning of Rule 13d-5(b)(1) under the Exchange Act) becomes the “beneficial owner” (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that a Person will be deemed to have “beneficial ownership” of all shares that any such Person has the right to acquire, whether such right is exercisable immediately or only after the passage of time) of 40 percent or more of the total voting power of all classes of the Voting Stock of Swift;
	(b) the sale, lease, transfer or other disposition, directly or indirectly, of all or substantially all the Property of Swift and the Restricted Subsidiaries taken as a whole (other than a disposition of such Property as an entirety or virtually as an entirety to any Wholly Owned Subsidiary) shall have occurred;
	(c) the shareholders of Swift shall have approved any plan of liquidation or dissolution of Swift;
	(d) Swift consolidates with or merges into another Person or any Person consolidates with or merges into us in any such event pursuant to a transaction in which the outstanding Voting Stock of Swift is reclassified into or exchanged for cash, securities or other Property, other than any such transaction where the outstanding Voting Stock of Swift is reclassified into or exchanged for Voting Stock of the surviving Person and the holders of the Voting Stock of Swift immediately prior to such transaction own, directly or indirectly, not less than a majority of the Voting Stock of the surviving Person immediately after such transaction in substantially the same proportion as before the transaction; or
	(e) during any period of two consecutive years, individuals who at the beginning of such period constituted Swift’s Board of Directors (together with any new directors whose election or appointment by such Board or whose nomination for election by the shareholders of Swift was approved by a vote of a majority of the directors then still in office who were either directors at the beginning of such period or whose election or nomination for election was previously approved by such a vote) cease for any reason to constitute a majority of Swift’s Board of Directors then in office.

      The Change of Control repurchase feature is a result of negotiations between Swift and the underwriters of the Offered Notes. We have no present intention to engage in a transaction involving a Change of Control, although it is possible that we would decide to do so in the future. Subject to certain covenants described below, we could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalizations, that would not constitute a Change of Control under the Indenture, but that could increase the amount of indebtedness outstanding at such time or otherwise affect Swift’s capital structure or credit ratings.

      The definition of Change of Control includes a phrase relating to the sale, lease, transfer or other disposition of “all or substantially all” of the Property of Swift and its Restricted Subsidiaries taken as a whole. The Indenture is governed by New York law, and there is no established quantitative definition under New York law of “substantially all” the assets of a corporation. Accordingly, if Swift or any Restricted Subsidiary were to engage in a transaction in which it disposed of less than all the assets of Swift and its Restricted Subsidiaries taken as a whole, a question of interpretation could arise as to whether such disposition was of “substantially all” such assets and whether we are required to make a Change of Control Offer.

      Except as described above with respect to a Change of Control, the Indenture does not contain any other provisions that permit the Holders of the Notes to require that we repurchase or redeem the Notes in the event of a takeover, recapitalization or similar restructuring.

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Certain Covenants

	Covenant Suspension

      During any period (the “Suspension Period”) that the Notes have a rating equal to or higher than BBB- by S&P and Baa3 by Moody’s (“Investment Grade Ratings”) and no Default has occurred and is continuing, we and our Restricted Subsidiaries will not be subject to the following covenants:

	(a) “– Limitation on Indebtedness;”
	(b) “– Limitation on Restricted Payments;”
	(c) “– Limitation on Issuance and Sale of Capital Stock of Restricted Subsidiaries;”
	(d) “– Limitation on Asset Sales;”
	(e) “– Limitation on Transactions with Affiliates;”
	(f) “– Limitation on Restrictions on Distributions from Restricted Subsidiaries;”
	(g) “– Future Subsidiary Guarantors;” and
	(h) clauses (d) and (e) of the covenant described under “– Merger, Consolidation and Sale of Substantially All Assets”

(collectively, the “Suspended Covenants”). In the event that we and our Restricted Subsidiaries are not subject to the Suspended Covenants for any period of time as a result of the preceding sentence, and subsequently one or both of S&P and Moody’s downgrade the rating assigned to the Notes below BBB-, in the case of S&P, and below Baa3, in the case of Moody’s, then we and our Restricted Subsidiaries will thereafter again be subject to the Suspended Covenants (subject to subsequent suspension if the Notes again receive Investment Grade Ratings). Notwithstanding that the Suspended Covenants may be reinstated, no Default or Event of Default will be deemed to have occurred as a result of a failure to comply with the Suspended Covenants during any Suspension Period. With respect to Restricted Payments proposed to be made after the time of such a downgrade, the permissibility of proposed Restricted Payments will be calculated in accordance with the terms of the covenant described below under “– Limitation on Restricted Payments” as though such covenant had been in effect since the Issue Date.

	Limitation on Indebtedness

      The Indenture provides that we will not, and will not permit any of our Restricted Subsidiaries to, directly or indirectly, Incur any Indebtedness unless, after giving pro forma effect to the Incurrence of such Indebtedness and the receipt and application of the proceeds thereof, no Default or Event of Default would occur as a consequence of, or be continuing following, such Incurrence and application and either:

	(a) after giving pro forma effect to such Incurrence and application, the Consolidated Interest Coverage Ratio would exceed 2.5 to 1.0; or
	(b) such Indebtedness is Permitted Indebtedness.

      “Permitted Indebtedness” means any and all of the following:

	(a) Indebtedness arising under the Indenture with respect to the Offered Notes and any Subsidiary Guaranties relating thereto;
	(b) Indebtedness under Bank Credit Facilities, provided that the aggregate principal amount of all Indebtedness under Bank Credit Facilities, at any one time outstanding does not exceed the greater of:

	(1) $300.0 million, which amount shall be permanently reduced by the amount of Net Available Cash used to permanently repay Indebtedness under Bank Credit Facilities and not subsequently reinvested in Additional Assets or used to permanently reduce other Indebtedness pursuant to the provisions of the Indenture described under “– Limitation on Asset Sales”, and

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	(2) an amount equal to the sum of:

	(A) $150.0 million, and
	(B) 25% of Adjusted Consolidated Net Tangible Assets determined as of the date of Incurrence of such Indebtedness,

	and, in the case of either (1) or (2), plus all interest and fees and other obligations thereunder and any Guarantee of such Indebtedness;

	(c) Indebtedness of Swift owing to and held by any Wholly Owned Subsidiary and Indebtedness of a Restricted Subsidiary owing to and held by Swift or any Wholly Owned Subsidiary; provided, however, that any subsequent issue or transfer of Capital Stock or other event that results in any such Wholly Owned Subsidiary ceasing to be a Wholly Owned Subsidiary or any subsequent transfer of any such Indebtedness (except to Swift or a Wholly Owned Subsidiary) shall be deemed, in each case, to constitute the Incurrence of such Indebtedness by the issuer thereof;
	(d) Indebtedness in respect of bid, performance, reimbursement or surety obligations issued by or for the account of Swift or any Restricted Subsidiary in the ordinary course of business, including Guarantees and letters of credit functioning as or supporting such bid, performance, reimbursement or surety obligations (in each case other than for an obligation for money borrowed);
	(e) Indebtedness under Permitted Hedging Agreements;
	(f) in-kind obligations relating to oil or gas balancing positions arising in the ordinary course of business;
	(g) Indebtedness outstanding on the Issue Date not otherwise permitted in clauses (a) through (f) above;
	(h) Non-recourse Purchase Money Indebtedness;
	(i) Indebtedness not otherwise permitted to be Incurred pursuant to this paragraph (excluding any Indebtedness Incurred pursuant to clause (a) of the covenant described under “– Limitation of Indebtedness”), provided that the aggregate principal amount of all Indebtedness Incurred pursuant to this clause (i), together with all Indebtedness Incurred pursuant to clause (j) of this definition in respect of Indebtedness previously Incurred pursuant to this clause (i), at any one time outstanding does not exceed $30.0 million;
	(j) Indebtedness Incurred in exchange for, or the proceeds of which are used to refinance:

	(1) Indebtedness referred to in clauses (a), (g), (h) and (i) of this definition (including Indebtedness previously Incurred pursuant to this clause (j)), and
	(2) Indebtedness Incurred pursuant to clause (a) of the covenant described under “– Limitation of Indebtedness”,

	provided that, in the case of each of the foregoing clauses (1) and (2), such Indebtedness is Permitted Refinancing Indebtedness; and

	(k) Indebtedness consisting of obligations in respect of purchase price adjustments, indemnities or Guarantees of the same or similar matters in connection with the acquisition or disposition of Property.

	Limitation on Liens

      The Indenture provides that we will not, and will not permit any Restricted Subsidiary to, directly or indirectly, enter into, create, Incur, assume or suffer to exist any Lien on or with respect to any Property of Swift or such Restricted Subsidiary, whether owned on the Issue Date or acquired after the Issue Date, or any interest therein or any income or profits therefrom, unless the Notes or any Subsidiary Guaranty of such Restricted Subsidiary are secured equally and ratably with, or prior to, any and all other obligations

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	Limitation on Restricted Payments

      We will not, and will not permit any of our Restricted Subsidiaries to, directly or indirectly, make any Restricted Payment if, at the time of and after giving effect to the proposed Restricted Payment:

	(a) any Default or Event of Default would have occurred and be continuing;
	(b) we could not Incur at least $1.00 of additional Indebtedness pursuant to clause (a) of the covenant described under “– Limitation on Indebtedness”; or
	(c) the aggregate amount expended or declared for all Restricted Payments from the Issue Date would exceed the sum of (without duplication):

	(1) 50% of the aggregate Consolidated Net Income of Swift accrued during the period (treated as one accounting period) commencing on the first day of the fiscal quarter during which the Issue Date occurs, and ending on the last day of the fiscal quarter immediately preceding the date of such proposed Restricted Payment (or, if such aggregate Consolidated Net Income shall be a loss, minus 100% of such loss),
	(2) the aggregate net cash proceeds, or the Fair Market Value of Property other than cash (provided that, in the case of Property that is Capital Stock, such Capital Stock falls within the meaning of clause (b) of the definition of “Additional Assets”), received by us from the issuance or sale (other than to a Subsidiary of Swift or an employee stock ownership plan or trust established by us or any such Subsidiary for the benefit of their employees) by Swift of its Capital Stock (other than Disqualified Stock) after the Issue Date, net of attorneys’ fees, accountants’ fees, underwriters’ or placement agents’ fees, discounts or commissions and brokerage, consultant and other fees actually Incurred in connection with such issuance or sale and net of taxes paid or payable as a result thereof,
	(3) the aggregate net cash proceeds, or the Fair Market Value of Property other than cash, received by us as capital contributions to Swift (other than from a Subsidiary of Swift) on or after the Issue Date,
	(4) the aggregate net cash proceeds received by us from the issuance or sale (other than to any Subsidiary of Swift or an employee stock ownership plan or trust established by us or any such Subsidiary for the benefit of their employees) on or after the Issue Date of convertible Indebtedness that has been converted into or exchanged for Capital Stock (other than Disqualified Stock) of Swift, together with the aggregate cash received by us at the time of such conversion or exchange or received by us from any conversion or exchange of convertible Indebtedness issued or sold (other than to any Subsidiary of Swift or an employee stock ownership plan or trust established by us or any such Subsidiary for the benefit of their employees) prior to the Issue Date, excluding:

	(A) any such Indebtedness issued or sold to us or a Subsidiary of Swift or an employee stock ownership plan or trust established by us or any such Subsidiary for the benefit of their employees, and
	(B) the aggregate amount of any cash or other Property distributed by us or any Restricted Subsidiary upon any such conversion or exchange,

	(5) to the extent not otherwise included in Swift’s Consolidated Net Income, an amount equal to the net reduction in Investments made by Swift and its Restricted Subsidiaries subsequent to the Issue Date in any Person resulting from:

	(A) payments of interest on debt, dividends, repayments of loans or advances or other transfers or distributions of Property, in each case to us or any Restricted Subsidiary from

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	any Person other than Swift or a Restricted Subsidiary, and in an amount not to exceed the book value of such Investments previously made in such Person that were treated as Restricted Payments, or
	(B) the designation of any Unrestricted Subsidiary as a Restricted Subsidiary, and in an amount not to exceed the lesser of:

	(x) the book value of all Investments previously made in such Unrestricted Subsidiary that were treated as Restricted Payments, and
	(y) the Fair Market Value of Swift’s and its Restricted Subsidiaries’ interest in such Unrestricted Subsidiary, and

	(6) $20.0 million.

      The limitations set forth in the preceding paragraph will not prevent us or any Restricted Subsidiary from making the following Restricted Payments so long as, at the time thereof, no Default or Event of Default shall have occurred and be continuing:

	(a) the payment of any dividend on Capital Stock of Swift or any Restricted Subsidiary within 60 days after the declaration thereof, if at such declaration date such dividend could have been paid in compliance with the preceding paragraph;
	(b) the repurchase, redemption or other acquisition or retirement for value of any Capital Stock of Swift or any of its Subsidiaries pursuant to the terms of agreements (including employment agreements) or plans (including by employee stock ownership plans but excluding other plans to purchase such Capital Stock in open market transactions, together with, in the case of employee stock ownership plans, loans to or Investments therein in an amount sufficient to fund such repurchase, redemption or other acquisition or retirement by such plan) approved by Swift’s Board of Directors, including any such repurchase, redemption, acquisition or retirement of shares of such Capital Stock that is deemed to occur upon the exercise of stock options or similar rights if such shares represent all or a portion of the exercise price or are surrendered in connection with satisfying Federal income tax obligations; provided, however, that the aggregate amount of such repurchase, redemptions, acquisitions and retirements shall not exceed the sum of:

	(1) $5.0 million in any twelve-month period, and
	(2) the aggregate net proceeds, if any, received by us during such twelve-month period from any issuance of such Capital Stock pursuant to such agreements or plans;

	(c) the purchase, redemption or other acquisition or retirement for value of any Capital Stock of Swift or any Restricted Subsidiary, in exchange for, or out of the aggregate net cash proceeds of, a substantially concurrent issuance and sale (other than to a Subsidiary of Swift or an employee stock ownership plan or trust established by us or any of its Subsidiaries, for the benefit of their employees) of Capital Stock of Swift (other than Disqualified Stock);
	(d) the purchase, redemption, legal defeasance, acquisition or retirement for value of any Subordinated Indebtedness in exchange for, or out of the proceeds of the substantially concurrent sale of, Capital Stock of Swift (other than Disqualified Stock and other than Capital Stock issued or sold to a Subsidiary of Swift or an employee stock ownership plan or trust established by us or any such Subsidiary for the benefit of their employees);
	(e) the making of any principal payment on or the repurchase, redemption, legal defeasance or other acquisition or retirement for value of (i) Swift’s 10 1/4% senior subordinated notes due 2009 outstanding on the Issue Date, plus the applicable premium thereon, out of the net proceeds of the sale of the Offered Notes or reborrowings under Swift’s bank credit facility that were temporarily repaid out of the net proceeds of the sale of the Offered Notes; (ii) other Subordinated Indebtedness in exchange for, or out of the net proceeds of a substantially concurrent Incurrence (other than a sale to a Subsidiary of Swift) of Subordinated Indebtedness so long as such new Indebtedness is Permitted

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	Refinancing Indebtedness; or (iii) Swift’s 9 3/8% senior subordinated notes due 2012, outstanding on the Issue Date, plus the applicable premium thereon, in exchange for, or out of the net proceeds of a substantially concurrent Incurrence (other than a sale to a Subsidiary of Swift) of Indebtedness Incurred pursuant to clause (a) of the covenant described under “– Limitation on Indebtedness.”
	(f) loans, in an aggregate principal amount outstanding at any one time of not more than $2.0 million, made to officers, directors or employees of Swift or any Restricted Subsidiary approved by the Board of Directors (or by a duly authorized officer) and in compliance with the Sarbanes-Oxley Act of 2002, the net cash proceeds of which are used solely:

	(1) to purchase common stock of Swift in connection with a restricted stock or employee stock purchase plan, or to exercise stock options received pursuant to an employee or director stock option plan or other incentive plan, in a principal amount not to exceed the purchase price of such common stock or the exercise price of such stock options, or
	(2) to refinance loans, together with accrued interest thereon, made pursuant to item of this clause (f).

      The actions described in clauses (a) and (b) of this paragraph shall be included in the calculation of the amount of Restricted Payments. The actions described in clauses (c), (d), (e) and (f) of this paragraph shall be excluded in the calculation of the amount of Restricted Payments, provided that the net cash proceeds from any issuance or sale of Capital Stock or Indebtedness of Swift pursuant to such clause (c), (d) or (e) shall be excluded from any calculations pursuant to clause (2), (3) or (4) under the immediately preceding paragraph.

	Limitation on Issuance and Sale of Capital Stock of Restricted Subsidiaries

      We will not:

	(a) permit any Restricted Subsidiary to sell or otherwise issue any Capital Stock other than to Swift or one of its Wholly Owned Subsidiaries; or
	(b) sell, hypothecate or otherwise dispose of any shares of Capital Stock of any Restricted Subsidiary, or permit any Restricted Subsidiary to do so, except, in each case, for:

	(1) directors’ qualifying shares, or
	(2) a sale of all the Capital Stock of a Restricted Subsidiary owned by Swift or its Subsidiaries effected in accordance with the provisions of the Indenture described under “– Limitation on Asset Sales.”

      In the event of the consummation of a sale of all the Capital Stock of a Restricted Subsidiary pursuant to the foregoing clause (2) and the execution and delivery of a supplemental indenture in form satisfactory to the Trustee, any such Restricted Subsidiary that is also a Subsidiary Guarantor shall be released from all its obligations under its Subsidiary Guaranty.

      For purposes of this covenant, the creation of a Lien on any Capital Stock of a Restricted Subsidiary to secure Indebtedness of Swift or any of its Restricted Subsidiaries will not be deemed to be a violation of this covenant; provided that any sale or disposition by the secured party of such Capital Stock following foreclosure of its Lien will be subject to this covenant.

	Limitation on Asset Sales

      The Indenture provides that we will not, and will not permit any Restricted Subsidiary to, consummate any Asset Sale unless:

	(a) Swift or such Restricted Subsidiary, as the case may be, receives consideration at the time of such Asset Sale at least equal to the Fair Market Value of the Property subject to such Asset Sale; and

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(b) all of the consideration paid to Swift or such Restricted Subsidiary in connection with such Asset Sale is in the form of cash, Permitted Short-Term Investments, Liquid Securities, Exchanged Properties or the assumption by the purchaser of liabilities of Swift (other than liabilities of Swift that are by their terms subordinated to the Notes) or liabilities of any Subsidiary Guarantor that made such Asset Sale (other than liabilities of a Subsidiary Guarantor that are by their terms subordinated to such Subsidiary Guarantor’s Subsidiary Guaranty), in each case as a result of which Swift and its remaining Restricted Subsidiaries are no longer liable for such liabilities, such consideration being defined as “Permitted Consideration”; provided, however, that Swift and its Restricted Subsidiaries shall be permitted to receive Property other than Permitted Consideration, so long as the aggregate Fair Market Value of all such Property other than Permitted Consideration received from Asset Sales and held by Swift or any Restricted Subsidiary at any one time shall not exceed 10.0% of Adjusted Consolidated Net Tangible Assets.

      The Net Available Cash from Asset Sales by us or a Restricted Subsidiary may be applied by us or such Restricted Subsidiary, to the extent we or such Restricted Subsidiary elects (or is required by the terms of any Senior Indebtedness of Swift or a Subsidiary Guarantor), to:

	(a) prepay, repay or purchase Senior Indebtedness of Swift or a Subsidiary Guarantor (in each case excluding Indebtedness owed to us or an Affiliate of Swift); or
	(b) to reinvest in Additional Assets (including by means of an Investment in Additional Assets by a Restricted Subsidiary with Net Available Cash received by us or another Restricted Subsidiary).

      Any Net Available Cash from an Asset Sale not applied in accordance with the preceding paragraph within 365 days from the date of such Asset Sale shall constitute “Excess Proceeds.” When the aggregate amount of Excess Proceeds exceeds $20.0 million, we will be required to make an offer (a “Prepayment Offer”) to purchase Notes having an aggregate principal amount equal to the aggregate amount of Excess Proceeds, at a purchase price equal to 100% of the principal amount of such Notes plus accrued and unpaid interest, if any, to the Purchase Date (as defined) in accordance with the procedures (including proration in the event of oversubscription) set forth in the Indenture, but, if the terms of any other Senior Indebtedness require that a Senior Indebtedness Offer be made contemporaneously with the Prepayment Offer, then the Excess Proceeds shall be prorated between the Prepayment Offer and such Senior Indebtedness Offer in accordance with the aggregate outstanding principal amounts of the Notes and such other Senior Indebtedness, and the aggregate principal amount of Notes for which the Prepayment Offer is made shall be reduced accordingly. If the aggregate principal amount of Notes tendered by Holders thereof exceeds the amount of available Excess Proceeds, then such Excess Proceeds will be allocated pro rata according to the principal amount of the Notes tendered and the Trustee will select the Notes to be purchased in accordance with the Indenture. To the extent that any portion of the amount of Excess Proceeds remains after compliance with the second sentence of this paragraph, and provided that all Holders of Notes have been given the opportunity to tender their Notes for purchase as described in the following paragraph in accordance with the Indenture, Swift and its Restricted Subsidiaries may use such remaining amount for purposes permitted by the Indenture, and the amount of Excess Proceeds will be reset to zero.

      Within 30 days after the 365th day following the date of an Asset Sale, Swift shall, if it is obligated to make an offer to purchase the Notes pursuant to the preceding paragraph, send a written Prepayment Offer notice, the “Prepayment Offer Notice,” by first-class mail, to the Holders of the Notes, accompanied by such information regarding Swift and its Subsidiaries as we believe will enable such Holders of the Notes to make an informed decision with respect to the Prepayment Offer. The Prepayment Offer Notice will state, among other things:

	(a) that we are offering to purchase Notes pursuant to the provisions of the Indenture;
	(b) that any Note (or any portion thereof) accepted for payment (and duly paid on the Purchase Date) pursuant to the Prepayment Offer shall cease to accrue interest on the Purchase Date;

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	(c) that any Notes (or portions thereof) not properly tendered will continue to accrue interest;
	(d) the purchase price and purchase date, the “Purchase Date,” which shall be, subject to any contrary requirements of applicable law, no less than 30 days nor more than 60 days after the date the Prepayment Offer Notice is mailed;
	(e) the aggregate principal amount of Notes to be purchased;
	(f) a description of the procedure that Holders of Notes must follow in order to tender their Notes for payment; and
	(g) all other instructions and materials necessary to enable Holders to tender Notes pursuant to the Prepayment Offer.

      We will comply, to the extent applicable, with the requirements of Section 14(e) under the Exchange Act and any other securities laws or regulations thereunder to the extent such laws and regulations are applicable in connection with the purchase of Notes as described above. To the extent that the provisions of any securities laws or regulations conflict with the provisions relating to the Prepayment Offer, we will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations described above by virtue thereof.

	Limitation on Transactions with Affiliates

      The Indenture provides that we will not, and will not permit any of our Restricted Subsidiaries to, directly or indirectly, conduct any business or enter into any transaction or series of transactions (including the sale, transfer, disposition, purchase, exchange or lease of Property, the making of any Investment, the giving of any Guarantee or the rendering of any service) with or for the benefit of any Affiliate of Swift (other than Swift or a Wholly Owned Subsidiary), unless:

	(a) such transaction is set forth in writing;
	(b) such transaction or series of transactions is on terms no less favorable to us or such Restricted Subsidiary than those that could be obtained in a comparable arm’s-length transaction with a Person that is not an Affiliate of Swift or such Restricted Subsidiary; and
	(c) with respect to a transaction or series of transactions involving aggregate payments by or to us or such Restricted Subsidiary having a Fair Market Value equal to or in excess of:

	(1) $10.0 million but less than $25.0 million, the Board of Directors of Swift (including a majority of the disinterested members of such Board of Directors) approves such transaction or series of transactions and certifies that such transaction or series of transactions complies with clause (b) of this paragraph, as evidenced by a certified resolution delivered to the Trustee, or
	(2) $25.0 million,

	(A) we receive from an independent, nationally recognized investment banking firm or appraisal firm, in either case specializing or having a specialty in the type and subject matter of the transaction (or series of transactions) at issue, a written opinion that such transaction (or series of transactions) is fair, from a financial point of view, to us or such Restricted Subsidiary, and
	(B) such Board of Directors (including a majority of the disinterested members of the Board of Directors of Swift) approves such transaction or series of transactions and certifies that such transaction or series of transactions complies with clause (b) of this paragraph, as evidenced by a certified resolution delivered to the Trustee.

      The limitations of the preceding paragraph do not apply to:

	(a) the payment of reasonable and customary regular fees to directors of Swift or any of its Restricted Subsidiaries who are not employees of Swift or any of its Restricted Subsidiaries;

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	(b) indemnities of officers and directors of Swift or any Subsidiary consistent with such Person’s charter, bylaws and applicable statutory provisions;
	(c) any issuance of securities, or other payments, awards or grants in cash, securities or otherwise pursuant to, or the funding of, employment arrangements, stock options and employee stock purchase and ownership plans approved by the Board of Directors of Swift;
	(d) loans made in compliance with the Sarbanes-Oxley Act of 2002:

	(1) to officers, directors or employees of Swift or any Restricted Subsidiary approved by the Board of Directors of Swift, the net proceeds of which are used solely to purchase common stock of Swift in connection with a restricted stock or employee stock purchase plan, or to exercise stock options received pursuant to an employee or director stock option plan or other incentive plan, in a principal amount not to exceed the purchase price of such common stock or the exercise price of such stock options, or
	(2) to refinance loans, together with accrued interest thereon, made pursuant to this clause (d);

	(e) advances and loans in compliance with the Sarbanes-Oxley Act of 2002 to officers, directors and employees of Swift or any Subsidiary in the ordinary course of business (including, without limitation, non-cash loans for the purchase of joint interests in exploratory and developmental oil and gas prospects or other similar ventures offered by Swift); provided such loans and advances (excluding loans or advances made pursuant to the preceding clause (d)) do not exceed $2.0 million at any one time outstanding;
	(f) any Restricted Payment permitted to be paid pursuant to the provisions of the Indenture described under “– Limitations on Restricted Payments”;
	(g) any transaction or series of transactions between Swift and one or more Restricted Subsidiaries or between two or more Restricted Subsidiaries in the ordinary course of business, provided that no more than 10% of the total voting power of the Voting Stock of any such Restricted Subsidiary is owned by an Affiliate of Swift (other than a Restricted Subsidiary); and
	(h) any transaction or series of transactions pursuant to any agreement or obligation of Swift or any of its Restricted Subsidiaries in effect on the Issue Date.

	Limitation on Restrictions on Distributions from Restricted Subsidiaries

      The Indenture provides that we will not, and will not permit any of our Restricted Subsidiaries to, directly or indirectly, create or otherwise cause or permit to exist or become effective any consensual encumbrance or restriction on the legal right of any Restricted Subsidiary to:

	(a) pay dividends, in cash or otherwise, or make any other distributions on or in respect of its Capital Stock, or pay any Indebtedness or other obligation owed, to us or any other Restricted Subsidiary;
	(b) make loans or advances to Swift or any other Restricted Subsidiary; or
	(c) transfer any of its Property to Swift or any other Restricted Subsidiary.

      Such limitation will not apply:

	(1) with respect to clauses (a), (b) and (c), to encumbrances and restrictions:

	(A) in agreements and instruments (including any Bank Credit Facilities) as in effect on the Issue Date,
	(B) relating to Indebtedness of a Restricted Subsidiary and existing at the time it became a Restricted Subsidiary if such encumbrance or restriction was not created in anticipation of or in

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	connection with the transactions pursuant to which such Restricted Subsidiary became a Restricted Subsidiary, or
	(C) that result from the renewal, refinancing, extension or amendment of an agreement that is the subject of clause (c)(1)(A) or (B) above or clause (c)(2)(A) or (B) below, provided that such encumbrance or restriction is not materially less favorable to the Holders of Notes than those under or pursuant to the agreement so renewed, refinanced, extended or amended, as determined in good faith by the Board of Directors of Swift, and,

	(2) with respect to clause (c) only, to:

	(A) restrictions pursuant to Liens permitted to be in effect without also securing the Notes under the provisions of the Indenture described under “– Limitation on Liens” that limit the right of the debtor to dispose of the Property subject to such Lien,
	(B) any encumbrance or restriction applicable to Property at the time it is acquired by us or a Restricted Subsidiary, so long as such encumbrance or restriction relates solely to the Property so acquired and was not created in anticipation of or in connection with such acquisition,
	(C) customary provisions restricting subletting or assignment of leases and customary provisions in other agreements that restrict assignment of such agreements or rights thereunder, and
	(D) customary restrictions contained in asset sale agreements limiting the transfer of such assets pending the closing of such sale.

	Future Subsidiary Guarantors

      We shall cause each Restricted Subsidiary (except an Exempt Foreign Subsidiary) that:

	(a) incurs Indebtedness or issues Preferred Stock following the Issue Date; or
	(b) has Indebtedness or Preferred Stock outstanding on the date on which such Restricted Subsidiary becomes a Restricted Subsidiary,

to execute and deliver to the Trustee a Subsidiary Guaranty at the time such Restricted Subsidiary Incurs such Indebtedness or becomes a Restricted Subsidiary; provided, however, that such Restricted Subsidiary shall not be required to deliver a supplemental indenture providing for a Subsidiary Guaranty if the aggregate amount of such Indebtedness or Preferred Stock, together with all other Indebtedness and Preferred Stock then outstanding among Restricted Subsidiaries (including Exempt Foreign Subsidiaries) that are not Subsidiary Guarantors, is less than $10.0 million.

      Swift Energy New Zealand Limited and Southern Petroleum (New Zealand) Exploration Limited are each eligible to become Foreign Exempt Subsidiaries.

	Restricted and Unrestricted Subsidiaries

      Unless defined or designated as an Unrestricted Subsidiary, any Person that becomes a Subsidiary of Swift or any of its Restricted Subsidiaries shall be classified as a Restricted Subsidiary subject to the provisions of the next paragraph. We may designate a Subsidiary (including a newly formed or newly acquired Subsidiary) of Swift or any of its Restricted Subsidiaries as an Unrestricted Subsidiary if:

	(a) such Subsidiary does not at such time own any Capital Stock or Indebtedness of, or own or hold any Lien on any Property of, Swift or any other Restricted Subsidiary;
	(b) such Subsidiary does not at such time have any Indebtedness or other obligations that, if in default, would result (with the passage of time or notice or otherwise) in a default on any Indebtedness of Swift or any Restricted Subsidiary; and

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	(c) (1) such designation is effective immediately upon such Subsidiary becoming a Subsidiary of Swift or of a Restricted Subsidiary,

	(2) the Subsidiary to be so designated has total assets of $1,000 or less, or
	(3) if such Subsidiary has assets greater than $1,000, then such redesignation as an Unrestricted Subsidiary is deemed to constitute a Restricted Payment in an amount equal to the Fair Market Value of Swift’s direct and indirect ownership interest in such Subsidiary, and such Restricted Payment would be permitted to be made at the time of such designation under “– Limitation on Restricted Payments.”

      Except as provided in the immediately preceding sentence, no Restricted Subsidiary may be redesignated as an Unrestricted Subsidiary. The designation of an Unrestricted Subsidiary or removal of such designation shall be made by the Board of Directors of Swift or a committee thereof pursuant to a certified resolution delivered to the Trustee and shall be effective as of the date specified in the applicable certified resolution, which shall not be prior to the date such certified resolution is delivered to the Trustees.

      We will not, and will not permit any Unrestricted Subsidiaries to, take any action or enter into any transaction or series of transactions that would result in a Person becoming a Restricted Subsidiary (whether through an acquisition or otherwise) unless, after giving effect to such action, transaction or series of transactions, on a pro forma basis:

	(a) we could Incur at least $1.00 of additional Indebtedness pursuant to clause (a) of the covenant described under “– Limitation on Indebtedness”; and
	(b) no Default or Event of Default would occur or be continuing.

Merger, Consolidation and Sale of Substantially All Assets

      We shall not consolidate with or merge with or into any Person, or sell, transfer, lease or otherwise dispose of, in one transaction or series of transactions, all or substantially all the Property of Swift and the Restricted Subsidiaries taken as a whole, unless:

	(a) the resulting, surviving or transferee Person (a “Successor Company”) shall be a Person organized or existing under the laws of the United States of America, any State thereof or the District of Columbia and the Successor Company (if not Swift) shall expressly assume, by a supplemental indenture, executed and delivered to the Trustee, in form satisfactory to the Trustee, all the obligations of Swift under the Notes and the Indenture;
	(b) in the case of a disposition of all or substantially all of the Property of Swift and the Restricted Subsidiaries taken as a whole, such Property shall have been so disposed of as an entirety or virtually as an entirety to one Person;
	(c) immediately after giving effect to such transaction (and treating, for purposes of this clause (c) and clauses (d) and (e) below, any Indebtedness that becomes or is anticipated to become an obligation of the Successor Company or any Restricted Subsidiary as a result of such transaction as having been Incurred by such Successor Company or such Restricted Subsidiary at the time of such transaction), no Default or Event of Default shall have occurred and be continuing;
	(d) immediately after giving effect to such transaction, the Successor Company would be able to Incur an additional $1.00 of Indebtedness pursuant to clause (a) of the covenant described under “– Limitation on Indebtedness;”
	(e) immediately after giving effect to such transaction, the Successor Company shall have Consolidated Net Worth in an amount that is not less than the Consolidated Net Worth of Swift immediately prior to such transaction; and

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	(f) we shall have delivered to the Trustee an Officers’ Certificate, stating that such consolidation, merger or disposition and such supplemental indenture (if any) comply with the Indenture;

provided, however, that clauses (d) and (e) will not be applicable to (1) a Restricted Subsidiary consolidating with, merging with or into or selling, transferring, leasing or otherwise disposing of all or substantially all its Property to Swift or a Subsidiary Guarantor that is a Wholly Owned Subsidiary or (2) Swift merging with or into an Affiliate of Swift solely for the purpose and with the sole effect of reincorporating Swift in another jurisdiction.

      The Successor Company shall be the successor to Swift and shall succeed to, and be substituted for, and may exercise every right and power of Swift under the Indenture, but the predecessor in the case of a lease shall not be released from the obligation to pay the principal of and interest on the Notes.

Reports

      Notwithstanding that we may not be subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, we shall file with the Commission and provide the Trustee and Holders of Notes with such annual reports and such information, documents and other reports as are specified in Sections 13 and 15(d) of the Exchange Act and applicable to a U.S. corporation subject to such Sections, such information, documents and reports to be so filed and provided at the times specified for the filing of such information, documents and reports under such Sections; provided, however, that we shall not be so obligated to file such information, documents and reports with the Commission if the Commission does not permit such filings.

Certain Definitions

      Set forth below is a summary of certain of the defined terms used in the Indenture. Reference is made to the Indenture for the full definition of all such terms, as well as any other capitalized terms used herein for which no definition is provided.

      “Additional Assets” means:

	(a) any Property (other than cash, Permitted Short-Term Investments or securities) used in the Oil and Gas Business or any business ancillary thereto;
	(b) Investments in any other Person engaged in the Oil and Gas Business or any business ancillary thereto (including the acquisition from third parties of Capital Stock of such Person) as a result of which such other Person becomes a Restricted Subsidiary in compliance with the provisions of the Indenture described under “– Certain Covenants – Restricted and Unrestricted Subsidiaries”;
	(c) the acquisition from third parties of Capital Stock of a Restricted Subsidiary; or
	(d) Permitted Business Investments.

      “Adjusted Consolidated Net Tangible Assets” means (without duplication), as of the date of determination, the remainder of:

	(a) the sum of:

(1) discounted future net revenues from proved oil and gas reserves of Swift and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state, federal or foreign income taxes, as estimated by Swift and confirmed by a nationally recognized firm of independent petroleum engineers in a reserve report prepared as of the end of our most recently completed fiscal year for which audited financial statements are available, as increased by, as of the date of determination, the estimated discounted future net revenues from:

	(A) estimated proved oil and gas reserves acquired since such year end, which reserves were not reflected in such year end reserve report, and

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	(B) estimated oil and gas reserves attributable to upward revisions of estimates of proved oil and gas reserves since such year end due to exploration, development or exploitation activities, in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year end reserve report),

	and decreased by, as of the date of determination, the estimated discounted future net revenues from:

	(C) estimated proved oil and gas reserves produced or disposed of since such year end, and
	(D) estimated oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since such year end due to changes in geological conditions or other factors that would, in accordance with standard industry practice, cause such revisions, in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year end reserve report),

provided that, in the case of each of the determinations made pursuant to clauses (A) through (D), such increases and decreases shall be as estimated by our petroleum engineers, unless there is a Material Change as a result of such acquisitions, dispositions or revisions, in which event the discounted future net revenues utilized for purposes of this clause (a)(1) shall be confirmed in writing by a nationally recognized firm of independent petroleum engineers,

	(2) the capitalized costs that are attributable to oil and gas properties of Swift and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on our books and records as of a date no earlier than the date of our latest annual or quarterly financial statements,
	(3) our Net Working Capital on a date no earlier than the date of our latest annual or quarterly financial statements, and
	(4) the greater of the net book value or the appraised value as estimated by independent appraisers of other tangible assets (including, without duplication, Investments in unconsolidated Restricted Subsidiaries) of Swift and its Restricted Subsidiaries, as of a date no earlier than the date of our latest audited financial statements. For these purposes, net book value shall be determined as of a date no earlier than the date of our latest annual or quarterly financial statements, and on a date no earlier than the date of our latest annual or quarterly financial statements;

	(b) minus the sum of:

	(1) minority interests,
	(2) any net gas balancing liabilities of Swift and its Restricted Subsidiaries reflected in its latest audited financial statements,
	(3) to the extent included in (a)(1) above, the discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices utilized in our year end reserve report), attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of Swift and its Restricted Subsidiaries with respect to Volumetric Production Payments (determined, if applicable, using the schedules specified with respect thereto), and
	(4) the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments that, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in (a)(1) above, would be necessary to fully satisfy the payment obligations of Swift and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

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      If we change our method of accounting from the full cost method to the successful efforts method or a similar method of accounting, “Adjusted Consolidated Net Tangible Assets” will continue to be calculated as if we were still using the full cost method of accounting.

      “Adjusted Treasury Rate” means, with respect to any redemption date:

	(a)(1) the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated “H.15(519)” or any successor publication which is published weekly by the Board of Governors of the Federal Reserve System and which establishes yields on actively traded United States Treasury securities adjusted to constant maturity under the caption “Treasury Constant Maturities,” for the maturity corresponding to the Comparable Treasury Issue (if no maturity is within three months before or after                     , 2008, yields for the two published maturities most closely corresponding to the Comparable Treasury Issue shall be determined and the Adjusted Treasury Rate shall be interpolated or extrapolated from such yields on a straight line basis, rounding to the nearest month) or
	(2) if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per year equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date, in each case calculated on the third Business Day immediately preceding the redemption date, plus
	(b) 0.50%.

      “Affiliate” of any specified Person means any other Person:

	(a) that directly or indirectly through one or more intermediaries controls, or is controlled by, or is under common control with, such specified Person; or
	(b) that beneficially owns or holds directly or indirectly 10% or more of any class of the Voting Stock of such specified Person or of any Subsidiary of such specified Person.

      For the purposes of this definition, “control,” when used with respect to any specified Person, means the power to direct the management and policies of such Person directly or indirectly, whether through the ownership of Voting Stock, by contract or otherwise; and the terms “controlling” and “controlled” have meanings correlative to the foregoing.

      “Applicable Premium” means, with respect to a Note at any redemption date, the greater of:

	(a) 1.0% of the principal amount of such Note and
	(b) the excess of

	(1) the present value at such redemption date of (A) the redemption price of such Note on                     , 2008 (such redemption price being described in the second paragraph and accompanying table of the “– Optional Redemption” section, exclusive of any accrued interest) plus (B) all required remaining scheduled interest payments due on such Note through                     , 2008, computed using a discount rate equal to the Adjusted Treasury Rate, over,
	(2) the principal amount of such Note on such redemption date.

      “Asset Sale” means, with respect to any Person, any transfer, conveyance, sale, lease or other disposition (collectively, “dispositions,” and including dispositions pursuant to any consolidation or merger) by such Person or any of its Restricted Subsidiaries in any single transaction or series of transactions of:

	(a) shares of Capital Stock or other ownership interests of another Person (including Capital Stock of Restricted Subsidiaries and Unrestricted Subsidiaries); or
	(b) any other Property of such Person or any of its Restricted Subsidiaries;

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provided, however, that the term “Asset Sale” shall not include:

	(a) the disposition of Permitted Short-Term Investments, inventory, accounts receivable, surplus or obsolete equipment or other Property (excluding the disposition of oil and gas in place and other interests in real property unless made in connection with a Permitted Business Investment) in the ordinary course of business;
	(b) the abandonment, assignment, lease, sublease or farm-out of oil and gas properties, or the forfeiture or other disposition of such properties pursuant to standard form operating agreements, in each case in the ordinary course of business in a manner that is customary in the Oil and Gas Business;
	(c) the disposition of Property received in settlement of debts owing to us or any Restricted Subsidiary as a result of foreclosure, perfection or enforcement of any Lien or debt, which debts were owing to us or any Restricted Subsidiary in the ordinary course of business of Swift or such Restricted Subsidiary;
	(d) any disposition that constitutes a Restricted Payment made in compliance with the provisions of the Indenture described under “– Certain Covenants – Limitation on Restricted Payments;”
	(e) when used with respect to us, any disposition of all or substantially all of the Property of Swift and its Restricted Subsidiaries taken as a whole permitted pursuant to the provisions of the Indenture described under “– Merger, Consolidation and Sale of Substantially All Assets;”
	(f) the disposition of any Property by us or a Restricted Subsidiary to Swift or a Wholly Owned Subsidiary;
	(g) the disposition of any Property with a Fair Market Value of less than $2.0 million; or
	(h) any Production Payments and Reserve Sales, provided that any such Production Payments and Reserve Sales, other than incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to us or a Restricted Subsidiary, shall have been created, Incurred, issued, assumed or Guaranteed in connection with the financing of, and within 60 days after the acquisition of, the Property that is subject thereto.

      “Average Life” means, with respect to any Indebtedness, at any date of determination, the quotient obtained by dividing:

	(a) the sum of the products of:

	(1) the number of years (and any portion thereof) from the date of determination to the date or dates of each successive scheduled principal payment (including any sinking fund or mandatory redemption payment requirements) of such Indebtedness, multiplied by
	(2) the amount of each such principal payment,

	(b) by the sum of all such principal payments.

      “Bank Credit Facilities” means, with respect to any Person, one or more debt facilities or commercial paper facilities with banks or other institutional lenders providing for revolving credit loans, term loans, receivables or inventory financing (including through the sale of receivables or inventory financing to such lenders or to special purpose entities formed to borrow from such lenders against such receivables or inventory) or trade or standby letters of credit, in each case together with any extensions, revisions, refinancings or replacements thereof by a lender or syndicate of lenders.

      “Capital Lease Obligation” means any obligation that is required to be classified and accounted for as a capital lease obligation in accordance with GAAP, and the amount of Indebtedness represented by such obligation shall be the capitalized amount of such obligation determined in accordance with GAAP, and

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      “Capital Stock” means, with respect to any Person, any shares or other equivalents (however designated) of any class of corporate stock or partnership interests or any other participations, rights, warrants, options or other interests in the nature of an equity interest in such Person, including Preferred Stock, but excluding any debt security convertible or exchangeable into such equity interest.

      “Comparable Treasury Issue” means the United States Treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term from the redemption date to                     , 2008, that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of a maturity most nearly equal to                     , 2008.

      “Comparable Treasury Price” means, with respect to any redemption date, if clause (a)(2) of the Adjusted Treasury Rate is applicable, the average of three, or such lesser number as is obtained by the Trustee, Reference Treasury Dealer Quotations for such redemption date.

      “Consolidated Interest Coverage Ratio” means, as of the date of the transaction (the “Transaction Date”) giving rise to the need to calculate the Consolidated Interest Coverage Ratio, the ratio of:

	(a) the aggregate amount of EBITDA of Swift and its consolidated Restricted Subsidiaries for the four full fiscal quarters immediately prior to the Transaction Date for which financial statements are available; to
	(b) the aggregate Consolidated Interest Expense of Swift and its Restricted Subsidiaries that is anticipated to accrue during a period consisting of the fiscal quarter in which the Transaction Date occurs and the three fiscal quarters immediately subsequent thereto (based upon the pro forma amount and maturity of, and interest payments in respect of, Indebtedness of Swift and its Restricted Subsidiaries expected by us to be outstanding on the Transaction Date), assuming for the purposes of this measurement the continuation of market interest rates prevailing on the Transaction Date and base interest rates in respect of floating interest rate obligations equal to the base interest rates on such obligations in effect as of the Transaction Date; provided, that if we or any of our Restricted Subsidiaries is a party to any Interest Rate Protection Agreement that would have the effect of changing the interest rate on any Indebtedness of Swift or any of its Restricted Subsidiaries for such four quarter period (or a portion thereof), the resulting rate shall be used for such four quarter period or portion thereof; provided further that any Consolidated Interest Expense with respect to Indebtedness Incurred or retired by Swift or any of its Restricted Subsidiaries during the fiscal quarter in which the Transaction Date occurs shall be calculated as if such Indebtedness was so Incurred or retired on the first day of the fiscal quarter in which the Transaction Date occurs.

      In addition, if at any time since the beginning of the four full fiscal quarter period preceding the Transaction Date through and including the Transaction Date:

	(a) Swift or any of its Restricted Subsidiaries shall have engaged in any Asset Sale, EBITDA for such period shall be reduced by an amount equal to the EBITDA (if positive), or increased by an amount equal to the EBITDA (if negative), directly attributable to the Property that is the subject of such Asset Sale for such period calculated on a pro forma basis as if such Asset Sale and any related retirement of Indebtedness had occurred on the first day of such period; or
	(b) (1) Swift or any of its Restricted Subsidiaries shall have acquired or made any Investment in any material assets, or

	(2) the transaction giving rise to the need to calculate the Consolidated Interest Coverage Ratio is such an Investment or acquisition,

	EBITDA shall be calculated on a pro forma basis as if such Investments or asset acquisitions had occurred on the first day of such four fiscal quarter period.

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      “Consolidated Interest Expense” means, with respect to any Person for any period, without duplication

	(a) the sum of:

	(1) the aggregate amount of cash and noncash interest expense (including capitalized interest) of such Person and its Restricted Subsidiaries for such period as determined on a consolidated basis in accordance with GAAP in respect of Indebtedness, including:

	(A) any amortization of debt discount,
	(B) net costs associated with Interest Rate Protection Agreements (including any amortization of discounts),
	(C) the interest portion of any deferred payment obligation,
	(D) all accrued interest, and
	(E) all commissions, discounts, commitment fees, origination fees and other fees and charges owed with respect to Bank Credit Facilities and other Indebtedness paid, accrued or scheduled to be paid or accrued during such period,

	(2) Disqualified Stock Dividends of such Person (and of its Restricted Subsidiaries if paid to a Person other than such Person or its Restricted Subsidiaries) and Preferred Stock Dividends of such Person’s Restricted Subsidiaries if paid to a Person other than such Person or its other Restricted Subsidiaries,
	(3) the portion of any obligation of such Person or its Restricted Subsidiaries in respect of any Capital Lease Obligation allocable to interest expense in accordance with GAAP,
	(4) the portion of any rental obligation of such Person or its Restricted Subsidiaries in respect of any Sale and Leaseback Transaction that is Indebtedness allocable to interest expense (determined as if such obligation were treated as a Capital Lease Obligation), and
	(5) to the extent any Indebtedness of any other Person (other than Restricted Subsidiaries) is Guaranteed by such Person or any of its Restricted Subsidiaries, the aggregate amount of interest paid, accrued or scheduled to be paid or accrued by such other Person during such period attributable to any such Indebtedness;

	less

	(b) to the extent included in (a) above, amortization or write-off of deferred financing costs (other than debt discounts) of such Person and its Restricted Subsidiaries during such period;

in the case of both (a) and (b) above, after elimination of intercompany accounts among such Person and its Restricted Subsidiaries and as determined in accordance with GAAP.

      “Consolidated Net Income” of any Person means, for any period, the aggregate net income (or net loss, as the case may be) of such Person and its Restricted Subsidiaries for such period on a consolidated basis, determined in accordance with GAAP; provided that there shall be excluded therefrom, without duplication:

	(a) items classified as extraordinary gains or losses net of tax (less all fees and expenses relating thereto);
	(b) any gain or loss net of taxes (less all fees and expenses relating thereto) realized on the sale or other disposition of Property, including the Capital Stock of any other Person (but in no event shall this clause apply to any gains or losses on the sale in the ordinary course of business of oil, gas or other hydrocarbons produced or manufactured);
	(c) the net income of any Restricted Subsidiary of such specified Person to the extent the transfer to that Person of that income is restricted by contract or otherwise, except for any cash

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	dividends or cash distributions actually paid by such Restricted Subsidiary to such Person during such period;
	(d) the net income (or loss) of any other Person in which such specified Person or any of its Restricted Subsidiaries has an interest (which interest does not cause the net income of such other Person to be consolidated with the net income of such specified Person in accordance with GAAP or is an interest in a consolidated Unrestricted Subsidiary), except to the extent of the amount of cash dividends or other cash distributions actually paid to such Person or its consolidated Restricted Subsidiaries by such other Person during such period;
	(e) any gain or loss, net of taxes, realized on the termination of any employee pension benefit plan;
	(f) any adjustments of a deferred tax liability or asset pursuant to Statement of Financial Accounting Standards No. 109 that result from changes in enacted tax laws or rates;
	(g) the cumulative effect of a change in accounting principles;
	(h) any write-downs of non-current assets, provided that any ceiling limitation write-downs under SEC guidelines shall be treated as capitalized costs, as if such write-downs had not occurred; and
	(i) any non-cash compensation expense realized upon issuance of stock under an employee stock purchase plan or for grants of performance shares, stock options or stock awards to officers, directors and employees of Swift or any of its Restricted Subsidiaries.

      “Consolidated Net Worth” of any Person means the stockholders’ equity of such Person and its Restricted Subsidiaries, as determined on a consolidated basis in accordance with GAAP, less (to the extent included in stockholders’ equity) amounts attributable to Disqualified Stock of such Person or its Restricted Subsidiaries.

      “Default” means any event, act or condition the occurrence of which is, or after notice or the passage of time or both would be, an Event of Default.

      “Disqualified Stock” means, with respect to any Person, any Capital Stock that by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable, in either case at the option of the holder thereof) or otherwise:

	(a) matures or is mandatorily redeemable pursuant to a sinking fund obligation or otherwise;
	(b) is or may become redeemable or repurchasable at the option of the holder thereof, in whole or in part; or
	(c) is convertible or exchangeable at the option of the holder thereof for debt or any other Disqualified Stock;

in each case on or prior to the first anniversary of the Stated Maturity of the Notes.

      “Disqualified Stock Dividends” means all dividends with respect to Disqualified Stock of Swift held by Persons other than a Wholly Owned Subsidiary. The amount of any such dividend shall be equal to the quotient of such dividend divided by the difference between one and the maximum statutory federal income tax rate (expressed as a decimal number between 1 and 0) then applicable to Swift.

      “Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

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      “EBITDA” means with respect to any Person for any period, the Consolidated Net Income of such Person for such period:

	(a) plus the sum of, to the extent reflected in the consolidated income statement of such Person and its Restricted Subsidiaries for such period from which Consolidated Net Income is determined and deducted in the determination of such Consolidated Net Income, without duplication:

	(1) income tax expense (but excluding income tax expense relating to sales or other dispositions of Property, including the Capital Stock of any other Person, the gains from which are excluded in the determination of such Consolidated Net Income),
	(2) Consolidated Interest Expense,
	(3) depreciation and depletion expense,
	(4) amortization expense,
	(5) exploration expense (if applicable to us after the Issue Date), and
	(6) any other noncash charges including unrealized foreign exchange losses (excluding, however, any such other noncash charge that requires an accrual of or reserve for cash charges for any future period);

	(b) less the sum of, to the extent reflected in the consolidated income statement of such Person and its Restricted Subsidiaries for such period from which Consolidated Net Income is determined and added in the determination of such Consolidated Net Income, without duplication:

	(1) income tax recovery (excluding, however, income tax recovery relating to sales or other dispositions of Property, including the Capital Stock of any other Person, the losses from which are excluded in the determination of such Consolidated Net Income), and
	(2) unrealized foreign exchange gains.

      “Equity Offering” means a bona fide underwritten sale to the public of common stock of Swift pursuant to a registration statement (other than a Form S-8 or any other form relating to securities issuable under any employee benefit plan of Swift) that is declared effective by the Commission following the Issue Date.

      “Exchanged Properties” means Properties used or useful in the Oil and Gas Business received by us or a Restricted Subsidiary in trade or as a portion of the total consideration for other such Properties.

      “Exchange Rate Contract” means, with respect to any Person, any currency swap agreements, forward exchange rate agreements, foreign currency futures or options, exchange rate collar agreements, exchange rate insurance and other agreements or arrangements, or any combination thereof, entered into by such Person in the ordinary course of its business for the purpose of limiting or managing exchange rate risks to which such Person is subject.

      “Exempt Foreign Subsidiary” means any Restricted Subsidiary that is a foreign corporation if more than 50% of:

	(a) the total combined voting power of all Voting Stock of the corporation, or
	(b) the total value of the Capital Stock of the corporation is owned or is considered as owned by United States shareholders on any day during the taxable year of the foreign corporation,

and that, in any case, is so designated by Swift in an Officers’ Certificate delivered to the Trustee, and which Restricted Subsidiary is not a guarantor of, and has no Lien (other than a Lien with respect to less than two-thirds of the Capital Stock of an Exempt Foreign Subsidiary) to secure the Bank Credit Facilities or any other Indebtedness of Swift or any Restricted Subsidiary other than an Exempt Foreign Subsidiary. A United States shareholder, as used in this definition, means any Person who owns or is considered as owning 10% or more of the total combined voting power of all Voting Stock of the foreign

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      “Fair Market Value” means, with respect to any Property to be transferred pursuant to any Asset Sale or Sale and Leaseback Transaction or any noncash consideration or Property transferred or received by any Person, the fair market value of such consideration or other Property as determined by:

	(a) any officer of Swift if such fair market value is greater than $2.0 million but less than $10.0 million; and
	(b) the Board of Directors of Swift as evidenced by a certified resolution delivered to the Trustee if such fair market value is equal to or in excess of $10.0 million.

      “GAAP” means United States generally accepted accounting principles as in effect on the date of the Indenture, unless stated otherwise.

      “Guarantee” by any Person means any obligation, contingent or otherwise, of such Person guaranteeing or having the economic effect of guaranteeing any indebtedness of any other Person (a “primary obligor”) in any manner, whether directly or indirectly, and including any Lien on the assets of such Person securing obligations to pay Indebtedness of the primary obligor, and any obligation of such Person:

	(a) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness or any security for the payment of such Indebtedness;
	(b) to purchase Property, securities or services for the purpose of assuring the holder of such indebtedness of the payment of such indebtedness; or
	(c) to maintain working capital, equity capital or other financial statement condition or liquidity of the primary obligor so as to enable the primary obligor to pay such indebtedness (and “Guaranteed”, “Guaranteeing” and “Guarantor” shall have meanings correlative to the foregoing);

	provided, however, that a Guarantee by any Person shall not include:

	(a) endorsements by such Person for collection or deposit, in either case, in the ordinary course of business; or
	(b) a contractual commitment by one Person to invest in another Person for so long as such Investment is reasonably expected to constitute a Permitted Investment under clause of the definition of Permitted Investments.

      “Holder” means the Person in whose name a Note is registered on the Securities Register.

      “Incur” means, with respect to any Indebtedness or other obligation of any Person, to create, issue, incur (by conversion, exchange or otherwise), assume, Guarantee or become liable (including by reason of a merger or consolidation) in respect of such Indebtedness or other obligation or the recording, as required pursuant to GAAP or otherwise, of any such indebtedness or obligation on the balance sheet of such Person (and “Incurrence,” “Incurred,” “Incurrable” and “Incurring” shall have meanings correlative to the foregoing); provided, however, that a change in GAAP that results in an obligation of such Person that exists at such time, and is not theretofore classified as Indebtedness, becoming Indebtedness shall not be deemed an Incurrence of such Indebtedness; provided further, however, that solely for purposes of determining compliance with “– Certain Covenants – Limitation on Indebtedness,” amortization of debt discount shall not be deemed to be the Incurrence of Indebtedness, provided that in the case of Indebtedness sold at a discount, the amount of such Indebtedness shall at all times be the aggregate principal amount at Stated Maturity. For purposes of this definition, Indebtedness of Swift or a Restricted Subsidiary held by a Wholly Owned Subsidiary shall be deemed to be Incurred by us or such Restricted

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      “Indebtedness” means at any time (without duplication), with respect to any Person, whether recourse is to all or a portion of the assets of such Person, and whether or not contingent:

	(a) any obligation of such Person for borrowed money;
	(b) any obligation of such Person evidenced by bonds, debentures, notes, Guarantees or other similar instruments, including any such obligations incurred in connection with the acquisition of Property, assets or business;
	(c) any reimbursement obligation of such Person with respect to letters of credit, bankers’ acceptances or similar facilities issued for the account of such Person;
	(d) any obligation of such Person issued or assumed as the deferred purchase price of Property or services (other than Trade Accounts Payable);
	(e) any Capital Lease Obligation of such Person;
	(f) the maximum fixed redemption or repurchase price of Disqualified Stock of such Person at the time of determination;
	(g) any Preferred Stock of any Restricted Subsidiary, provided that such Restricted Subsidiary is not a Subsidiary Guarantor;
	(h) any payment obligation of such Person under Exchange Rate Contracts, Interest Rate Protection Agreements, Oil and Gas Hedging Contracts or under any similar agreements or instruments;
	(i) any obligation to pay rent or other payment amounts of such Person with respect to any Sale and Leaseback Transaction to which such Person is a party;
	(j) any obligation of the type referred to in clauses (a) through (h) of this paragraph of another Person and all dividends of another Person the payment of which, in either case, such Person has Guaranteed or is responsible or liable, directly or indirectly, as obligor, Guarantor or otherwise; and
	(k) all obligations of the type referred to in clauses (a) through (i) of another Person secured by any Lien on any Property of such Person (whether or not such obligation is assumed by such Person), the amount of such obligation being deemed to be the lesser of the value of such Property or the amount of the obligation so secured;

provided, however, that Indebtedness shall not include Production Payments and Reserve Sales. For purposes of this definition, the maximum fixed repurchase price of any Disqualified Stock that does not have a fixed repurchase price shall be calculated in accordance with the terms of such Disqualified Stock as if such Disqualified Stock were repurchased on any date on which Indebtedness shall be required to be determined pursuant to the Indenture; provided, however, that if such Disqualified Stock is not then permitted to be repurchased, the repurchase price shall be the book value of such Disqualified Stock. The amount of Indebtedness of any Person at any date shall be the outstanding balance at such date of all unconditional obligations as described above and the maximum liability at such date in respect of any contingent obligations described above.

      “Interest Rate Protection Agreement” means, with respect to any Person, any interest rate swap agreement, forward rate agreement, interest rate cap or collar agreement or other financial agreement or arrangement entered into by such Person in the ordinary course of its business for the purpose of limiting or managing interest rate risks to which such Person is subject.

      “Investment” means, with respect to any Person:

	(a) any amount paid by such Person, directly or indirectly, to any other Person for Capital Stock of, or as a capital contribution to, any other Person; or

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	(b) any direct or indirect loan or advance to any other Person (other than accounts receivable of such Person arising in the ordinary course of business);

	provided, however, that Investments shall not include:

	(1) in the case of clause (a) as used in the definition of “Restricted Payments” only, any such amount paid through the issuance of Capital Stock of Swift (other than Disqualified Stock); and
	(2) in the case of clause (a) or (b), extensions of trade credit on commercially reasonable terms in accordance with normal trade practices and any increase in the equity ownership in any Person resulting from retained earnings of such Person.

      “Issue Date” means the date on which the Offered Notes first were issued under the Indenture.

      “Lien” means, with respect to any Property, any mortgage or deed of trust, pledge, hypothecation, assignment, deposit arrangement, security interest, lien (statutory or other), charge, easement, encumbrance, preference, priority or other security or similar agreement or preferential arrangement of any kind or nature whatsoever on or with respect to such Property (including any conditional sale or other title retention agreement having substantially the same economic effect as any of the foregoing). For purposes of the provisions of the Indenture described under “– Certain Covenants – Limitation on Liens,” a Capital Lease Obligation shall be deemed to be secured by a Lien on the Property being leased.

      “Liquid Securities” means securities:

	(a) of an issuer that is not an Affiliate of Swift;
	(b) that are publicly traded on the New York Stock Exchange, the American Stock Exchange or the Nasdaq National Market; and
	(c) as to which Swift is not subject to any restrictions on sale or transfer (including any volume restrictions under Rule 144 under the Securities Act or any other restrictions imposed by the Securities Act) or as to which a registration statement under the Securities Act covering the resale thereof is in effect for as long as the securities are held;

	provided that securities meeting the requirements or clauses (a), (b) and (c) above shall be treated as Liquid Securities from the date of receipt thereof until and only until the earlier of:

	(1) the date on which such securities are sold or exchanged for cash or Permitted Short-Term Investments, and
	(2) 240 days following the date of receipt of such securities. If such securities are not sold or exchanged for cash or Permitted Short-Term Investments within 240 days of receipt thereof, for purposes of determining whether the transaction pursuant to which Swift or the Restricted Subsidiary received the securities was in compliance with the provisions of the Indenture described under “– Certain Covenants – Limitation on Asset Sales,” such securities shall be deemed not to have been Liquid Securities at any time.

      “Material Change” means an increase or decrease (except to the extent resulting from changes in prices) of more than 30% during a fiscal quarter in the estimated discounted future net revenues from proved oil and gas reserves of Swift and its Restricted Subsidiaries, calculated in accordance with clause (a)(1) of the definition of Adjusted Consolidated Net Tangible Assets; provided, however, that the following will be excluded from the calculation of Material Change:

	(a) any acquisitions during the quarter of oil and gas reserves with respect to which our estimate of the discounted future net revenues from proved oil and gas reserves has been confirmed by independent petroleum engineers; and
	(b) any dispositions of Properties during such quarter that were disposed of in compliance with the provisions of the Indenture described under “– Certain Covenants – Limitation on Asset Sales.”

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      “Moody’s” means Moody’s Investors Service, Inc. and its successors.

      “Net Available Cash” from an Asset Sale means cash proceeds received therefrom, including:

	(a) any cash proceeds received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise, but only as and when received; and
	(b) the Fair Market Value of Liquid Securities and Permitted Short-Term Investments, and excluding:

	(1) any other consideration received in the form of assumption by the acquiring Person of Indebtedness or other obligations relating to the Property that is the subject of such Asset Sale, and
	(2) except to the extent converted within 240 days after such Asset Sale to cash, Liquid Securities or Permitted Short-Term Investments, consideration constituting Exchanged Properties or consideration other than as identified in the immediately preceding clauses (a) and (b),

	in each case net of:

	(a) all legal, title and recording expenses, commissions and other fees and expenses Incurred, and all federal, state, foreign and local taxes required to be paid or accrued as a liability under GAAP as a consequence of such Asset Sale;
	(b) all payments made on any Indebtedness (but specifically excluding Indebtedness of Swift and its Restricted Subsidiaries assumed in connection with or in anticipation of such Asset Sale) that is secured by any assets subject to such Asset Sale, in accordance with the terms of any Lien upon such assets, or that must by its terms, or in order to obtain a necessary consent to such Asset Sale or by applicable law, be repaid out of the proceeds from such Asset Sale, provided that such payments are made in a manner that results in the permanent reduction in the balance of such Indebtedness and, if applicable, a permanent reduction in any outstanding commitment for future incurrences of Indebtedness thereunder,
	(c) all distributions and other payments required to be made to minority interest holders in Subsidiaries or joint ventures as a result of such Asset Sale; and
	(d) the deduction of appropriate amounts to be provided by the seller as a reserve, in accordance with GAAP, against any liabilities associated with the assets disposed of in such Asset Sale and retained by us or any Restricted Subsidiary after such Asset Sale;

provided, however, that if any consideration for an Asset Sale (which would otherwise constitute Net Available Cash) is required to be held in escrow pending determination of whether a purchase price adjustment will be made, such consideration (or any portion thereof) shall become Net Available Cash only at such time as it is released to such Person or its Restricted Subsidiaries from escrow.

      “Net Working Capital” means:

	(a) all current assets of Swift and its Restricted Subsidiaries; less
	(b) all current liabilities of Swift and its Restricted Subsidiaries, except current liabilities included in Indebtedness,

in each case as set forth in consolidated financial statements of Swift prepared in accordance with GAAP.

      “Non-recourse Purchase Money Indebtedness” means Indebtedness (other than Capital Lease Obligations) of Swift or any Restricted Subsidiary Incurred in connection with the acquisition by us or such Restricted Subsidiary in the ordinary course of business of fixed assets used in the Oil and Gas

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	(a) the holders of such Indebtedness agree that they will look solely to the fixed assets so acquired that secure such Indebtedness, and neither Swift nor any Restricted Subsidiary:

	(1) is directly or indirectly liable for such Indebtedness, or
	(2) provides credit support, including any undertaking, Guarantee, agreement or instrument that would constitute Indebtedness (other than the grant of a Lien on such acquired fixed assets); and

(b) no default or event of default with respect to such Indebtedness would cause, or permit (after notice or passage of time or otherwise), any holder of any other Indebtedness of Swift or a Restricted Subsidiary to declare a default on such other Indebtedness or cause the payment, repurchase, redemption, defeasance or other acquisition or retirement for value thereof to be accelerated or payable prior to any scheduled principal payment, scheduled sinking fund payment or maturity.

      “Oil and Gas Business” means the business of exploiting, exploring for, developing, acquiring, operating, producing, processing, gathering, marketing, storing, selling, hedging, treating, swapping, refining and transporting hydrocarbons and other related energy businesses.

      “Oil and Gas Hedging Contract” means, with respect to any Person, any agreement or arrangement, or any combination thereof, relating to oil and gas or other hydrocarbon prices, transportation or basis costs or differentials or other similar financial factors, that is customary in the Oil and Gas Business and is entered into by such Person in the ordinary course of its business for the purpose of limiting or managing risks associated with fluctuations in such prices, costs, differentials or similar factors.

      “Oil and Gas Liens” means:

	(a) Liens on any specific Property or any interest therein, construction thereon or improvement thereto to secure all or any part of the costs incurred for surveying, exploration, drilling, extraction, development, operation, production, construction, alteration, repair or improvement of, in, under or on such Property and the plugging and abandonment of wells located thereon (it being understood that, in the case of oil and gas producing properties, or any interest therein, costs incurred for “development” shall include costs incurred for all facilities relating to such properties or to projects, ventures or other arrangements of which such properties form a part or which relate to such properties or interests);
	(b) Liens on an oil or gas producing property to secure obligations incurred or guarantees of obligations incurred in connection with or necessarily incidental to commitments for the purchase or sale of, or the transportation or distribution of, the products derived from such Property;
	(c) Liens arising under partnership agreements, oil and gas leases, overriding royalty agreements, net profits agreements, production payment agreements, royalty trust agreements, incentive compensation programs for geologists, geophysicists and other providers of technical services to us or a Restricted Subsidiary, master limited partnership agreements, farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of oil, gas or other hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, operating agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements that are customary in the Oil and Gas Business; provided, however, in all instances that such Liens are limited to the assets that are the subject of the relevant agreement, program, order or contract;
	(d) Liens arising in connection with Production Payments and Reserve Sales; and

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	(e) Liens on pipelines or pipeline facilities that arise by operation of law.

      “Permitted Business Investments” means Investments and expenditures made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business as a means of actively engaging therein through agreements, transactions, interests or arrangements that permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of Oil and Gas Business jointly with third parties, including:

	(a) ownership interests in oil and gas properties or gathering, transportation, processing, storage or related systems; and
	(b) Investments and expenditures in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling arrangements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited) and other similar agreements (including for limited liability companies) with third parties, excluding, however, Investments in corporations other than Restricted Subsidiaries.

      “Permitted Hedging Agreements” means:

	(a) Exchange Rate Contracts and Oil and Gas Hedging Contracts; and
	(b) Interest Rate Protection Agreements but only to the extent that the stated aggregate notional amount thereunder does not exceed 100% of the aggregate principal amount of the Indebtedness of Swift or a Restricted Subsidiary covered by such Interest Rate Protection Agreements at the time such agreements were entered into.

      “Permitted Investments” means any and all of the following:

	(a) Permitted Short-Term Investments;
	(b) Investments in property, plant and equipment used in the ordinary course of business and Permitted Business Investments;
	(c) Investments by any Restricted Subsidiary in Swift;
	(d) Investments by us or any Restricted Subsidiary in any Restricted Subsidiary;
	(e) Investments by us or any Restricted Subsidiary:

	(1) in any Person that will, upon the making of such Investment, become a Restricted Subsidiary, or
	(2) if as a result of such Investment such Person is merged or consolidated with or into, or transfers or conveys all or substantially all its Property to, us or a Restricted Subsidiary;

	(f) Investments in the form of securities received from Asset Sales, provided that such Asset Sales are made in compliance within the provisions of the Indenture described under “– Certain Covenants – Limitation on Asset Sales;”
	(g) Investments in negotiable instruments held for collection; lease, utility and other similar deposits; and stock, obligations or other securities received in settlement of debts (including under any bankruptcy or other similar proceeding) owing to us or any of our Restricted Subsidiaries as a result of foreclosure, perfection or enforcement of any Liens or Indebtedness, in each of the foregoing cases in the ordinary course of business of Swift or such Restricted Subsidiary;
	(h) relocation allowances for, and advances and loans in compliance with the Sarbanes-Oxley Act of 2002 to, officers, directors and employees of Swift or any of its Restricted Subsidiaries made in the ordinary course of business, provided such items do not exceed in the aggregate $2.0 million at any one time outstanding;

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	(i) Investments intended to promote our strategic objectives in the Oil and Gas Business in an amount not to exceed 5% of Adjusted Consolidated Net Tangible Assets (determined as of the date of the making of any such Investment) at any one time outstanding, which Investments shall be deemed to be no longer outstanding only to the extent of dividends, repayments of loans or advances or other transfers of Property or returns of capital received by us or any Restricted Subsidiary from such Persons, provided that, for purposes of the covenant described under “– Certain Covenants – Limitation on Restricted Payments” the receiving of such amounts by us or our Restricted Subsidiaries does not increase the amount of Restricted Payments that Swift and our Restricted Subsidiaries may make pursuant to clause of such covenant;
	(j) Investments made pursuant to Permitted Hedging Agreements of Swift and its Restricted Subsidiaries; and
	(k) Investments pursuant to any agreement or obligation of Swift or any of its Restricted Subsidiaries as in effect on the Issue Date (other than Investments described in clauses (a) through (j) above), provided that Investments made pursuant to this clause shall be included in the calculation of Restricted Payments.

      “Permitted Liens” means any and all of the following:

	(a) any Lien existing on any Property of Swift and any Subsidiary Guarantor securing Indebtedness or other obligations under Bank Credit Facilities that are permitted to be Incurred by clause (b) of the definition of Permitted Indebtedness;
	(b) Liens existing as of the Issue Date;
	(c) Liens securing the Notes, any Subsidiary Guaranties and other obligations arising under the Indenture;
	(d) any Lien existing on any Property of a Person at the time such Person is merged or consolidated with or into Swift or a Restricted Subsidiary or becomes a Restricted Subsidiary (and not incurred in anticipation of or in connection with such transaction), provided that such Liens are not extended to other Property of Swift or the Restricted Subsidiaries;
	(e) any Lien existing on any Property at the time of the acquisition thereof (and not incurred in anticipation of or in connection with such transaction), provided that such Lien is not extended to other Property of Swift or the Restricted Subsidiaries;
	(f) any Lien incurred in the ordinary course of business incidental to the conduct of the business of Swift or the Restricted Subsidiaries or the ownership of their Property, including:

	(1) easements, rights of way and similar encumbrances,
	(2) rights or title of lessors under leases (other than Capital Lease Obligations),
	(3) rights of collecting banks having rights of setoff, revocation, refund or chargeback with respect to money or instruments of Swift or the Restricted Subsidiaries on deposit with or in the possession of such banks,
	(4) Liens imposed by law, including Liens under workers’ compensation or similar legislation and mechanics’, carriers’, warehousemen’s, materialmen’s, suppliers’ and vendors’ Liens,
	(5) Liens incurred to secure performance of obligations with respect to statutory or regulatory requirements, performance or return-of-money bonds, surety bonds or other obligations of alike nature and incurred in a manner consistent with industry practice, and
	(6) Oil and Gas Liens,

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	in each case that is not incurred in connection with the borrowing of money, the obtaining of advances or credit or the payment of the deferred purchase price of Property (other than Trade Accounts Payable);

	(g) Liens for taxes, assessments and governmental charges not yet due or the validity of which is being contested in good faith by appropriate proceedings, promptly instituted and diligently conducted, and for which adequate reserves have been established to the extent required by GAAP as in effect at such time;
	(h) Liens incurred to secure appeal bonds and judgment and attachment Liens, in each case in connection with litigation or legal proceedings that are being contested in good faith by appropriate proceedings so long as reserves have been established to the extent required by GAAP as in effect at such time and so long as such Liens do not encumber assets by an aggregate amount (together with the amount of any unstayed judgments against us or any Restricted Subsidiary but excluding any such Liens to the extent securing insured or indemnified judgments or orders) in excess of $20.0 million;
	(i) Liens securing Permitted Hedging Agreements of Swift and its Restricted Subsidiaries;
	(j) Liens securing Capital Lease Obligations, provided that such Capital Lease Obligations are permitted under “– Certain Covenants – Limitation on Indebtedness” and the Liens attach only to the Property acquired with the proceeds of such Capital Lease Obligations;
	(k) Liens securing Non-recourse Purchase Money Indebtedness granted in connection with the acquisition by us or any Restricted Subsidiary in the ordinary course of business of fixed assets used in the Oil and Gas Business (including office buildings and other real property used by us or such Subsidiary Guarantor in conducting its operations), provided that:

	(1) such Liens attach only to the fixed assets acquired with the proceeds of such Non-recourse Purchase Money Indebtedness, and
	(2) such Non-recourse Purchase Money Indebtedness is not in excess of the purchase price of such fixed assets;

	(l) Liens resulting from the deposit of funds or evidences of Indebtedness in trust for the purpose of decreasing or legally defeasing Indebtedness of Swift or any of its Subsidiaries so long as such deposit of funds is permitted by the provisions of the Indenture described under “– Limitation on Restricted Payments”;
	(m) Liens resulting from a pledge of Capital Stock of a Person that is not a Restricted Subsidiary to secure obligations of such Person and any refinancings thereof;
	(n) Liens to secure any permitted extension, renewal, refinancing, refunding or exchange (or successive extensions, renewals, refinancings, refundings or exchanges), in whole or in part, of or for any Indebtedness secured by Liens referred to in clauses (a), (b), (c), (d), (i) and (j) above; provided, however, that:

	(1) such new Lien shall be limited to all or part of the same Property (including future improvements thereon and accessions thereto) subject to the original Lien, and
	(2) the Indebtedness secured by such Lien at such time is not increased to any amount greater than the sum of:

	(A) the outstanding principal amount or, if greater, the committed amount of the Indebtedness secured by such original Lien immediately prior to such extension, renewal, refinancing, refunding or exchange, and
	(B) an amount necessary to pay any fees and expenses, including premiums, related to such refinancing, refunding, extension, renewal or replacement;

	(o) Liens in favor of us or a Restricted Subsidiary; and

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	(p) Liens not otherwise permitted by clauses (a) through (o) above incurred in the ordinary course of business of Swift and its Restricted Subsidiaries and encumbering Property having an aggregate Fair Market Value not in excess of $5.0 million at any one time.

      Notwithstanding anything in this paragraph to the contrary, the term “Permitted Liens” does not include Liens resulting from the creation, incurrence, issuance, assumption or Guarantee of any Production Payments and Reserve Sales other than:

	(a) any such Liens existing as of the Issue Date;
	(b) Production Payments and Reserve Sales in connection with the acquisition of any Property after the Issue Date, provided that any such Lien created in connection therewith is created, incurred, issued, assumed or guaranteed in connection with the financing of, and within 60 days after the acquisition of, such Property;
	(c) Production Payments and Reserve Sales, other than those described in clauses (a) and (b) of this sentence, to the extent such Production Payments and Reserve Sales constitute Asset Sales made pursuant to and in compliance with the provisions of the Indenture described under “– Limitation on Asset Sales”; and
	(d) incentive compensation programs for geologists, geophysicists and other providers of technical services to us or a Restricted Subsidiary;

provided, however, that, in the case of the immediately foregoing clauses (a), (b), (c) and (d), any Lien created in connection with any such Production Payments and Reserve Sales shall be limited to the Property that is the subject of such Production Payments and Reserve Sales.

      “Permitted Refinancing Indebtedness” means Indebtedness (“new Indebtedness”), Incurred in exchange for, or proceeds of which are used to refinance, other Indebtedness (“old Indebtedness”); provided, however, that:

	(a) such new Indebtedness is in an aggregate principal amount not in excess of the sum of:

	(1) the aggregate principal amount then outstanding of the old Indebtedness (or, if such old Indebtedness provides for an amount less than the principal amount thereof to be due and payable upon a declaration of acceleration thereof, such lesser amount as of the date of determination), and
	(2) an amount necessary to pay any fees and expenses, including premiums, related to such exchange or refinancing;

	(b) such new Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the old Indebtedness;
	(c) such new Indebtedness has an Average Life at the time such new Indebtedness is Incurred that is equal to or greater than the Average Life of the old Indebtedness at such time;
	(d) such new Indebtedness is subordinated in right of payment to the Notes (or, if applicable, the Subsidiary Guaranties) to at least the same extent, if any, as the old Indebtedness; and
	(e) if such old Indebtedness is Non-recourse Purchase Money Indebtedness or Indebtedness that refinanced Non-recourse Purchase Money Indebtedness, such new Indebtedness satisfies clauses (a) and (b) of the definition of “Non-recourse Purchase Money Indebtedness.”

      “Permitted Short-Term Investments” means:

	(a) Investments in U.S. Government Obligations maturing within one year of the date of acquisition thereof;
	(b) Investments in demand accounts, time deposit accounts, certificates of deposit, bankers’ acceptances and money market deposits maturing within one year of the date of acquisition thereof

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	issued by a bank or trust company that is organized under the laws of the United States of America or any State thereof or the District of Columbia that is a member of the Federal Reserve System having capital, surplus and undivided profits aggregating in excess of $500.0 million and whose long-term Indebtedness is rated “A” (or higher) according to Moody’s;
	(c) Investments in deposits available for withdrawal on demand with any commercial bank that is organized under the laws of any country in which we or any Restricted Subsidiary maintains an office or is engaged in the Oil and Gas Business, provided that:

	(1) all such deposits have been made in such accounts in the ordinary course of business, and
	(2) such deposits do not at any one time exceed $15.0 million in the aggregate;

	(d) repurchase and reverse repurchase obligations with a term of not more than seven days for underlying securities of the types described in clause entered into with a bank meeting the qualifications described in clause (b);
	(e) Investments in commercial paper or notes, maturing not more than one year after the date of acquisition, issued by a corporation (other than an Affiliate of Swift) organized and in existence under the laws of the United States of America or any State thereof or the District of Columbia with a short-term rating at the time as of which any Investment therein is made of “P-1” (or higher) according to Moody’s or “A-1” (or higher) according to S&P or a long-term rating at the time as of which any Investment is made of “A3” (or higher) according to Moody’s or “A-” (or higher) according to S&P;
	(f) Investments in any money market mutual fund having assets in excess of $250.0 million all of which consist of other obligations of the types described in clauses (a), (b), (d) and (e) hereof; and
	(g) Investments in asset-backed securities maturing within one year of the date of acquisition thereof with a long-term rating at the time as of which any Investment therein is made of “A3” (or higher) according to Moody’s or “A-” (or higher) according to S&P.

      “Person” means any individual, corporation, partnership, joint venture, limited liability company, unlimited liability company, trust, estate, unincorporated organization or government or any agency or political subdivision thereof.

      “Preferred Stock” of any Person means Capital Stock of such Person of any class or classes (however designated) that ranks prior, as to the payment of dividends or as to the distribution of assets upon any voluntary or involuntary liquidation, dissolution or winding up of such Person, to shares of Capital Stock of any other class of such Person.

      “Preferred Stock Dividends” means all dividends with respect to Preferred Stock of Restricted Subsidiaries held by Persons other than Swift or a Wholly Owned Subsidiary. The amount of any such dividend shall be equal to the quotient of such dividend divided by the difference between one and the maximum statutory federal income rate (expressed as a decimal number between 1 and 0) then applicable to the issuer of such Preferred Stock.

      “Principal” of any Indebtedness (including the Notes) means the principal amount of such Indebtedness plus the premium, if any, on such Indebtedness.

      “Production Payments and Reserve Sales” means the grant or transfer by us or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), partnership or other interest in oil and gas properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary

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      “Property” means, with respect to any Person, any interest of such Person in any kind of property or asset, whether real, personal, or mixed, or tangible or intangible, including Capital Stock and other securities issued by any other Person (but excluding Capital Stock or other securities issued by such first mentioned Person).

      “Quotation Agent” means the Reference Treasury Dealer selected by the Trustee after consultation with Swift.

      “Reference Treasury Dealer” means Credit Suisse First Boston LLC and its successors and assigns,                     , and its successors and assigns and one other nationally recognized investment banking firm selected by Swift that is a primary U.S. Government securities dealer.

      “Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Trustee, of the bid and asked prices for the Comparable Treasury Issue, expressed in each case as a percentage of its principal amount, quoted in writing to the Trustee by such Reference Treasury Dealer at 5:00 p.m., New York City Time, on the third Business Day immediately preceding such redemption date.

      “Restricted Payment” means:

	(a) a dividend or other distribution declared or paid on the Capital Stock of Swift or to our shareholders (other than dividends, distributions or payments made solely in Capital Stock (other than Disqualified Stock of Swift) of Swift or in options, warrants or other rights to purchase or acquire Capital Stock (other than Disqualified Stock)), or declared and paid to any Person other than Swift or any of its Restricted Subsidiaries (and, if such Restricted Subsidiary is not a Wholly Owned Subsidiary, to the other shareholders of such Restricted Subsidiary on a pro rata basis or on a basis that results in the receipt by us or a Restricted Subsidiary of dividends or distributions of greater value than it would receive on a pro rata basis) on the Capital Stock of any Restricted Subsidiary;
	(b) a payment made by us or any of our Restricted Subsidiaries (other than to us or any Restricted Subsidiary) to purchase, redeem, acquire or retire any Capital Stock, or any options, warrants or other rights to acquire Capital Stock, of Swift or of a Restricted Subsidiary;
	(c) a payment made by us or any of our Restricted Subsidiaries to redeem, repurchase, legally defease or otherwise acquire or retire for value (including pursuant to mandatory repurchase covenants), prior to any scheduled maturity, scheduled sinking fund or scheduled mandatory redemption, any Indebtedness of Swift or a Restricted Subsidiary that is subordinate (whether pursuant to its terms or by operation of law) in right of payment to the Notes or the relevant Subsidiary Guaranty, as the case may be, provided that this clause shall not include any such payment with respect to:

	(1) any such subordinated Indebtedness to the extent of Excess Proceeds remaining after compliance with the provisions of the Indenture described under “– Certain Covenants – Limitation on Asset Sales” and to the extent required by the Indenture or other agreement or instrument pursuant to which such subordinated Indebtedness was issued, or
	(2) the purchase, repurchase or other acquisition of any such subordinated Indebtedness purchased in anticipation of satisfying a scheduled maturity, scheduled sinking fund or scheduled mandatory redemption, in each case due within one year of the date of acquisition; or

	(d) an Investment (other than a Permitted Investment) by us or a Restricted Subsidiary in any Person.

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      “Restricted Subsidiary” means any Subsidiary of Swift that has not been designated an Unrestricted Subsidiary pursuant to the provision of the Indenture described under “– Certain Covenants – Restricted and Unrestricted Subsidiaries.”

      “S&P” means Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc., and its successors.

      “Sale and Leaseback Transaction” means, with respect to any Person, any direct or indirect arrangement (excluding, however, any such arrangement between such Person and a Wholly Owned Subsidiary of such Person or between one or more Wholly Owned Subsidiaries of such Person) pursuant to which Property is sold or transferred by such Person or a Restricted Subsidiary of such Person and is thereafter leased back from the purchaser or transferee thereof by such Person or one of its Restricted Subsidiaries.

      “Senior Indebtedness” when used with respect to us means our obligations with respect to Indebtedness of Swift, whether outstanding on the date of the Indenture or thereafter Incurred, and any renewal, refunding, refinancing, replacement or extension thereof, unless, in the case of any particular Indebtedness, the instrument creating or evidencing the same or pursuant to which the same is outstanding expressly provides that such Indebtedness shall be subordinate in right of payment to the Notes; provided, however, that Senior Indebtedness of Swift shall not include:

	(a) Indebtedness of Swift to a Subsidiary of Swift;
	(b) Indebtedness Incurred in violation of the Indenture;
	(c) amounts payable or any other Indebtedness to employees of Swift or any Subsidiary of Swift;
	(d) any Indebtedness of Swift that, when Incurred and without regard to any election under Section 1111(b) of the United States Bankruptcy Code, was without recourse to us;
	(e) Subordinated Indebtedness of Swift;
	(f) obligations with respect to any Capital Stock of Swift; and
	(g) in-kind obligations relating to net oil and gas balancing positions.

      “Senior Indebtedness” of any Subsidiary Guarantor has a correlative meaning.

      “Senior Indebtedness Offer” means an offer by us or a Subsidiary Guarantor to purchase all or a portion of Senior Indebtedness to the extent required by the indenture or other agreement or instrument pursuant to which such Senior Indebtedness was issued.

      “Significant Subsidiary” means, at any date of determination, any Restricted Subsidiary that would be a “Significant Subsidiary” of Swift within the meaning of Rule 1-02 under Regulation S-X promulgated by the Commission.

      “Stated Maturity” when used with respect to any security or any installment of principal thereof or interest thereon, means the date specified in such security as the fixed date on which the principal of such security or such installment of principal or interest is due and payable, including pursuant to any mandatory redemption provision (but excluding any provision providing for the repurchase of such security at the option of the holder thereof upon the happening of any contingency unless such contingency has occurred).

      “Subordinated Indebtedness” means Indebtedness of Swift (or a Subsidiary Guarantor) that is subordinated or junior in right of payment to the Notes (or a Subsidiary Guaranty, as appropriate) pursuant to a written agreement to that effect.

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      “Subsidiary” of a Person means:

	(a) another Person that is a corporation a majority of whose Voting Stock is at the time, directly or indirectly, owned or controlled by:

	(1) the first Person,
	(2) the first Person and one or more of its Subsidiaries, or
	(3) one or more of the first Person’s Subsidiaries; or

	(b) another Person that is not a corporation (x) at least 50% of the Capital Stock of which, and (y) the power to elect or direct the election of a majority of the directors or other governing body of which are controlled by Persons referred to in clause (1), (2) or (3) above.

      “Subsidiary Guarantors” means, unless released from their Subsidiary Guaranties as permitted by the Indenture, any Restricted Subsidiary that becomes a guarantor of the Notes in compliance with the provisions of the Indenture and executes a supplemental indenture agreeing to be bound by the terms of the Indenture.

      “Subsidiary Guaranty” means an unconditional senior guaranty of the Notes given by any Restricted Subsidiary pursuant to the terms of the Indenture.

      “Trade Accounts Payable” means accounts payable or other obligations of Swift or any Restricted Subsidiary to trade creditors created or assumed by us or such Restricted Subsidiary in the ordinary course of business in connection with the obtaining of goods or services.

      “Unrestricted Subsidiary” means:

	(a) each Subsidiary of Swift that we have designated pursuant to the provisions of the Indenture described under “– Certain Covenants – Restricted and Unrestricted Subsidiaries” as an Unrestricted Subsidiary; and
	(b) any Subsidiary of an Unrestricted Subsidiary.

      “U.S. Government Obligations” means securities that are:

	(a) direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged; or
	(b) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America, the timely payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States of America

that, in either case, are not callable or redeemable at the option of the issuer thereof, and shall also include a depository receipt issued by a bank (as defined in Section 3(a) of the Securities Act), as custodian, with respect to any such U.S. Government Obligation or a specific payment of principal of or interest on any such U.S. Government Obligation held by such custodian for the account of the holder of such depository receipt; provided, however, that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the U.S. Government Obligation or the specific payment or principal of or interest on the U.S. Government Obligation evidenced by such depository receipt.

      “Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

      “Voting Stock” of any Person means Capital Stock of such Person that ordinarily has voting power for the election of directors (or persons performing similar functions) of such Person whether at all times or only so long as no senior class of securities has such voting power by reason of any contingency.

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      “Wholly Owned Subsidiary” means, at any time, a Restricted Subsidiary of Swift all the Voting Stock of which (other than directors’ qualifying shares) is at such time owned, directly or indirectly, by us and our other Wholly Owned Subsidiaries.

Defeasance and Covenant Defeasance

      The Indenture provides that we will, at our election at any time, be discharged from our obligations with respect to the Notes (“Legal Defeasance”) except for certain obligations to:

	(a) exchange or register the transfer of Notes;
	(b) to replace stolen, lost or mutilated Notes;
	(c) to maintain paying agencies; and
	(d) to hold moneys for payment in trust.

In addition, the Indenture provides that if we take the actions described below, we may omit to comply with certain covenants, including those described under “– Repurchase at the Option of Holders Upon a Change of Control,” “– Certain Covenants” and in clauses and under the first paragraph of “– Merger, Consolidation and Sale of Substantially All Assets.” Additionally, the occurrence of the Events of Default described below in clauses and (with respect to such covenants) and clauses (e), (f), (g) (with respect to Significant Subsidiaries) and (h) under “– Events of Default and Notice” will be deemed not to be or result in an Event of Default.

      Such Legal Defeasance and Covenant Defeasance may occur only if, among other things, we:

	(a) deposit in trust for the benefit of the Holders of the Notes, money or U.S. Government Obligations, or a combination thereof, that, through the payment of principal, premium, if any, and interest in respect thereof in accordance with their terms, will provide money in an amount sufficient to pay the principal of and any premium and interest on the Notes at the Stated Maturity thereof or on earlier redemption in accordance with the terms of the Indenture and the Notes; and
	(b) in the case of Legal Defeasance, deliver to the Trustee an Opinion of Counsel

	(1) to the effect that:

	(A) we have received from, or there has been published by, the United States Internal Revenue Service a ruling, or
	(B) since the date of the Indenture there has been a change in the applicable federal income tax law,

	in either case to the effect that Holders of the Notes will not recognize gain or loss for federal income tax purposes as a result of such deposit, defeasance and discharge and will be subject to federal income tax on the same amount, in the same manner and at the same times as would have been the case if such deposit, defeasance and discharge were not to occur, and

	(2) that the resulting trust will not be an “Investment Company” within the meaning of the Investment Company Act of 1940 unless such trust is qualified thereunder or exempt from regulation thereunder; or

	(c) in the case of Covenant Defeasance, deliver to the Trustee on Opinion of Counsel to the effect that:

	(1) Holders of the Notes will not recognize gain or loss for federal income tax purposes as a result of such deposit and defeasance of certain obligations and will be subject to federal income tax on the same amount, in the same manner and at the same times as would have been the case if such deposit and defeasance were not to occur, and

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	(2) that the resulting trust will not be an “Investment Company” within the meaning of the Investment Company Act of 1940 unless such trust is qualified thereunder or exempt from regulation thereunder.

      If we were to exercise this option and the Notes were declared due and payable because of the occurrence of any Event of Default, the amount of money and U.S. Government Obligations so deposited in trust would be sufficient to pay amounts due on the Notes at the time of their Stated Maturity but may not be sufficient to pay amounts due on the Notes upon any acceleration resulting from such Event of Default. In such case, we would remain liable for such payments.

      If we exercise either of the options described above, each Subsidiary Guarantor, if any, will be released from all its obligations under its Subsidiary Guaranty.

Events of Default and Notice

      The following are summaries of Events of Default under the Indenture with respect to the Notes:

	(a) failure to pay any interest on the Notes when due, continued for 30 days;
	(b) failure to pay principal of (or premium, if any, on) the Notes when due;
	(c) failure to comply with the provisions of the Indenture described under “Merger, Consolidation and Sale of Substantially All Assets”;
	(d) failure to perform any other covenant of Swift or any Subsidiary Guarantor in the Indenture, continued for 30 days after written notice to us from the Trustee or the Holders of at least 25% in aggregate principal amount of the outstanding Notes;
	(e) a default by us or any Restricted Subsidiary under any Indebtedness for borrowed money in an aggregate amount greater than $10.0 million (other than Non-recourse Purchase Money Indebtedness) that results in acceleration of the maturity of such Indebtedness, or failure to pay any such Indebtedness at maturity, if such Indebtedness is not discharged or such acceleration is not rescinded or annulled within 10 days after written notice as provided in the Indenture;
	(f) one or more final judgments or orders by a court of competent jurisdiction are entered against us or any Restricted Subsidiary in an uninsured or unindemnified aggregate amount outstanding at any time in excess of $10.0 million and such judgments or orders are not discharged, waived, stayed, satisfied or bonded for a period of 60 consecutive days;
	(g) certain events of bankruptcy, insolvency or reorganization with respect to Swift or any Significant Subsidiary; or
	(h) a Subsidiary Guaranty ceases to be in full force and effect (other than in accordance with the terms of the Indenture and such Subsidiary Guaranty) or a Subsidiary Guarantor denies or disaffirms its obligations under its Subsidiary Guaranty.

      The Indenture provides that if an Event of Default (other than an Event of Default described in clause (g) above) with respect to the Notes at the time outstanding shall occur and be continuing, either the Trustee or the Holders of at least 25% in aggregate principal amount of the outstanding Notes by notice as provided in the Indenture may declare the principal amount of the Notes to be due and payable immediately. If an Event of Default described in clause above with respect to the Notes at the time outstanding shall occur, the principal amount of all the Notes will automatically, and without any action by the Trustee or any Holder, become immediately due and payable. After any such acceleration, but before a judgment or decree based on acceleration, the Holders of at least a majority in aggregate principal amount of the outstanding Notes may, under certain circumstances, rescind and annul such acceleration if all Events of Default, other than the nonpayment of accelerated principal, have been cured or waived as provided in the Indenture.

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      Subject to the provisions of the Indenture relating to the duties of the Trustee, in case an Event of Default shall occur and be continuing, the Trustee will be under no obligation to exercise any of its rights or powers under the Indenture at the request or direction of any of the Holders of the Notes, unless such Holders shall have offered to the Trustee reasonable indemnity. Subject to such provisions for the indemnification of the Trustee, the Holders of at least a majority in aggregate principal amount of the outstanding Notes will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or exercising any trust or power conferred on the Trustee with respect to the Notes.

      No Holder of Notes will have any right to institute any proceeding with respect to the Indenture, or for the appointment of a receiver or a trustee, or for any other remedy thereunder, unless:

	(a) such Holder has previously given to the Trustee written notice of a continuing Event of Default with respect to the Notes;
	(b) the Holders of at least 25% in aggregate principal amount of the outstanding Notes have made written request, and such Holder or Holders have offered reasonable indemnity, to the Trustee to institute such proceeding as trustee; and
	(c) the Trustee has failed to institute such proceeding and has not received from the Holders of at least a majority in aggregate principal amount of the outstanding Notes a direction inconsistent with such request, within 60 days after such notice, request and offer.

However, such limitations do not apply to a suit instituted by a Holder of Notes for the enforcement of payment of the principal of or any premium or interest on such Notes on or after the applicable due date specified in such Notes.

Modification of the Indenture; Waiver

      The Indenture provides that modifications and amendments of the Indenture may be made by us, any Subsidiary Guarantors and the Trustee without the consent of any Holders of Notes in certain limited circumstances, including:

	(a) to cure any ambiguity, omission, defect or inconsistency;
	(b) to provide for the assumption of the obligations of Swift under the Indenture upon the merger, consolidation or sale or other disposition of all or substantially all the Property of Swift and the Restricted Subsidiaries taken as a whole and certain other events specified in the provisions of the Indenture described under “Merger, Consolidation and Sale of Substantially All Assets”;
	(c) to provide for uncertificated Notes in addition to or in place of certificated Notes;
	(d) to comply with any requirement of the SEC in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act;
	(e) to make any change that does not adversely affect the rights of any Holder of Notes in any material respect;
	(f) to add or remove Subsidiary Guarantors pursuant to the procedure set forth in the Indenture; and
	(g) certain other modifications and amendments as set forth in the Indenture.

      The Indenture contains provisions permitting us, any Subsidiary Guarantors and the Trustee with the written consent of the Holders of not less than a majority in aggregate principal amount of the outstanding Notes, to execute supplemental indentures or amendments adding any provisions to or changing or eliminating any of the provisions of the Indenture or modifying the rights of the Holders of the Notes,

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	(a) reduce the principal amount of Notes whose Holders must consent to an amendment or waiver;
	(b) reduce the rate of or change the time for payment of interest on any Notes;
	(c) change the currency in which any amount due in respect of the Notes is payable;
	(d) reduce the principal of or any premium on or change the Stated Maturity of any Notes or alter the redemption provisions with respect thereto;
	(e) reduce the relative ranking of any Notes;
	(f) release any security that may have been granted to the Trustee in respect of the Notes;
	(g) at any time after a Change of Control has occurred, change the repurchase price or the time at which the Change of Control Offer relating thereto must be made or at which the Notes must be repurchased pursuant to such Change of Control Offer; or
	(h) make certain other significant amendments or modifications as specified in the Indenture.

      The Holders of at least a majority in aggregate principal amount of the outstanding Notes may waive compliance by Swift with certain restrictive provisions of the Indenture. The Holders of at least a majority in aggregate principal amount of the outstanding Notes may waive any past default under the Indenture, except a default in the payment of principal, premium or interest and certain covenants and provisions of the Indenture that cannot be amended without the consent of the Holders of each outstanding Note.

      No amendment may be made to the subordination provisions of the Indenture that adversely affects the rights of any holder of Senior Indebtedness then outstanding unless the holders of such Senior Indebtedness (or their Representative) consent to such change. The consent of the Holders of the Notes is not necessary under the Indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment. After an amendment under the Indenture becomes effective, we are required to mail to each registered Holder of the Notes at such Holder’s address appearing in the Security Register a notice briefly describing such amendment. However, the failure to give such notice to all Holders of the Notes, or any defect therein, will not impair or affect the validity of the amendment.

Notices

      Notices to Holders of the Notes will be given by mail to the addresses of such Holders as they may appear in the Security Register.

Governing Law

      The Indenture and the Notes are governed by and construed in accordance with the laws of the State of New York.

Trustee

      Wells Fargo Bank, National Association is the Trustee under the Indenture. Wells Fargo Bank, National Association maintains normal banking relationships with us and our Subsidiaries and may perform certain services and transact other business with us and our Subsidiaries from time to time in the ordinary course of business. In accordance with the Trust Indenture Act, if the Trustee acquires any conflicting interest it must either eliminate such conflict within 90 days, apply to the SEC for permission to continue or resign.

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Book-Entry System

      The Notes will be initially issued in the form of one or more Global Securities registered in the name of The Depository Trust Company (“DTC”) or its nominee.

      Upon the issuance of a Global Security, DTC will credit the accounts of Persons holding through it with the respective principal amounts of the Notes represented by such Global Security purchased by such Persons in this offering of the Notes. Such accounts shall be designated by the underwriters of the Offered Notes. Ownership of beneficial interests in a Global Security will be limited to Persons that have accounts with DTC (“participants”) or Persons that may hold interests through participants. Ownership of beneficial interests in a Global Security will be shown on, and the transfer of that ownership interest will be effected only through, records maintained by DTC (with respect to participants’ interests) and such participants (with respect to the owners of beneficial interests in such Global Security other than participants). The laws of some jurisdictions require that certain purchasers of securities take physical delivery of such securities in definitive form. Such limits and such laws may impair the ability to transfer beneficial interests in a Global Security.

      Payment of principal of and interest on Notes represented by a Global Security will be made in immediately available funds to DTC or its nominee, as the case may be, as the sole registered owner and the sole holder of the Notes represented thereby for all purposes under the Indenture. We have been advised by DTC that upon receipt of any payment of principal of or interest on any Global Security, DTC will immediately credit, on its book-entry registration and transfer system, the accounts of participants with payments in amounts proportionate to their respective beneficial interests in the principal or face amount of such Global Security as shown on the records of DTC. Payments by participants to owners of beneficial interests in a Global Security held through such participants will be governed by standing instructions and customary practices as is now the case with securities held for customer accounts registered in “street name” and will be the sole responsibility of such participants.

      A Global Security may not be transferred except as a whole by DTC or a nominee of DTC to a nominee of DTC or to DTC. A Global Security is exchangeable for certificated Notes only if:

	(a) DTC notifies us that it is unwilling or unable to continue as a depositary for such Global Security or if at any time DTC ceases to be a clearing agency registered under the Exchange Act; or
	(b) a Default or an Event of Default with respect to the Notes represented by such Global Security occurs, and DTC requests the Trustee and us to effect such an exchange.

      Any Global Security that is exchangeable for certificated Notes pursuant to the preceding sentence will be exchanged for certificated Notes in authorized denominations and registered in such names as DTC or any successor depositary holding such Global Security may direct. Subject to the foregoing, a Global Security is not exchangeable, except for a Global Security of like denomination to be registered in the name of DTC or any successor depositary or its nominee. In the event that a Global Security becomes exchangeable for certificated Notes,

	(a) certificated Notes will be issued only in fully registered form in denominations of $1,000 or integral multiples thereof,
	(b) payment of principal of, and premium, if any, and interest on, the certificated Notes will be payable, and the transfer of the certificated Notes will be registrable, at the office or agency of Swift maintained for such purposes, and
	(c) no service charge will be made for any registration of transfer or exchange of the certificated Notes, although we may require payment of a sum sufficient to cover any tax or governmental charge imposed in connection therewith.

      So long as DTC or any successor depositary for a Global Security, or any nominee, is the registered owner of such Global Security, DTC or such successor depositary or nominee, as the case may be, will be considered the sole owner or holder of the Notes represented by such Global Security for all purposes

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      DTC has advised us that DTC is a limited-purpose trust company organized under the Banking Law of the State of New York, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code and a “clearing agency” registered under the Exchange Act. DTC was created to hold the securities of its participants and to facilitate the clearance and settlement of securities transactions among its participants in such securities through electronic book-entry changes in accounts of the participants, thereby eliminating the need for physical movement of securities certificates. DTC’s participants include securities brokers and dealers (which may include the underwriters of the Offered Notes), banks, trust companies, clearing corporations and certain other organizations some of whom (or their representatives) own DTC. Access to DTC’s book-entry system is also available to others, such as banks, brokers, dealers and trust companies, that clear through or maintain a custodial relationship with a participant, either directly or indirectly.

      Although DTC has agreed to the foregoing procedures in order to facilitate transfers of interests in Global Securities among participants of DTC, it is under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued at any time. None of Swift, the Trustee or the underwriters of the Offered Notes will have any responsibility for the performance by DTC or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

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CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS

      The following is a summary of certain U.S. federal income tax consequences of the purchase, ownership and disposition of the notes by initial purchasers of the notes who are U.S. Holders (as defined below) and certain U.S. federal income and estate tax consequences of the purchase, ownership and disposition of the notes by initial purchasers who are Non-U.S. Holders (as defined below). This discussion is based on currently existing provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing, temporary and proposed Treasury regulations promulgated thereunder, and administrative and judicial interpretations thereof, all as in effect or proposed on the date hereof and all of which are subject to change, possibly with retroactive effect.

      This discussion does not address the U.S. federal income tax consequences to subsequent purchasers of notes, and is limited to initial purchasers who purchase the notes at the public offering price to investors set forth on the cover page of this prospectus supplement who hold the notes as capital assets, within the meaning of section 1221 of the Code. Moreover, this discussion is for general information only and does not address all of the tax consequences that may be relevant to particular initial purchasers in light of their personal circumstances (for example, persons subject to the alternative minimum tax provisions of the Code, or a holder whose “functional currency” is not the U.S. dollar) or to certain types of initial purchasers (such as persons subject to special rules applicable to former citizens and residents of the United States, grantor trusts, real estate investment trusts, thrifts, banks and financial institutions, insurance companies, tax-exempt entities, dealers in securities or currencies or persons holding the notes in connection with a hedging transaction, straddle, conversion transaction or other integrated transaction, corporations treated as foreign or domestic personal holding companies, controlled foreign corporations, passive foreign investment companies, foreign investment companies or Non-U.S. Holders that are owned or controlled by U.S. Holders). This discussion also does not describe the effect of any applicable foreign, state or local laws, the applicability of any treaty or, except to a limited extent under the caption “Non-U.S. Holders,” any possible applicability of U.S. federal gift or estate tax law.

      We have not obtained, nor do we intend to obtain a ruling from the Internal Revenue Service (“IRS”) with respect to any of the matters discussed herein. The IRS could at any time challenge one or more of the tax consequences discussed herein and such a challenge could be successful.

U.S. Federal Income Taxation of U.S. Holders

      As used herein, the term “U.S. Holder” means the beneficial owner of a note that is, for U.S. federal income tax purposes:

	•	a citizen or resident of the United States;
	•	a corporation, or other entity taxable as a corporation for U.S. Federal income tax purposes, created or organized in or under the laws of the United States, any state of the U.S. or the District of Columbia;
	•	an estate the income of which is subject to U.S. federal income taxation, regardless of its source; or
	•	a trust:

	(i) whose administration is subject to the primary supervision of a U.S. court with respect to which one or more U.S. persons have the authority to control all substantial decisions; or
	(ii) that has a valid election in effect under applicable Treasury regulations to be treated as a U.S. person.

      If a partnership (including for this purpose any entity, domestic or foreign, treated as a partnership for U.S. federal income tax purposes) or other flow-through or fiscally transparent entity is a beneficial owner of a note, the tax treatment of a partner or owner in the entity will generally depend upon the status of the partner or other owner and upon the activities of the partnership or entity. Partners of partnerships or

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	Interest and Original Issue Discount on the Notes

      The notes pay interest at a stated rate of      percent (     %). A U.S. Holder will be required to include stated interest on a note in his, her or its income as ordinary income in accordance with the U.S. Holder’s method of accounting for U.S. federal income tax purposes. We expect that the notes will not be issued with original issue discount within the meaning of the Code.

	Effect of Repurchase or Optional Redemption on Interest Original Issue Discount

      Holders of notes have the right to require us to repurchase all or any part of such holder’s notes upon a Change of Control. See “Description of the Notes – Repurchase at the Option of Holders Upon a Change of Control.” We also have the right to redeem all or any portion of the notes on or after                     , 2008, redeem up to 35% of the aggregate principal amount of the notes originally issued with the net proceeds of one or more Equity Offerings prior to                     , 2007, and redeem all but not less than all of the notes at any time prior to                     , 2008. See “Description of the Notes – Optional Redemption.” Under applicable Treasury regulations, computation of the interest or original issue discount on a debt instrument is not affected by these repurchase rights and obligations if, based on all facts and circumstances as of the issue date, the likelihood that the contingencies that give rise to the repurchase rights and obligations will occur is remote. Further with respect to any unconditional option we have to redeem the notes, solely for the purpose of computing original issue discount, we will be assumed to exercise any such option to redeem if the exercise will lower the yield-to-maturity of the debt instrument. We intend to take the position (which generally will be binding on a U.S. Holder unless the U.S. Holder explicitly discloses a different position on his, her or its timely filed U.S. federal income tax return) that the interest or original issue discount on the notes is unaffected by the repurchase and optional redemption provisions described in this paragraph. There can be no assurance that the IRS will agree with this conclusion, however, if the IRS were successful in challenging this conclusion, a U.S. Holder may be required to recognize additional income on a note or to treat as ordinary income, rather than as capital gain, certain income recognized on the taxable disposition of a note.

      The actual occurrence of the contingencies described herein could cause the notes to be treated, for original issue discount purposes, as retired and then reissued on the date of the change in circumstances for an amount, with respect to each note, that is equal to the note’s adjusted issue price on that date. U.S. Holders should consult their own tax advisors regarding the potential effect, if any, of these events on their particular situation.

	Sale, Disposition or Retirement

      Upon the sale, retirement at maturity or other taxable disposition of a note, a U.S. Holder generally will recognize capital gain or loss equal to the difference between the sum of cash plus the fair market value of all other property received on such disposition (except to the extent such cash or property is attributable to accrued but unpaid interest, which will be taxable as ordinary income) and such U.S. Holder’s adjusted tax basis in the note. A U.S. Holder’s adjusted tax basis in a note generally will equal the cost of the note to such U.S. Holder. Gain or loss recognized on the disposition of a note will be long-term capital gain or loss if, at the time of such disposition, the U.S. Holder’s holding period for the note is more than one year. Long term capital gain of individuals, estates, and trusts currently are subject to a maximum rate of federal income tax of 15%. Capital gain that is not long term capital gain is taxed at ordinary income tax rates. The deductibility of capital losses by a U.S. Holder is subject to limitations.

	Backup Withholding and Information Reporting

      A U.S. Holder of a note may be subject, under certain circumstances, to information reporting and backup withholding at the then applicable rate (currently at a rate of 28% in 2004) with respect to

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	•	furnish his, her or its taxpayer identification number (social security or employer identification number);
	•	certify under penalties or perjury that his, her or its number is correct;
	•	certify under penalties or perjury that he, she or it is not subject to backup withholding; or
	•	otherwise comply with the applicable requirements of the backup withholding rules.

Certain U.S. Holders, including corporations, are exempt from backup withholding. Any amounts withheld under the backup withholding rules from a payment to a U.S. Holder will be allowed as a credit against that U.S. Holder’s U.S. federal income tax liability and may entitle the holder to a refund, provided that the required information is timely furnished to the IRS. U.S. Holders of notes should consult their tax advisors regarding the application of information reporting and backup withholding in their particular situations, the availability of an exemption therefrom, and the procedure for obtaining such an exemption, if available.

U.S. Federal Income Taxation of Non-U.S. Holders

      As used herein, the term “Non-U.S. Holder” means any beneficial owner of a note that is not a U.S. Holder.

	Interest on the Notes

      In general, stated interest received by a Non-U.S. Holder will qualify as “portfolio interest” and thus be exempt from U.S. federal income and withholding tax, provided that:

	(i) the Non-U.S. Holder does not own, actually or constructively, 10% or more of the total combined voting power of all classes of our stock entitled to vote;
	(ii) the interest is not effectively connected with the conduct by the Non-U.S. Holder of a trade or business within the United States; and
	(iii) the Non-U.S. Holder satisfies a certification requirement.

The certification requirement is generally satisfied if the Non-U.S. Holder certifies on IRS Form W-8BEN (or a suitable substitute form) under penalties of perjury, that he, she or it is not a U.S. person and provides the form to us or our paying agent. If the Non-U.S. Holder holds the note through a financial institution or other agent acting on the holder’s behalf, the Non-U.S. Holder will be required to provide appropriate documentation to them. The financial institution or agent will then be required to provide certification to us or our paying agent, either directly or through other intermediaries.

      The certification requirement is not met if either we or the withholding agent has actual knowledge or reason to know that the beneficial owner is a U.S. person or that the conditions of any exemption are not, in fact, satisfied. Non-U.S. Holders, including foreign partnerships and their partners, should consult their own tax advisors regarding the certification requirements for Non-U.S. Holders and the effect, if any, of the certification requirements on their particular situation.

      Interest received by a Non-U.S. Holder that is not exempt from U.S. federal withholding tax as described above will be subject to withholding tax at the rate of 30%, unless (i) such withholding tax is reduced under an applicable income tax treaty or (ii) the interest is effectively connected with the conduct of a U.S. trade or business and the holder provides Form W-8ECI (or a suitable substitute form) to the withholding agent and meets any other applicable certification requirement. In order to claim a reduced or zero withholding rate under an applicable income tax treaty, the beneficial owner of the note must, under penalties of perjury, provide the withholding agent with a properly completed and executed IRS Form W-8BEN (or a suitable substitute form) claiming an exemption from, or reduction in the rate of

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	Sale, Disposition or Retirement

      A Non-U.S. Holder generally will not be subject to U.S. federal income tax (and generally no tax will be withheld) with respect to gain (excluding gain representing accrued interest in which case the rules for interest apply) realized on the sale, exchange, retirement at maturity or other taxable disposition of a note unless:

	•	the Non-U.S. Holder is an individual who is present in the United States for a period or periods aggregating 183 or more days in the taxable year of the disposition and, generally, either has a “tax home” or “other fixed place of business” in the United States; or
	•	such gains are effectively connected with the conduct by the Non-U.S. Holder of a trade or business within the United States.

	U.S. Trade or Business

      If a Non-U.S. Holder holds a note in connection with the conduct of a trade or business in the United States, (i) any interest on the note, and any gain from disposing of the note generally will be subject to U.S. federal income tax as if the holder were a U.S. Holder, and (ii) Non-U.S. Holders that are corporations may be subject to the “branch profits tax” on earnings that are connected with a U.S. trade or business, including earnings from the note. This tax is 30% but may be reduced or eliminated by an applicable income tax treaty provided any applicable certification requirement is met.

	Backup Withholding and Information Reporting

      Backup withholding (currently at a rate of 28% in 2004) and information reporting requirements generally will not apply to payments of interest made by us or our paying agent to Non-U.S. Holders if the criteria for exemption from U.S. federal income and withholding tax for portfolio interest described above under “U.S. Federal Income Taxation of Non-US. Holders-Interest on the Notes” are met, provided that the neither we nor our agent has actual knowledge or reason to know that the holder is a U.S. person or that the conditions for exemption are not, in fact, satisfied. If the sale, exchange or other taxable disposition of a note is made to or through a foreign office of a foreign broker who pays the proceeds on the sale of a note to the seller outside the United States, backup withholding and information reporting generally will not apply. Information reporting requirements (but not backup withholding) will normally apply to a payment by a foreign office of a broker that is a U.S. person with certain exceptions. Payment by a U.S. office of a broker is subject to information reporting and possible backup withholding unless the Non-U.S. Holder meets the criteria for exemption, provided that the broker does not have actual knowledge or reason to know that the holder is a U.S. person or that the conditions for exemption are not, in fact, satisfied.

      Certain Non-U.S. Holders are exempt from backup withholding. Non-U.S. Holders of notes should consult their tax advisors regarding the application of information reporting and backup withholding in their particular situations, the availability of an exemption therefrom, and the procedure for obtaining such an exemption, if available. Any amounts withheld under the backup withholding rules from a payment to a Non-U.S. Holder will be allowed as a credit against such Non-U.S. Holder’s U.S. federal income tax liability and may entitle the holder to a refund, provided that the required information is timely furnished to the IRS.

U.S. Federal Estate Taxation of Non-U.S. Holders

      Subject to applicable estate tax treaty provisions, notes held at the time of death (or notes transferred before death but subject to certain retained rights or powers) by an individual who at the time of death is not a citizen or resident of the United States (as specifically defined for U.S. federal estate tax purposes),

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      THE PRECEDING DISCUSSION OF CERTAIN U.S. FEDERAL INCOME AND ESTATE TAX CONSEQUENCES IS FOR GENERAL INFORMATION ONLY. IT IS NOT TAX ADVICE. EACH PROSPECTIVE HOLDER SHOULD CONSULT HIS, HER OR ITS OWN TAX ADVISOR AS TO THE PARTICULAR TAX CONSEQUENCES OF PARTICIPATION IN THE OFFERING AND THE OWNERSHIP, EXCHANGE AND DISPOSITION OF THE NOTES, INCLUDING THE APPLICABILITY OF ANY U.S. FEDERAL TAX LAWS OR ANY STATE, LOCAL OR FOREIGN TAX LAWS OR AN APPLICABLE TAX TREATY, AND ANY CHANGES (OR PROPOSED CHANGES) IN APPLICABLE TAX LAWS OR INTERPRETATIONS THEREOF.

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UNDERWRITING

      Under the terms and subject to the conditions contained in an underwriting agreement dated May      , 2004 , we have agreed to sell to the underwriters named below, for whom Credit Suisse First Boston LLC is acting as representative, the following respective principal amounts of the notes.

			Principal
Underwriter			Amount
Credit Suisse First Boston LLC			$
Goldman, Sachs & Co.
Jefferies & Company, Inc.
Banc One Capital Markets, Inc.
Deutsche Bank Securities Inc.
CIBC World Markets Corp.
BNP Paribas Securities Corp.
Calyon Securities (USA) Inc.
SG Americas Securities, LLC
Wells Fargo Securities
	Total		$	150,000,000

      The underwriting agreement provides that the underwriters are obligated to purchase all of the notes if any are purchased. The underwriting agreement also provides that, if an underwriter defaults, the purchase commitments of non-defaulting underwriters may be increased or the offering of notes may be terminated.

      The underwriters propose to offer the notes initially at the public offering price on the cover page of this prospectus supplement and to selling group members at that price less a selling concession of      % of the principal amount per note. The underwriters and selling group members may allow a discount of      % of the principal amount per note on sales to other broker/ dealers. After the initial public offering the representative may change the public offering price and concession and discount to broker/ dealers.

      We estimate that our out of pocket expenses for this offering will be approximately $625,000.

      The notes are a new issue of securities with no established trading market. One or more of the underwriters intends to make a secondary market for the notes. However, they are not obligated to do so and may discontinue making a secondary market for the notes at any time without notice. No assurance can be given as to how liquid the trading market for the notes will be.

      We have agreed that we will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the SEC a registration statement under the Securities Act of 1933 (the “Securities Act”) relating to, any additional debt securities, or publicly disclose the intention to make any such offer, sale, pledge, disposition or filing, without the prior written consent of Credit Suisse First Boston LLC for a period of 60 days after the date of this prospectus.

      We have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments which the underwriters may be required to make in that respect.

      In connection with the offering the underwriters, may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934 (the “Exchange Act”).

	•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
	•	Over-allotment involves sales by the underwriters of notes in excess of the principal amount of the notes the underwriters are obligated to purchase, which creates a syndicate short position.

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	•	Syndicate covering transactions involve purchases of the notes in the open market after the distribution has been completed in order to cover syndicate short positions. A short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the notes in the open market after pricing that could adversely affect investors who purchase in the offering.
	•	Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the notes originally sold by the syndicate member are purchased in a stabilizing transaction or a syndicate covering transaction to cover syndicate short positions.

      These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of the notes or preventing or retarding a decline in the market price of the notes. As a result the price of the notes may be higher than the price that might otherwise exist in the open market. These transactions, if commenced, may be discontinued at any time.

      We expect that delivery of the notes will be made against payment therefor on or about                     , 2004, which will be the tenth business day following the date of pricing of the notes. Under Rule 15c6-1 under the Exchange Act, trades in the secondary market generally are required to settle in three business days, unless the parties to any such trade expressly agree otherwise. Accordingly, if you wish to trade notes on the date of pricing or the next two succeeding business days you will be required, by virtue of the fact that the notes initially will settle in T+10, to specify an alternate settlement cycle at the time of any such trade to prevent a failed settlement. Purchasers of notes who wish to trade notes on the date of pricing or the next seven succeeding business days should consult their own advisors.

      In the ordinary course of their businesses, certain of the underwriters and their affiliates have engaged, and may in the future engage, in investment banking or commercial banking transactions with us and our affiliates. Also, affiliates of each of Banc One Capital Markets, Inc., CIBC World Markets Corp., BNP Paribas Securities Corp., Calyon Securities (USA) Inc., SG Americas Securities, LLC, and Wells Fargo Securities are lenders under our bank credit facility. Prior to the repurchase of our 10 1/4% senior subordinated notes due 2009, we intend to use a portion of the net proceeds from this notes offering to repay all outstanding indebtedness under our bank credit facility. The decision of the underwriters to distribute the notes was made independently of the affiliates of the underwriters that are lenders under the credit facility, which lenders had no involvement in determining whether or when to distribute the notes under this offering or the terms of this offering. Wells Fargo Securities, an affiliate of Wells Fargo Bank, National Association, the Trustee under the indenture for the notes, is a participant in the underwriting syndicate for this notes offering.

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NOTICE TO CANADIAN RESIDENTS

Resale Restrictions

      The distribution of the notes in Canada is being made only on a private placement basis exempt from the requirement that we prepare and file a prospectus with the securities regulatory authorities in each province where trades of notes are made. Any resale of the notes in Canada must be made under applicable securities laws, which will vary depending on the relevant jurisdiction, and which may require resales to be made under available statutory exemptions or under a discretionary exemption granted by the applicable Canadian securities regulatory authority. Purchasers are advised to seek legal advice prior to any resale of the notes.

Representations of Purchasers

      By purchasing notes in Canada and accepting a purchase confirmation a purchaser is representing to us and the dealer from whom the purchase confirmation is received that

	•	the purchaser is entitled under applicable provincial securities laws to purchase the notes without the benefit of a prospectus qualified under those securities laws,
	•	where required by law, that the purchaser is purchasing as principal and not as agent, and
	•	the purchaser has reviewed the text above under Resale Restrictions.

Rights of Action – Ontario Purchasers Only

      Under Ontario securities legislation, a purchaser who purchases a security offered by this prospectus during the period of distribution will have a statutory right of action for damages, or while still the owner of the notes, for rescission against us in the event that this prospectus supplement contains a misrepresentation. A purchaser will be deemed to have relied on the misrepresentation. The right of action for damages is exercisable not later than the earlier of 180 days from the date the purchaser first had knowledge of the facts giving rise to the cause of action and three years from the date on which payment is made for the notes. The right of action for rescission is exercisable not later than 180 days from the date on which payment is made for the notes. If a purchaser elects to exercise the right of action for rescission, the purchaser will have no right of action for damages against us. In no case will the amount recoverable in any action exceed the price at which the notes were offered to the purchaser and if the purchaser is shown to have purchased the securities with knowledge of the misrepresentation, we will have no liability. In the case of an action for damages, we will not be liable for all or any portion of the damages that are proven to not represent the depreciation in value of the notes as a result of the misrepresentation relied upon. These rights are in addition to, and without derogation from, any other rights or remedies available at law to an Ontario purchaser. The foregoing is a summary of the rights available to an Ontario purchaser. Ontario purchasers should refer to the complete text of the relevant statutory provisions.

Enforcement of Legal Rights

      All of our directors and officers as well as the experts named herein may be located outside of Canada and, as a result, it may not be possible for Canadian purchasers to effect service of process within Canada upon us or those persons. All or a substantial portion of our assets and the assets of those persons may be located outside of Canada and, as a result, it may not be possible to satisfy a judgment against us or those persons in Canada or to enforce a judgment obtained in Canadian courts against us or those persons outside of Canada.

Taxation and Eligibility for Investment

      Canadian purchasers of notes should consult their own legal and tax advisors with respect to the tax consequences of an investment in the notes in their particular circumstances and about the eligibility of the notes for investment by the purchaser under relevant Canadian legislation.

S-97

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LEGAL MATTERS

      The validity of the offered notes and U.S. tax matters relating to the notes will be passed upon for us by Jenkens & Gilchrist, a Professional Corporation, Houston, Texas. Certain legal matters will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

      The consolidated financial statements of Swift Energy Company as of December 31, 2003 and 2002, and for each of the two years in the period ended December 31, 2003, appearing in Swift Energy Company’s Annual Report on Form 10-K for the year ended December 31, 2003, and appearing and incorporated by reference in this prospectus supplement and incorporated by reference in the accompanying prospectus, have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon also appearing and incorporated by reference elsewhere herein, and are included herein and incorporated herein by reference in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

      A copy of the previously issued report dated February 18, 2002 of Arthur Andersen LLP on the consolidated balance sheets of Swift Energy Company as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three-years ended December 31, 2001, is included in this prospectus supplement, but such previously issued report has not been reissued.

      Information set forth in this prospectus supplement regarding our estimated quantities of oil and gas reserves and the discounted present value of future net cash flows therefrom is based upon estimates of such reserves and present values audited by H.J. Gruy & Associates, Inc., independent petroleum engineers. All such information has been so included herein in reliance upon the authority of such firm as experts in such matters.

S-98

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GLOSSARY OF TERMS

      The following abbreviations and terms have the indicated meanings when used in this report:

      Bbl – Barrel or barrels of oil.

      Bcf – Billion cubic feet of natural gas.

      Bcfe – Billion cubic feet of natural gas equivalent (see Mcfe).

      BOE – Barrels of oil equivalent.

      Development Well – A well drilled within the presently proved productive area of an oil or natural gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir.

      Discovery Cost – With respect to proved reserves, a three-year average (unless otherwise indicated) calculated by dividing total incurred exploration and development costs (exclusive of future development costs) by net reserves added during the period through extensions, discoveries, and other additions.

      Dry Well – An exploratory or development well that is not a producing well.

      Exploratory Well – A well drilled either in search of a new, as yet undiscovered oil or natural gas reservoir or to greatly extend the known limits of a previously discovered reservoir.

      FASB – The Financial Accounting Standards Board.

      Gigajoules – A unit of energy equivalent to .95 Mcf of 1,000 Btu of natural gas.

      Gross Acre – An acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

      Gross Well – A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.

      MBbl – Thousand barrels of oil.

      Mcf – Thousand cubic feet of natural gas.

      Mcfe – Thousand cubic feet of natural gas equivalent, which is determined using the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf of natural gas.

      MMBbl – Million barrels of oil.

      MMBtu – Million British thermal units, which is a heating equivalent measure for natural gas and is an alternate measure of natural gas reserves, as opposed to Mcf, which is strictly a measure of natural gas volumes. Typically, prices quoted for natural gas are designated as price per MMBtu, the same basis on which natural gas is contracted for sale.

      MMcf – Million cubic feet of natural gas.

      MMcfe – Million cubic feet of natural gas equivalent (see Mcfe).

      Net Acre – A net acre means the sum of fractional working interests owned in gross acres equals one. The number of net acres is the sum of fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

      Net Production – The sum of fractional working interests in gross production owned directly or indirectly after deducting royalty, limited partner, and other similar interests.

      Net Well – A net well means the sum of fractional working interests owned in gross wells equals one. The number of net wells is the sum of fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

      NGLs – Natural gas liquids.

S-99

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      Petajoules – A unit of energy equivalent to .95 Bcf of 1,000 Btu of natural gas.

      Producing Well – An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

      Proved Developed Oil and Gas Reserves – Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

      Proved Oil and Gas Reserves – The estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made.

      Proved Undeveloped Oil and Gas Reserves – Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

      Proved Undeveloped (PUD) Locations – A location containing proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

      PV-10 Value – The estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs and future development costs, using prices and costs in effect as of a certain date, without escalation and without giving effect to non-property related expenses, such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion, and amortization.

      Reserves Replacement Cost – With respect to proved reserves, a three-year average (unless otherwise indicated) calculated by dividing total incurred acquisition, exploration, and development costs (exclusive of future development costs) by net reserves added during the period.

      SFAS – Statement of Financial Accounting Standards.

      TAWN – New Zealand producing properties acquired by Swift in January 2002. TAWN is comprised of the Tariki, Ahuroa, Waihapa, and Ngaere fields.

S-100

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SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS

Audited Annual Consolidated Financial Statements of Swift Energy Company
Report of Independent Auditors			F-2
Report of Independent Public Accountants			F-3
Consolidated Balance Sheets as of December 31, 2003 and 2002			F-4
Consolidated Statements of Income for the years ended December 31, 2003, 2002 and 2001			F-5
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2003, 2002 and 2001			F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001			F-7
Notes to Consolidated Financial Statements for the years ended December 31, 2003, 2002 and 2001			F-8
Unaudited Interim Consolidated Financial Statements of Swift Energy Company
Consolidated Balance Sheets as of March 31, 2004 (Unaudited) and December 31, 2003			F-34
Consolidated Statements of Income for the three month periods ended March 31, 2004 and 2003 (Unaudited)			F-35
Consolidated Statements of Stockholders’ Equity for the three month period ended March 31, 2004 (Unaudited) and year ended December 31, 2003			F-36
Consolidated Statements of Cash Flows for the three month periods ended March 31, 2004 and 2003 (Unaudited)			F-37
Notes to Consolidated Financial Statements for the three month period ended March 31, 2004 (Unaudited)			F-38

F-1

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REPORT OF INDEPENDENT AUDITORS

Board of Directors

      We have audited the accompanying consolidated balance sheets of Swift Energy Company and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements of Swift Energy Company and subsidiaries for the year ended December 31, 2001, were audited by other auditors who have ceased operations and whose report dated February 18, 2002, expressed an unqualified opinion on those statements.

      We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, the 2002 and 2003 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Swift Energy Company and subsidiaries at December 31, 2003 and 2002, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States.

      As discussed in Note 1 to the consolidated financial statements, in 2003 the Company changed its method of accounting for asset retirement obligations.

	ERNST & YOUNG LLP

Houston, Texas

F-2

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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders and Board of Directors of Swift Energy Company:

      We have audited the accompanying consolidated balance sheets of Swift Energy Company (a Texas corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

      We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Swift Energy Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.

	ARTHUR ANDERSEN LLP

Houston, Texas

NOTE: This is a copy of the report previously issued by Arthur Andersen LLP and has not been reissued.

F-3

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CONSOLIDATED BALANCE SHEETS

SWIFT ENERGY COMPANY AND SUBSIDIARIES

					December 31,
					2003				2002
ASSETS
Current Assets:
	Cash and cash equivalents				$	1,066,280			$	3,816,107
	Accounts receivable –
		Oil and gas sales				26,942,920				17,360,716
		Affiliated limited partnerships				356,118				191,964
		Joint interest owners				1,350,707				3,364,846
	Other current assets					4,957,647				5,034,566
			Total Current Assets			34,673,672				29,768,199
Property and Equipment:
	Oil and gas, using full-cost accounting
		Proved properties				1,305,763,355				1,150,633,802
		Unproved properties				67,557,969				69,603,481
						1,373,321,324				1,220,237,283
	Furniture, fixtures, and other equipment					10,602,786				9,595,944
						1,383,924,110				1,229,833,227
	Less – Accumulated depreciation, depletion, and amortization					(567,464,334	)			(504,323,773	)
						816,459,776				725,509,454
Other Assets:
	Deferred income taxes					1,905,909				2,680,585
	Debt issuance costs					8,015,575				9,047,621
						9,921,484				11,728,206
					$	861,054,932			$	767,005,859
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
	Accounts payable and accrued liabilities				$	63,100,669			$	43,028,708
	Payable to affiliated limited partnerships					516,006				91,126
	Undistributed oil and gas revenues					6,156,055				3,764,350
			Total Current Liabilities			69,772,730				46,884,184
Long-Term Debt						340,254,783				324,271,973
Deferred Income Taxes						43,498,682				30,776,518
Asset Retirement Obligation						10,137,473				—
Commitments and Contingencies
Stockholders’ Equity:
	Preferred stock, $.01 par value, 5,000,000 shares authorized, none outstanding					—				—
	Common stock, $.01 par value, 85,000,000 shares authorized, 28,011,109 and 27,811,632 shares issued, and 27,484,091 and 27,201,509 shares outstanding, respectively					280,111				278,116
	Additional paid-in capital					334,865,204				333,543,471
	Treasury stock held, at cost, 527,018 and 610,123 shares, respectively					(7,558,093	)			(8,749,922	)
	Retained earnings					70,073,384				40,179,572
	Accumulated other comprehensive loss, net of income tax					(269,342	)			(178,053	)
						397,391,264				365,073,184
					$	861,054,932				767,005,859

See accompanying Notes to Consolidated Financial Statements.

F-4

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CONSOLIDATED STATEMENTS OF INCOME

SWIFT ENERGY COMPANY AND SUBSIDIARIES

				Year Ended December 31,
				2003				2002				2001
Revenues:
	Oil and gas sales			$	211,032,639			$	141,195,713			$	181,184,635
	Fees from affiliated limited partnerships				28,068				67,173				427,583
	Interest income				184,383				263,738				49,281
	Gain on asset disposition				—				7,332,668				—
	Price-risk management and other, net				(2,344,107	)			1,110,519				2,145,991
					208,900,983				149,969,811				183,807,490
Costs and Expenses:
	General and administrative, net				14,097,066				10,564,849				8,186,654
	Depreciation, depletion, and amortization				63,072,057				56,224,392				59,502,040
	Accretion of asset retirement obligation				857,356				—				—
	Oil and gas production				52,866,802				41,497,312				36,719,609
	Interest expense, net				27,268,524				23,274,969				12,627,022
	Other expenses				—				—				2,102,251
	Write-down of oil and gas properties				—				—				98,862,247
					158,161,805				131,561,522				217,999,823
Income (Loss) Before Income Taxes and
	Change in Accounting Principle				50,739,178				18,408,289				(34,192,333	)
Provision (Benefit) for Income Taxes					16,468,514				6,485,062				(12,237,436	)
Income (Loss) Before Change
	In Accounting Principle			$	34,270,664			$	11,923,227			$	(21,954,897	)
Cumulative Effect of Change in Accounting Principle (net of taxes)					4,376,852				—				392,868
Net Income (Loss)				$	29,893,812			$	11,923,227			$	(22,347,765	)
Per Share Amounts –
	Basic: Income (Loss) Before Change in Accounting Principle			$	1.25			$	0.45			$	(0.89	)
		Change in Accounting Principle			(0.16	)			—				(0.01	)
		Net Income (Loss)		$	1.09			$	0.45			$	(0.90	)
	Diluted: Income (Loss) Before Change in Accounting Principle			$	1.24			$	0.45			$	(0.89	)
		Change in Accounting Principle			(0.16	)			—				(0.01	)
		Net Income (Loss)		$	1.08			$	0.45			$	(0.90	)
Weighted Average Shares Outstanding					27,357,579				26,382,906				24,732,099

See accompanying Notes to Consolidated Financial Statements.

F-5

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

SWIFT ENERGY COMPANY AND SUBSIDIARIES

																				Accumulated
								Additional								Retained				Other
				Common				Paid-In								Earnings				Comprehensive
				Stock(1)				Capital				Treasury Stock				(Deficit)				Loss				Total
Balance, December 31, 2000				$	254,521			$	293,396,723			$	(12,101,199	)		$	50,604,110			$	—			$	332,154,155
	Stock issued for benefit plans (11,945 shares)				72				354,973				68,408				—				—				423,453
	Stock options exercised (152,915 shares)				1,529				1,942,634				—				—				—				1,944,163
	Employee stock purchase plan (22,360 shares)				224				478,490				—				—				—				478,714
Comprehensive income:
	Net loss				—				—				—				(22,347,765	)			—				(22,347,765	)
		Total comprehensive income			—				—				—				—				—				(22,347,765	)
Balance, December 31, 2001				$	256,346			$	296,172,820			$	(12,032,791	)		$	28,256,345			$	—			$	312,652,720
	Stock issued for benefit plans (38,149 shares)				292				617,960				127,795				—				—				746,047
	Stock options exercised (112,995 shares)				1,130				1,206,413				—				—				—				1,207,543
	Public stock offering (1,725,000 shares)				17,250				30,465,809				—				—				—				30,483,059
	Employee stock purchase plan (9,801 shares)				98				122,343				—				—				—				122,441
	Stock issued in acquisitions (520,000 shares)				3,000				4,958,126				3,155,074				—				—				8,116,200
Comprehensive income:
	Net income				—				—				—				11,923,227				—				11,923,227
	Change in fair value of cash flow hedges, net of income tax				—				—				—				—				(178,053	)			(178,053	)
		Total comprehensive income			—				—				—				—				—				11,745,174
Balance, December 31, 2002				$	278,116			$	333,543,471			$	(8,749,922	)		$	40,179,572			$	(178,053	)		$	365,073,184
	Stock issued for benefit plans (83,201 shares)				1				(408,178	)			1,191,829				—				—				783,652
	Stock options exercised (142,807 shares)				1,428				1,315,964				—				—				—				1,317,392
	Employee stock purchase plan (56,574 shares)				566				413,947				—				—				—				414,513
Comprehensive income:
	Net income				—				—				—				29,893,812				—				29,893,812
	Change in fair value of cash flow hedges, net of income tax				—				—				—				—				(91,289	)			(91,289	)
		Total comprehensive income			—				—				—				—				—				29,802,523
Balance, December 31, 2003				$	280,111			$	334,865,204			$	(7,558,093	)		$	70,073,384			$	(269,342	)		$	397,391,264

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(1)	$.01 par value.

See accompanying Notes to Consolidated Financial Statements.

F-6

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CONSOLIDATED STATEMENTS OF CASH FLOWS

SWIFT ENERGY COMPANY AND SUBSIDIARIES

						Year Ended December 31,
						2003				2002				2001
Cash Flows from Operating Activities:
	Net income (loss)					$	29,893,812			$	11,923,227			$	(22,347,765	)
	Adjustments to reconcile net income (loss) to net cash provided by operating activities –
		Cumulative effect of change in accounting principle					4,376,852				—				—
		Depreciation, depletion, and amortization					63,072,057				56,224,392				59,502,040
		Write-down of oil and gas properties					—				—				98,862,247
		Accretion of asset retirement obligation					857,356				—				—
		Deferred income taxes					16,332,492				6,482,724				(12,555,618	)
		Gain on asset disposition					—				(7,332,668	)			—
		Other					908,927				270,770				509,973
		Change in assets and liabilities –
			(Increase) decrease in accounts receivable, excluding income taxes receivable				(7,163,304	)			283,419				16,207,377
			Increase in accounts payable and accrued liabilities				2,542,803				3,174,450				12,984
			(Increase) decrease in income taxes receivable and payable				6,284				600,000				(306,983	)
				Net Cash Provided by Operating Activities			110,827,279				71,626,314				139,884,255
Cash Flows from Investing Activities:
	Additions to property and equipment						(144,503,180	)			(155,233,923	)			(275,126,333	)
	Proceeds from the sale of property and equipment						10,186,970				13,256,674				9,274,440
	Net cash received as operator of oil and gas properties						3,073,718				4,152,645				5,927,539
	Net cash received (distributed) as operator of partnerships						260,726				(23,241,501	)			(3,574,601	)
	Other						(71,193	)			(39,953	)			(534,898	)
				Net Cash Used in Investing Activities			(131,052,959	)			(161,106,058	)			(264,033,853	)
Cash Flows from Financing Activities:
	Proceeds from long-term debt						—				200,000,000				—
	Net proceeds from (payments of) bank borrowings						15,900,000				(134,000,000	)			123,400,000
	Net proceeds from issuances of common stock						1,575,853				31,409,200				1,633,508
	Payments of debt issuance costs						—				(6,262,435	)			(721,756	)
				Net Cash Provided by Financing Activities			17,475,853				91,146,765				124,311,752
Net Increase (Decrease) in Cash and Cash Equivalents						$	(2,749,827	)		$	1,667,021			$	162,154
Cash and Cash Equivalents at Beginning of Year							3,816,107				2,149,086				1,986,932
Cash and Cash Equivalents at End of Year						$	1,066,280			$	3,816,107			$	2,149,086
Supplemental Disclosures of Cash Flows Information:
	Cash paid during year for interest, net of amounts capitalized					$	25,763,169			$	19,189,822			$	12,207,205
	Cash paid during year for income taxes					$	129,738			$	2,500			$	441,926
Non-Cash Financing Activity:
	Issuance of common stock in acquisitions					$	—			$	8,116,200			$	—

See accompanying Notes to Consolidated Financial Statements.

F-7

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SWIFT ENERGY COMPANY AND SUBSIDIARIES

1.	Summary of Significant Accounting Policies

      Principles of Consolidation. The accompanying consolidated financial statements include the accounts of Swift Energy Company and our wholly owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and natural gas properties, with a focus on onshore and inland waters oil and natural gas reserves in Texas and Louisiana, as well as onshore oil and natural gas reserves in New Zealand. Our investments in ventures and affiliated oil and gas partnerships are accounted for using the proportionate consolidation method, whereby our proportionate share of each entity’s assets, liabilities, revenues, and expenses are included in the appropriate classifications in the consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the consolidated financial statements.

      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. Significant estimates include proved reserve volumes, DD&A, and deferred income taxes.

      Property and Equipment. 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 exploration, development, and acquisition of oil and gas reserves are capitalized. Under the full-cost method of accounting, such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the years 2003, 2002, and 2001, such internal costs capitalized totaled $11.5 million, $10.7 million, and $11.6 million, respectively. Interest costs are also capitalized to unproved oil and gas properties. For the years 2003, 2002, and 2001, capitalized interest on unproved properties totaled $6.8 million, $7.0 million, and $6.3 million, respectively. Interest not capitalized and 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 involving a significant amount of reserves or where the proceeds from the sale of oil and gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.

      Future development costs are estimated property by property based on current economic conditions and are amortized to expense as our capitalized oil and gas property costs are amortized.

      We compute the provision for depreciation, depletion, and amortization of oil and gas properties using 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 costs, gas processing facilities, and capitalized asset retirement obligations, net of salvage values, 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 at the beginning of the period. This calculation is done on a country-by-country basis. Our amortization per Mcfe was $1.17, $1.11, and $1.31 in 2003, 2002, and 2001, respectively. Furniture, fixtures, and other equipment are depreciated by the straight-line method at rates based on the estimated useful lives of the property. Repairs and maintenance are charged to expense as incurred. Renewals and betterments are capitalized.

F-8

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SWIFT ENERGY COMPANY AND SUBSIDIARIES

      Geological and geophysical (G&G) costs are recorded in Proved Property and therefore subject to amortization as incurred on developed properties. In exploration areas, G&G costs are capitalized in Unproved Property and evaluated as part of the total capitalized costs associated with a prospect.

      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, we evaluate current drilling results, lease expiration dates, 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. To the extent costs accumulate in countries where there are no proved reserves, any costs determined by management to be impaired are charged to expense.

      Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and gas properties, including gas processing facilities and the fair value of asset retirement obligations, net of related salvage values, deferred income taxes, and excluding the asset retirement obligation liability is limited to the sum of the estimated future net revenues from proved properties, excluding cash outflows from asset retirement obligations, using hedged adjusted 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”). Our hedges at year-end 2003 consisted of natural gas price floors with strike prices lower than the period end price and thus did not affect prices used in this calculation. 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.

      In the fourth quarter of 2001, as a result of low oil and gas prices at December 31, 2001, we reported a non-cash write-down on a before-tax basis of $98.9 million ($63.5 million after tax) on our domestic properties. We had no write-down on our New Zealand properties.

      Given the volatility of oil and gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline from the Company’s period-end prices used in the Ceiling Test, even if only for a short period, it is possible that additional non-cash write-downs of oil and gas properties could occur in the future.

      Revenue Recognition. Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. The Company uses the entitlement method of accounting in which the Company recognizes its ownership interest in production as revenue. If our sales exceed our ownership share of production, the differences are reported in “Accounts payable and accrued liabilities” on the accompanying balance sheet. Natural gas balancing receivables are reported in “Other current assets” on the accompanying balance sheet when our ownership share of production exceeds sales. As of December 31, 2003, we did not have any material natural gas imbalances.

      Accounts Receivable. Included in the total “Accounts receivable” balance, which totaled $28.6 million and $20.9 million at December 31, 2003 and 2002, respectively, on the accompanying balance sheet, is approximately $2.3 million of receivables related to volumes produced from 2001 and 2002 that we were notified, were disputed in early 2003. Accordingly, we did not record a receivable with regard to 2003

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volumes. We assess the collectibility of trade and other receivables. Based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At December 31, 2003 and 2002, we had an allowance for doubtful accounts of $0.8 million and $0.3 million, respectively. These allowances for doubtful accounts balances have been deducted from the total “Accounts receivable” balances on the accompanying consolidated balance sheet.

      Debt Issuance Costs. Legal and accounting fees, underwriting fees, printing costs, and other direct expenses associated with the public offering in August 1999 of our 10.25% Senior Subordinated Notes due 2009, the September 2001 extension of our bank credit facility, and the public offering in April 2002 of our 9.375% Senior Subordinated Notes due 2012 were capitalized and are amortized over the life of each of the respective note offerings and credit facility. The Senior Subordinated Notes due 2009 mature on August 1, 2009, and the balance of their issuance costs at December 31, 2003, was $2.4 million, net of accumulated amortization of $1.1 million. The issuance costs associated with our revolving credit facility, which was extended in September 2001, have been capitalized and are being amortized over the life of the facility. The balance of revolving credit facility issuance costs at December 31, 2003, was $0.6 million, net of accumulated amortization of $1.3 million. The Senior Subordinated Notes due 2012 mature on May 1, 2012, and the balance of their issuance costs at December 31, 2003, was $5.0 million, net of accumulated amortization of $0.6 million.

      Limited Partnerships. At year-end 2003, we serve as managing general partner for six drilling partnerships, and during fiscal 2003 less than 1% of our total oil and gas sales was attributable to our interests in those partnerships. These six partnerships were formed between 1996 and 1998, and will continue to operate until their limited partners vote otherwise.

      Price-Risk Management Activities. The Company follows SFAS No. 133, which requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The statement also 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 a liability measured at its fair value. Special hedge accounting for qualifying hedges would allow the gains and losses on derivatives to offset related results on the hedged item in the income statements and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. Hedges that do not meet the criteria for special hedge accounting are accounted for under mark to market accounting. SFAS No. 133, as amended by SFAS No. 137 and SFAS No. 138, was adopted by us on January 1, 2001.

      We have a price-risk management policy to use derivative instruments to protect against declines in oil and gas prices, mainly through the purchase of price floors and collars. Upon adoption of SFAS No. 133 on January 1, 2001, we recorded a net of taxes charge of $0.4 million, which is recorded as a Cumulative Effect of Change in Accounting Principle. During 2003, 2002 and 2001, we recognized net losses (gains) of $2.8 million, $0.2 million and ($1.2) million, respectively, relating to our derivative activities. This activity is recorded in “Price-risk management and other, net” on the accompanying statements of income. At December 31, 2003, the Company had recorded $0.3 million, net of taxes of $0.2 million, of derivative losses in “Other comprehensive loss” on the accompanying balance sheet. This amount represents the change in fair value for the effective portion of our collar transactions that were qualified as cash flow hedges. The ineffectiveness reported in “Price-risk management and other, net” for 2003 and 2002 was not material. The Company expects to reclassify all amounts currently held in “Other comprehensive loss” into the statement of income within the next six months when the forecasted sale of hedged production occurs.

      As of December 31, 2003, we had in place natural gas price floors in effect for the January 2004 contract month through the June 2004 contract, which cover our domestic natural gas production for January 2004 to June 2004. The natural gas price floors cover notional volumes of 3,300,000 Mmbtu with

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a weighted average floor price of $4.77. When we entered into these transactions, they were designated as a hedge of the variability in cash flows associated with the forecasted sale of natural gas production. Changes in the fair value of a hedge that is highly effective and is designated and qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded in Other Comprehensive Income (Loss). When the hedged transactions are recorded upon the actual sale of oil and natural gas, these gains or losses are reclassified from Other Comprehensive Income (Loss) and recorded in “Price-risk management and other, net” on the consolidated statement of income. The fair value of our derivatives are computed using the Black-Scholes option pricing model and are periodically verified against quotes from brokers. The fair value of these instruments at December 31, 2003, was $0.5 million and is recognized on the balance sheet in “Other current assets.”

      Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate including our working interest share on wells where we have a 100% working interest. These supervision fees are recorded as a reduction to general and administrative expenses and oil and gas production expenses based on our estimate of the costs incurred to operate the wells. Effective October 1, 2003, we began recording the supervision fee as a reduction to general and administrative expense only. The total amount of supervision fees charged to the wells we operate was $5.1 million in 2003, $5.3 million in 2002, and $6.8 million in 2001.

      Inventories. Inventories consist principally of tubular goods and equipment, stated at the lower of weighted-average cost or market, and oil produced but not sold, stated at the lower of cost (a combination of production costs and depreciation, depletion and amortization expense) or market.

      Income Taxes. Under SFAS No. 109, “Accounting for Income Taxes,” deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax bases of assets and liabilities, given the provisions of the enacted tax laws.

      Accounts Payable and Accrued Liabilities. Included in accounts payable and accrued liabilities at December 31, 2003 and 2002 are liabilities of approximately $11.9 million and $8.4 million, respectively, representing the amount by which checks issued, but not presented to the Company’s banks for collection, exceeded balances in the applicable bank accounts.

      Cash and Cash Equivalents. We consider all highly liquid debt instruments with an initial maturity of three months or less to be cash equivalents.

      Credit Risk Due to Certain Concentrations. We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. During 2003, oil and gas sales to Shell, both domestically and in New Zealand, were $31.1 million, or 15% of total oil and gas sales, while sales to subsidiaries of Contact Energy in New Zealand were $23.5 million, or 11.2% of total oil and gas sales. During 2002, oil and gas sales to Eastex Crude Company were $25.4 million, or 18.0% of total oil and gas sales, while sales to subsidiaries of Contact Energy in New Zealand were $14.6 million, or 10.3% of total oil and gas sales. During 2001, oil and gas sales to Eastex Crude Company were $31.6 million, or 18.1% of total oil and gas sales, while sales to subsidiaries of Enron were $18.2 million, or 10.4% of total oil and gas sales. During the fourth quarter of 2001, we wrote off $1.4 million due to uncollected receivables related to gas sold to Enron in November 2001. This amount is included in “Other expenses” on the Consolidated Statement of Income. In 2001, we discontinued sales of oil and gas to Enron and are selling that production to other purchasers. Credit losses in 2002 and 2003 have been immaterial.

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      Environmental Costs. Our operations include activities that are subject to extensive federal and state environmental regulations. Costs associated with redemption projects, which are probable and quantifiable, are accrued in advance. Ongoing environmental compliance costs are expensed as incurred.

      Foreign Currency. We use the U.S. Dollar as our functional currency in New Zealand. The functional currency is determined by examining the entities cash flows, commodity pricing environment and financing arrangements. We have both assets and liabilities denominated in New Zealand Dollars, predominantly our portion of our “Deferred income taxes” and a portion of our “Asset Retirement Obligation” on the accompanying balance sheet. For accounts other than “Deferred income taxes,” as the currency rate changes between the U.S. Dollar and the New Zealand Dollar, we recognize transaction gains and losses in “Price-risk management and other, net” on the accompanying statements of income. We recognize transaction gains and losses on “Deferred income taxes” in “Provision for Income Taxes” on the accompanying statement of income.

      Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and senior subordinated notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the bank borrowings approximate the carrying amounts as of December 31, 2003 and 2002, and were determined based upon variable interest rates currently available to us for borrowings with similar terms. Based on quoted market prices as of the respective dates, the fair values of our Senior Subordinated Notes due 2009 were $135.6 million and $129.0 million at December 31, 2003 and 2002, respectively. Based upon quoted market prices as of December 31, 2003 and 2002, the fair values of our Senior Subordinated Notes due 2012 were $218.0 million and $189.2 million, respectively. The carrying value of our Senior Subordinated Notes due 2009 was $124.4 million and $124.3 million at December 31, 2003 and 2002, respectively. The carrying value of our Senior Subordinated Notes due 2012 was $200.0 million at both December 31, 2003 and 2002.

      Other Comprehensive Loss. We follow the provisions of SFAS No. 130, “Reporting Comprehensive Income,” which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income or loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company. At December 31, 2003, we recorded $0.3 million, net of taxes of $0.2 million, of derivative losses in “Other comprehensive loss” on the accompanying balance sheet. The components of accumulated other comprehensive loss and related tax effects for 2003 were as follows:

										Net of
		Gross Value				Tax Effect				Tax Value
Balance at December 31, 2002		$	278,208			$	100,155			$	178,053
Change in fair value of cash flow hedges			2,488,136				895,729				1,592,407
Effect of cash flow hedges settled during the period			(2,345,497	)			(844,379	)			(1,501,118	)
Balance at December 31, 2003		$	420,847			$	151,505			$	269,342

      Total comprehensive income was $29.8 million and $11.7 million for 2003 and 2002, respectively. Total comprehensive loss was $22.3 million in 2001.

      Stock Based Compensation. We have three stock-based compensation plans, which are described more fully in Note 6. We account for those plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. No stock-based employee compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of the grant; or in

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the case of the employee stock purchase plan, the purchase price is 85% of the lower of the closing price of our common stock as quoted on the New York Stock Exchange at the beginning or end of the plan year or a date during the year chosen by the participant. Had compensation expense for these plans been determined based on the fair value of the options consistent with SFAS No. 123, “Accounting for Stock-Based Compensation,” our net income (loss) and earnings (loss) per share would have been adjusted to the following pro forma amounts:

				2003				2002				2001
Net Income (Loss):		As Reported		$	29,893,812			$	11,923,227			$	(22,347,765	)
		Stock-based employee compensation expense determined under fair value method for all awards, net of tax			(4,112,455	)			(4,451,799	)			(4,284,859	)
		Pro Forma		$	25,781,357			$	7,471,428			$	(26,632,624	)
Basic EPS:		As Reported			$1.09				$.45				$(0.90	)
		Pro Forma			$0.94				$.28				$(1.08	)
Diluted EPS:		As Reported			$1.08				$.45				$(0.90	)
		Pro Forma			$0.94				$.27				$(1.08	)

      Pro forma compensation cost reflected above may not be representative of the cost to be expected in future years. The fair value of each option grant, as opposed to its exercise price, is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions in 2003, 2002, and 2001, respectively: no dividend yield; expected volatility factors of 34.71%, 73.72%, and 46.9%; risk-free interest rates of 4.63%, 4.74%, and 5.24%; and expected lives of 7.2, 7.4, and 7.3 years.

      Asset Retirement Obligation. In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” The statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. The liability is discounted from the year the well is expected to deplete. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. This standard requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values. SFAS No. 143 was adopted by us effective January 1, 2003. Upon adoption of SFAS No. 143 effective January 1, 2003, we recorded an asset retirement obligation of $8.9 million, an addition to oil and gas properties of $2.0 million, and a non-cash charge of $4.4 million (net of $2.5 million of deferred taxes), which is recorded as a Cumulative Effect of Change in Accounting Principle. The cumulative charge to earnings took into consideration the impact of adopting SFAS No. 143 on previous full-cost ceiling tests. SFAS No. 143 is silent with respect to whether prior period ceiling tests should be reflected in the implementation entry calculation; however, management believes that any impairment on the properties should be reflected in the historical periods. Had the Company not considered the impact of adopting SFAS No. 143 on previous full-cost ceiling tests, the charge recognized would have been reduced. Excluding the Cumulative Effect of Change in Accounting

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Principle, the adoption of SFAS No. 143 reduced our 2003 net income by approximately $0.6 million, or $0.02 per diluted share. The following provides a roll-forward of our asset retirement obligation:

Asset Retirement Obligation recorded as of January 1, 2003			$	8,934,320
	Accretion expense for 2003			857,356
	Liabilities incurred for new wells and facilities construction			608,166
	Reductions due to sold and abandoned wells			(443,391	)
	Revisions in estimated cash flows			67,511
	Increase due to currency exchange rate fluctuations			113,511
Asset Retirement Obligation as of December 31, 2003			$	10,137,473

      The pro forma effect for 2001, assuming adoption of SFAS No. 143 effective January 1, 2001, would have included a non-cash charge of $2.6 million (net of $1.5 million of deferred taxes), which would have been recorded as a Cumulative Effect of Change in Accounting Principle and recognition of an asset retirement obligation of $4.3 million. The following table displays our pro forma results for the years ended December 31, 2002 and 2001, had we adopted SFAS No. 143 effective January 1, 2001.

			Year Ended				Year Ended
			December 31, 2002				December 31, 2001
							(Unaudited)
Net Income (Loss):
	Actual – as reported		$	11,923,227			$	(22,347,765	)
	Pro Forma		$	11,515,205			$	(25,246,667	)
Basic EPS:
	Actual – as reported		$	0.45			$	(0.90	)
	Pro Forma		$	0.44			$	(1.02	)
Diluted EPS:
	Actual – as reported		$	0.45			$	(0.90	)
	Pro Forma		$	0.43			$	(1.02	)

      New Accounting Pronouncements. In June 2001, the FASB issued SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Intangible Assets.” We adopted these statements on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires that all business combinations initiated after June 30, 2001, be accounted for using the purchase method and that intangible assets be disaggregated and reported separately from goodwill. SFAS No. 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and other indefinite lived intangible assets are not amortized but reviewed annually for impairment.

      An issue has arisen for companies engaged in oil and gas exploration and production regarding the application of SFAS No. 141 and SFAS No. 142 as they relate to mineral rights held under lease or other contractual arrangements, and as to whether costs associated with these rights should be classified as intangible assets on the balance sheet, apart from other capitalized oil and gas property costs, and to provide specific footnote disclosure. We understand that the Emerging Issues Task Force of the FASB has placed this issue on its agenda, although the date and outcome of the resolution of the issue is unknown.

      Historically, we have classified our oil and gas mineral rights held under lease as tangible assets along with our other oil and gas properties, which is in accordance with the Securities and Exchange Commission’s (“SEC”) full cost accounting rules, and we intend to continue to do so until further guidance is provided. We have estimated the amount associated with these mineral rights using historical depletion rates, estimates of the timing of impairment of unproved properties and assuming the cost for the

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mineral rights was unaffected by the ceiling test write-down recorded in December 2001 because we cannot associate the ceiling test write-down with particular types of costs. Based on these limitations and assumptions, we estimate the net cost of mineral rights that would be reclassified from oil and gas properties to intangible assets to be approximately $55-60 million at December 31, 2003 and approximately $45-50 million at December 31, 2002. These amounts are from July 1, 2001 (the date we adopted SFAS No. 141) to December 31, 2003 as we are not able to calculate amounts to reclassify before that period as our property records did not break out that information. Only our balance sheet accounts would be affected by the reclassification, and our results of operations and cash flows would not be materially impacted by any such reclassification. These mineral rights would continue to be amortized in accordance with full cost accounting rules for oil and gas companies provided in SEC Regulation S-X Rule 4-10. We also do not believe classifying these assets as intangible would have any impact on our compliance with covenants under our debt agreements.

      In November 2002, the FASB issued Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” This interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarified that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this Interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year-end. The Company adopted this pronouncement upon the FASB’s issuance and the implementation had no impact on the consolidated financial statements.

      In January 2003, the FASB issued Interpretation No. 46 (Revised December 2003), Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51 Consolidated Financial Statements (the “Interpretation”). The Interpretation significantly changes whether entities included in its scope are consolidated by their sponsors, transferors, or investors. The Interpretation introduces a new consolidation model-the variable interest model; which determines control (and consolidation) based on potential variability in gains and losses of the entity being evaluated for consolidation. The Interpretation provides guidance for determining whether an entity lacks sufficient equity or its equity holders lack adequate decision-making ability. These variable interest entities (“VIEs”) are covered by the Interpretation and are to be evaluated for consolidation based on their variable interests. These provisions apply immediately to variable interests in VIEs created after January 31, 2003, and to variable interests in special purpose entities for periods ending after December 15, 2003. The provisions apply for all other types of variable interests in VIEs for periods ending after March 15, 2004. We have no variable interests in VIEs created after January 31, 2003, nor do we have variable interests in special purpose entities. The effect of applying the Interpretation is to be reported as the cumulative effect of an accounting change. We have not completed the process of evaluating the effects that will result from adopting the Interpretation.

      In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” This statement sets standards for classifying and measuring certain financial instruments with characteristics of both liabilities and equity. This statement is effective for periods ending after December 15, 2003. The impact of recognizing this statement was not material for the Company.

2.	Earnings Per Share

      Basic EPS has been computed using the weighted average number of common shares outstanding during the respective periods. Diluted earnings per share for all periods also assumes, as of the beginning of the period, exercise of stock options using the treasury stock method. Certain of our stock options that

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would potentially dilute Basic EPS in the future were also antidilutive for the 2003, 2002, and 2001 periods.

      The following is a reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS for the years ended December 31, 2003, 2002, and 2001:

			2003												2002												2001
			Net								Per Share				Net								Per Share				Net								Per Share
			Income				Shares				Amount				Income				Shares				Amount				Loss				Shares				Amount
Basic EPS:
	Net Income (Loss) and Share Amounts		$	29,893,812				27,357,579			$	1.09			$	11,923,227				26,382,906			$	0.45			$	(22,347,765	)			24,732,099			$	(0.90	)
Dilutive Securities:
	Stock Options			—				203,360								—				372,700								—				—
Diluted EPS:
	Net Income (Loss) and Assumed Share Conversions		$	29,893,812				27,560,939			$	1.08			$	11,923,227				26,755,606			$	0.45			$	(22,347,765	)			24,732,099			$	(0.90	)

      Options to purchase approximately 3.2 million shares at an average exercise price of $16.37 were outstanding at December 31, 2003. Approximately 1.7 million, 1.3 million, and 0.8 million options to purchase shares were not included in the computation of Diluted EPS for the year ended December 31, 2003, 2002, and 2001, respectively, because these options were antidilutive in that the option price was greater than the average closing market price for the common shares during those periods.

3.	Provision for Income Taxes

      Income before taxes is as follows:

		Year Ended December 31,
		2003				2002				2001
United States		$	38,955,404			$	12,889,583			$	(35,427,252	)
Foreign			11,783,773				5,518,706				1,234,919
Total		$	50,739,177			$	18,408,289			$	(34,192,333	)

      The following is an analysis of the consolidated income tax provision (benefit):

		Year Ended December 31,
		2003				2002				2001
Current		$	164,284			$	2,338			$	114,611
Deferred
– Domestic			14,386,868				4,870,239				(12,759,570	)
– Foreign			1,917,362				1,612,485				407,523
Total Deferred			16,304,230				6,482,724				(12,352,047	)
Total		$	16,468,514			$	6,485,062			$	(12,237,436	)

      The differences between income taxes computed using the federal statutory rate of 35% and our effective income tax rates (32.5%, 35.2%, and 35.8% for 2003, 2002, and 2001, respectively), are primarily the result of the currency exchange rate effect on foreign deferred income taxes, state income taxes and foreign income taxes (New Zealand’s statutory rate is 33%). We have not computed any provision for

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U.S. taxes on the undistributed earnings of our New Zealand subsidiaries as management intends to permanently reinvest such earnings. Upon distribution of these earnings in the form of dividends or otherwise, we may be subject to U.S. income taxes and New Zealand withholding taxes. It is not practical, however, to estimate the amount of taxes that may be payable on the eventual remittance of these earnings. Presently, there are no foreign tax credits available to reduce the U.S. taxes on such amounts if repatriated.

      SENZ uses the U.S. Dollar as its functional currency for financial reporting purposes, but income taxes are paid in the New Zealand Dollar. Because of the difference in currencies used for financial reporting and tax, there is potential for significant exchange impact on the tax provision calculation. Due to the strengthening of the New Zealand Dollar vs. the U.S. Dollar in 2003, the U.S. Dollar value of the deferred tax assets in New Zealand increased, resulting in favorable adjustment of $2.9 million compared to the 33% New Zealand statutory rate.

      During 2003 the Company increased its provision for state income taxes by $1.2 million, primarily due to its increased level of business activity in Louisiana. The company calculates its Louisiana income tax using the “apportionment” accounting method. Under apportionment accounting, total federal taxable income is allocated based on the proportional level of U.S. business activity within the state. Due to the relative increase in the Company’s domestic activity conducted in Louisiana, the Company increased its estimate of future Louisiana taxable income that will result from the reversal of prior years’ timing differences.

      Reconciliations of income taxes computed using the statutory rate to the effective income tax rates are as follows:

		2003				2002				2001
Income taxes computed at U.S. statutory rate		$	17,758,712			$	6,442,901			$	(11,967,317	)
State tax provisions, net of federal benefits			373,992				323,902				(279,875	)
Effect of foreign operations			(235,675	)			(110,374	)			(24,698	)
Currency remeasurement gain on foreign tax asset			(2,893,655	)			(208,688	)			—
Change in estimate for deferred Louisiana income taxes			1,216,105				—				—
Other, net			249,035				37,321				34,454
Provision (benefit) for income taxes		$	16,468,514			$	6,485,062			$	(12,237,436	)

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      The tax effects of temporary differences representing the net deferred tax liability (asset) at December 31, 2003 and 2002, were as follows:

				2003				2002
Deferred tax assets:
	Alternative minimum tax credits (Domestic)			$	(1,979,399	)		$	(1,979,399	)
	Carryover items (Domestic)				(53,036,919	)			(51,174,237	)
	Acquired deferred tax asset (Foreign)				(3,802,435	)			(4,753,044	)
	Carryover Items (Foreign)				(28,294,320	)			(19,494,129	)
		Total deferred tax assets		$	(87,113,073	)		$	(77,400,809	)
Deferred tax liabilities
	Domestic oil and gas exploration and development costs			$	98,010,617			$	83,361,520
	Foreign oil and gas exploration and development costs				30,190,846				21,566,588
	Other				504,383				568,634
		Total deferred tax liabilities		$	128,705,846			$	105,496,742
Net deferred tax liabilities				$	41,592,773			$	28,095,933

      The tax basis of the assets of Southern NZ on the acquisition date exceeded the cash purchase price paid by SENZ to acquire this entity. To account for the future tax benefits of this additional basis, SENZ recorded a deferred tax asset of $4.9 million. The asset is being amortized over the period in which the tax amortization is deducted. The remaining asset value at December 31, 2003, is $3.8 million. The other foreign carryover asset is attributable to cumulative New Zealand net operating losses. New Zealand tax net operating losses do not expire.

      At December 31, 2003, the Company had alternative minimum tax credits of $2.0 million that carry forward indefinitely. These credits are available to reduce future regular tax liability to the extent they exceed the alternative minimum tax otherwise due.

      The domestic deferred tax carryover items are attributable to expected future tax benefits in the amounts of $44.9 million for federal net operating losses, $1.5 million for State of Louisiana net operating losses and $6.5 million for capital losses. At December 31, 2003, cumulative federal net operating losses were $128.1 million, which will expire between 2018 and 2022. Louisiana net operating losses total $44.1 million and will expire between 2013 and 2018.

      The Company has not recorded any valuation allowance against the deferred tax assets attributable to net operating loss carryovers at December 31, 2003 and 2002, as management estimates that it is more likely than not that these assets will be fully utilized before they expire. Significant changes in estimates caused by changes in oil and gas prices, production levels, capital expenditures, and other variables could impact the Company’s ability to utilize the carryover amounts.

      In 2002 we recognized a capital loss of approximately $18.6 million as the result of the liquidation of our partnerships. This loss can only be utilized to offset capital gains and will expire in 2007. The Company plans to sell a number of oil and gas properties over the next few years in order to optimize its portfolio of non-core oil and gas properties. To generate capital gains from these dispositions, the sales proceeds must exceed the Company’s total investment in the properties. Company management has identified several qualified properties it intends to sell that have estimated current market values in excess of the total original costs. Management believes that it is more likely than not that the Company will fully utilize the capital loss carryover. If the Company is unable to complete the sale of these properties at the

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prices it has estimated to be the fair market value, then a significant portion of the capital loss carryover could expire before it is utilized.

4.	Long-Term Debt

      Our long-term debt as of December 31, 2003 and 2002, is as follows:

			2003				2002
Bank Borrowings			$	15,900,000			$	—
Senior Subordinated Notes due 2009				124,354,783				124,271,973
Senior Subordinated Notes due 2012				200,000,000				200,000,000
	Long-Term Debt		$	340,254,783			$	324,271,973

      Bank Borrowings. At December 31, 2003, we had $15.9 million in outstanding borrowings under our $300.0 million credit facility with a syndicate of ten banks that has a borrowing base of $250.0 million and expires in October 2005. At December 31, 2002, we had no outstanding borrowings under our credit facility. The interest rate is either (a) the lead bank’s prime rate (4.00% at December 31, 2003) 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 $15.9 million borrowed at December 31, 2003, $15.5 million was borrowed at the LIBOR rate plus applicable margin, which averaged 2.41%.

      The terms of our credit facility include, among other restrictions, a limitation on the level of cash dividends (not to exceed $5.0 million in any fiscal year), a remaining aggregate limitation on purchases of our stock of $15.0 million, requirements as to maintenance of certain minimum financial ratios (principally pertaining to working capital, debt, and equity ratios), and limitations on incurring other debt or repurchasing our Senior Subordinated Notes. Since inception, no cash dividends have been declared on our common stock. We are currently in compliance with the provisions of this agreement. The credit facility is secured by our domestic oil and gas properties. We have also pledged 65% of the stock in our two active New Zealand subsidiaries as collateral for this credit facility. The borrowing base is re-determined at least every six months and was reconfirmed by our bank group and increased to $250.0 million effective November 1, 2003, an increase of $55.0 million from the previous level of $195.0 million. We requested that the commitment amount with our bank group be reduced to $150.0 million effective May 9, 2003. Under the terms of the credit facility, we can increase this commitment amount back to the total amount of the borrowing base at our discretion, subject to the terms of the credit agreement. The next scheduled borrowing base review is in May 2004.

      Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $1.6 million in 2003, $3.6 million in 2002, and $5.8 million in 2001. The amount of commitment fees included in interest expense was $0.6 million in both 2003 and 2002 and $0.3 million in 2001.

      Senior Subordinated Notes Due 2009. Our Senior Subordinated Notes due 2009 consist of $125.0 million of 10.25% Senior Subordinated Notes due August 2009. The Senior Subordinated Notes were issued at 99.236% of the principal amount on August 4, 1999, and will mature on August 1, 2009. The Senior Subordinated Notes are unsecured senior subordinated obligations and are subordinated in right of payment to all our existing and future senior debt, including our bank borrowings. Interest on the Senior Subordinated 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 Subordinated Notes are redeemable for cash at the option of Swift, with certain restrictions, at 105.125% of principal, declining to 100% in 2007. Upon certain changes in control of Swift, each holder of Senior Subordinated Notes will

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have the right to require us to repurchase the Senior Subordinated Notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The terms of these Senior Subordinated Notes include, among other restrictions, a limit on repurchases by Swift of its common stock. We are currently in compliance with the provisions of the indenture governing the Senior Subordinated Notes.

      Interest expense on the Senior Subordinated Notes due 2009, including amortization of debt issuance costs and discount, totaled $13.2 million in both 2003 and 2002, and $13.1 million in 2001.

      Senior Subordinated Notes Due 2012. Our Senior Subordinated Notes due 2012 consist of $200.0 million of 9.375% Senior Subordinated Notes due May 2012. The Senior Subordinated Notes were issued on April 11, 2002, and will mature on May 1, 2012. 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 Subordinated Notes is payable semiannually on May 1 and November 1, with the first interest payment on November 1, 2002. On or after May 1, 2007, the Senior Subordinated Notes are redeemable for cash at the option of Swift, with certain restrictions, at 104.688% of principal, declining to 100% in 2010. In addition, prior to May 1, 2005, we may redeem up to 33.33% of the Senior Subordinated Notes with the proceeds of qualified offerings of our equity at 109.375% of the principal amount of the Senior Subordinated Notes, together with accrued and unpaid interest. Upon certain changes in control of Swift, each holder of Senior Subordinated Notes will have the right to require us to repurchase the Senior Subordinated Notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The terms of these Senior Subordinated Notes include, among other restrictions, a limit on repurchases by Swift of its common stock. We are currently in compliance with the provisions of the indenture governing the Senior Subordinated Notes.

      Interest expense on the Senior Subordinated Notes due 2012, including amortization of debt issuance costs and discount, totaled $19.1 million in 2003 and $13.5 million in 2002.

      The aggregate maturities on our long-term debt are $0, $15.9 million, $0, $0, and $0, and $325.0 million for 2004, 2005, 2006, 2007, 2008, and thereafter, respectively.

      We have capitalized interest on our unproved properties in the amount of $6.8 million, $7.0 million, and $6.3 million, in 2003, 2002, and 2001, respectively.

5.	Commitments and Contingencies

      Total rental and lease expenses were $2.2 million in 2003, $1.9 million in 2002, and $1.3 million in 2001 and are included in “General and administrative, net” on our consolidated statements of income. Our remaining minimum annual obligations under non-cancelable operating lease commitments are $2.1 million for 2004, $0.5 million for 2005, $0.2 million for 2006, $0.2 million for 2007, $0.1 million in 2008, and less than $0.1 million thereafter or $3.1 million in the aggregate. The rental and lease expenses and remaining minimum annual obligations under non-cancelable operating lease commitments primarily relate to the lease of our office space in Houston, Texas, and in New Zealand.

      In the ordinary course of business, we have entered into agreements with pipeline operators that require us to contribute a portion of the pipeline construction cost in the event certain transportation volumes are not met. We have $0.1 million accrued in “Accounts payable and accrued liabilities” at December 31, 2003, on the accompanying balance sheet related to these commitments.

      In the ordinary course of business, we have entered into agreements with drilling and seismic contractors for such services. The remaining commitments at December 31, 2003 for these services totaled $5.9 million and these services are expected to be provided in 2004.

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      As of December 31, 2003, we were the managing general partner of six limited partnerships. Because we serve as the general partner of these entities, under state partnership law we are contingently liable for the liabilities of these partnerships, which liabilities are not material for any of the periods presented in relation to the partnerships’ respective assets.

      In the ordinary course of business, we have been party to various legal actions, which arise primarily from our activities as operator of oil and gas wells. In management’s opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on the consolidated financial position or results of operations of Swift.

6.	Stockholders’ Equity

      Common Stock. During the first quarter of 2002, we issued 1.725 million shares of common stock at a price of $18.25 per share. Gross proceeds from this offering were $31.5 million, with issuance costs of $1.0 million.

      Stock-Based Compensation Plans. We have two current stock option plans, the 2001 Omnibus Stock Compensation Plan, which was adopted by our board of directors in February 2001 and was approved by shareholders at the 2001 annual meeting of shareholders, and the 1990 Non-Qualified Stock Option Plan solely for our independent directors. In addition, we have an employee stock purchase plan.

      Under the 2001 plan, incentive stock options and other options and awards may be granted to employees to purchase shares of common stock. Under the 1990 non-qualified plan, non-employee members of our board of directors are automatically granted options to purchase shares of common stock on a formula basis. Both plans provide that the exercise prices equal 100% of the fair value of the common stock on the date of grant. Unless otherwise provided, options become exercisable for 20% of the shares on the first anniversary of the grant of the option and are exercisable for an additional 20% per year thereafter. Options granted expire 10 years after the date of grant or earlier in the event of the optionee’s separation from employment. At the time the stock options are exercised, the option price is credited to common stock and additional paid-in capital.

      The employee stock purchase plan provides eligible employees the opportunity to acquire shares of Swift common stock at a discount through payroll deductions. The plan year is from June 1 to the following May 31. The first year of the plan commenced June 1, 1993. To date, employees have been allowed to authorize payroll deductions of up to 10% of their base salary during the plan year by making an election to participate prior to the start of a plan year. The purchase price for stock acquired under the plan is 85% of the lower of the closing price of our common stock as quoted on the New York Stock Exchange at the beginning or end of the plan year or a date during the year chosen by the participant. Under this plan for the last three years, we have issued 56,574 shares at a price range of $6.80 to $11.85 in 2003, 9,801 shares at a price of $12.47 in 2002, and 22,360 shares at a price of $21.41 in 2001. The estimated weighted average fair value of shares issued under this plan, as determined using the Black-Scholes option-pricing model, was $1.75 in 2003, $1.92 in 2002, and $8.19 in 2001. As of December 31, 2003, 296,053 shares remained available for issuance under this plan.

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      The following is a summary of our stock options under these plans as of December 31, 2003, 2002, and 2001:

		2003								2002								2001
						Weighted Average								Weighted Average								Weighted Average
		Shares				Exercise Price				Shares				Exercise Price				Shares				Exercise Price
Options outstanding, beginning of period			3,018,505			$	16.64				2,639,504			$	17.44				2,076,593			$	11.70
Options granted			504,014			$	13.20				585,055			$	12.32				747,073			$	31.51
Options canceled			(110,901	)		$	21.02				(84,254	)		$	23.37				(31,247	)		$	14.09
Options exercised			(173,007	)		$	8.85				(121,800	)		$	8.61				(152,915	)		$	8.69
Options outstanding, end of period			3,238,611			$	16.37				3,018,505			$	16.64				2,639,504			$	17.44
Options exercisable, end of period			1,714,789			$	15.00				1,480,490			$	13.71				1,181,141			$	11.49
Options available for future grant, end of period			494,925								419,845								1,155,057
Estimated weighted average fair value per share of options granted during the year		$	6.93							$	9.55							$	20.68

      The following table summarizes information about stock options outstanding at December 31, 2003:

		Options Outstanding												Options Exercisable
		Number				Weighted Average								Number
		Outstanding				Remaining				Weighted Average				Exercisable				Weighted Average
Range of Exercise Prices		at 12/31/03				Contractual Life				Exercise Price				at 12/31/03				Exercise Price
$7.00 to $17.99			2,301,259				6.2			$	11.04				1,224,119			$	9.67
$18.00 to $28.99			246,111				4.7			$	22.79				195,911			$	22.88
$29.00 to $41.00			691,241				7.2			$	31.82				294,759			$	31.89
$7.00 to $41.00			3,238,611				6.3			$	16.37				1,714,789			$	15.00

      Employee Stock Ownership Plan. In 1996, we established an Employee Stock Ownership Plan (“ESOP”) effective January 1, 1996. All employees over the age of 21 with one year of service are participants. This plan has a five-year cliff vesting, and service is recognized after the ESOP effective date. The ESOP is designed to enable our employees to accumulate stock ownership. While there will be no employee contributions, participants will receive an allocation of stock that has been contributed by Swift. Compensation expense is reported when such shares are released to employees. The plan may also acquire Swift common stock, purchased at fair market value. The ESOP can borrow money from Swift to buy Swift stock. Benefits will be paid in a lump sum or installments, and the participants generally have the choice of receiving cash or stock. At December 31, 2003, 2002, and 2001, all of the ESOP compensation was earned. Our contribution to the ESOP plan totaled $0.2 million for the years ended December 31, 2003, 2002, and 2001 and are recorded as “General and administrative, net” on the accompanying consolidated statements of income.

      Employee Savings Plan. We have a savings plan under Section 401(k) of the Internal Revenue Code. Eligible employees may make voluntary contributions into the 401(k) savings plan with Swift contributing on behalf of the eligible employee an amount equal to 100% of the first 2% of compensation and 75% of the next 4% of compensation based on the contributions made by the eligible employees. Our contributions to the 401(k) savings plan were $0.6 million for each of the years ended December 31, 2003, 2002, and 2001 and are recorded as “General and administrative, net” on the accompanying consolidated statements of income. The contributions in 2003, 2002, and 2001 were made all in common stock. The

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shares of common stock contributed to the 401(k) savings plan totaled 34,280, 64,490, and 28,798 shares for the 2003, 2002, and 2001 contributions, respectively.

      Common Stock Repurchase Program. In March 1997, our board of directors approved a common stock repurchase program that terminated as of June 30, 1999. Under this program, we spent approximately $13.3 million to acquire 927,774 shares in the open market at an average cost of $14.34 per share. At December 31, 2003, 527,018 shares remain in treasury (net of 400,756 shares used to fund ESOP, 401(k) contributions and acquisitions) with a total cost of $7.6 million and are included in “Treasury stock held, at cost” on the balance sheet.

      Shareholder Rights Plan. In August 1997, the board of directors declared a dividend of one preferred share purchase right on each outstanding share of Swift common stock. The rights are not currently exercisable but would become exercisable if certain events occurred relating to any person or group acquiring or attempting to acquire 15% or more of our outstanding shares of common stock. Thereafter, upon certain triggers, each right not owned by an acquirer allows its holder to purchase Swift securities with a market value of two times the $150 exercise price.

7.	Related-Party Transactions

      We are the operator of a number of properties owned by our affiliated limited partnerships and, accordingly, charge these entities operating fees. In accordance with the partnership agreements, operating fees charged to the partnerships in 2003, 2002, and 2001 totaled approximately $0.2 million, $0.3 million, and $1.0 million, respectively, and are recorded as reductions in general and administrative expense and oil and gas production expense. We are also reimbursed for direct, administrative, and overhead costs incurred in conducting the business of the limited partnerships, which totaled approximately $0.4 million, $1.0 million, and $3.1 million in 2003, 2002, and 2001, respectively. In partnerships in which the limited partners have voted to sell their remaining properties and liquidate their limited partnerships, we are also reimbursed for direct, administrative, and overhead costs incurred in the disposition of such properties, totaling less than $0.1 million, $0.5 million, and $2.4 million in 2003, 2002, and 2001, respectively.

8.	Foreign Activities

      As of December 31, 2003, our gross capitalized oil and gas property costs in New Zealand totaled approximately $205.3 million. Approximately $169.5 million has been included in the proved properties portion of our oil and gas properties, while $35.8 million is included as unproved properties. Our functional currency in New Zealand is the U.S. Dollar.

9.	Acquisitions and Dispositions

	New Zealand

      Through our subsidiary, Swift Energy New Zealand Limited (“SENZ”), we acquired Southern Petroleum (NZ) Exploration Limited (“Southern NZ”) in January 2002 for approximately $51.4 million in cash. We allocated $36.1 million of the acquisition price to “Proved properties,” $10.0 million to “Unproved properties,” $4.9 million to “Deferred income taxes,” and $0.4 million to “Other current assets” on our Consolidated Balance Sheet. Southern NZ was an affiliate of Shell New Zealand and owns interests in four onshore producing oil and gas fields, hydrocarbon processing facilities, and pipelines connecting the fields and facilities to export terminals and markets. These assets fit strategically with our existing assets in New Zealand. This acquisition was accounted for by the purchase method of accounting. The revenues and expenses from these TAWN properties have been included in our consolidated statements of income from the date of acquisition forward. In conjunction with this TAWN acquisition, we granted Shell New Zealand a short-term option to acquire an undivided 25% interest in our permit 38719,

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which included our Rimu and Kauri areas and the Rimu Production Station. This option was not exercised and expired on May 15, 2002.

      In March 2002, we purchased through our subsidiary, SENZ, all of the New Zealand assets owned by Antrim for 220,000 shares of Swift Energy common stock valued at $4.2 million and an effective date adjustment of approximately $0.5 million for total consideration of $4.7 million. Antrim owned a 5% interest in permit 38719 and a 7.5% interest in permit 38716.

      In September 2002, we purchased through our subsidiary, SENZ, Bligh’s 5% working interest in permit 38719 and 5% interest in the Rimu petroleum mining permit 38151, along with their 3.24% working interest in the four TAWN petroleum mining licenses for 300,000 shares of Swift Energy common stock valued at $3.9 million and $2.7 million in cash for total consideration of $6.6 million.

	Russia

      In 1993, we entered into a Participation Agreement with Senega, a Russian Federation joint stock company, to assist in the development and production of reserves from two fields in Western Siberia and received a 5% net profits interest. We also purchased a 1% net profits interest. Our investment in Russia was fully impaired in the third quarter of 1998. In March 2002, we received $7.5 million for our investment in Russia. Although the proceeds from sales of oil and gas properties are generally treated as a reduction of oil and gas property costs, because we had previously charged to expense all $10.8 million of cumulative costs relating to our Russian activities, this cash payment, net of transaction expenses, resulted in recognition of a $7.3 million non-recurring gain on asset disposition in the first quarter of 2002.

10.	Segment Information

      The Company has two reportable segments that are in the business of crude oil and natural gas exploration and production. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on profit or loss from oil and gas operations before other revenues, general and administrative expenses, and interest expense, net. The Company’s reportable segments are managed separately based on their geographic locations. Financial information by operating segment is presented below:

			2003
			Domestic				New Zealand				Total
Oil and gas sales			$	164,167,390			$	46,865,249			$	211,032,639
Costs and Expenses:
	Depreciation, depletion, and amortization			(44,645,939	)			(18,426,118	)			(63,072,057	)
	Accretion of asset retirement obligation			(623,948	)			(233,408	)			(857,356	)
	Oil and gas production			(39,313,081	)			(13,553,721	)			(52,866,802	)
Income from oil and gas operations			$	79,584,422			$	14,652,002			$	94,236,424
	Other revenues(1)											(2,131,656	)
	General and administrative, net											(14,097,066	)
	Interest expense, net											(27,268,524	)
	Income before Income Taxes and Cumulative Effect of Change in Accounting Principle										$	50,739,178
Property and Equipment, net			$	642,019,661			$	174,440,115			$	816,459,776

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			2002
			Domestic				New Zealand				Total
Oil and gas sales			$	112,065,003			$	29,130,710			$	141,195,713
Costs and Expenses:
	Depreciation, depletion, and amortization			(43,660,843	)			(12,563,549	)			(56,224,392	)
	Oil and gas production			(33,088,958	)			(8,408,354	)			(41,497,312	)
Income from oil and gas operations			$	35,315,202			$	8,158,807			$	43,474,009
	Other revenues(1)											8,774,098
	General and administrative, net											(10,564,849	)
	Interest expense, net											(23,274,969	)
Income before Income Taxes and Cumulative Effect of Change in Accounting Principle											$	18,408,289
Property and Equipment, net			$	565,149,393			$	160,360,061			$	725,509,454

			2001
			(Unaudited)				(Unaudited)
			Domestic				New Zealand				Total
Oil and gas sales			$	179,360,844			$	1,823,791			$	181,184,635
Costs and Expenses:
	Depreciation, depletion, and amortization			(59,318,768	)			(183,272	)			(59,502,040	)
	Oil and gas production			(36,554,418	)			(165,191	)			(36,719,609	)
	Write-down of oil and gas properties			(98,862,247	)			—				(98,862,247	)
Income from oil and gas operations			$	(15,374,589	)		$	1,475,328			$	(13,899,261	)
	Other revenues(1)											2,622,855
	General and administrative, net											(8,186,654	)
	Other expenses											(2,102,251	)
	Interest expense, net											(12,627,022	)
Income before Income Taxes and Cumulative Effect of Change in Accounting Principle											$	(34,192,333	)
Property and Equipment, net			$	547,232,724			$	83,975,947			$	631,208,671

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(1)	Other revenues consist of Fees from affiliated limited partnerships, Interest income, Gain on asset disposition, Price-risk management and other, net, on the accompanying consolidated statements of income.

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SUPPLEMENTAL INFORMATION (UNAUDITED)

      Capitalized Costs. The following table presents our aggregate capitalized costs relating to oil and gas producing activities and the related depreciation, depletion, and amortization:

			Total				Domestic				New Zealand
December 31, 2003:
	Proved oil and gas properties		$	1,305,763,355			$	1,136,267,890			$	169,495,465
	Unproved oil and gas properties			67,557,969				31,802,621				35,755,348
				1,373,321,324				1,168,070,511				205,250,813
	Accumulated depreciation, depletion, and amortization			(560,961,013	)			(529,272,658	)			(31,688,355	)
	Net capitalized costs		$	812,360,311			$	638,797,853			$	173,562,458
December 31, 2002:
	Proved oil and gas properties		$	1,150,633,802			$	1,005,583,492			$	145,050,310
	Unproved oil and gas properties			69,603,481				41,850,890				27,752,591
				1,220,237,283				1,047,434,382				172,802,901
	Accumulated depreciation, depletion, and amortization			(498,619,342	)			(485,289,654	)			(13,329,688	)
	Net capitalized costs		$	721,617,941			$	562,144,728			$	159,473,213

      Of the $31,802,621 of domestic unproved property costs (primarily seismic and lease acquisition costs) at December 31, 2003, excluded from the amortizable base, $8,350,017 was incurred in 2003, $7,952,698 was incurred in 2002, $7,294,531 was incurred in 2001, and $8,205,375 was incurred in prior years. When we are in an active drilling mode, we evaluate the majority of these unproved costs within a two to four year time frame.

      Of the $35,755,348 of New Zealand unproved property costs at December 31, 2003, excluded from the amortizable base, $9,309,694 was incurred in 2003, $17,593,162 was incurred or acquired in 2002, $2,644,091 was incurred in 2001, and $6,208,401 was incurred in prior years. We expect to continue drilling in New Zealand to delineate our prospects there within a two to four year time frame.

      Capitalized asset retirement obligations have been included in the proved properties as of December 31, 2003, as we adopted SFAS No. 143 “Accounting for Asset Retirement Obligations” effective January 1, 2003.

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      Costs Incurred. The following table sets forth costs incurred related to our oil and gas operations:

			Year Ended December 31, 2003
			Total				Domestic				New Zealand
Acquisition of proved properties			$	1,942,868			$	1,635,316			$	307,552
Lease acquisitions(1)				18,869,099				12,440,144				6,428,955
Exploration				14,467,455				11,789,700				2,677,755
Development				116,451,112				100,549,351				15,901,761
	Total acquisition, exploration, and development(2)		$	151,730,534			$	126,414,511			$	25,316,023
Processing plants			$	6,192,199			$	907,771			$	5,284,428
Field compression facilities				3,521,522				3,521,522				—
	Total plants and facilities		$	9,713,721			$	4,429,293			$	5,284,428
Total costs incurred(3)			$	161,444,255			$	130,843,804			$	30,600,451

			Year Ended December 31, 2002
			Total				Domestic				New Zealand
Acquisition of proved properties			$	64,229,283			$	5,415,932			$	58,813,351
Lease acquisitions(1)				16,009,939				10,789,876				5,220,063
Exploration				18,395,335				7,571,215				10,824,120
Development				47,407,087				40,366,378				7,040,709
	Total acquisition, exploration, and development(2)		$	146,041,644			$	64,143,401			$	81,898,243
Processing plants			$	7,845,520			$	1,313,299			$	6,532,221
Field compression facilities				2,251,247				2,251,247				—
	Total plants and facilities		$	10,096,767			$	3,564,546			$	6,532,221
Total costs incurred			$	156,138,411			$	67,707,947			$	88,430,464

			Year Ended December 31, 2001
			Total				Domestic				New Zealand
Acquisition of proved properties			$	41,286,539			$	40,491,203			$	795,336
Lease acquisitions(1)				31,225,493				25,688,068				5,537,425
Exploration				41,981,536				35,944,405				6,037,131
Development				132,246,713				112,597,856				19,648,857
	Total acquisition, exploration, and development(2)		$	246,740,281			$	214,721,532			$	32,018,749
Processing plants			$	23,331,095			$	817,454			$	22,513,641
Field compression facilities				319,703				319,703				—
	Total plants and facilities		$	23,650,798			$	1,137,157			$	22,513,641
Total costs incurred			$	270,391,079			$	215,858,689			$	54,532,390

---

(1)	These are actual amounts as incurred by year, including both proved and unproved lease costs. The annual lease acquisition amounts added to proved oil and gas properties in 2003, 2002, and 2001 were $20,702,276, $23,454,234, and $22,470,263, respectively.
(2)	Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $11.5 million, $10.7 million, and $11.6 million in 2003, 2002, and 2001, respectively. In addition, total includes $6.9 million, $7.0, and $6.3 million in 2003, 2002, and 2001, respectively, of capitalized interest on unproved properties.
(3)	Asset retirement obligations incurred during 2003 have been included in exploration and development costs as applicable for the year ended December 31, 2003, as we adopted SFAS No. 143 “Accounting for Asset Retirement Obligations” effective January 1, 2003.

F-27

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SWIFT ENERGY COMPANY AND SUBSIDIARIES

Results of Operations.

		Year Ended December 31, 2003
		Total				Domestic				New Zealand
Oil and gas sales		$	211,032,639			$	164,167,390			$	46,865,249
Oil and gas production costs			(52,866,802	)			(39,313,081	)			(13,553,721	)
Depreciation and depletion			(62,037,680	)			(43,818,709	)			(18,218,971	)
Accretion of asset retirement obligation			(857,356	)			(623,948	)			(233,408	)
			95,270,801				80,411,652				14,859,149
Provision for income taxes			32,321,635				29,696,023				2,625,612
Results of producing activities		$	62,949,166			$	50,715,629			$	12,233,537
Amortization per physical unit of production (equivalent Mcf of gas)		$	1.17			$	1.30			$	0.94

		Year Ended December 31, 2002
		Total				Domestic				New Zealand
Oil and gas sales		$	141,195,713			$	112,065,003			$	29,130,710
Oil and gas production costs			(41,497,312	)			(33,088,958	)			(8,408,354	)
Depreciation and depletion			(55,254,467	)			(42,807,364	)			(12,447,103	)
			44,443,934				36,168,681				8,275,253
Provision for income taxes			15,860,064				13,129,231				2,730,833
Results of producing activities		$	28,583,870			$	23,039,450			$	5,544,420
Amortization per physical unit of production (equivalent Mcf of gas)		$	1.11			$	1.25			$	0.80

		Year Ended December 31, 2001
		Total				Domestic				New Zealand
Oil and gas sales		$	181,184,635			$	179,360,844			$	1,823,791
Oil and gas production costs			(36,719,609	)			(36,554,418	)			(165,191	)
Depreciation and depletion			(58,589,116	)			(58,417,637	)			(171,479	)
Write-down of oil and gas properties			(98,862,247	)			(98,862,247	)			—
			(12,986,337	)			(14,473,458	)			1,487,121
Provision (benefit) for income taxes			(4,647,810	)			(5,138,560	)			490,750
Results of producing activities		$	(8,338,527	)		$	(9,334,898	)		$	996,371
Amortization per physical unit of production (equivalent Mcf of gas)		$	1.31				1.32				0.34

      These results of operations do not include the losses (gains) from our hedging activities of $2.8 million, $0.2 million and ($1.2) million for 2003, 2002 and 2001, respectively.

      The accretion of asset retirement obligation has been included in the 2003 period, as we adopted SFAS No. 143 “Accounting for Asset Retirement Obligations” effective January 1, 2003.

      We used our effective tax rate in each country to compute the provision for income taxes in each year presented.

F-28

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SWIFT ENERGY COMPANY AND SUBSIDIARIES

      Supplemental Reserve Information. The following information presents estimates of our proved oil and gas reserves. Reserves were determined by us and audited by H. J. Gruy and Associates, Inc. (“Gruy”), independent petroleum consultants. Gruy’s audit was conducted according to standards approved by the Board of Directors of the Society of Petroleum Engineers, Inc. and included examination, on a test basis, of the evidence supporting our reserves. Gruy’s audit was based upon review of production histories and other geological, economic, and engineering data provided by Swift. Where Gruy had material disagreements with Swift reserve estimates, we revised our estimates to be in agreement. Gruy’s report dated January 23, 2004, is set forth as an exhibit to the Form 10-K Report for the year ended December 31, 2003, and includes definitions and assumptions that served as the basis for the audit of proved reserves and future net cash flows. Such definitions and assumptions should be referred to in connection with the following information:

	Estimates of Proved Reserves

			Total								Domestic								New Zealand
							Oil, NGL,								Oil, NGL,								Oil, NGL,
							and								and								and
			Natural Gas				Condensate				Natural Gas				Condensate				Natural Gas				Condensate
			(Mcf)				(Bbls)				(Mcf)				(Bbls)				(Mcf)				(Bbls)
Proved reserves as of December 31, 2000				418,613,976				35,133,596				363,300,499				23,942,709				55,313,477				11,190,887
	Revisions of previous estimates(1)			(122,127,541	)			5,621,556				(101,693,477	)			8,460,690				(20,434,064	)			(2,839,134	)
	Purchases of minerals in place			10,038,803				7,430,591				10,038,803				7,430,591				—				—
	Sales of minerals in place			(7,508,064	)			(555,586	)			(7,508,064	)			(555,586	)			—				—
	Extensions, discoveries, and other additions			52,353,909				8,907,852				50,810,697				6,257,441				1,543,212				2,650,411
	Production			(26,458,958	)			(3,055,373	)			(26,458,958	)			(2,971,112	)			—				(84,261	)
Proved reserves as of December 31, 2001				324,912,125				53,482,636				288,489,500				42,564,733				36,422,625				10,917,903
	Revisions of previous estimates(1)			(29,972,714	)			5,298,439				(29,470,419	)			8,675,082				(502,295	)			(3,376,643	)
	Purchases of minerals in place			51,940,044				3,711,948				226,245				24,207				51,713,799				3,687,741
	Sales of minerals in place			(3,839,124	)			(464,490	)			(3,839,124	)			(464,490	)			—				—
	Extensions, discoveries, and other additions			10,822,919				12,180,558				197,919				11,304,782				10,625,000				875,776
	Production			(27,131,578	)			(3,770,128	)			(15,780,059	)			(3,074,674	)			(11,351,519	)			(695,454	)
Proved reserves as of December 31, 2002				326,731,672				70,438,963				239,824,062				59,029,640				86,907,610				11,409,323
	Revisions of previous estimates(1)			(6,445,114	)			4,975,920				(1,418,312	)			3,497,022				(5,026,802	)			1,478,898
	Purchases of minerals in place			273,623				35,472				273,623				35,472				—				—
	Sales of minerals in place			(3,984,209	)			(228,505	)			(3,984,209	)			(228,505	)			—				—
	Extensions, discoveries, and other additions			47,231,609				9,730,665				21,370,151				8,018,766				25,861,458				1,711,899
	Production			(28,002,719	)			(4,192,612	)			(13,744,040	)			(3,336,702	)			(14,258,679	)			(855,910	)
Proved reserves as of December 31, 2003				335,804,862				80,759,903				242,321,275				67,015,693				93,483,587				13,744,210
Proved developed reserves:(2)
	December 31, 2000			215,169,833				10,980,196				215,169,833				10,980,196				—				—
	December 31, 2001			181,651,578				23,759,574				167,401,736				20,393,142				14,249,842				3,366,432
	December 31, 2002			233,514,572				35,928,395				149,731,562				26,530,112				83,783,010				9,398,283
	December 31, 2003			210,119,927				45,525,366				138,173,341				38,767,983				71,946,586				6,757,383

---

(1)

Revisions of previous estimates are related to upward or downward variations based on current engineering information for production rates, volumetrics, and reservoir pressure. Additionally, changes in quantity estimates are affected by the increase or decrease in crude oil, NGL, and natural gas prices at each year-end. Proved reserves, as of December 31, 2003, were based upon hedge adjusted prices in effect at year-end. Our hedges at year-end 2003 consisted of natural gas price floors with strike prices

F-29

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SWIFT ENERGY COMPANY AND SUBSIDIARIES

	lower than the period end price and thus did not affect prices used in these calculations. The weighted average of 2003 year-end prices for total, domestic, and New Zealand were $4.56, $5.53, and $2.04 per Mcf of natural gas, $30.16, $30.88, and $26.78 per barrel of oil, and $20.61, $21.81 and $14.10 per barrel of NGL, respectively. This compares to $3.49, $4.23, and $1.48 per Mcf, $29.27, $29.36, and $28.80 per barrel of oil, and $16.54, $17.30 and $12.24 per barrel of NGL as of December 31, 2002, for total, domestic, and New Zealand, respectively. The weighted average of 2001 year-end prices for total, domestic, and New Zealand were $2.51, $2.68, and $1.18 per Mcf of natural gas, $18.45, $18.51, and $18.25 per barrel of oil, and $10.70, $11.00, and $8.90 per barrel of NGL, respectively.
(2)	At December 31, 2003, 59% of our reserves were proved developed, compared to 60% at December 31, 2002, 50% at December 31, 2001, and 45% at December 31, 2000.

F-30

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SWIFT ENERGY COMPANY AND SUBSIDIARIES

     Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:

		Year Ended December 31, 2003
		Total				Domestic				New Zealand
Future gross revenues		$	3,805,349,886			$	3,279,884,680			$	525,465,206
Future production costs			(831,430,479	)			(678,983,441	)			(152,447,038	)
Future development costs			(331,816,723	)			(301,874,087	)			(29,942,636	)
Future net cash flows before income taxes			2,642,102,684				2,299,027,152				343,075,532
Future income taxes			(729,624,048	)			(657,354,849	)			(72,269,199	)
Future net cash flows after income taxes			1,912,478,636				1,641,672,303				270,806,333
Discount at 10% per annum			(777,622,101	)			(678,769,827	)			(98,852,274	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		$	1,134,856,535			$	962,902,476			$	171,954,059

		Year Ended December 31, 2002
		Total				Domestic				New Zealand
Future gross revenues		$	2,990,669,570			$	2,578,435,576			$	412,233,994
Future production costs			(720,599,745	)			(612,094,088	)			(108,505,657	)
Future development costs			(224,792,520	)			(208,492,520	)			(16,300,000	)
Future net cash flows before income taxes			2,045,277,305				1,757,848,968				287,428,337
Future income taxes			(599,195,484	)			(512,966,321	)			(86,229,163	)
Future net cash flows after income taxes			1,446,081,821				1,244,882,647				201,199,174
Discount at 10% per annum			(609,212,030	)			(540,375,347	)			(68,836,683	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		$	836,869,791			$	704,507,300			$	132,362,491

		Year Ended December 31, 2001
		Total				Domestic				New Zealand
Future gross revenues		$	1,706,475,138			$	1,485,480,927			$	220,994,211
Future production costs			(483,588,857	)			(436,141,429	)			(47,447,428	)
Future development costs			(198,172,628	)			(185,347,628	)			(12,825,000	)
Future net cash flows before income taxes			1,024,713,653				863,991,870				160,721,783
Future income taxes			(261,635,331	)			(208,726,729	)			(52,908,602	)
Future net cash flows after income taxes			763,078,322				655,265,141				107,813,181
Discount at 10% per annum			(308,520,417	)			(274,882,174	)			(33,638,243	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		$	454,557,905			$	380,382,967			$	74,174,938

F-31

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SWIFT ENERGY COMPANY AND SUBSIDIARIES

      The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

	1. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.
	2. The estimated future gross revenues of proved reserves are priced on the basis of year-end prices, except in those instances where fixed and determinable gas price escalations are covered by contracts limited to the price we reasonably expect to receive.
	3. The future gross revenue streams are reduced by estimated future costs to develop and to produce the proved reserves, as well as asset retirement obligation costs, net of salvage value, based on year-end cost estimates and the estimated effect of future income taxes.
	4. Future income taxes are computed by applying the statutory tax rate to future net cash flows reduced by the tax basis of the properties, the estimated permanent differences applicable to future oil and gas producing activities, and tax carry forwards.

      The estimates of cash flows and reserves quantities shown above are based on year-end hedge adjusted oil and gas prices for each period and do not include the effects of our hedging activities. Our hedges at year-end 2003 consisted of natural gas price floors with strike prices lower than the period end price and thus did not affect prices used in these calculations. Subsequent changes to such year-end oil and gas prices could have a significant impact on discounted future net cash flows. Under Securities and Exchange Commission rules, companies that follow the full-cost accounting method are required to make quarterly Ceiling Test calculations using hedge adjusted prices in effect as of the period end date presented (see Note 1 to the Consolidated Financial Statements). Application of these rules during periods of relatively low oil and gas prices, even if of short-term seasonal duration, may result in non-cash write-downs.

      The standardized measure of discounted future net cash flows is not intended to present the fair market value of our oil and gas property reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment, and the risks inherent in reserves estimates.

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SWIFT ENERGY COMPANY AND SUBSIDIARIES

      The following are the principal sources of change in the standardized measure of discounted future net cash flows:

			Year Ended December 31,
			2003				2002				2001
Beginning balance			$	836,869,791			$	454,557,905			$	1,577,958,466
Revisions to reserves proved in prior years –
	Net changes in prices, production costs, and future development costs			109,501,730				373,890,614				(1,692,627,074	)
	Net changes due to revisions in quantity estimates			48,194,999				2,582,633				(93,669,181	)
	Accretion of discount			116,136,717				60,298,619				231,325,481
	Other			(57,822,716	)			(88,675,455	)			(204,768,815	)
Total revisions				216,010,730				348,096,411				(1,759,739,589	)
New field discoveries and extensions, net of future production and development costs				243,183,114				190,461,371				110,213,160
Purchases of minerals in place				1,019,290				76,538,437				39,544,163
Sales of minerals in place				(13,660,012	)			(5,769,642	)			(50,131,970	)
Sales of oil and gas produced, net of production costs				(158,165,836	)			(99,698,403	)			(144,262,145	)
Previously estimated development costs incurred				77,404,994				48,752,814				94,107,760
Net change in income taxes				(67,805,536	)			(176,069,102	)			586,868,060
Net change in standardized measure of discounted future net cash flows				297,986,744				382,311,886				(1,123,400,561	)
Ending balance			$	1,134,856,535			$	836,869,791			$	454,557,905

      Quarterly Data (Unaudited). The following table presents summarized quarterly financial information for the years ended December 31, 2002 and 2003:

							Income Before												Basic EPS				Diluted EPS
							Income Taxes,				Income Before								Income Before				Income Before
							and Change				Change in								Change In				Change In
							in Accounting				Accounting								Accounting				Accounting				Basic EPS				Diluted EPS
			Revenues				Principle(2)				Principle(2)				Net Income				Principle(2)				Principle(2)				Net Income				Net Income
2002:
First(1)			$	34,354,077			$	4,674,075			$	3,019,810			$	3,019,810			$	0.12			$	0.12			$	0.12			$	0.12
Second				38,570,269				5,518,886				3,584,092				3,584,092				0.13				0.13				0.13				0.13
Third				36,570,809				2,933,350				1,947,006				1,947,006				0.07				0.07				0.07				0.07
Fourth				40,474,656				5,281,978				3,372,319				3,372,319				0.12				0.12				0.12				0.12
	Total		$	149,969,811			$	18,408,289			$	11,923,227			$	11,923,227			$	0.45			$	0.45			$	0.45			$	0.45
2003:
First			$	53,499,993			$	16,223,744			$	10,484,937			$	6,108,085			$	0.38			$	0.38			$	0.22			$	0.22
Second				50,717,529				11,073,804				7,221,426				7,221,426				0.26				0.26				0.26				0.26
Third				51,552,522				11,153,368				7,062,625				7,062,625				0.26				0.26				0.26				0.26
Fourth				53,130,939				12,288,262				9,501,676				9,501,676				0.35				0.34				0.35				0.34
	Total		$	208,900,983			$	50,739,178			$	34,270,664			$	29,893,812			$	1.25			$	1.24			$	1.09			$	1.08

(1)	First quarter 2002 results include a gain on asset disposition of $7,332,668.
(2)	There were no extraordinary items in 2002 or 2003.

     The sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share as each quarterly computation is based on the weighted average number of common shares outstanding during that period. In addition, certain potentially dilutive securities were not included in certain of the quarterly computations of diluted net income per common share because to do so would have been antidilutive.

F-33

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CONSOLIDATED BALANCE SHEETS

SWIFT ENERGY COMPANY

									December 31,
					March 31, 2004				2003
					(Unaudited)
ASSETS
Current Assets:
	Cash and cash equivalents				$	4,398,581			$	1,066,280
	Accounts receivable —
		Oil and gas sales				27,201,434				26,082,650
		Joint interest owners				1,942,313				1,350,707
	Other current assets					6,959,951				4,957,647
			Total Current Assets			40,502,279				33,457,284
Property and Equipment:
	Oil and gas, using full-cost accounting
		Proved properties being amortized				1,341,732,893				1,305,763,355
		Unproved properties not being amortized				67,625,981				67,557,969
						1,409,358,874				1,373,321,324
	Furniture, fixtures, and other equipment					10,936,689				10,602,786
						1,420,295,563				1,383,924,110
	Less — Accumulated depreciation, depletion, and amortization					(585,839,389	)			(567,464,334	)
						834,456,174				816,459,776
Other Assets:
	Deferred income taxes					3,663,957				1,905,909
	Debt issuance costs					7,746,868				8,015,575
						11,410,825				9,921,484
					$	886,369,278			$	859,838,544
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
	Accounts payable and accrued liabilities				$	16,434,311			$	25,450,477
	Accrued capital costs					22,725,804				29,417,542
	Accrued interest					10,072,226				8,748,656
	Undistributed oil and gas revenues					6,639,926				4,939,667
		Total Current Liabilities				55,872,267				68,556,342
Long-Term Debt						356,876,926				340,254,783
Deferred Income Taxes						49,425,159				43,498,682
Asset Retirement Obligation						10,367,979				10,137,473
Commitments and Contingencies
Stockholders’ Equity:
	Preferred stock, $.01 par value, 5,000,000 shares authorized, none outstanding					—				—
	Common stock, $.01 par value, 85,000,000 shares authorized, 28,102,324 and 28,011,109 shares issued, and 27,621,456 and 27,484,091 shares outstanding, respectively					281,023				280,111
	Additional paid-in capital					336,050,367				334,865,204
	Treasury stock held, at cost, 480,868 and 527,018 shares, respectively					(6,896,245	)			(7,558,093	)
	Retained earnings					84,661,238				70,073,384
	Other comprehensive loss, net of taxes					(269,436	)			(269,342	)
						413,826,947				397,391,264
					$	886,369,278			$	859,838,544

See accompanying notes to consolidated financial statements.

F-34

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CONSOLIDATED STATEMENTS OF INCOME

SWIFT ENERGY COMPANY

					Three Months Ended
					March 31,				March 31,
					2004				2003
Revenues:
	Oil and gas sales				$	65,953,770			$	54,850,299
	Price-risk management and other, net					(598,040	)			(1,350,306	)
						65,355,730				53,499,993
Costs and Expenses:
	General and administrative, net					4,029,674				3,556,548
	Depreciation, depletion and amortization					18,295,684				14,911,763
	Accretion of asset retirement obligation					170,476				215,383
	Lease operating costs					9,625,980				7,313,104
	Severance and other taxes					6,246,559				4,594,549
	Interest expense, net					6,901,175				6,684,902
						45,269,548				37,276,249
Income Before Income Taxes and Cumulative Effect of Change in Accounting Principle						20,086,182				16,223,744
Provision for Income Taxes						5,498,328				5,738,807
Income Before Cumulative Effect of Change in Accounting Principle						14,587,854				10,484,937
Cumulative Effect of Change in Accounting Principle (net of taxes)						—				4,376,852
			Net Income		$	14,587,854			$	6,108,085
Per share amounts —
	Basic:
		Income Before Cumulative Effect of Change in Accounting Principle			$	0.53			$	0.38
		Cumulative Effect of Change in Accounting Principle				—				(0.16	)
			Net Income		$	0.53			$	0.22
	Diluted:
		Income Before Cumulative Effect of Change in Accounting Principle			$	0.52			$	0.38
		Cumulative Effect of Change in Accounting Principle				—				(0.16	)
			Net Income		$	0.52			$	0.22
Weighted Average Shares Outstanding						27,552,827				27,243,142

See accompanying notes to consolidated financial statements.

F-35

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

SWIFT ENERGY COMPANY

																			Accumulated
							Additional												Other
			Common				Paid-in				Treasury				Retained				Comprehensive
			Stock(1)				Capital				Stock				Earnings				Loss				Total
Balance, December 31, 2002			$	278,116			$	333,543,471			$	(8,749,922	)		$	40,179,572			$	(178,053	)		$	365,073,184
	Stock issued for benefit plans (83,201 shares)			1				(408,178	)			1,191,829				—				—				783,652
	Stock options exercised (142,807 shares)			1,428				1,315,964				—				—				—				1,317,392
	Employee stock purchase plan (56,574 shares)			566				413,947				—				—				—				414,513
Comprehensive income:
	Net income			—				—				—				29,893,812				—				29,893,812
	Change in fair value of cash flow hedges, net of income tax																			(91,289	)			(91,289	)
Total comprehensive income				—				—				—				—				—				29,802,523
Balance, December 31, 2003			$	280,111			$	334,865,204			$	(7,558,093	)		$	70,073,384			$	(269,342	)		$	397,391,264
	Stock issued for benefit plans (46,150 shares)(2)			—				166,298				661,848				—				—				828,146
	Stock options exercised (91,215 shares)(2)			912				1,018,865				—				—				—				1,019,777
Comprehensive income:
	Net income(2)			—				—				—				14,587,854				—				14,587,854
	Change in fair value of cash flow hedges, net of income tax(2)			—				—				—				—				(94	)			(94	)
	Total comprehensive income(2)																							14,587,760
Balance, March 31, 2004(2)			$	281,023			$	336,050,367			$	(6,896,245	)		$	84,661,238			$	(269,436	)		$	413,826,947

---

(1)	$.01 par value
(2)	Unaudited

See accompanying notes to consolidated financial statements.

F-36

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CONSOLIDATED STATEMENTS OF CASH FLOWS

SWIFT ENERGY COMPANY

						Period Ended March 31,
						2004				2003
Cash Flows From Operating Activities:
	Net income					$	14,587,854			$	6,108,085
	Adjustments to reconcile net income to net cash provided by operating activities —
		Cumulative effect of change in accounting principle					—				4,376,852
		Depreciation, depletion, and amortization					18,295,684				14,911,763
		Accretion of asset retirement obligation					170,476				215,383
		Deferred income taxes					5,434,312				5,738,807
		Other					274,125				291,780
		Change in assets and liabilities —
			Increase in accounts receivable				(2,021,976	)			(7,076,900	)
			Increase in accounts payable and accrued liabilities				1,531,695				747,167
			Increase in accrued interest				1,323,570				1,485,861
				Net Cash Provided by Operating Activities			39,595,740				26,798,798
Cash Flows From Investing Activities:
	Additions to property and equipment						(45,149,834	)			(26,335,122	)
	Proceeds from the sale of property and equipment						23,255				551,263
	Net cash distributed as operator of oil and gas properties						(8,707,560	)			(5,889,986	)
	Net cash received (distributed) as operator of partnerships and joint ventures						105,566				(286,935	)
	Other						(934	)			(35,839	)
				Net Cash Used in Investing Activities			(53,729,507	)			(31,996,619	)
Cash Flows From Financing Activities:
	Net proceeds from bank borrowings						16,600,000				5,700,000
	Net proceeds from issuances of common stock						866,068				—
				Net Cash Provided by Financing Activities			17,466,068				5,700,000
Net Increase in Cash and Cash Equivalents							3,332,301				502,179
Cash and Cash Equivalents at Beginning of Period							1,066,280				3,816,107
Cash and Cash Equivalents at End of Period						$	4,398,581			$	4,318,286
Supplemental disclosures of cash flows information:
Cash paid during period for interest, net of amounts capitalized						$	5,300,358			$	4,939,154
Cash paid during period for income taxes						$	—			$	—

See accompanying notes to consolidated financial statements.

F-37

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SWIFT ENERGY COMPANY

(1)	General Information

      The consolidated financial statements included herein have been prepared by Swift Energy Company and are unaudited, except for the consolidated balance sheet at December 31, 2003 and consolidated statement of stockholders’ equity for the year ended December 31, 2003, 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. Certain reclassifications have been made to prior period financial information to conform to the current period presentation. The 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 exploration, development, and acquisition of oil and gas reserves are capitalized. Under the full-cost method of accounting, such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended March 31, 2004 and 2003, such capitalized internal costs totaled $2.9 million and $3.0 million, respectively. Interest costs are also capitalized to unproved oil and gas properties. For the three months ended March 31, 2004 and 2003, capitalized interest on our unproved properties totaled $1.6 million and $1.8 million, respectively. Interest not capitalized and 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 involving a significant amount of reserves or where the proceeds from the sale of oil and gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.

      Future development costs are estimated property-by-property based on current economic conditions and are amortized to expense as our capitalized oil and gas property costs are amortized.

      We compute the provision for depreciation, depletion, and amortization of oil and gas properties by 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 costs, gas processing facilities and capitalized asset retirement obligations, 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 at the beginning of the period. This calculation is done on a country-by-country basis. Furniture, fixtures, and other equipment are depreciated by the straight-line method at rates based on the estimated useful lives of the property. Repairs and maintenance are charged to expense as incurred. Renewals and betterments are capitalized.

F-38

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SWIFT ENERGY COMPANY

      Geological and geophysical (G&G) costs incurred on developed properties are recorded in Proved Property and therefore subject to amortization. In exploration areas, G&G costs are capitalized in Unproved Property and evaluated as part of the total capitalized costs associated with a prospect.

      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, we evaluate current drilling results, lease expiration dates, 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. To the extent costs accumulate in countries where there are no proved reserves, any costs determined by management to be impaired are charged to expense.

      Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and gas properties, including gas processing facilities and capitalized asset retirement obligations, net of related salvage values and deferred income taxes, and excluding the asset retirement obligation liability is limited to the sum of the estimated future net revenues from proved properties, excluding cash outflows from asset retirement obligations, using period-end prices, adjusted for the effects of hedging, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“Ceiling Test”). Our hedges at March 31, 2004 consisted of natural gas price floors with strike prices lower than the period end price and thus did not affect prices used in this calculation. 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.

      Given the volatility of oil and gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline from our period-end prices used in the Ceiling Test, even if only for a short period, it is possible that additional non-cash write-downs of oil and gas properties could occur in the future.

	Principles of Consolidation

      The accompanying consolidated financial statements include the accounts of Swift Energy Company and our wholly owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and natural gas properties, with a focus on onshore and inland waters oil and natural gas reserves in Texas and Louisiana, as well as onshore oil and natural gas reserves in New Zealand. Our investments in affiliated oil and gas partnerships and other ventures are accounted for using the proportionate consolidation method, whereby our proportionate share of each entity’s assets, liabilities, revenues, and expenses are included in the appropriate classifications in the consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the consolidated financial statements.

F-39

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SWIFT ENERGY COMPANY

	Accounts Receivable

      Included in the total “Accounts receivable” balance, which totaled $29.1 million and $27.4 million at March 31, 2004 and December 31, 2003, respectively, on the accompanying consolidated balance sheet, is approximately $2.3 million of receivables related to hydrocarbon volumes produced during 2001 and 2002 that have been disputed since early 2003. Accordingly, we did not record a receivable with regard to 2003 volumes. We continually assess the collectibility of trade and other receivables, and based on our judgment, we establish a reserve when we believe a receivable may not be collected. At both March 31, 2004 and December 31, 2003, we had an allowance for doubtful accounts of $0.8 million. These allowances for doubtful accounts have been deducted from the total “Accounts receivable” balances on the accompanying consolidated balance sheets.

	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. Significant estimates include proved reserve volumes, DD&A, and deferred income taxes.

	Income Taxes

      Income tax expense in the first quarter of 2004 includes a reduction from the U.S. statutory rate, primarily from the result of the currency exchange rate effect on the New Zealand deferred tax, along with a reduction in tax expense primarily attributable to an adjustment of the tax basis of the TAWN properties acquired in 2002.

	Earnings Per Share

      Basic earnings per share (“Basic EPS”) have been computed using the weighted average number of common shares outstanding during the respective periods. Diluted earnings per share (“Diluted EPS”) for all periods also assume, as of the beginning of the period, exercise of stock options using the treasury stock method. Certain of our stock options that would potentially dilute Basic EPS in the future were antidilutive for the three months ended March 31, 2004 and 2003. The following is a reconciliation of the

F-40

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SWIFT ENERGY COMPANY

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, 2004 and 2003:

			Three Months Ended March 31,
			2004												2003
											Per Share												Per Share
			Net Income				Shares				Amount				Net Income				Shares				Amount
Basic EPS:
	Net Income Before Cumulative Effect of Change in Accounting Principle and Share Amounts		$	14,587,854				27,552,827			$	.53			$	10,484,937				27,243,142			$	.38
	Stock Options			—				546,460								—				66,734
Diluted EPS:
Net Income Before Cumulative Effect of Change in Accounting Principle and Assumed Share Conversions			$	14,587,854				28,099,287			$	.52			$	10,484,937				27,309,876			$	.38

      Options to purchase approximately 3.2 million shares of common stock, at an average exercise price of $16.58 were outstanding at March 31, 2004, and 3.0 million shares of common stock, at an average price of $16.59 were outstanding at March 31, 2003. Approximately 0.9 million and 1.7 million options to purchase shares were not included in the computation of Diluted EPS for the three-month periods ended March 31, 2004 and 2003, respectively, because the options were antidilutive, given that the option price was greater than the average closing market price of the common shares during those periods.

	Other Comprehensive Loss

      We follow the provisions of SFAS No. 130 “Reporting Comprehensive Income,” which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income or loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company. At March 31, 2004, we recorded $269,436, net of taxes of $151,558, of derivative losses in “Other comprehensive loss” on the accompanying balance sheet. The components of accumulated other comprehensive loss and related tax effects for the three-month period ended March 31, 2004 were as follows:

		Gross Value				Tax Effect				Net of Tax Value
Balance at December 31, 2003		$	420,847			$	151,505			$	269,342
Change in fair value of cash flow hedges			634,987				228,595				406,392
Effect of cash flow hedges settled during the period			(634,840	)			(228,542	)			(406,298	)
Balance at March 31, 2004		$	420,994			$	151,558			$	269,436

      For the three-month periods ended March 31, 2004 and 2003, total comprehensive income was $14.6 million and $6.0 million, respectively.

F-41

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SWIFT ENERGY COMPANY

	Stock Based Compensation

      We account for three stock-based compensation plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. No stock-based employee compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of the grant; or in the case of the employee stock purchase plan, the purchase price is 85% of the lower of the closing price of our common stock as quoted on the New York Stock Exchange at the beginning or end of the plan year or a date during the year chosen by the participant. Had compensation expense for these plans been determined based on the fair value of the options consistent with SFAS No. 123, “Accounting for Stock-Based Compensation,” our net income and earnings per share would have been adjusted to the following pro forma amounts:

				Three Months Ended
				200March				31,2003
Net Income:		As Reported			$14,587,854				$6,108,085
		Stock-based employee compensation expense determined under fair value method for all awards, net of tax			(1,022,306	)			(981,942	)
		Pro Forma			$13,565,548				$5,126,143
Basic EPS:		As Reported			$.53				$.22
		Pro Forma			$.49				$.19
Diluted EPS:		As Reported			$.52				$.22
		Pro Forma			$.48				$.18

      Pro forma compensation cost reflected above may not be representative of the cost to be expected in future periods. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model.

	Price-Risk Management Activities

      We follow SFAS No. 133, which requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The statement also 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 a liability measured at its fair value. Special hedge accounting for qualifying hedges would allow the gains and losses on derivatives to offset related results on the hedged item in the income statements and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. Hedges that do not meet the criteria for special hedge accounting are accounted for under mark to market accounting. SFAS No. 133, as amended, was adopted by us on January 1, 2001.

      We have a price-risk management policy to use derivative instruments to protect against declines in oil and gas prices, mainly through the purchase of price floors and collars. During the first quarters of 2004 and 2003, we recognized net losses of $0.6 million and $1.4 million, respectively, relating to our derivative activities. This activity is recorded in “Price-risk management and other, net” on the accompanying statements of income. At March 31, 2004, we had recorded $0.3 million, net of taxes of $0.2 million, of derivative losses in “Other comprehensive loss” on the accompanying balance sheet. This amount represents the change in fair value for the effective portion of our hedging transactions that were qualified as cash flow hedges. The ineffectiveness reported in “Price-risk management and other, net” for the first three months of 2004 and 2003 was not material. We expect to reclassify all amounts currently held in

F-42

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SWIFT ENERGY COMPANY

“Other comprehensive loss” into the statement of income within the next three months when the forecasted sale of hedged production occurs.

      As of March 31, 2004, we had in place natural gas price floors in effect for the April 2004 contract month through the June 2004 contract month, which cover a portion of our domestic natural gas production for April 2004 to June 2004. The natural gas price floors cover notional volumes of 1,800,000 Mmbtu with a weighted average floor price of $4.83 per Mmbtu. Our hedges in place at March 31, 2004 are expected to cover approximately 55% to 65% of our domestic natural gas production from April 2004 to June 2004. When we entered into these transactions, they were designated as a hedge of the variability in cash flows associated with the forecasted sale of natural gas production. Changes in the fair value of a hedge that is highly effective and is designated and qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded in “Other Comprehensive Income (Loss).” When the hedged transactions are recorded upon the actual sale of oil and natural gas, these gains or losses are reclassified from “Other comprehensive income (loss)” and recorded in “Price-risk management and other, net” on the consolidated statement of income. The fair value of our derivatives are computed using the Black-Scholes option pricing model and are periodically verified against quotes from brokers. The fair value of these instruments at March 31, 2004, was less than $0.1 million and is recognized on the balance sheet in “Other current assets.”

	Asset Retirement Obligation

      In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” The statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. The liability is discounted from the year the well is expected to deplete. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. This standard requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values. SFAS No. 143 was adopted by us effective January 1, 2003. Upon adoption of SFAS No. 143 effective January 1, 2003, we recorded an asset retirement obligation of $8.9 million, an addition to oil and gas properties of $2.0 million and a non-cash charge of $4.4 million (net of $2.5 million of deferred taxes), which is recorded as a Cumulative Effect of Change in Accounting Principle. The cumulative charge to earnings took into consideration the impact of adopting SFAS No. 143 on previous full-cost ceiling tests. SFAS No. 143 is silent with respect to whether prior period ceiling tests should be reflected in the implementation entry calculation; however, management believes that any impairment on the properties should be reflected in the historical periods. Had we not considered the impact of adopting SFAS No. 143 on previous full-cost ceiling tests, the charge recognized would have been reduced. Excluding the Cumulative Effect of Change in Accounting Principle, the adoption of SFAS No. 143 reduced our net income for the three months

F-43

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SWIFT ENERGY COMPANY

ended March 31, 2003 by approximately $0.2 million, or $0.01 per diluted share. The following provides a roll-forward of our asset retirement obligation:

			2004				2003
Asset Retirement Obligation recorded as of January 1			$	10,137,473			$	8,934,320
	Accretion expense for the three months ended March 31			170,476				215,383
	Liabilities incurred for new wells and facilities construction			81,953				35,843
	Reductions due to sold and abandoned wells			(26,000	)			—
	Increase due to currency exchange rate fluctuations			4,077				—
Asset Retirement Obligation as of March 31			$	10,367,979			$	9,185,546

	New Accounting Principles

      In March 2004, the FASB issued an exposure draft that would amend SFAS No. 123 “Accounting for Stock Based Compensation” and SFAS No. 95 “Statement of Cash Flows.” This exposure draft was issued to improve existing accounting rules and provide more complete, higher quality information for investors on employee stock compensation matters. The comment period for the exposure draft ends June 30, 2004. The exposure draft covers a wide range of equity-based arrangements including stock options. Under the FASB’s proposal, share-based payments to employees, including stock options, would be treated the same as other forms of compensation by recognizing the related cost in the income statement. The expense of the award would generally be measured at fair value at the grant date. Current accounting guidance requires that the expense relating to employee stock options only be disclosed in the footnotes of the financial statements. The Company is evaluating the effects that will result from future adoption of this proposed statement or related accounting changes.

      In January 2003, the FASB issued Interpretation No. 46 (Revised December 2003), Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51 Consolidated Financial Statements (the “Interpretation”). The Interpretation significantly changes whether entities included in its scope are consolidated by their sponsors, transferors, or investors. The Interpretation introduces a new consolidation model — the variable interest model; which determines control (and consolidation) based on potential variability in gains and losses of the entity being evaluated for consolidation. The Interpretation provides guidance for determining whether an entity lacks sufficient equity or its equity holders lack adequate decision-making ability. These variable interest entities (“VIEs”) are covered by the Interpretation and are to be evaluated for consolidation based on their variable interests. These provisions applied immediately to variable interests in VIEs created after January 31, 2003, and to variable interests in special purpose entities for periods ending after December 15, 2003. The provisions apply for all other types of variable interests in VIEs for periods ending after March 15, 2004. We have no variable interests in VIEs, nor do we have variable interests in special purpose entities. The adoption of this interpretation had no impact on the Company’s financial position or results of operations.

      In June 2001, the FASB issued SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Intangible Assets.” We adopted these statements on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires that all business combinations initiated after June 30, 2001, be accounted for using the purchase method and that intangible assets be disaggregated and reported separately from goodwill. SFAS No. 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and other indefinite lived intangible assets are not amortized but reviewed annually for impairment.

F-44

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SWIFT ENERGY COMPANY

      An issue, EITF Issue 04-2, had arisen for companies engaged in oil and gas exploration and production regarding the application of SFAS No. 141 and SFAS No. 142 as they relate to mineral rights held under lease or other contractual arrangements, and as to whether costs associated with these rights should be classified as intangible assets on the balance sheet, apart from other capitalized oil and gas property costs, and to provide specific footnote disclosure. In March 2004, the Emerging Issues Task Force of the FASB reached a consensus that mineral rights are tangible assets. In April 2004, the FASB ratified the EITF’s consensus by issuing FASB Staff Position (FSP) 141-1 and 142-1, which amend SFAS No. 141 and SFAS No. 142 to address the inconsistency between the EITF consensus on EITF Issue No. 04-02 and SFAS No. 141 and SFAS No. 142. The FSP is effective for reporting periods beginning after April 29, 2004 and defines mineral rights as tangible assets. These staff positions will have no impact on our consolidated financial statements.

(3)	Long-Term Debt

      Our long-term debt as of March 31, 2004 and December 31, 2003, was as follows:

			March 31,				December 31,
			2004				2003
Bank Borrowings			$	32,500,000			$	15,900,000
Senior Subordinated Notes due 2009				124,376,926				124,354,783
Senior Subordinated Notes due 2012				200,000,000				200,000,000
	Long-Term Debt		$	356,876,926			$	340,254,783

      The unamortized discount on the Senior Subordinated Notes due 2009 was $0.6 million at both March 31, 2004 and December 31, 2003, respectively.

	Bank Borrowings

      At March 31, 2004, we had $32.5 million in outstanding borrowings under our $300.0 million credit facility with a syndicate of ten banks that has a borrowing base of $250.0 million and expires in October 2005. At December 31, 2003, we had $15.9 million in outstanding borrowings under our credit facility. The interest rate is either (a) the lead bank’s prime rate (4% at March 31, 2004) 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 $32.5 million borrowed at March 31, 2004, $30.0 million was borrowed at the LIBOR rate plus applicable margin, which was 2.34%, the remaining $2.5 million of borrowings was borrowed at 4%.

      The terms of our credit facility include, among other restrictions, a limitation on the level of cash dividends (not to exceed $5.0 million in any fiscal year), a remaining aggregate limitation on purchases of our stock of $15.0 million, requirements as to maintenance of certain minimum financial ratios (principally pertaining to working capital, debt, and equity ratios), and limitations on incurring other debt or repurchasing our Senior Subordinated Notes. Since inception, no cash dividends have been declared on our common stock. We are currently in compliance with the provisions of this agreement. The credit facility is secured by our domestic oil and gas properties. We have also pledged 65% of the stock in our two active New Zealand subsidiaries as collateral for this credit facility. The borrowing base is re-determined at least every six months and was reaffirmed by our bank group at $250.0 million effective May 1, 2004. We requested that the commitment amount with our bank group be reduced to $150.0 million effective May 9, 2003. Under the terms of the credit facility, we can increase this commitment amount back to the total

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SWIFT ENERGY COMPANY

amount of the borrowing base at our discretion, subject to the terms of the credit agreement. The next borrowing base review is scheduled for November 2004.

	Senior Subordinated Notes Due 2009

      Our Senior Subordinated Notes due 2009 consist of $125.0 million of 10.25% Senior Subordinated Notes due 2009. These Senior Subordinated Notes were issued at 99.236% of the principal amount on August 4, 1999, and will mature on August 1, 2009. The Senior Subordinated Notes are unsecured senior subordinated obligations and are subordinated in right of payment to all our existing and future senior debt, including our bank borrowings. Interest on these Senior Subordinated Notes is payable semiannually on February 1 and August 1. On or after August 1, 2004, the Senior Subordinated Notes are redeemable for cash at the option of Swift, with certain restrictions, at 105.125% of principal, declining to 100% in 2007. Upon certain changes in control of Swift, each holder of Senior Subordinated Notes will have the right to require us to repurchase the Senior Subordinated Notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The terms of these Senior Subordinated Notes include, among other restrictions, a limit on repurchases by Swift of its common stock. We are currently in compliance with the provisions of the indenture governing the Senior Subordinated Notes.

	Senior Subordinated Notes Due 2012

      Our Senior Subordinated Notes due 2012 consist of $200.0 million of 9.375% Senior Subordinated Notes due 2012. The Senior Subordinated Notes were issued on April 11, 2002 at 100% of the principal amount, and will mature on May 1, 2012. 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 borrowings. Interest on the Senior Subordinated Notes is payable semiannually on May 1 and November 1. On or after May 1, 2007, the Senior Subordinated Notes are redeemable for cash at the option of Swift, with certain restrictions, at 104.688% of principal, declining to 100% in 2010. In addition, prior to May 1, 2005, we may redeem up to 33.33% of the Senior Subordinated Notes with the proceeds of qualified offerings of our equity at 109.375% of the principal amount of the Senior Subordinated Notes, together with accrued and unpaid interest. Upon certain changes in control of Swift, each holder of Senior Subordinated Notes will have the right to require us to repurchase the Senior Subordinated Notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The terms of these Senior Subordinated Notes include, among other restrictions, a limit on repurchases by Swift of its common stock. We are currently in compliance with the provisions of the indenture governing the Senior Subordinated Notes.

      The aggregate maturities on our long-term debt are $0, $32.5 million, $0, $0, $0, and $325.0 million for the remainder of 2004, 2005, 2006, 2007, 2008, and thereafter, respectively.

(4)	Foreign Activities

      As of March 31, 2004, our gross capitalized oil and gas property costs in New Zealand totaled approximately $212.0 million. Approximately $177.2 million has been included in the proved properties portion of our oil and gas properties, while $34.8 million is included as unproved properties. Our functional currency in New Zealand is the U.S. dollar.

(5)	Segment Information

      The Company has two reportable segments, one domestic and one foreign, that are in the business of crude oil and natural gas exploration and production. The accounting policies of the segments are the same

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SWIFT ENERGY COMPANY

as those described in the summary of significant accounting policies. The Company evaluates performance based on profit or loss from oil and gas operations before other revenues, general and administrative expenses, and interest expense, net. The Company’s reportable segments are managed separately based on their geographic locations. Financial information by operating segment is presented below:

			Three Months Ended March 31,
			2004												2003
							New												New
			Domestic				Zealand				Total				Domestic				Zealand				Total
Oil and gas sales			$	54,666,162			$	11,287,608			$	65,953,770			$	43,741,176			$	11,109,123			$	54,850,299
Costs and Expenses:
	Depreciation, depletion and amortization			14,517,949				3,777,735				18,295,684				9,796,980				5,114,783				14,911,763
	Accretion of asset retirement obligation			130,548				39,928				170,476				149,441				65,942				215,383
	Lease operating costs			6,919,281				2,706,699				9,625,980				5,516,453				1,796,651				7,313,104
	Severance and other taxes			5,418,881				827,678				6,246,559				3,656,366				938,183				4,594,549
Income from oil and gas operations			$	27,679,503			$	3,935,568			$	31,615,071			$	24,621,936			$	3,193,564			$	27,815,500
	Price-risk management and other, net											(598,040	)											(1,350,306	)
	General and administrative, net											4,029,674												3,556,548
	Interest expense, net											6,901,175												6,684,902
Income before income taxes and cumulative effect of change in accounting principle											$	20,086,182											$	16,223,744
Property, plant and equipment, net			$	657,041,778			$	177,414,396			$	834,456,174			$	575,025,253			$	163,782,385			$	738,807,638

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$350,000,000

Debt Securities

        Swift Energy Company may offer and sell from time to time debt securities, common stock, preferred stock, depositary shares or warrants. You should carefully read this prospectus and any prospectus supplement before you invest.

      Our common stock is traded on the New York Stock Exchange and the Pacific Stock Exchange under the symbol “SFY.”

      There are significant risks associated with an investment in our securities. See “Risk Factors” beginning on page 3.

      This prospectus provides you with a general description of the securities that may be offered. This prospectus may not be used to sell securities unless accompanied by a prospectus supplement that describes those securities. We will provide specific terms of the offering and sale of these securities in supplements to this prospectus. These terms will include the initial offering price, aggregate amount of the offering, listing on any securities exchange or quotation system, risk factors and the agents, dealers or underwriters, if any, to be used in connection with the sale of these securities. The Supplements may also add, update or change information contained in this prospectus.

      Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities, or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is May 11, 2004

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      You should rely only on the information contained in or incorporated by reference in this prospectus and in any prospectus supplement. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted. You should not assume that the information contained in or incorporated by reference in this prospectus is accurate as of any date other than the date on the front of this prospectus or the applicable prospectus supplement.

TABLE OF CONTENTS

		Page
ABOUT THIS PROSPECTUS			1
WHERE YOU CAN FIND MORE INFORMATION			1
RISK FACTORS			3
FORWARD-LOOKING STATEMENTS			4
THE COMPANY			5
RATIO OF EARNINGS TO FIXED CHARGES			6
USE OF PROCEEDS			6
DESCRIPTION OF DEBT SECURITIES			7
DESCRIPTION OF CAPITAL STOCK			15
DESCRIPTION OF DEPOSITARY SHARES			18
DESCRIPTION OF WARRANTS			19
PLAN OF DISTRIBUTION			21
LEGAL OPINIONS			22
EXPERTS			22

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ABOUT THIS PROSPECTUS

      This prospectus is part of a registration statement that we filed with the Securities and Exchange Commission using a “shelf” registration process. Under the shelf process, we may sell any combination of the securities described in this prospectus in one or more offerings up to a total dollar amount of $350,000,000. This prospectus provides you with a general description of the securities we may offer. Each time we sell securities, we will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add, update or change information contained in this prospectus. You should carefully read this prospectus, any applicable prospectus supplement, together with additional information described under the heading “Where You Can Find More Information” before you invest in any of these securities.

      As used in this prospectus, “Swift,” “we,” “us,” and “our” refer to Swift Energy Company and its subsidiaries.

WHERE YOU CAN FIND MORE INFORMATION

      We are subject to the informational requirements of the Securities Exchange Act of 1934, which requires us to file annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission, or the “SEC.” You may read and copy any document that we file at the Public Reference Room of the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of its public reference room. In addition, our reports and other information concerning us can be inspected at the New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005, where our common stock is listed. You may also inspect our filings over the Internet at the SEC’s web site at http://www.sec.gov, or at our own website at http://www.swiftenergy.com. However, the other information on Swift’s website does not constitute a part of this prospectus.

      This prospectus constitutes part of a Registration Statement on Form S-3 filed with the SEC under the Securities Act of 1933. It omits some of the information contained in the Registration Statement, and reference is made to the Registration Statement for further information with respect to us and the securities we are offering. Any statement contained in this prospectus concerning the provisions of any document filed as an exhibit to the Registration Statement or otherwise filed with the SEC is not necessarily complete, and in each instance reference is made to the copy of the filed document.

      The SEC allows us to “incorporate by reference” the information we file with them, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is considered to be part of this prospectus, and later information that we file with the SEC will automatically update and supersede this information and the information in the prospectus. We incorporate by reference (excluding any information furnished pursuant to Item 9 or Item 12 of any report on Form 8-K) the documents listed below and any future filings made with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 until we sell all the securities covered by this prospectus:

	1. Our Annual Report on Form 10-K for the year ended December 31, 2003;
	2. The description of our common stock contained in our registration statement on Form 8-A filed on July 24, 1981, as amended, including any amendment or report filed before or after the date of this prospectus for the purpose of updating the description;
	3. The description of our preferred share purchase rights contained in our registration statement on Form 8-A filed on August 11, 1997, as amended on April 7, 1999, including any amendment or report filed before or after the date of this prospectus for the purpose of updating the description; and
	4. Our Current Report on Form 8-K dated February 11, 2004.

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      Any statement contained in a document incorporated or considered to be incorporated by reference in this prospectus shall be considered to be modified or superseded for purposes of this prospectus to the extent that a statement contained in this prospectus or in any subsequently filed document that is or is considered to be incorporated by reference modifies or supersedes that statement. Any statement that is modified or superseded shall not, except as so modified or superseded, constitute a part of this prospectus.

      You may request a copy of these filings at no cost, by writing or telephoning Bruce H. Vincent, Executive Vice President – Corporate Development, Swift Energy Company, Suite 400, 16825 Northchase Drive, Houston, Texas 77060, phone: (281) 874-2700.

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RISK FACTORS

      There are a number of risks associated with investing in Swift and in our industry. You should carefully review the more detailed description of risk factors contained in the supplement to this prospectus.

Steep or prolonged drops in prices can harm us financially and hurt our ability to grow.

      Our revenue, profitability and cash flow depend upon the prices and demand for oil and gas. The markets for these commodities are very volatile and steep or prolonged drops in prices can harm us financially and hurt our ability to grow. The changes in oil and natural gas prices have a significant impact on the value of our reserves, on our revenues, profitability, and on our cash flow.

Oil and natural gas drilling and producing operations involve various risks.

      Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Operating and developing oil and natural gas properties involves a number of inherent risks, including the risk of personal injury, environmental contamination or loss of wells. In addition, our drilling operations may be curtailed, delayed or canceled as a result of other factors, including title problems, adverse weather conditions, facility or equipment malfunctions and compliance with environmental and other governmental requirements. We may not be able to insure against all of these risks.

Estimating our reserves, production and future net cash flow is difficult to do with any certainty.

      Estimates of our proved developed oil and natural gas reserves and the resulting future net revenues contained in this prospectus and elsewhere are based on a number of uncertainties. A failure to realize our estimated prices or estimated production volumes could materially adversely affect our revenues, profitability, cash flow, and financial health.

Shortages of oil field equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

      Our ability to conduct operations in a timely and cost effective manner depends on the availability of supplies, equipment and personnel. The oil and gas industry is cyclical and experiences periodic shortages of drilling rigs and other equipment, tubular goods, supplies and experienced personnel. Shortages can delay operations and materially increase operating and capital costs.

Our level of indebtedness may adversely affect operations and limit our growth.

      We make, and will continue to make, substantial capital expenditures to acquire, develop, produce, explore and abandon our oil and natural gas reserves. Our bank borrowing base is adjusted at the banks’ discretion and is based in part upon external factors over which we have no control. Further, our cash flow from operations is highly dependent on the prices that we receive for oil and natural gas. Any decrease in our revenues, as a result of lower oil or gas prices or otherwise, could limit our ability to replace reserves or maintain production at current levels. If our cash flow from operations drops significantly, we may be unable to grow our production and proved reserves which in turn could materially adversely affect our revenues, profitability, financial health, and on our ability to service our debt.

Our future success depends on our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable.

      Our future success depends on our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Failure to do so will result in lower production and cash flow.

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Investors in our securities may encounter difficulties in obtaining, or may be unable to obtain, recoveries from Arthur Andersen LLP with respect to its audits of our financial statements at December 31, 2001 and for the year-ended December 31, 2001.

      Because we are unable to obtain the written consent of Arthur Andersen LLP to our naming it in this prospectus as having certified our financial statements at December 31, 2001 and for prior periods, the rights of investors in our securities to assert claims against Arthur Andersen LLP will be limited. For example, because of this lack of consent, you will not be able to sue Arthur Andersen LLP under Section 11(a)(4) of the Securities Act for any untrue statement of a material fact contained in the financial statements audited by Arthur Andersen LLP or any omissions to state a material fact required to be stated in those financial statements.

FORWARD-LOOKING STATEMENTS

      Some of the information included in this prospectus, any prospectus supplement and the documents we have incorporated by reference contain forward-looking statements. Forward-looking statements use forward-looking terms such as “believe,” “expect,” “may,” “intend,” “will,” “project,” “budget,” “should” or “anticipate” or other similar words. These statements discuss “forward-looking” information such as:

	•	anticipated capital expenditures and budgets;
	•	future cash flows and borrowings;
	•	pursuit of potential future acquisition or drilling opportunities; and
	•	sources of funding for exploration and development.

      These forward-looking statements are based on assumptions that we believe are reasonable, but they are open to a wide range of uncertainties and business risks, including the following:

	•	fluctuations of the prices received or demand for oil and natural gas;
	•	uncertainty of drilling results, reserve estimates and reserve replacement;
	•	operating hazards;
	•	acquisition risks;
	•	unexpected substantial variances in capital requirements;
	•	environmental matters; and
	•	general economic conditions.

      Other factors that could cause actual results to differ materially from those anticipated are discussed in our periodic filings with the SEC, including our Annual Report on Form 10-K for the year ended December 31, 2003.

      When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus, any prospectus supplement and the documents we have incorporated by reference. We will not update these forward-looking statements unless the securities laws require us to do so.

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THE COMPANY

      Swift Energy Company, a Texas corporation, is engaged in developing, exploring, acquiring, and operating oil and gas properties, with a focus on onshore and inland waters oil and natural gas reserves in Texas and Louisiana and onshore oil and gas reserves in New Zealand. As of December 31, 2003, we had interests in 998 oil and gas wells located domestically in four states, in federal offshore waters and in New Zealand. We operated 870 of these wells, representing 95% of our proved reserves. At year-end 2003, our estimated proved reserves were 820.4 Bcfe, of which approximately 41% was natural gas, 47% crude oil, and 12% natural gas liquids, and overall 59% of these reserves were proved developed. Our proved reserves at that date were concentrated 40% in Texas, 37% in Louisiana and 21% in New Zealand.

      Our core domestic areas for development and exploration drilling are the Lake Washington Area located in South Louisiana, the AWP Olmos Area located in South Texas, the Brookeland Area located in East Texas and the Masters Creek Area in Central Louisiana. The Lake Washington Area accounted for approximately 32% of our proved reserves as of December 31, 2003 and approximately 23% of our production for the year ended December 31, 2003, while the AWP Olmos Field accounted for approximately 26% of our proved reserves as of December 31, 2003 and approximately 16% of our production for the year ended December 31, 2003. New Zealand accounted for approximately 21% of our proved reserves as of December 31, 2003 and 36% of our production for the year ended December 31, 2003 and the Masters Creek Area accounted for approximately 8% of proved reserves as of December 31, 2003 and 11% of our production for the year ended December 31, 2003. Our net sales volume for the year ended December 31, 2003 was 53.2 Bcfe, of which 53% was natural gas. Brookeland had 5% of proved reserves and 7% of production in 2003.

      We have increased our proved reserves from 436.1 Bcfe at year-end 1998 to 820.4 Bcfe at year-end 2003, which has resulted in the replacement of 266% of our production during the same period. Our five-year average reserves replacement costs were $1.25 per Mcfe. In 2003, we increased our proved reserves by 9%, which replaced 234% of our 2003 production. We have increased our production from 39.0 Bcfe at year-end 1998 to 53.2 Bcfe at year-end 2003. Net cash provided by operating activities has had average annual growth of 15% per year from year-end 1998 to year-end 2003.

      We added 105.6 Bcfe of proved reserves through drilling in 2003 (36.1 Bcfe from New Zealand), 83.9 Bcfe in 2002 (15.9 Bcfe from New Zealand), and 105.8 Bcfe in 2001 (17.4 Bcfe from New Zealand). The 2003 additions were primarily a result of our development completion rate, as we successfully completed 53 of 63 domestic development wells and 3 of 3 New Zealand development wells, while five of eight domestic exploratory wells were successfully completed. Our only New Zealand exploratory well was not successful.

      Swift’s philosophy is to pursue a balanced growth strategy that includes an active drilling program, strategic acquisitions, and the utilization of advanced technologies. We seek to increase our reserves through both drilling and acquisitions, shifting the balance between the two activities in response to market conditions. For example, when oil and gas prices are low, we focus upon acquiring producing properties. When oil and gas prices are high, we shift our focus to drilling wells.

      Our principal executive offices are located at 16825 Northchase Drive, Suite 400, Houston, Texas 77060 and our telephone number is (281) 874-2700.

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RATIO OF EARNINGS TO FIXED CHARGES

      The following table sets forth our ratio of earnings to fixed charges:

		Year Ended December 31,
		2003				2002				2001(1)				2000				1999
Ratio of earnings to fixed charges			2.29	x			1.38	x			—				5.18	x			2.39	x

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(1)	Due to the $98.9 million non-cash charge incurred in the fourth quarter of 2001 caused by a write-down in the carrying value of oil and gas properties, 2001 earnings were insufficient by $40.2 million to cover fixed charges in this period. If the $98.9 million non-cash charge is excluded, the ratio of earnings to fixed charges would have been 4.09 for 2001.

     For purposes of calculating the ratio of earnings to fixed charges, fixed charges include interest expense net (which includes amortization of debt issuance costs and discounts), capitalized interest and that portion of non-capitalized rental expense deemed to be the equivalent of interest. Earnings represent income before income taxes and cumulative effect of change in accounting principle and from continuing operations before fixed charges (excluding capitalized interest, net of depletion).

USE OF PROCEEDS

      Unless we specify otherwise in an accompanying prospectus supplement, we intend to use the net proceeds we receive from the sale of securities offered by this prospectus and the accompanying prospectus supplement for the repayment of debt and for general corporate purposes. General corporate purposes may include additions to working capital, development and exploration expenditures or the financing of possible acquisitions.

      The net proceeds may be invested temporarily until they are used for their stated purpose.

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DESCRIPTION OF DEBT SECURITIES

      This section describes the general terms and provisions of the debt securities which may be offered by us from time to time. The applicable prospectus supplement will describe the specific terms of the debt securities offered by that prospectus supplement.

      We may issue debt securities either separately or together with, or upon the conversion of, or in exchange for, other securities. The debt securities are to be either senior obligations of ours issued in one or more series and referred to herein as the “Senior Debt Securities,” or subordinated obligations of ours issued in one or more series and referred to herein as the “Subordinated Debt Securities.” The Senior Debt Securities and the Subordinated Debt Securities are collectively referred to as the “Debt Securities.” The Debt Securities will be general obligations of the Company. Each series of Debt Securities will be issued under an agreement, or “Indenture,” between Swift and an independent third party, usually a bank or trust company, known as a “Trustee,” who will be legally obligated to carry out the terms of the Indenture. The name(s) of the Trustee(s) will be set forth in the applicable prospectus supplement. We may issue all the Debt Securities under the same Indenture, as one or as separate series, as specified in the applicable prospectus supplement(s).

      This summary of certain terms and provisions of the Debt Securities and Indentures is not complete. If we refer to particular provisions of an Indenture, the provisions, including definitions of certain terms, are incorporated by reference as a part of this summary. The Indentures are or will be filed as an exhibit to the registration statement of which this prospectus is a part, or as exhibits to documents filed under the Securities Exchange Act of 1934, which are incorporated by reference into this prospectus. The Indentures are subject to and governed by the Trust Indenture Act of 1939, as amended. You should refer to the applicable Indenture for the provisions that may be important to you.

General

      The Indentures will not limit the amount of Debt Securities that we may issue. We may issue Debt Securities up to an aggregate principal amount as we may authorize from time to time. The applicable prospectus supplement will describe the terms of any Debt Securities being offered, including:

	•	the title and aggregate principal amount;
	•	the date(s) when principal is payable;
	•	the interest rate, if any, and the method for calculating the interest rate;
	•	the interest payment dates and the record dates for the interest payments;
	•	the places where the principal and interest will be payable;
	•	any mandatory or optional redemption or repurchase terms or prepayment, conversion, sinking fund or exchangeability or convertibility provisions;
	•	whether such Debt Securities will be Senior Debt Securities or Subordinated Debt Securities and, if Subordinated Debt Securities, the subordination provisions and the applicable definition of “Senior Indebtedness”;
	•	additional provisions, if any, relating to the defeasance and covenant defeasance of the Debt Securities;
	•	if other than denominations of $1,000 or multiples of $1,000, the denominations the Debt Securities will be issued in;
	•	whether the Debt Securities will be issued in the form of Global Securities, as defined below, or certificates;
	•	whether the Debt Securities will be issuable in registered form, referred to as “Registered Securities,” or in bearer form, referred to as “Bearer Securities” or both and, if Bearer Securities

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		are issuable, any restrictions applicable to the exchange of one form for another and the offer, sale and delivery of Bearer Securities;
	•	any applicable material federal tax consequences;
	•	the dates on which premiums, if any, will be payable;
	•	our right, if any, to defer payment of interest and the maximum length of such deferral period;
	•	any paying agents, transfer agents, registrars or trustees;
	•	any listing on a securities exchange;
	•	if convertible into common stock or preferred stock, the terms on which such Debt Securities are convertible;
	•	the terms, if any, of the transfer, mortgage, pledge, or assignment as security for any series of Debt Securities of any properties, assets, proceeds, securities or other collateral, including whether certain provisions of the Trust Indenture Act are applicable, and any corresponding changes to provisions of the Indenture as currently in effect;
	•	the initial offering price; and
	•	other specific terms, including covenants and any additions or changes to the events of default provided for with respect to the Debt Securities.

      The terms of the Debt Securities of any series may differ and, without the consent of the holders of the Debt Securities of any series, we may reopen a previous series of Debt Securities and issue additional Debt Securities of such series or establish additional terms of such series, unless otherwise indicated in the applicable prospectus supplement.

Non U.S. Currency

      If the purchase price of any Debt Securities is payable in a currency other than U.S. dollars or if principal of, or premium, if any, or interest, if any, on any of the Debt Securities is payable in any currency other than U.S. dollars, the specific terms with respect to such Debt Securities and such foreign currency will be specified in the applicable prospectus supplement.

Original Issue Discount Securities

      Debt Securities may be issued as “Original Issue Discount Securities” to be sold at a substantial discount below their principal amount. Original Issue Discount Securities may include “zero coupon” securities that do not pay any cash interest for the entire term of the securities. In the event of an acceleration of the maturity of any Original Issue Discount Security, the amount payable to the holder thereof upon such acceleration will be determined in the manner described in the applicable prospectus supplement. Conditions pursuant to which payment of the principal of the Subordinated Debt Securities may be accelerated will be set forth in the applicable prospectus supplement. Material federal income tax and other considerations applicable to Original Issue Discount Securities will be described in the applicable prospectus supplement.

Covenants

      Under the Indentures, we will be required to:

	•	pay the principal, interest and any premium on the Debt Securities when due;
	•	maintain a place of payment;
	•	deliver a report to the Trustee at the end of each fiscal year reviewing our obligations under the Indentures; and

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	•	deposit sufficient funds with any paying agent on or before the due date for any principal, interest or any premium.

      Any additional covenants will be described in the applicable prospectus supplement.

Registration, Transfer, Payment and Paying Agent

      Unless otherwise indicated in a prospectus supplement, each series of Debt Securities will be issued in registered form only, without coupons. The Indentures, however, provide that we may also issue Debt Securities in bearer form only, or in both registered and bearer form. Bearer Securities shall not be offered, sold, resold or delivered in connection with their original issuance in the United States or to any United States person other than offices located outside the United States of certain United States financial institutions. “United States person” means any citizen or resident of the United States, any corporation, partnership or other entity created or organized in or under the laws of the United States, any estate the income of which is subject to United States federal income taxation regardless of its source, or any trust whose administration is subject to the primary supervision of a United States court and which has one or more United States fiduciaries who have the authority to control all substantial decisions of the trust. “United States” means the United States of America (including the states thereof and the District of Columbia), its territories, its possessions and other areas subject to its jurisdiction. Purchasers of Bearer Securities will be subject to certification procedures and may be affected by certain limitations under United States tax laws. Such procedures and limitations will be described in the prospectus supplement relating to the offering of the Bearer Securities.

      Unless otherwise indicated in a prospectus supplement, Registered Securities will be issued in denominations of $1,000 or any integral multiple thereof, and Bearer Securities will be issued in denominations of $5,000.

      Unless otherwise indicated in a prospectus supplement, the principal, premium, if any, and interest, if any, of or on the Debt Securities will be payable, and Debt Securities may be surrendered for registration of transfer or exchange, at an office or agency to be maintained by us in the Borough of Manhattan, The City of New York, provided that payments of interest with respect to any Registered Security may be made at our option by check mailed to the address of the person entitled to payment or by transfer to an account maintained by the payee with a bank located in the United States. No service charge shall be made for any registration of transfer or exchange of Debt Securities, but we may require payment of a sum sufficient to cover any tax or other governmental charge and any other expenses that may be imposed in connection with the exchange or transfer.

      Unless otherwise indicated in a prospectus supplement, payment of principal of, premium, if any, and interest, if any, on Bearer Securities will be made, subject to any applicable laws and regulations, at such office or agency outside the United States as specified in the prospectus supplement and as we may designate from time to time. Unless otherwise indicated in a prospectus supplement, payment of interest due on Bearer Securities on any interest payment date will be made only against surrender of the coupon relating to such interest payment date. Unless otherwise indicated in a prospectus supplement, no payment of principal, premium or interest with respect to any Bearer Security will be made at any office or agency in the United States or by check mailed to any address in the United States or by transfer to an account maintained with a bank located in the United States; except that if amounts owing with respect to any Bearer Securities shall be payable in U.S. dollars, payment may be made at the Corporate Trust Office of the applicable Trustee or at any office or agency designated by us in the Borough of Manhattan, The City of New York, if (but only if) payment of the full amount of such principal, premium or interest at all offices outside of the United States maintained for such purpose by us is illegal or effectively precluded by exchange controls or similar restrictions.

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      Unless otherwise indicated in the applicable prospectus supplement, we will not be required to:

	•	issue, register the transfer of or exchange Debt Securities of any series during a period beginning at the opening of business 15 days before any selection of Debt Securities of that series of like tenor to be redeemed and ending at the close of business on the day of that selection;
	•	register the transfer of or exchange any Registered Security, or portion thereof, called for redemption, except the unredeemed portion of any Registered Security being redeemed in part;
	•	exchange any Bearer Security called for redemption, except to exchange such Bearer Security for a Registered Security of that series and like tenor that is simultaneously surrendered for redemption; or
	•	issue, register the transfer of or exchange any Debt Security which has been surrendered for repayment at the option of the holder, except the portion, if any, of the Debt Security not to be so repaid.

Ranking of Debt Securities

      The Senior Debt Securities will be unsubordinated obligations of ours and will rank equally in right of payment with all other unsubordinated indebtedness of ours. The Subordinated Debt Securities will be obligations of ours and will be subordinated in right of payment to all existing and future Senior Indebtedness. The prospectus supplement will describe the subordination provisions and set forth the definition of “Senior Indebtedness” applicable to the Subordinated Debt Securities, and will set forth the approximate amount of such Senior Indebtedness outstanding as of a recent date.

Global Securities

      The Debt Securities of a series may be issued in whole or in part in the form of one or more global securities that will be deposited with, or on behalf of, a “Depository” identified in the prospectus supplement relating to such series. Global Debt Securities may be issued in either registered or bearer form and in either temporary or permanent form. Unless and until it is exchanged in whole or in part for individual certificates evidencing Debt Securities, a Global Debt Security may not be transferred except as a whole:

	•	by the Depository to a nominee of such Depository;
	•	by a nominee of such Depository to such Depository or another nominee of such Depository; or
	•	by such Depository or any such nominee to a successor of such Depository or a nominee of such successor.

      The specific terms of the depository arrangement with respect to a series of Global Debt Securities and certain limitations and restrictions relating to a series of Global Bearer Securities will be described in the applicable prospectus supplement.

Outstanding Debt Securities

      In determining whether the holders of the requisite principal amount of outstanding Debt Securities have given any authorization, demand, direction, notice, consent or waiver under the relevant Indenture, the amount of outstanding Debt Securities will be calculated based on the following:

	•	the portion of the principal amount of an Original Issue Discount Security that shall be deemed to be outstanding for such purposes shall be that portion of the principal amount thereof that could be declared to be due and payable upon a declaration of acceleration pursuant to the terms of such Original Issue Discount Security as of the date of such determination;

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	•	the principal amount of a Debt Security denominated in a currency other than U.S. dollars shall be the U.S. dollar equivalent, determined on the date of original issue of such Debt Security, of the principal amount of such Debt Security; and
	•	any Debt Security owned by us or any obligor on such Debt Security or any affiliate of us or such other obligor shall be deemed not to be outstanding.

Redemption and Repurchase

      The Debt Securities may be redeemable at our option, may be subject to mandatory redemption pursuant to a sinking fund or otherwise, or may be subject to repurchase by Swift at the option of the holders, in each case upon the terms, at the times and at the prices set forth in the applicable prospectus supplement.

Conversion and Exchange

      The terms, if any, on which Debt Securities of any series are convertible into or exchangeable for common stock, preferred stock, or other Debt Securities will be set forth in the applicable prospectus supplement. Such terms of conversion or exchange may be either mandatory, at the option of the holders, or at our option.

Consolidation, Merger and Sale of Assets

      Each Indenture generally will permit a consolidation or merger between us and another corporation, if the surviving corporation meets certain limitations and conditions. Subject to those conditions, each Indenture may also permit the sale by us of all or substantially all of our property and assets. If this happens, the remaining or acquiring corporation shall assume all of our responsibilities and liabilities under the Indentures including the payment of all amounts due on the Debt Securities and performance of the covenants in the Indentures.

      We are only permitted to consolidate or merge with or into any other corporation or sell all or substantially all of our assets according to the terms and conditions of the Indentures, as indicated in the applicable prospectus supplement. The remaining or acquiring corporation will be substituted for us in the Indentures with the same effect as if it had been an original party to the Indenture. Thereafter, the successor corporation may exercise our rights and powers under any Indenture, in our name or in its own name. Any act or proceeding required or permitted to be done by our board of directors or any of our officers may be done by the board or officers of the successor corporation.

Events of Default

      Unless otherwise specified in the applicable prospectus supplement, an Event of Default, as defined in the Indentures and applicable to Debt Securities issued under such Indentures, typically will occur with respect to the Debt Securities of any series under the Indenture upon:

	•	default for a period to be specified in the applicable prospectus supplement in payment of any interest with respect to any Debt Security of such series;
	•	default in payment of principal or any premium with respect to any Debt Security of such series when due upon maturity, redemption, repurchase at the option of the holder or otherwise;
	•	default in deposit of any sinking fund payment when due with respect to any Debt Security of such series;
	•	default by us in the performance, or breach, of any other covenant or warranty in such Indenture, which shall not have been remedied for a period to be specified in the applicable prospectus supplement after notice to us by the applicable Trustee or the holders of not less than a fixed percentage in aggregate principal amount of the Debt Securities of all series issued under the applicable Indenture;

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	•	certain events of bankruptcy, insolvency or reorganization of Swift; or
	•	any other Event of Default that may be set forth in the applicable prospectus supplement, including an Event of Default based on other debt being accelerated, known as a “cross-acceleration.”

      No Event of Default with respect to any particular series of Debt Securities necessarily constitutes an Event of Default with respect to any other series of Debt Securities. If the Trustee considers it in the interest of the holders to do so, the Trustee under an Indenture may withhold notice of the occurrence of a default with respect to the Debt Securities to the holders of any series outstanding, except a default in payment of principal, premium, if any, interest, if any.

      Each Indenture will provide that if an Event of Default with respect to any series of Debt Securities issued thereunder shall have occurred and be continuing, either the relevant Trustee or the holders of at least a fixed percentage in principal amount of the Debt Securities of such series then outstanding may declare the principal amount of all the Debt Securities of such series to be due and payable immediately. In the case of Original Issue Discount Securities, the Trustee may declare as due and payable such lesser amount as may be specified in the applicable prospectus supplement. However, upon certain conditions, such declaration and its consequences may be rescinded and annulled by the holders of at least a fixed percentage in principal amount of the Debt Securities of all series issued under the applicable Indenture.

      The applicable prospectus supplement will provide the terms pursuant to which an Event of Default shall result in acceleration of the payment of principal of Subordinated Debt Securities.

      In the case of a default in the payment of principal of, or premium, if any, or interest, if any, on any Subordinated Debt Securities of any series, the applicable Trustee, subject to certain limitations and conditions, may institute a judicial proceeding for the collection thereof.

      No holder of any of the Debt Securities of any series will have any right to institute any proceeding with respect to the Indenture or any remedy thereunder, unless the holders of at least a fixed percentage in principal amount of the outstanding Debt Securities of such series:

	•	have made written request to the Trustee to institute such proceeding as Trustee, and offered reasonable indemnity to the Trustee,
	•	the Trustee has failed to institute such proceeding within the time period specified in the applicable prospectus supplement after receipt of such notice, and
	•	the Trustee has not within such period received directions inconsistent with such written request by holders of a majority in principal amount of the outstanding Debt Securities of such series. Such limitations do not apply, however, to a suit instituted by a holder of a Debt Security for the enforcement of the payment of the principal of, premium, if any, or any accrued and unpaid interest on, the Debt Security on or after the respective due dates expressed in the Debt Security.

      During the existence of an Event of Default under an Indenture, the Trustee is required to exercise such rights and powers vested in it under the Indenture and use the same degree of care and skill in its exercise thereof as a prudent person would exercise under the circumstances in the conduct of such person’s own affairs. Subject to the provisions of the Indenture relating to the duties of the Trustee, if an Event of Default shall occur and be continuing, the Trustee is under no obligation to exercise any of its rights or powers under the Indenture at the request or direction of any of the holders, unless such holders shall have offered to the Trustee reasonable security or indemnity. Subject to certain provisions concerning the rights of the Trustee, the holders of at least a fixed percentage in principal amount of the outstanding Debt Securities of any series have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee, or exercising any power conferred on the Trustee with respect to such series.

      The Indentures provide that the Trustee will, within the time period specified in the applicable prospectus supplement after the occurrence of any default, give to the holders of the Debt Securities of such series notice of such default known to it, unless such default shall have been cured or waived;

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      Swift is required to furnish to the Trustee annually a statement as to compliance with all conditions and covenants under the Indentures.

Modification and Waivers

      From time to time, when authorized by resolutions of our board of directors and by the Trustee, without the consent of the holders of Debt Securities of any series, we may amend, waive or supplement the Indentures and the Debt Securities of such series for certain specified purposes, including, among other things:

	•	to cure ambiguities, defects or inconsistencies;
	•	to provide for the assumption of our obligations to holders of the Debt Securities of such series in the case of a merger or consolidation;
	•	to add to our Events of Default or our covenants or to make any change that would provide any additional rights or benefits to the holders of the Debt Securities of such series;
	•	to add or change any provisions of such Indenture to facilitate the issuance of Bearer Securities;
	•	to establish the form or terms of Debt Securities of any series and any related coupons;
	•	to add guarantors with respect to the Debt Securities of such series;
	•	to secure the Debt Securities of such series;
	•	to maintain the qualification of the Indenture under the Trust Indenture Act; or
	•	to make any change that does not adversely affect the rights of any holder.

      Other amendments and modifications of the Indentures or the Debt Securities issued thereunder may be made by Swift and the Trustee with the consent of the holders of not less than a fixed percentage of the aggregate principal amount of the outstanding Debt Securities of each series affected, with each series voting as a separate class; provided that, without the consent of the holder of each outstanding Debt Security affected, no such modification or amendment may:

	•	reduce the principal amount of, or extend the fixed maturity of the Debt Securities, or alter or waive any redemption, repurchase or sinking fund provisions of the Debt Securities;
	•	reduce the amount of principal of any Original Issue Discount Securities that would be due and payable upon an acceleration of the maturity thereof;
	•	change the currency in which any Debt Securities or any premium or the accrued interest thereon is payable;
	•	reduce the percentage in principal amount outstanding of Debt Securities of any series which must consent to an amendment, supplement or waiver or consent to take any action under the Indenture or the Debt Securities of such series;
	•	impair the right to institute suit for the enforcement of any payment on or with respect to the Debt Securities;
	•	waive a default in payment with respect to the Debt Securities or any guarantee;
	•	reduce the rate or extend the time for payment of interest on the Debt Securities;

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	•	adversely affect the ranking of the Debt Securities of any series;
	•	release any guarantor from any of its obligations under its guarantee or the Indenture, except in compliance with the terms of the Indenture; or
	•	solely in the case of a series of Subordinated Debt Securities, modify any of the applicable subordination provisions or the applicable definition of Senior Indebtedness in a manner adverse to any holders.

      The holders of a fixed percentage in aggregate principal amount of the outstanding Debt Securities of any series may waive compliance by us with certain restrictive provisions of the relevant Indenture, including any set forth in the applicable prospectus supplement. The holders of a fixed percentage in aggregate principal amount of the outstanding Debt Securities of any series may, on behalf of the holders of that series, waive any past default under the applicable Indenture with respect to that series and its consequences, except a default in the payment of the principal of, or premium, if any, or interest, if any, on any Debt Securities of such series, or in respect of a covenant or provision which cannot be modified or amended without the consent of a larger fixed percentage of holders or by the holder of each outstanding Debt Securities of the series affected.

Discharge, Termination and Covenant Termination

      When we establish a series of Debt Securities, we may provide that such series is subject to the termination and discharge provisions of the applicable Indenture. If those provisions are made applicable, we may elect either:

	•	to terminate and be discharged from all of our obligations with respect to those Debt Securities subject to some limitations; or
	•	to be released from our obligations to comply with specified covenants relating to those Debt Securities, as described in the applicable prospectus supplement.

      To effect that termination or covenant termination, we must irrevocably deposit in trust with the relevant Trustee an amount which, through the payment of principal and interest in accordance with their terms, will provide money sufficient to make payments on those Debt Securities and any mandatory sinking fund or similar payments on those Debt Securities. This deposit may be made in any combination of funds or government obligations. On such a termination, we will not be released from certain of our obligations that will be specified in the applicable prospectus supplement.

      To establish such a trust we must deliver to the relevant Trustee an opinion of counsel to the

	•	will not recognize income, gain or loss for U.S. federal income tax purposes as a result of the termination or covenant termination; and
	•	will be subject to U.S. federal income tax on the same amounts, in the same manner and at the same times as would have been the case if the termination or covenant termination had not occurred.

      If we effect covenant termination with respect to any Debt Securities, the amount of deposit with the relevant Trustee must be sufficient to pay amounts due on the Debt Securities at the time of their stated maturity. However, those Debt Securities may become due and payable prior to their stated maturity if there is an Event of Default with respect to a covenant from which we have not been released. In that event, the amount on deposit may not be sufficient to pay all amounts due on the Debt Securities at the time of the acceleration.

      The applicable prospectus supplement may further describe the provisions, if any, permitting termination or covenant termination, including any modifications to the provisions described above.

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Governing Law

      The Indentures and the Debt Securities will be governed by, and construed in accordance with, the laws of the State of New York.

Regarding the Trustees

      The Trust Indenture Act contains limitations on the rights of a trustee, should it become a creditor of ours, to obtain payment of claims in certain cases or to realize on certain property received by it in respect of any such claims, as security or otherwise. Each Trustee is permitted to engage in other transactions with us from time to time, provided that if such Trustee acquires any conflicting interest, it must eliminate such conflict upon the occurrence of an Event of Default under the relevant Indenture, or else resign.

DESCRIPTION OF CAPITAL STOCK

General

      As of the date of this prospectus, we are authorized to issue up to 90,000,000 shares of stock, including up to 85,000,000 shares of common stock and up to 5,000,000 shares of preferred stock. As of December 31, 2003, we had 27,484,091 shares of common stock and no shares of preferred stock outstanding. As of December 31, 2003, we also had approximately 3,238,611 million shares of common stock reserved for issuance upon exercise of outstanding options or in connection with other awards outstanding under various employee or director incentive, compensation and option plans.

      The following is a summary of the key terms and provisions of our equity securities. You should refer to the applicable provisions of our articles of incorporation, bylaws, the Texas Business Corporation Act and the documents we have incorporated by reference for a complete statement of the terms and rights of our capital stock.

Common Stock

      Voting Rights. Each holder of common stock is entitled to one vote per share. Subject to the rights, if any, of the holders of any series of preferred stock pursuant to applicable law or the provision of the certificate of designation creating that series, all voting rights are vested in the holders of shares of common stock. Holders of shares of common stock have noncumulative voting rights, which means that the holders of more than 50% of the shares voting for the election of directors can elect 100% of the directors, and the holders of the remaining shares voting for the election of directors will not be able to elect any directors.

      Dividends. Dividends may be paid to the holders of common stock when, as and if declared by the board of directors out of funds legally available for their payment, subject to the rights of holders of any preferred stock. Swift has never declared a cash dividend and intends to continue its policy of using retained earnings for expansion of its business.

      Rights upon Liquidation. In the event of our voluntary or involuntary liquidation, dissolution or winding up, the holders of common stock will be entitled to share equally, in proportion to the number of shares of common stock held by them, in any of our assets available for distribution after the payment in full of all debts and distributions and after the holders of all series of outstanding preferred stock, if any, have received their liquidation preferences in full.

      Non-Assessable. All outstanding shares of common stock are fully paid and non-assessable. Any additional common stock we offer and issue under this Prospectus will also be fully paid and non-assessable.

      No Preemptive Rights. Holders of common stock are not entitled to preemptive purchase rights in future offerings of our common stock.

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      Listing. Our outstanding shares of common stock are listed on the New York Stock Exchange and the Pacific Stock Exchange under the symbol “SFY.” Any additional common stock we issue will also be listed on the NYSE and the PSE.

Preferred Stock

      Our board of directors can, without approval of our shareholders, issue one or more series of preferred stock and determine the number of shares of each series and the rights, preferences and limitations of each series. The following description of the terms of the preferred stock sets forth certain general terms and provisions of our authorized preferred stock. If we offer preferred stock, a description will be filed with the SEC and the specific designations and rights will be described in a prospectus supplement, including the following terms:

	•	the series, the number of shares offered and the liquidation value of the preferred stock;
	•	the price at which the preferred stock will be issued;
	•	the dividend rate, the dates on which the dividends will be payable and other terms relating to the payment of dividends on the preferred stock;
	•	the liquidation preference of the preferred stock;
	•	the voting rights of the preferred stock;
	•	whether the preferred stock is redeemable or subject to a sinking fund, and the terms of any such redemption or sinking fund;
	•	whether the preferred stock is convertible or exchangeable for any other securities, and the terms of any such conversion; and
	•	any additional rights, preferences, qualifications, limitations and restrictions of the preferred stock.

      The description of the terms of the preferred stock to be set forth in an applicable prospectus supplement will not be complete and will be subject to and qualified in its entirety by reference to the certificate of designation relating to the applicable series of preferred stock. The registration statement of which this prospectus forms a part will include the certificate of designation as an exhibit or incorporate it by reference.

      Undesignated preferred stock may enable our board of directors to render more difficult or to discourage an attempt to obtain control of us by means of a tender offer, proxy contest, merger or otherwise, and to thereby protect the continuity of our management. The issuance of shares of preferred stock may adversely affect the rights of the holders of our common stock. For example, any preferred stock issued may rank prior to our common stock as to dividend rights, liquidation preference or both, may have full or limited voting rights and may be convertible into shares of common stock. As a result, the issuance of shares of preferred stock may discourage bids for our common stock or may otherwise adversely affect the market price of our common stock or any existing preferred stock.

      Any preferred stock will, when issued, be fully paid and non-assessable.

Anti-takeover Provisions

      Certain provisions in our articles of incorporation, bylaws and our shareholders’ rights plan may encourage persons considering unsolicited tender offers or other unilateral takeover proposals to negotiate with our board of directors rather than pursue non-negotiated takeover attempts.

      Our Classified Board of Directors. Our bylaws provide that our board of directors is divided into three classes as nearly equal in number as possible. The directors of each class are elected for three-year terms, and the terms of the three classes are staggered so that directors from a single class are elected at each annual meeting of stockholders. A staggered board makes it more difficult for shareholders to change the majority of the directors and instead promotes continuity of existing management.

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      Our Ability to Issue Preferred Stock. As discussed above, our board of directors can set the voting rights, redemption rights, conversion rights and other rights relating to authorized but unissued shares of preferred stock and could issue that stock in either private or public transactions. Preferred stock could be issued for the purpose of preventing a merger, tender offer or other takeover attempt which the board of directors opposes.

      Our Rights Plan. Our board of directors has adopted a stockholders’ rights plan. The rights attach to all common stock certificates representing outstanding shares. One right is issued for each share of common stock outstanding. Each right entitles the registered holder, under the circumstances described below, to purchase from us one one-thousandth of a share of our Series A Junior Participating Preferred Stock, a “Series A” share, at a price of $150.00 per one one-thousandth of a Series A share, subject to adjustment. The dividend and liquidation rights and the non-redemption feature of the Series A shares are designed so that the value of one one-thousandth of a Series A share purchasable upon exercise of each right will approximate the value of one share of common stock. The following is a summary of the terms of the rights plan. You should refer to the applicable provisions of the rights plan which we have incorporated by reference as an exhibit to the registration statement of which this prospectus is a part.

      The rights will separate from the common stock and right certificates will be distributed to the holders of common stock as of the earlier of:

	•	10 business days following a public announcement that a person or group of affiliated persons has acquired beneficial ownership of 15% or more of our outstanding voting shares, or
	•	10 business days following the commencement or announcement of an intention to commence a tender offer or exchange offer which would result in a person or group beneficially owning 15% or more of our outstanding voting shares.

      The rights are not exercisable until rights certificates are distributed. The rights will expire on July 31, 2007 unless that date is extended or the rights are earlier redeemed or exchanged.

      If a person or group (with certain exceptions for investment advisers) acquires 15% or more of our voting shares, each right then outstanding, other than rights beneficially owned by such person or group, becomes a right to buy that number of shares of common stock or other securities or assets having a market value of two times the exercise price of the right. The rights belonging to the acquiring person or group become null and void.

      If Swift is acquired in a merger or other business combination, or 50% of its consolidated assets or assets producing more than 50% of its earning power or cash flow are sold, each holder of a right will have the right to receive that number of shares of common stock of the acquiring company which at the time of such transaction has a market value of two times the purchase price of the right.

      At any time after a person or group acquires beneficial ownership of 15% or more of our outstanding voting shares and before the earlier of the two events described in the prior paragraph or acquisition by a person or group of beneficial ownership of 50% or more of our outstanding voting shares, our board of directors may, at its option, exchange the rights, other than those owned by such person or group, in whole or in part, at an exchange ratio of one share of common stock or a fractional share of Series A stock or other preferred stock equivalent in value thereto, per right.

      The Series A shares issuable upon exercise of the rights will be non-redeemable and rank junior to all other series of our preferred stock. Each whole Series A share will be entitled to receive a quarterly preferential dividend in an amount per share equal to the greater of $1.00 in cash, or in the aggregate, 1,000 times the dividend declared on the common stock, subject to adjustment. In the event of liquidation, the holders of Series A share may receive a preferential liquidation payment equal to the greater of $1,000 per share, or in the aggregate, 1,000 times the payment made on the shares of common stock. In the event of any merger, consolidation or other transaction in which the shares of common stock are exchanged for or changed into other stock or securities, cash or other property, each whole Series A share will be entitled to receive 1,000 times the amount received per share of common stock. Each whole

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      Prior to the earlier of the date it is determined that right certificates are to be distributed or the expiration date of the rights, our board of directors may redeem all, but not less than all, of the then outstanding rights at a price of $0.01 per right. Our board of directors in its sole discretion may establish the effective date and other terms and conditions of the redemption. Upon redemption, the ability to exercise the rights will terminate and the holders of rights will only be entitled to receive the redemption price.

      As long as the rights are redeemable, we may amend the rights agreement in any manner except to change the redemption price. After the rights are no longer redeemable, we may, except with respect to the redemption price, amend the rights agreement in any manner that does not adversely affect the interests of holders of the rights.

      Business Combinations Under Texas Law. Swift is a Texas corporation subject to Part Thirteen of the Texas Business Corporation Act known as the “Business Combination Law.” In general, the Business Combination Law prevents an affiliated shareholder, or its affiliates or associates, from entering into a business combination with an issuing public corporation during the three-year period immediately following the date on which the affiliated shareholder became an affiliated shareholder, unless:

	•	before the date such person became an affiliated shareholder, the board of directors of the issuing public corporation approves the business combination or the acquisition of shares that caused the affiliated shareholder to become an affiliated shareholder; or
	•	not less than six months after the date such person became an affiliated shareholder, the business combination is approved by the affirmative vote of holders of at least two-thirds of the issuing public corporation’s outstanding voting shares not beneficially owned by the affiliated shareholder, or its affiliates or associates.

An affiliated shareholder is a person that is or was within the preceding three-year period the beneficial owner of 20% or more of a corporation’s outstanding voting shares. An issuing public corporation includes most publicly held Texas corporations, including Swift. The term business combination includes:

	•	mergers, share exchanges or conversions involving the affiliated shareholder;
	•	dispositions of assets involving the affiliated shareholder having an aggregate value of 10% or more of the market value of the assets or of the outstanding common stock or representing 10% or more of the earning power or net income of the corporation;
	•	issuances or transfers of securities by the corporation to the affiliated shareholder other than on a pro rata basis;
	•	plans or agreements relating to a liquidation or dissolution of the corporation involving an affiliated shareholder;
	•	reclassifications, recapitalizations, distributions or other transactions that would have the effect of increasing the affiliated shareholder’s percentage ownership of the corporation; and
	•	the receipt of tax, guarantee, loan or other financial benefits by an affiliated shareholder other than proportionately as a shareholder of the corporation.

DESCRIPTION OF DEPOSITARY SHARES

      We may offer preferred stock represented by depositary shares and issue depositary receipts evidencing the depositary shares. Each depositary share will represent a fraction of a share of preferred stock. Shares of preferred stock of each class or series represented by depositary shares will be deposited under a separate deposit agreement among us, a bank or trust company acting as the “Depository” and the

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      If depositary shares are offered, the applicable prospectus supplement will describe the terms of such depositary shares, the deposit agreement and, if applicable, the depositary receipts, including the following, where applicable:

	•	the payment of dividends or other cash distributions to the holders of depositary receipts when such dividends or other cash distributions are made with respect to the preferred stock;
	•	the voting by a holder of depositary shares of the preferred stock underlying such depositary shares at any meeting called for such purpose;
	•	if applicable, the redemption of depositary shares upon a redemption by us of shares of preferred stock held by the Depository;
	•	if applicable, the exchange of depositary shares upon an exchange by us of shares of preferred stock held by the Depository for debt securities or common stock;
	•	if applicable, the conversion of the shares of preferred stock underlying the depositary shares into shares of our common stock, other shares of our preferred stock or our debt securities;
	•	the terms upon which the deposit agreement may be amended and terminated;
	•	a summary of the fees to be paid by us to the Depository;
	•	the terms upon which a Depository may resign or be removed by us; and
	•	any other terms of the depositary shares, the deposit agreement and the depositary receipts.

      If a holder of depositary receipts surrenders the depositary receipts at the corporate trust office of the Depository, unless the related depositary shares have previously been called for redemption, converted or exchanged into other securities of Swift, the holder will be entitled to receive at this office the number of shares of preferred stock and any money or other property represented by such depositary shares. Holders of depositary receipts will be entitled to receive whole and, to the extent provided by the applicable prospectus supplement, fractional shares of the preferred stock on the basis of the proportion of preferred stock represented by each depositary share as specified in the applicable prospectus supplement. Holders of shares of preferred stock received in exchange for depositary shares will no longer be entitled to receive depositary shares in exchange for shares of preferred stock. If the holder delivers depositary receipts evidencing a number of depositary shares that is more than the number of depositary shares representing the number of shares of preferred stock to be withdrawn, the Depository will issue the holder a new depositary receipt evidencing such excess number of depositary shares at the same time.

      Prospective purchasers of depositary shares should be aware that special tax, accounting and other considerations may be applicable to instruments such as depositary shares.

DESCRIPTION OF WARRANTS

      We may issue warrants for the purchase of preferred or common stock, either independently or together with other securities. Each series of warrants will be issued under a warrant agreement to be entered into between Swift and a bank or trust company. You should refer to the warrant agreement relating to the specific warrants being offered for the complete terms of such warrant agreement and the warrants.

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      Each warrant will entitle the holder to purchase the number of shares of preferred or common stock at the exercise price set forth in, or calculable as set forth in any applicable prospectus supplement. The exercise price may be subject to adjustment upon the occurrence of certain events, as set forth in any applicable prospectus supplement. After the close of business on the expiration date of the warrant, unexercised warrants will become void. The place or places where, and the manner in which, warrants may be exercised shall be specified in any applicable prospectus supplement.

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PLAN OF DISTRIBUTION

      We may sell the securities offered by this prospectus and applicable prospectus supplements:

	•	through underwriters or dealers;
	•	through agents;
	•	directly to purchasers; or
	•	through a combination of any such methods of sale.

Any such underwriter, dealer or agent may be deemed to be an underwriter within the meaning of the Securities Act of 1933.

      The applicable prospectus supplement relating to the securities will set forth:

	•	their offering terms, including the name or names of any underwriters, dealers or agents;
	•	the purchase price of the securities and the proceeds to us from such sale;
	•	any underwriting discounts, commissions and other items constituting compensation to underwriters, dealers or agents;
	•	any initial public offering price;
	•	any discounts or concessions allowed or reallowed or paid by underwriters or dealers to other dealers;
	•	in the case of debt securities, the interest rate, maturity and redemption provisions; and
	•	any securities exchanges on which the securities may be listed.

      If underwriters or dealers are used in the sale, the securities will be acquired by the underwriters or dealers for their own account and may be resold from time to time in one or more transactions in accordance with the rules of the New York Stock Exchange and the Pacific Stock Exchange:

	•	at a fixed price or prices which may be changed;
	•	at market prices prevailing at the time of sale;
	•	at prices related to such prevailing market prices; or
	•	at negotiated prices.

The securities may be offered to the public either through underwriting syndicates represented by one or more managing underwriters or directly by one or more of such firms. Unless otherwise set forth in an applicable prospectus supplement, the obligations of underwriters or dealers to purchase the securities will be subject to certain conditions precedent and the underwriters or dealers will be obligated to purchase all the securities if any are purchased. Any public offering price and any discounts or concessions allowed or reallowed or paid by underwriters or dealers to other dealers may be changed from time to time.

      Securities may be sold directly by us or through agents designated by us from time to time. Any agent involved in the offer or sale of the securities in respect of which this prospectus and a prospectus supplement is delivered will be named, and any commissions payable by us to such agent will be set forth, in the prospectus supplement. Unless otherwise indicated in the prospectus supplement, any such agent will be acting on a best efforts basis for the period of its appointment.

      If so indicated in the prospectus supplement, we will authorize underwriters, dealers or agents to solicit offers from certain specified institutions to purchase securities from us at the public offering price set forth in the prospectus supplement pursuant to delayed delivery contracts providing for payment and delivery on a specified date in the future. Such contracts will be subject to any conditions set forth in the prospectus supplement and the prospectus supplement will set forth the commission payable for solicitation

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      Underwriters, dealers and agents may be entitled under agreements entered into with us to be indemnified by us against certain civil liabilities, including liabilities under the Securities Act of 1933, or to contribution by Swift to payments which they may be required to make. The terms and conditions of such indemnification will be described in an applicable prospectus supplement. Underwriters, dealers and agents may be customers of, engage in transactions with, or perform services for, us in the ordinary course of business.

      Each class or series of securities will be a new issue of securities with no established trading market, other than the common stock, which is listed on the New York Stock Exchange and the Pacific Stock Exchange. We may elect to list any other class or series of securities on any exchange, other than the common stock, but we are not obligated to do so. Any underwriters to whom securities are sold by us for public offering and sale may make a market in such securities, but such underwriters will not be obligated to do so and may discontinue any market making at any time without notice. No assurance can be given as to the liquidity of the trading market for any securities.

      Certain persons participating in any offering of securities may engage in transactions that stabilize, maintain or otherwise affect the price of the securities offered. In connection with any such offering, the underwriters or agents, as the case may be, may purchase and sell securities in the open market. These transactions may include overallotment and stabilizing transactions and purchases to cover syndicate short positions created in connection with the offering. Stabilizing transactions consist of certain bids or purchases for the purpose of preventing or retarding a decline in the market price of the securities; and syndicate short positions involve the sale by the underwriters or agents, as the case may be, of a greater number of securities than they are required to purchase from us, as the case may be, in the offering. The underwriters may also impose a penalty bid, whereby selling concessions allowed to syndicate members or other broker-dealers for the securities sold for their account may be reclaimed by the syndicate if such securities are repurchased by the syndicate in stabilizing or covering transactions. These activities may stabilize, maintain or otherwise affect the market price of the securities, which may be higher than the price that might otherwise prevail in the open market, and if commenced, may be discontinued at any time. These transactions may be effected on the New York Stock Exchange, the Pacific Stock Exchange, in the over-the-counter market or otherwise. These activities will be described in more detail in the sections entitled “Plan of Distribution” or “Underwriting” in the applicable prospectus supplement.

LEGAL OPINIONS

      Jenkens & Gilchrist, A Professional Corporation, Houston, Texas, will issue an opinion for Swift regarding the legality of the securities offered by this prospectus and applicable prospectus supplement. If the securities are being distributed in an underwritten offering, certain legal matters will be passed upon for the underwriters by counsel identified in the applicable prospectus supplement.

EXPERTS

      The consolidated financial statements of Swift Energy Company as of December 31, 2003 and 2002 and for each of the two years in the period ended December 31, 2003, appearing in Swift Energy Company’s Annual Report (Form 10-K) for the year ended December 31, 2003, have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon included therein and incorporated herein by reference. Such consolidated financial statements are incorporated herein by reference in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

      The consolidated financial statements of Swift Energy Company at December 31, 2001 and for the year ended December 31, 2001 appearing in Swift Energy Company’s Annual Report on Form 10-K for the year ended December 31, 2003 have been audited by Arthur Andersen LLP, independent auditors, as

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      Because Arthur Andersen is no longer in a position to consent to the inclusion or incorporation by reference in any prospectus or registration statement of its report on such financial statements, we are not able to obtain, and have not filed, Arthur Andersen’s consent in reliance on Rule 437(a) under the Securities Act of 1933. Consequently, your ability to assert claims against Arthur Andersen LLP will be limited. In particular, because of this lack of consent, you will not be able to sue Arthur Andersen LLP under Section 11(a)(4) of the Securities Act for any untrue statement of a material fact contained in the financial statements audited by Arthur Andersen LLP or any omissions to state a material fact required to be stated in those financial statements. Therefore, your right of recovery against Arthur Andersen under that section will be limited.

      On June 18, 2002, we filed a Current Report on Form 8-K announcing that our board of directors, acting upon the recommendation of our audit committee, engaged Ernst & Young LLP as our independent public accountants for fiscal 2002, replacing Arthur Andersen LLP. The decision to change independent public accountants was not the result of any disagreement with Arthur Andersen LLP on matters of accounting principles or practices, financial statement disclosure or auditing scope and procedure.

      Information referenced or incorporated by reference in this prospectus regarding our estimated quantities of oil and gas reserves and the discounted present value of future net cash flows therefrom is based upon estimates of such reserves and present values audited by H.J. Gruy and Associates, Inc., independent petroleum engineers.

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