e424b4

424B4 1 d24464b4e424b4.htm PROSPECTUS e424b4

Filed Pursuant to Rule 424(b)(4)

File Number 333-124797

File Number 333-126952

10,200,000 Shares

Alon USA Energy, Inc.

Common Stock

Prior to this offering, there has been no public market for our common stock. The initial public offering price of our common stock is $16.00 per share. Our common stock has been approved for listing on the New York Stock Exchange under the symbol “ALJ.”

The underwriters have an option to purchase a maximum of 1,530,000 additional shares from us to cover over-allotments of shares.

Investing in our common stock involves risks. See “Risk Factors” beginning on page 12.


			Underwriting
			Discounts and		Proceeds to
	Price to Public		Commissions		Alon USA Energy, Inc.

Per Share		$16.00		$1.12		$14.88
Total		$163,200,000		$11,424,000		$151,776,000

Delivery of the shares of common stock will be made on or about August 2, 2005.

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.


Credit Suisse First Boston	Deutsche Bank Securities	Lehman Brothers

The date of this prospectus is July 28, 2005.

TABLE OF CONTENTS


	Page

PROSPECTUS SUMMARY		1
RISK FACTORS		12
FORWARD-LOOKING STATEMENTS		23
USE OF PROCEEDS		24
DIVIDEND POLICY		24
CAPITALIZATION		25
DILUTION		26
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION		27
SELECTED HISTORICAL CONSOLIDATED AND COMBINED FINANCIAL AND OPERATING DATA		30
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		34
REFINING INDUSTRY OVERVIEW		59
BUSINESS		62
MANAGEMENT		79
PRINCIPAL STOCKHOLDERS		89
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS		93
DESCRIPTION OF CAPITAL STOCK		98
SHARES ELIGIBLE FOR FUTURE SALE		102
U.S. FEDERAL TAX CONSEQUENCES TO NON-U.S. HOLDERS OF COMMON STOCK		104
UNDERWRITING		107
NOTICE TO CANADIAN RESIDENTS		110
LEGAL MATTERS		111
EXPERTS		111
WHERE YOU CAN FIND MORE INFORMATION		111
GLOSSARY OF SELECTED TERMS		112
INDEX TO FINANCIAL STATEMENTS		F-1

You should rely only on the information contained in this document or to which we have referred you. We have not authorized anyone to provide you with information that is different. This document may be used only where it is legal to sell these securities. The information in this document may be accurate only on the date of this document.

Dealer Prospectus Delivery Obligation

Until August 22, 2005 (25 days after the commencement of this offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

Industry and Market Data

Industry and market data used throughout this prospectus were obtained through studies conducted by third parties and industry and general publications. The prices of crude oil and gasoline given in this prospectus are based upon information published by Platt’s Oilgram News.

Company References

In this prospectus, unless otherwise specified or the context otherwise requires, “Alon,” “we,” “us” and “our” refer to Alon USA Energy, Inc., a holding company incorporated in Delaware and the issuer of common stock in this offering, and its subsidiaries. In addition, references to the following terms are to the entities named:


Alon Israel		Alon Israel Oil Company, Ltd., an Israeli limited liability company and the direct parent of Alon USA Energy, Inc.
Alon USA		Alon USA, Inc., a Delaware corporation and a subsidiary of Alon USA Energy, Inc.
Alon Operating		Alon USA Operating, Inc., a Delaware corporation and a subsidiary of Alon USA.
Alon Capital		Alon USA Capital, Inc., a Delaware corporation and a subsidiary of Alon USA.
Alon Assets		Alon Assets, Inc., a Delaware corporation and a subsidiary of Alon Capital.
SCS		Southwest Convenience Stores, LLC, a Texas limited liability company and an indirect subsidiary of Alon Operating.
Fina		Atofina Petrochemicals, Inc.
Our predecessor		Our business under the ownership of Fina.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary does not contain all of the information that may be important to you. You should read this entire prospectus carefully, including the risks discussed under “Risk Factors” and the financial statements and notes thereto included elsewhere in this prospectus. In this prospectus, all references to “Alon,” “we,” “us” and “our” refer to Alon USA Energy, Inc. and its subsidiaries unless the context otherwise requires or where otherwise indicated. You should refer to the “Glossary of Selected Terms” beginning on page 112 for definitions of some of the terms we use to describe our business and industry.

Alon

We are an independent refiner and marketer of petroleum products operating primarily in the Southwestern and South Central regions of the United States. Our business consists of two operating segments: (1) refining and marketing and (2) retail. Our business is physically integrated, with the majority of our refinery’s production being distributed through our product pipeline and terminal network to our wholesale customers and our retail segment.

We own and operate a sophisticated sour crude oil refinery in Big Spring, Texas, our Big Spring refinery, which we recently expanded from a crude oil throughput capacity of 62,000 barrels per day, or bpd, to 70,000 bpd. We own a crude oil pipeline system totaling approximately 500 miles. Our product pipeline and terminal network consists of seven product pipelines totaling approximately 840 miles and six product terminals, which we own or access through leases or long-term throughput agreements. We market our gasoline and diesel products under the FINA brand name to approximately 1,300 retail sites. We also market unbranded gasoline, diesel, jet fuel and other refinery products, and we are one of the largest suppliers of asphalt in West Texas, New Mexico and Arizona.

As of March 31, 2005, we operated 167 7-Eleven branded convenience stores in West Texas and New Mexico. Our convenience stores typically offer merchandise, food products and motor fuels under the 7-Eleven and FINA brand names. 7-Eleven has advised us that we are the largest 7-Eleven licensee in the United States, and we are one of the top three convenience store operators, based on number of stores, in the cities of El Paso, Midland, Odessa, Big Spring and Lubbock, Texas. We also have a significant presence in Wichita Falls, Texas and Albuquerque, New Mexico. We supply our stores with substantially all of their motor fuel needs through our product pipeline and terminal network.

Our parent company, Alon Israel, is the largest services and trade company in Israel. Alon Israel entered the gasoline marketing and convenience store business in Israel in 1989 and has grown to become a leading marketer of petroleum products and one of the largest operators of retail gasoline and convenience stores in Israel. Alon Israel is a controlling shareholder of Blue Square Israel, Ltd., a leading retailer in Israel, which is listed on the New York Stock Exchange and the Tel Aviv Stock Exchange.

Refining and Marketing Segment

We acquired our Big Spring refinery and certain crude oil pipelines, product pipelines and product terminals from Fina in August 2000. In connection with this acquisition, we retained substantially all of the Fina management and employees associated with the assets we purchased.

Our Big Spring refinery has the capability to process substantial volumes of less expensive high-sulfur, or sour, crude oils to produce a high percentage of light, high-value refined products. Typically, sour crude oil has accounted for over 90% of our crude oil input, of which approximately 99% has been West Texas Sour, or WTS, crude oil. We also have access to domestic and foreign crude oils available on the Gulf Coast, which we are able to deliver to our Big Spring refinery through our Amdel pipeline. We currently convert approximately 86% of our feedstock into light, high-value products such as gasoline, diesel, jet fuel and petrochemicals, with the remaining 14% consisting primarily of asphalt and liquefied petroleum gas.

We conduct the majority of our operations in West Texas, Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in this region as our physically integrated system because we are able to supply our branded and unbranded distributors in this region with motor fuels produced at our Big Spring refinery and distributed through our product pipeline and terminal network. Our physically integrated system includes our retail segment convenience stores and nearly 400 other FINA branded retail sites. We also operate in East Texas and Arkansas. We refer to our operations in this region as our non-integrated system because we supply our branded and unbranded distributors in this region with motor fuels obtained from third parties.

Retail Segment

Our 167 convenience stores typically sell general merchandise, food products and motor fuels. Substantially all of the motor fuel sold by our retail stores is produced at our Big Spring refinery and transported to our retail sites through our product pipeline and terminal network. During 2004, we sold over 97.5 million gallons of motor fuels through our retail segment, representing approximately 13% of the motor fuel produced at our Big Spring refinery. Our retail segment provides a relatively stable and secure outlet for a significant portion of our Big Spring refinery’s motor fuel production. In addition, non-fuel sales by our retail segment provide us with a diverse source of revenues to complement our refining and marketing revenues. We believe this secure outlet and diversification provide us with advantages over our competitors who lack retail operations.

Competitive Strengths

Physically Integrated Refining and Marketing System. Our pipeline and terminal network provides us with the flexibility to: (1) access a variety of crude oils, thereby allowing us to optimize our refinery’s crude supply; (2) efficiently distribute our motor fuel products to markets in West Texas, Central Texas and Oklahoma; and (3) access other markets, including New Mexico and Arizona, through interconnections with third-party transportation systems. Our physically integrated system also allows us to achieve cost efficiencies that are not available to our competitors who are not similarly integrated.

Sophisticated Refinery with Cost and Supply Advantages. Our Big Spring refinery ranks in the second quartile of all refineries in the United States in terms of net cash margin per barrel as reported in the most recent Solomon Associates competitive analysis. Our refinery’s high relative net cash margin per barrel is due primarily to:


	•	our ability to process substantial volumes of sour crude oil;

	•	our low relative transportation cost to source WTS crude oil due to the refinery’s location in the Permian Basin;

	•	our ability to access domestic and foreign crude oils through our Amdel pipeline when processing such crude oils allows us to improve our margins; and

	•	the higher value we are able to realize from our asphalt production as compared to the value of alternative products, such as No. 6 Fuel Oil.

Ability to Process Substantial Volumes of Sour Crude Oil. Typically, over 90% of the crude oil processed at our Big Spring refinery is sour crude oil. Sour crude oils cost less than low sulfur, or sweet, crude oils such as West Texas Intermediate, or WTI, which results in lower feedstock costs and provides us with a competitive advantage over refineries that lack the ability to process substantial volumes of sour crude oil.

Leading Producer of Asphalt Products. The Texas Department of Transportation has advised us that we are the second largest supplier of asphalt to the State of Texas, which is the largest asphalt consuming state in the United States. We produce many advanced asphalt products such as rubberized asphalt, PMA and GTR, which are increasingly specified by government agencies for use in highway projects in the State of Texas. Our refinery can produce up to 23 different asphalt product formulations.

Strong Brand Recognition. The FINA brand is well-known in the Southwestern and South Central United States, where motor fuels have been marketed under the FINA brand since 1963. We have an exclusive license to market gasoline, diesel and jet fuels under the FINA brand in Texas, Oklahoma, New Mexico and five other states through July 2012. 7-Eleven has advised us that we are the largest 7-Eleven licensee in the United States, and we have an exclusive license to use the 7-Eleven brand in West Texas and most of New Mexico. 7-Eleven is one of the largest convenience store chains in the United States.

Proven Retail Marketing Expertise. Our retail operations benefit from the combination of our strengths in retail marketing and those of Alon Israel. Since acquiring 100.0% of our retail operations in 2001, we have improved per store fuel sales volumes, fuel sales margins and merchandise sales.

Experienced Leadership. A number of our executive officers and key operating personnel, including our Chief Executive Officer, have spent the majority of their careers operating our Big Spring refinery and have successfully managed our business through multiple industry cycles. Since our acquisition from Fina, our management team has completed a number of strategic transactions that have strengthened our financial condition and positioned us for future growth. We also benefit from the management and transactional experience provided by Alon Israel, which has grown since its formation in 1989 to become the largest services and trade company in Israel.

Strategy

Our objective is to increase stockholder value through sustained earnings and cash flow growth. Our principal strategies to achieve this objective are to:

Increase the Capacity and Yields of Our Refinery. We regularly evaluate ways to improve the profitability of our Big Spring refinery through cost-effective upgrades and expansions. We have identified a project to further expand our Big Spring refinery’s crude oil throughput capacity to 75,000 bpd, and we are evaluating other projects to increase our light product yields.

Expand Our Physically Integrated System. We intend to expand our crude oil and product pipeline systems to enhance our ability to access optimal crude oil supplies and to increase the volume and profitability of our integrated product distribution system.

Enhance and Expand Our Retail Operations. We intend to continue to leverage our relationships with 7-Eleven and Alon Israel to increase our same store sales and profitability and to adopt innovative technologies to enhance our convenience store operations. We also intend to increase the number of our retail outlets in West Texas and New Mexico.

Continue to Increase Our Asphalt Production and Margins. We are planning to increase the ratio of our high-value to low-value asphalt grades to realize the greater margins associated with the higher value products. Pursuant to this strategy, we constructed a GTR asphalt plant adjacent to our Big Spring refinery and acquired an 85% interest in an asphalt blending terminal in Bakersfield, California. We plan to purchase or build additional asphalt blending terminals to expand our market penetration and increase our sales of higher margin asphalt grades.

Grow through Selective Acquisitions. Our growth strategy is focused on the expansion of our physically integrated system and the acquisition of complementary refining and retail assets. We believe the consummation of this offering will enhance our capability to realize significant growth opportunities.

Market Trends

We have identified several key factors that we believe support a favorable outlook for the U.S. refining industry:


	•	High capital costs, excess capacity and environmental regulatory requirements have limited the construction of new refineries in the United States over the past thirty years. No new major refinery has been built in the United States since 1976. In addition, more than 190 refineries have been shut down since 1981.

	•	The United States is increasingly reliant on imports to satisfy demand for refined products.

	•	The supply and demand fundamentals of the domestic refining industry have improved since the 1990s and are expected to remain favorable as the demand for refined products continues to exceed increases in refining capacity, both on a global basis and in the United States.

	•	New and evolving fuel specifications, including ultra-low sulfur content, reduced vapor pressure and the addition of oxygenates such as ethanol, should benefit complex refiners who are able to efficiently produce fuels that meet these specifications.

	•	Increased demand for sweet crude oils and higher incremental production of lower cost sour crude oils is expected to provide a cost advantage to complex refiners with the ability to process sour crude oils.

Recent Developments

2005 Turnaround and Refinery Expansion. In March 2005, we successfully completed a major turnaround at our Big Spring refinery. We believe the completion of this project will permit us to operate our Big Spring refinery without significant planned maintenance shut downs for the next four to five years. In connection with this turnaround, we expanded our crude oil throughput capacity from 62,000 bpd to 70,000 bpd at a cost of $6.4 million, or $800 per bpd of additional throughput capacity. We expect this 8,000 bpd expansion to positively affect our operating results by increasing our refining margin and decreasing our per barrel operating costs.

HEP Transaction. On February 28, 2005, we completed the contribution of three product pipelines and three product terminals to Holly Energy Partners, L.P., or HEP, including our Trust and River pipelines, which we acquired for approximately $9.4 million in June 2004. In exchange for this contribution, which we refer to as the HEP transaction, we received $120 million in cash and 937,500 subordinated Class B limited partnership units in HEP. Simultaneously with this transaction, we entered into a Pipelines and Terminals Agreement with HEP with an initial term of 15 years and three additional five-year renewal terms exercisable at our option. Pursuant to the Pipelines and Terminals Agreement, we have committed to transport and store minimum volumes of refined products in these pipelines and terminals and to pay specified tariffs and fees during the term of such agreement. See “Business — Pipelines and Product Terminals — HEP Transaction.”

Recent Financial Results. We preliminarily estimate that operating income for the second quarter of 2005 will be approximately $48 million to $51 million as compared to $33.6 million for the second quarter of 2004. Operating income for the six months ended June 30, 2005, is preliminarily estimated to be approximately $92 million to $95 million as compared to $42.4 million for the six months ended June 30, 2004. We preliminarily estimate that, as of June 30, 2005, our cash and cash equivalents balance was approximately $165 million, and our total debt outstanding was approximately $158 million.

The expected increase in second quarter 2005 operating income as compared to second quarter of 2004 operating income is primarily attributable to higher refinery operating margins and the additional refinery throughput volumes as a result of the expansion of our Big Spring refinery’s throughput capacity in the first quarter of 2005.

The preliminary estimates of our operating income for the second quarter of 2005 and the six months ended June 30, 2005, and our cash balance and total debt as of June 30, 2005, are not final and are subject to further review. Accordingly, our actual operating income for the second quarter of 2005 and the six months ended June 30, 2005, and our cash balance and total debt as of June 30, 2005, could differ from our estimates, and any such difference could be significant. We are currently performing our quarterly internal review procedures for the three months and six months ended June 30, 2005, prior to our independent public accounting firm’s completion of its interim review. You should consider this additional information in conjunction with the audited consolidated financial statements for the three-year period ended December 31, 2004 and the unaudited consolidated financial statements for the three months ended March 31, 2005 and 2004, as well as “Risk Factors,” “Forward-Looking Statements,” “Selected Historical Consolidated and Combined Financial and Operating Data,” “Unaudited Pro Forma Condensed Consolidated Financial Information” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this prospectus.

Risks Affecting Us

Our business is subject to numerous risks as discussed more fully in the section entitled “Risk Factors” immediately following this Prospectus Summary. We believe that the most significant of these risks include the following:


	•	price volatility of crude oil, other feedstocks, refined products and fuel and utility sources;

	•	significant increases in crude oil prices;

	•	conduct of our refining operations through a single refinery; and

	•	competition in the refining and marketing industry and retail industry.

The Offering


Common stock offered by us		10,200,000 shares (or 11,730,000 shares, if the underwriters exercise their over-allotment option in full)

Common stock to be outstanding after the offering		45,201,120 shares

NYSE symbol		ALJ

Use of proceeds		We estimate that the net proceeds to us from this offering will be approximately $149.8 million, or approximately $172.5 million if the underwriters exercise their over-allotment option in full. We plan to use these net proceeds to repay certain of our existing indebtedness, to pay dividends to our stockholders of record prior to this offering and for general corporate purposes, including loans to our subsidiaries, discretionary and non-discretionary capital expenditures.

Dividend policy		We intend to pay quarterly cash dividends on our common stock at an initial annual rate of $0.16 per share commencing in the first quarter of 2006. The declaration and payment of future dividends to holders of our common stock will be at the discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, legal requirements, restrictions in our debt agreements and other factors our board of directors deems relevant.

Risk Factors		You should carefully read and consider the information set forth under “Risk Factors,” together with all of the other information set forth in this prospectus, before deciding to invest in shares of our common stock.

Unless we indicate otherwise, the number of shares of common stock shown to be outstanding after the offering:


	•	gives effect to a 33,600-for-one stock split of our common stock, effected on July 6, 2005;

	•	excludes 2,200,000 shares of common stock reserved for issuance under our Incentive Plan; and

	•	assumes no exercise by the underwriters of their option to purchase up to 1,530,000 additional shares from us to cover over-allotments of shares.

Our Executive Offices

Our principal executive offices are located at 7616 LBJ Freeway, Suite 300, Dallas, Texas 75251-1100, and our telephone number at this address is (972) 367-3600. Our website is www.alonusa.com. Information on, or accessible through, this website is not a part of, and is not incorporated into, this prospectus.

Summary Consolidated Financial and Operating Data

The following tables set forth our summary consolidated financial and operating data for the periods indicated below. The summary consolidated statement of operations data for the years ended December 31, 2002, 2003 and 2004, and the summary consolidated balance sheet data as of December 31, 2003 and 2004, have been derived from our audited consolidated financial statements, which are included elsewhere in this prospectus. The summary consolidated balance sheet data as of December 31, 2002, have been derived from our audited consolidated balance sheet as of December 31, 2002, which is not included in this prospectus.

The summary consolidated financial data as of and for the three months ended March 31, 2004 and 2005 are derived from our unaudited consolidated financial statements, which are included elsewhere in this prospectus. We have prepared our unaudited consolidated financial statements on the same basis as our audited consolidated financial statements and have included all adjustments, consisting of normal and recurring adjustments, that we consider necessary for a fair presentation of our financial position and operating results for the unaudited periods. The summary consolidated financial and operating data as of and for the three months ended March 31, 2005 are not necessarily indicative of the results that may be obtained for a full year.

Earnings per share data are based upon the weighted average number of shares outstanding during the periods presented, as adjusted for the 33,600-for-one stock split, and do not reflect the increase in outstanding shares that will result from this offering.

The information presented below should be read in conjunction with “Use of Proceeds,” “Capitalization,” “Unaudited Pro Forma Condensed Consolidated Financial Information,” “Selected Historical Consolidated and Combined Financial and Operating Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and the notes thereto included elsewhere in this prospectus.


										Three Months Ended
			Year Ended December 31,							March 31,

			2002		2003		2004			2004			2005

			(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
Net sales			$	1,207,723	$	1,410,766	$	1,707,564		$	352,723		$	407,974
Operating costs and expenses:
	Cost of sales(a)			1,044,675		1,215,032		1,469,940			302,980			351,554
	Direct operating expenses			53,696		66,113		75,742			18,912			18,336
	Selling, general and administration expenses			69,439		69,066		73,554			17,318			16,665
	Depreciation and amortization			14,853		18,262		19,064			4,762			4,834

		Total operating costs and expenses		1,182,663		1,368,473		1,638,300			343,972			391,389

Gain on disposition of assets(b)				—		—		175			—			27,693

Operating income				25,060		42,293		69,439			8,751			44,278
Interest expense				14,385		16,284		23,704			6,015			5,007
Equity (earnings) in investee				—		—		—			—			(135	)
Other (income) expense, net				381		1,819		(277	)		(93	)		(250	)
Income tax expense				3,913		9,105		18,315			1,119			15,655
Minority interest in income of subsidiaries				2,029		681		2,565			213			1,565

Net income before accounting change				4,352		14,404		25,132			1,497			22,436
Cumulative effect of adoption of accounting principle				—		336		—			—			—

Net income			$	4,352	$	14,068	$	25,132		$	1,497		$	22,436

Earnings per share, basic and diluted(c)			$	.12	$	.40	$	.72		$	.04		$	.64
Weighted average shares, basic and diluted				35,001,120		35,001,120		35,001,120			35,001,120			35,001,120


											Three Months Ended
		Year Ended December 31,									March 31,

		2002			2003			2004			2004			2005

		(dollars in thousands, except per barrel data)
CASH FLOW DATA:
Net cash provided by (used in):
	Operating activities	$	5,001		$	76,173		$	76,743		$	(11,200	)	$	(16,437	)
	Investing activities		(70,918	)		(34,664	)		(39,886	)		(2,232	)		96,520
	Financing activities		62,238			(39,667	)		19,244			29,412			(34,451	)

OTHER DATA:
Adjusted EBITDA(d)			39,532			58,400			88,605			13,606			21,804
Capital expenditures, net of disposition proceeds(e)			66,967			33,117			37,564			1,142			(106,902	)
Capital expenditures for turnarounds and catalysts			3,951			1,547			2,322			1,090			10,382

BALANCE SHEET DATA (end of period):
Cash and equivalents		$	5,414		$	7,256		$	63,357		$	23,236		$	108,989
Working capital			30,962			5,071			44,443			53,991			116,924
Total assets			392,066			386,982			472,516			436,111			553,801
Total debt			214,539			166,816			187,706			202,481			158,155
Stockholders’ equity			33,128			46,923			71,472			48,560			93,908

KEY OPERATING STATISTICS:
Refining and marketing:
Total sales volume (bpd)			93,691			90,914			85,950			82,153			72,253
Non-integrated marketing sales volume (bpd)(f)			25,867			24,093			19,926			19,734			20,061
Non-integrated marketing margin (per barrel sales volume)(f)		$	0.44		$	0.52		$	0.03		$	0.03		$	(0.93	)
Total refinery throughput (bpd)(g)			60,906			64,354			61,664			61,851			47,447
Per barrel of throughput:
	Refinery operating margin(h)	$	4.65		$	5.80		$	8.03		$	6.58		$	10.56
	Direct operating expenses		2.42			2.81			3.36			3.36			4.29

Retail:
Number of stores (end of period)			170			170			167			168			167
Fuel sales (thousands of gallons)			91,882			100,389			97,541			24,001			23,387
Fuel sales (thousands of gallons per site per month)			45			50			49			48			48
Fuel margin (cents per gallon)(i)			10.1	¢		11.9	¢		12.9	¢		10.9	¢		12.9	¢
Merchandise sales		$	128,260		$	130,413		$	130,117		$	30,652		$	29,994
Merchandise sales (per site per month)			63			64			65			61			60
Merchandise margin(j)			36.1	%		33.0	%		33.5	%		32.7	%		33.3	%


(a)		2002 cost of sales reflects an $18.6 million credit associated with our LIFO inventory valuation methodology. We account for our finished product and raw materials inventories under the LIFO inventory valuation method. In 2001, market prices fell below LIFO costs, resulting in a $23.2 million charge to cost of sales. In 2002, market prices recovered significantly, allowing us to recover $18.6 million of the 2001 inventory write-down. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies.”

(b)		Gain on disposition of assets reported in the three months ended March 31, 2005, reflects the initial pre-tax gain recognized in connection with assets contributed in the HEP transaction and one month’s recognition of the deferred gain recorded in connection with the HEP transaction. The transaction was recorded as a partial sale for accounting purposes. See “Business — Pipelines and Product Terminals — HEP Transaction” for additional information related to the HEP transaction.

(c)		If, for purposes of calculating earnings per share, basic and diluted, for the year ended December 31, 2004 and the three months ended March 31, 2005, the weighted average shares, basic and diluted, outstanding during such periods were increased by the 10,200,000 shares offered hereby, the resulting earnings per share, basic and diluted, for such periods would be $0.56 and $0.50, respectively.

(d)		Adjusted EBITDA represents earnings before minority interest, income tax expense, interest expense, depreciation, amortization and gain on dispositions of assets. However, Adjusted EBITDA is not a recognized measurement under GAAP. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of minority interests, financings, income taxes and dispositions of assets and the accounting effects of capital expenditures and acquisitions, items which may vary for different companies for reasons unrelated to overall operating


		performance. Adjusted EBITDA, with adjustments specified in our credit agreements, is also the basis for calculating selected financial ratios as required in the debt covenants in our credit agreements. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Cash Position and Indebtedness.”


	Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:


	•	Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

	•	Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;

	•	Adjusted EBITDA does not reflect the prior claim that minority stockholders have on the income generated by our non-wholly-owned subsidiaries;

	•	Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and

	•	Our calculation of Adjusted EBITDA may differ from the EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.


	Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.

	The following table reconciles net income to Adjusted EBITDA for the periods presented:


									Three Months
		Year Ended December 31,							Ended March 31,

		2002		2003		2004			2004		2005

		(dollars in thousands)
Net income		$	4,352	$	14,068	$	25,132		$	1,497	$	22,436
	Minority interest		2,029		681		2,565			213		1,565
	Income tax expense		3,913		9,105		18,315			1,119		15,655
	Interest expense		14,385		16,284		23,704			6,015		5,007
	Depreciation and amortization		14,853		18,262		19,064			4,762		4,834
	Gain on disposition of assets		—		—		(175	)		—		(27,693	)

Adjusted EBITDA		$	39,532	$	58,400	$	88,605		$	13,606	$	21,804


(e)		Capital expenditures include $40.4 million, $10.0 million and $10.0 million paid in 2002, 2003 and 2004, respectively, in connection with our acquisition of the 40% equity interest in Alon Capital that was previously owned by third parties. Capital expenditures for the three months ended March 31, 2005 are net of $118.0 million of net cash proceeds received in the HEP transaction. See “Business — Pipelines and Product Terminals — HEP Transaction” for additional information related to the HEP transaction.

(f)		The non-integrated marketing sales volume represents refined products sales to our wholesale marketing customers located in our non-integrated region. The refined products we sell in this region are obtained from third-party suppliers. The non-integrated marketing margin represents the margin between the net sales and cost of sales attributable to our non-integrated refined products sales volume, expressed on a per barrel basis.

(g)		Refinery throughput represents the total of crude oil and blendstock inputs in the refinery production process.

(h)		Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales attributable to our refining and marketing segment, exclusive of net sales and cost of sales relating to our non-integrated system, by our Big Spring refinery’s throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margin to these crack spreads to assess our operating performance relative to other participants in our industry.

(i)		Fuel margin represents the difference between motor fuel revenues and the net cost of purchased fuel, including transportation costs and associated motor fuel taxes, expressed on a cents per gallon basis. Motor fuel margins are frequently used in the retail industry to measure operating results related to motor fuel sales.

(j)		Merchandise margin represents the difference between merchandise sales revenues and the delivered cost of merchandise purchases, net of rebates and commissions, expressed as a percentage of merchandise sales revenues. Merchandise margins, also referred to as in-store margins, are commonly used in the retail industry to measure in-store, or non-fuel, operating results.

Summary Pro Forma Financial Information

On February 28, 2005, we completed the contribution of three product pipelines and three product terminals to HEP. In exchange for this contribution, we received $120 million in cash and 937,500 subordinated Class B limited partnership units in HEP. Simultaneously with this transaction, we entered into a Pipelines and Terminals Agreement with HEP with an initial term of 15 years and three additional five-year renewal terms exercisable at our option. Pursuant to the Pipelines and Terminals Agreement, we have agreed to transport and store minimum volumes of refined products in these pipelines and terminals and to pay specified tariffs and fees for such transportation and storage during the term of such agreement.

The following summary pro forma financial information for the year ended December 31, 2004 and the three months ended March 31, 2005, is derived from the unaudited pro forma statements of operations contained under “Unaudited Pro Forma Condensed Consolidated Financial Information.” This information gives effect to the HEP transaction and the repayment of $25 million of indebtedness with a portion of the proceeds therefrom as if each such transaction had occurred on January 1, 2004. This information does not give effect to this offering or the application of the net proceeds thereof, including the effect of this offering on interest expense, the termination of our payment obligations under our management and consulting agreement with Alon Israel or the recent expansion of our Big Spring refinery’s crude oil throughput capacity from 62,000 bpd to 70,000 bpd. Earnings per share data are based upon the weighted average number of shares outstanding during the periods presented, as adjusted for the 33,600-for-one stock split, and do not reflect the increase in outstanding shares that will result from this offering.

The following summary pro forma financial information is presented for informational purposes only and does not purport to represent or be indicative of the results that actually would have been obtained had the transactions described above occurred on January 1, 2004 or that may be obtained for any future period.

The information presented below should be read in conjunction with “Use of Proceeds,” “Capitalization,” “Unaudited Pro Forma Condensed Consolidated Financial Information,” “Selected Historical Consolidated and Combined Financial and Operating Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and notes thereto included elsewhere in this prospectus.


						Three Months
			Year Ended			Ended
			December 31, 2004			March 31, 2005

			(dollars in thousands,
			except per share data)
STATEMENT OF OPERATIONS DATA:
Net sales			$	1,707,564		$	407,974
Operating costs and expenses:
	Cost of sales			1,485,346			354,337
	Direct operating expenses			75,742			18,336
	Selling, general and administrative expenses			73,554			16,665
	Depreciation and amortization			17,414			4,565

		Total operating costs and expenses		1,652,056			393,903

Gain on disposition of assets				175			—

Operating income				55,683			14,071
Interest expense				21,954			4,695
Equity (earnings) in investee				(599	)		(314	)
Other (income), net				(277	)		(250	)
Income tax expense				13,810			3,917
Minority interest in income of subsidiaries				1,987			558

Net income			$	18,808		$	5,465

Earnings per share, basic and diluted			$	.54		$	.16
Weighted average shares, basic and diluted				35,001,120			35,001,120


				Three Months
		Year Ended		Ended
		December 31, 2004		March 31, 2005

		(dollars in thousands, except
		per barrel data)
OTHER DATA:
Adjusted EBITDA(a)		$	73,798	$	19,200
Per barrel of throughput:
	Refinery operating margin(b)	$	7.35	$	9.91
	Direct operating expenses		3.36		4.29


(a)		Adjusted EBITDA represents earnings before minority interest, income tax expense, interest expense, depreciation, amortization and gain on dispositions of assets. However, Adjusted EBITDA is not a recognized measurement under GAAP. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of minority interests, financings, income taxes and dispositions of assets and the accounting effects of capital expenditures and acquisitions, items which may vary for different companies for reasons unrelated to overall operating performance. Adjusted EBITDA, with adjustments specified in our credit agreements, is also the basis for calculating selected financial ratios as required in the debt covenants in our credit agreements. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Cash Position and Indebtedness.”


		Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:


	•	Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

	•	Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;

	•	Adjusted EBITDA does not reflect the prior claim that minority stockholders have on the income generated by our non-wholly-owned subsidiaries;

	•	Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and

	•	Our calculation of Adjusted EBITDA may differ from the EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.


		Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.

		The following table reconciles pro forma net income to pro forma Adjusted EBITDA for the periods presented:


		Year Ended			Three Months
		December 31, 2004			Ended March 31, 2005

		(dollars in thousands)
Net income		$	18,808		$	5,465
	Minority interest		1,987			558
	Income tax expense		13,810			3,917
	Interest expense		21,954			4,695
	Depreciation and amortization		17,414			4,565
	Gain on disposition of assets		(175	)		—

Adjusted EBITDA		$	73,798		$	19,200


(b)		Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales attributable to our refining and marketing segment, exclusive of net sales and cost of sales relating to our non-integrated system, by our Big Spring refinery’s throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margin to these crack spreads to assess our operating performance relative to other participants in our industry.

RISK FACTORS

An investment in our common stock involves various risks. Before making an investment in our common stock, you should carefully consider the following risks, as well as the other information contained in this prospectus, including our consolidated financial statements and the notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The risks described below are those which we believe are the material risks we face. Any of the risk factors described below could significantly and adversely affect our business, prospects, financial condition and results of operations. As a result, the trading price of our common stock could decline and you may lose a part or all of your investment.

Risks Relating to Our Business and Our Industry

The price volatility of crude oil, other feedstocks, refined products and fuel and utility services may have a material adverse effect on our earnings, profitability and cash flows.

Our refining and marketing earnings, profitability and cash flows from operations depend on the margin above fixed and variable expenses (including the cost of refinery feedstocks, such as crude oil) at which we are able to sell refined products. Refining margins historically have been volatile, and are likely to continue to be volatile, as a result of a variety of factors, including fluctuations in the prices of crude oil, other feedstocks, refined products and fuel and utility services.

In recent years, the prices of crude oil, other feedstocks and refined products have fluctuated substantially. For example, from January 2003 to March 31, 2005, the price for WTI crude oil fluctuated between $25.20 and $56.88 per barrel, while the price for Gulf Coast unleaded gasoline fluctuated between 69.4 cents per gallon, or cpg, and 161.7 cpg. These fluctuations were due to, among other things, increased demand for fuel products in the United States, China and India and high utilization rates for existing U.S. refineries. Future volatility may have a negative effect on our results of operations to the extent the margin between refined product prices and feedstock prices narrows.

The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Because crude oil and refined products are essentially commodities, we have no control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market value under the LIFO inventory valuation methodology, if the market value of our inventory were to decline to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of sales. For example, during 2001, inventory market prices declined significantly below our inventory cost determined under the LIFO valuation method, resulting in our recording a $23.2 million write-down of inventory and a corresponding non-cash charge to cost of sales. In 2002, the market prices for our inventory increased significantly, allowing us to recover $18.6 million of the 2001 inventory write-down with a corresponding non-cash credit to cost of sales.

In addition, the volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refinery and other operations affect operating costs. Fuel and utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for fuel and utility services in both local and regional markets. Natural gas prices have historically been volatile. For example, daily prices as reported on the NYMEX ranged between $4.57 and $8.75 per million British thermal units, or MMBTU, in 2004. During the first quarter of 2005, these prices ranged between $5.79 and $7.65 per MMBTU. Typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a negative effect on our results of operations.

The prices of crude oil, feedstocks and refined products depend upon many factors that are beyond our control and could adversely affect our profitability.

Prices of crude oil, other feedstocks and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline and other refined products. Such supply and demand are affected by, among other things:


	•	changes in global and local economic conditions;

	•	domestic and foreign demand for fuel products, especially in the United States, China and India;

	•	worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa and Venezuela;

	•	the level of foreign and domestic production of crude oil and refined products and the level of crude oil, feedstock and refined products imported into the United States;

	•	utilization rates of U.S. refineries;

	•	development and marketing of alternative and competing fuels;

	•	U.S. government regulations; and

	•	local factors, including market conditions, weather conditions and the level of operations of other refineries and pipelines in our markets.

If the margin between refined product prices and crude oil and other feedstock prices contracts, it could negatively affect our earnings and profitability.


	*Our profitability is linked to the sweet/sour crude oil price spread, which increased significantly in 2004. A decrease in this spread would negatively affect our profitability.*

Our profitability is linked to the price spread between sweet crude oil and sour crude oil, which we refer to as the sweet/sour spread. We prefer to refine sour crude oils because they have historically provided wider refining margins than sweet crude oils. During 2004, relatively high demand for sweet crude oils due to increasing demand for lower sulfur fuels resulted in a wider sweet/sour spread. However, a tightening of the sweet/sour spread could adversely affect our profitability, particularly if there is a worldwide softening of product demand that lessens the demand for sweet crude oils.


	*If the price of crude oil increases significantly, it could limit our ability to purchase enough crude oil to operate our refinery at full capacity.*

We rely in part on borrowings and letters of credit under our revolving credit facility to purchase crude oil for our refinery. If the price of crude oil increases significantly, we may not have sufficient capacity under our revolving credit facility to purchase enough crude oil to operate our refinery at full capacity. A failure to operate our refinery at full capacity could adversely affect our profitability and cash flows.


	Changes in our credit profile could affect our relationships with our suppliers, which could have a material adverse effect on our liquidity and our ability to operate our Big Spring refinery at full capacity.

Changes in our credit profile could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms of their invoices with us. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our creditors of more burdensome payment terms on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This in turn could cause us to be unable to operate our Big Spring refinery at full capacity. A failure to operate our refinery at full capacity could adversely affect our profitability and cash flows.


	*Covenants and events of default in our debt instruments could limit our ability to undertake certain types of transactions and adversely affect our liquidity.*

Our revolving credit facility and term loan contain negative and financial covenants and events of default that may limit our financial flexibility and ability to undertake certain types of transactions. For instance, we are subject to negative covenants that restrict our activities, including restrictions on creating liens, engaging in mergers, consolidations and sales of assets, incurring additional indebtedness, providing guaranties, engaging in different businesses, making loans and investments, entering into certain lease obligations, making certain capital expenditures, making certain dividend, debt and other restricted payments, compromising or adjusting receivables, engaging in certain transactions with affiliates and amending or waiving certain material agreements. We are also subject to financial covenants that require us to maintain specified financial ratios and to satisfy other financial tests. In addition, an event of default would occur if Mr. Wiessman were to cease to be our chairman or Mr. Morris were to cease to be, with respect to our revolving credit facility, involved in the operations and management of our business, or with respect to our term loan, the president and chief executive officer of Alon USA, and in all cases an acceptable successor were not appointed within 180 days, or if Alon Israel were to cease to own at least 51% of the aggregate voting power represented by our outstanding capital stock. If we fail to satisfy the covenants set forth in our revolving credit facility and term loan or another event of default occurs under these facilities, the maturity of the loans could be accelerated or, in the case of the revolving credit facility, we could be prohibited from borrowing for our working capital needs. If the loans are accelerated and we do not have sufficient cash on hand to pay all amounts due, we could be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing. Refinancing may not be possible and additional financing may not be available on commercially acceptable terms, or at all. If we cannot borrow under the revolving credit facility, we would need to seek additional financing, if available, or curtail our operations.


	Competition in the refining and marketing industry is intense, and an increase in competition in the markets in which we sell our products could adversely affect our earnings and profitability.

We compete with a broad range of companies in our refining and marketing operations. Many of these competitors are integrated, multinational oil companies that are substantially larger than we are. Because of their diversity, integration of operations, larger capitalization, larger and more complex refineries and greater resources, these companies may be better able to withstand volatile market conditions, to compete on the basis of price and to obtain crude oil in times of shortage.


	*Competition in the retail industry is intense, and an increase in competition in the markets in which our retail businesses operate could adversely affect our earnings and profitability.*

Our retail operations compete with numerous convenience stores, gasoline service stations, supermarket chains, drug stores, fast food operations and other retail outlets. Increasingly, high-volume grocery and dry-goods retailers, such as Albertson’s, Wal-Mart and HEB, a Texas-based regional grocer, are entering the gasoline retailing business. Many of these competitors are substantially larger than we are. Because of their diversity, integration of operations and greater resources, these companies may be better able to withstand volatile market conditions or levels of low or no profitability in the retail segment. In addition, these retailers may use promotional pricing or discounts, both at the pump and in the store, to encourage in-store merchandise sales. These activities by our competitors could adversely affect our profit margins. Additionally, our convenience stores could lose market share, relating to both gasoline and merchandise, to these and other retailers, which could adversely affect our sales and profitability.

Our convenience stores compete in large part based on their ability to offer convenience to customers. Consequently, changes in traffic patterns and the type, number and location of competing stores could result in the loss of customers and reduced sales and profitability at affected stores.


	*We may incur significant costs to comply with new or changing environmental laws and regulations.*

Our operations are subject to extensive regulatory controls on air emissions, water discharges, waste management and the clean-up of contamination that can require costly compliance measures. We anticipate that compliance with new regulations lowering the permitted level of sulfur in gasoline and highway diesel fuel will require us to spend approximately $29.4 million through 2010, of which approximately $6.5 million is expected to be spent in the remainder of 2005. Actual costs could, however, significantly exceed current estimates, and we may be required to incur such costs at an earlier date than planned, particularly if we were to lose our small refiner status. If we fail to meet environmental requirements, we may be subject to administrative, civil and criminal proceedings by state and federal authorities, as well as civil proceedings by environmental groups and other individuals, which could result in substantial fines and penalties against us as well as governmental or court orders that could alter, limit or stop our operations.

In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. We are not able to predict the impact of new or changed laws or regulations or changes in the ways that such laws or regulations are administered, interpreted or enforced. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. To the extent that the costs associated with meeting any of these requirements are substantial and not adequately provided for, our earnings and cash flows could suffer.


	We may incur significant costs and liabilities with respect to environmental lawsuits and proceedings and any investigation and remediation of existing and future environmental conditions.

We are currently investigating and remediating, in some cases pursuant to government orders, soil and groundwater contamination at our refinery, terminals and convenience stores. Since August 2000, we have spent approximately $10.3 million with respect to the investigation and remediation of our Big Spring refinery and our terminals. We anticipate spending an additional $6.7 million in investigation and remediation expenses over the next five years. We cannot assure you, however, that we will not have to spend more than this amount. Our handling and storage of petroleum and hazardous substances may lead to additional contamination at our facilities and facilities to which we send or sent wastes or by-products for treatment or disposal, in which case we may be subject to additional cleanup costs, governmental penalties, and third-party suits alleging personal injury and property damage. Although we have sold three of our pipelines and three of our terminals pursuant to the HEP transaction, we have agreed, subject to certain limitations, to indemnify HEP for costs and liabilities that may be incurred by them as a result of environmental conditions existing at the time of the sale. See “Business — Environmental Regulation — Environmental Indemnity to HEP.” If we are forced to incur costs or pay liabilities in connection with such proceedings and investigations, such costs and payments could be significant and could adversely affect our profitability.

We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.

From time to time, we have been sued or investigated for alleged violations of health, safety, environmental and other laws. If a lawsuit or enforcement proceeding were commenced or resolved against us, we could incur significant costs and liabilities. In addition, our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to

revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our earnings and cash flows.


	*We may incur significant costs to comply with new or changing laws and regulation related to our pipelines.*

Our Amdel pipeline is regulated by the Federal Energy Regulatory Commission. All of our pipelines are regulated by the Department of Transportation, and our intrastate pipelines are regulated by the Texas Railroad Commission. Both the State of Texas and the Federal Department of Transportation have recently promulgated new regulations on pipeline safety. These regulations require pipelines that are located in populated or environmentally sensitive areas to prepare and implement a program for managing the integrity of these pipelines, including the repair of any defects identified as a result of pipeline integrity assessments. We estimate that compliance with these new regulations will require us to invest $1.3 million over the next five years. Actual costs could, however, significantly exceed current estimates. If we fail to meet these new regulations, we may be subject to administrative, civil and criminal proceedings, which could result in substantial fines and penalties against us as well as governmental or court orders that could alter, limit or stop our pipeline operations. To the extent our pipelines become subject to new or changing laws or regulations in the future, we may need to incur additional costs to comply with these laws and regulations.

The dangers inherent in our operations could cause disruptions and could expose us to potentially significant losses, costs or liabilities. We are particularly vulnerable to disruptions in our operations because all of our refining operations are conducted at a single facility.

Our operations are subject to significant hazards and risks inherent in refining operations and in transporting and storing crude oil, intermediate products and refined products. These hazards and risks include, but are not limited to, natural disasters, fires, explosions, pipeline ruptures and spills, third party interference and mechanical failure of equipment at our or third-party facilities, any of which could result in production and distribution difficulties and disruptions, environmental pollution, personal injury or wrongful death claims and other damage to our properties and the properties of others.

Because all of our refining operations are conducted at a single refinery, any such events at our refinery could significantly disrupt our production and distribution of refined products, and any sustained disruption could have a material adverse effect on our business, financial condition and results of operations. For example, in September 2002, a fire at our refinery caused the refinery to be shut down for 12 days. After giving effect to insurance and other recoveries from third parties, our net losses associated with the fire, including lost margin opportunity due to the interruption of our business, were approximately $4.0 million.

We are subject to interruptions of supply as a result of our reliance on pipelines for transportation of crude oil and refined products.

Our refinery receives substantially all of its crude oil and delivers a substantial percentage of its refined products through pipelines. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, governmental regulation, terrorism, other third-party action or any of the types of events described in the preceding risk factor. Our prolonged inability to use any of the pipelines that we use to transport crude oil or refined products could have a material adverse effect on our business, financial condition and results of operations.

Our insurance policies do not cover all losses, costs or liabilities that we may experience.

We maintain significant insurance coverage, capped at $260.0 million, but it does not cover all potential losses, costs or liabilities, and our business interruption insurance coverage does not apply unless a business interruption exceeds 45 days. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

We are exposed to risks associated with the credit-worthiness of our insurers.

The insurer under three of our environmental policies is The Kemper Insurance Companies, which has experienced significant downgrades of its credit ratings in recent years. Of these three policies, two are 20-year policies that were purchased to protect us against expenditures not covered by our indemnification agreement with Fina, and the third policy is a ten-year policy covering our operations subsequent to our acquisition of them from Fina. Our insurance brokers have advised us that environmental insurance policies with terms in excess of ten years are not currently generally available and that policies with shorter terms are available only at premiums substantially in excess of the premiums paid for our policies with Kemper. Accordingly, we are currently subject to the risk that Kemper will be unable to comply with its obligations under these policies and that comparable insurance may not be available or, if available, only at substantially higher premiums than our current premiums with Kemper.

If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively impacted.

Our future performance depends to a significant degree upon the continued contributions of our senior management team and key technical personnel. We do not currently maintain key man life insurance with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of members of our senior management team and key technical personnel would be unavailable to us for any reason, we would be required to hire other personnel to manage and operate our company and to develop our products and technology. We cannot assure you that we would be able to locate or employ such qualified personnel on acceptable terms or at all.

A substantial portion of our refining workforce is unionized, and we may face labor disruptions that would interfere with our operations.

As of April 30, 2005, we employed approximately 170 people at our refinery, approximately 120 of whom were covered by a collective bargaining agreement. The collective bargaining agreement expires March 31, 2006. We may not be able to renegotiate our collective bargaining agreement on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreement may not prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse affect on our results of operation and financial condition.

We conduct our convenience store business under a license agreement with 7-Eleven, and the loss of this license could adversely affect the results of operations of our retail segment.

All of our convenience store operations are currently conducted under the 7-Eleven name pursuant to a license agreement between 7-Eleven, Inc. and us. 7-Eleven may terminate the agreement if we default on our obligations under the agreement. This termination would result in our convenience stores losing the use of the 7-Eleven brand name, the accompanying 7-Eleven advertising and certain other brand names used exclusively by 7-Eleven. Termination of the license agreement could have a material adverse affect on our convenience store operations.

We may not be able to successfully execute our strategy of growth through acquisitions.

A component of our growth strategy is to selectively acquire refining and marketing assets and retail assets in order to increase cash flow and earnings. Our ability to do so will be dependent upon a number of factors, including our ability to identify acceptable acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth and many other factors beyond our control. Risks associated with acquisitions include those relating to:


	•	diversion of management time and attention from our existing business;

	•	challenges in managing the increased scope, geographic diversity and complexity of operations;

	•	difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations;

	•	liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance;

	•	greater than anticipated expenditures required for compliance with environmental or other regulatory standards or for investments to improve operating results;

	•	difficulties in achieving anticipated operational improvements;

	•	incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and

	•	issuance of additional equity, which could result in further dilution of the ownership interest of existing stockholders.

We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.

Terrorist attacks, threats of war or actual war may negatively affect our operations, financial condition, results of operations and prospects.

Terrorist attacks in the United States and the war with Iraq, as well as events occurring in response to or in connection with them, may adversely affect our operations, financial condition, results of operations and prospects. Energy-related assets (which could include refineries, terminals and pipelines such as ours) may be at greater risk of future terrorist attacks than other possible targets in the United States. A direct attack on our assets or assets used by us could have a material adverse effect on our operations, financial condition, results of operations and prospects. In addition, any terrorist attack could have an adverse impact on energy prices, including prices for our crude oil and refined products, and an adverse impact on the margins from our refining and marketing operations. In addition, disruption or significant increases in energy prices could result in government-imposed price controls.

While we currently maintain insurance that provides coverage against terrorist attacks, such insurance has become increasingly expensive and difficult to obtain. Therefore, it is possible that we will not be able to purchase this coverage in the future or to afford it if it remains available.


	*If the price of crude oil increases significantly, it could reduce our profit on our fixed-price asphalt supply contracts.*

We enter into fixed-price supply contracts pursuant to which we agree to deliver asphalt to customers at future dates. We set the pricing terms in these agreements based, in part, upon the price of crude oil at the time we enter into each contract. If the price of crude oil increases from the time we enter into the contract to the time we produce the asphalt, our profits from these sales could be adversely affected.

Our operating results are seasonal and generally lower in the first and fourth quarters of the year.

Demand for gasoline and asphalt products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. Seasonal fluctuations in highway traffic also affect motor fuels and merchandise sales in our retail stores. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year.

We depend upon our subsidiaries for cash to meet our obligations and pay any dividends, and do not own 100% of the stock of our operating subsidiaries.

We are a holding company. Our subsidiaries conduct all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations or pay dividends to our stockholders depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of dividends, tax sharing payments or otherwise. Our subsidiaries’ ability to make any payments will depend on their earnings, the terms of their indebtedness, including our revolving credit facility and term loan, tax considerations and legal restrictions.

Three of our executive officers, Messrs. Morris, Hart and Concienne, own shares of non-voting stock of two of our subsidiaries, Alon Assets and Alon Operating. Following this offering, the shares owned by these executive officers will represent 4.93% of the aggregate equity interest in these subsidiaries. In addition, these executive officers hold options vesting through 2010 which, if exercised, could increase their aggregate ownership to 8.64% of Alon Assets and Alon Operating. To the extent these two subsidiaries pay dividends to us, Messrs. Morris, Hart and Concienne will be entitled to receive pro rata dividends based on their equity ownership. For additional information, see “Principal Stockholders.”

Messrs. Morris, Hart and Concienne are parties to stockholders’ agreements with Alon Assets and Alon Operating, pursuant to which we may elect or be required to purchase their shares in connection with put/call rights or rights of first refusal contained in those agreements. The purchase price for the shares is generally determined pursuant to certain formulas set forth in the stockholders’ agreements, but after July 31, 2010, the purchase price, under certain circumstances involving a termination of, or resignation from, employment would be the fair market value of the shares. For additional information, see “Certain Relationships and Related Transactions — Stockholders’ Agreements with Mr. Morris, Mr. Hart and Mr. Concienne” and “Principal Stockholders.”


	*It may be difficult to serve process on or enforce a United States judgment against certain of our directors.*

All of our directors named in this prospectus, other than Messrs. Haddock and Morris, reside outside the United States. In addition, a substantial portion of the assets of these directors are located outside of the United States. As a result, you may have difficulty serving legal process within the United States upon any of these persons. You may also have difficulty enforcing, both in and outside the United States, judgments you may obtain in United States courts against these persons in any action, including actions based upon the civil liability provisions of United States federal or state securities laws. Furthermore, there is substantial doubt that the courts of the State of Israel would enter judgments in original actions brought in those courts predicated on U.S. federal or state securities laws.


	If we are, or become, a U.S. real property holding corporation, the FIRPTA rules may apply to a sale, exchange or other disposition of common stock and non-U.S. holders may be less inclined to invest in our stock as they may be subject to U.S. federal income tax in certain situations.

The FIRPTA rules may apply to a sale, exchange or other disposition of common stock if we are, or were within five years before the transaction, a “U.S. real property holding corporation,” or a USRPHC. In general, we would be a USRPHC if interests in U.S. real estate comprised most of our assets. Because of the real property, refinery assets and convenience stores we own, we may be USRPHC. If we are or become a USRPHC, so long as our common stock is regularly traded on an established securities market, only a non-U.S. holder who, actually or constructively, holds or held (at any time during the shorter of the

five-year period preceding the date of disposition or the holder’s holding period) more than 5% of our common stock will be subject to withholding of U.S. federal income tax on the disposition of our common stock.

Risks Related to this Offering


	There is no existing market for our common stock, and we do not know if one will develop to provide you with adequate liquidity. If our stock price fluctuates after this offering, you could lose a significant part or all of your investment.

Prior to this offering, there has not been a public market for our common stock. We cannot predict the extent to which investor interest in our company will lead to the development of an active trading market on the New York Stock Exchange or otherwise or how liquid that market might become. If an active trading market does not develop, you may have difficulty selling any of our common stock that you buy. The initial public offering price for the shares has been determined by negotiations between us and the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering. The market price of our common stock may be influenced by many factors, some of which are beyond our control, including:


	•	general economic and stock market conditions;

	•	risks relating to our business and our industry, including those discussed above;

	•	strategic actions by us or our competitors;

	•	announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;

	•	the failure of securities analysts to cover our common stock after this offering or changes in financial estimates by analysts;

	•	variations in our quarterly results of operations;

	•	future sales of our common stock; and

	•	investor perceptions of the investment opportunity associated with our common stock relative to other investment alternatives.

A decrease in the market price of our common stock could cause you to lose some or all of your investment.


	*Being a public company will increase our expenses and administrative workload.*

As a public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain provisions of the Sarbanes-Oxley Act of 2002, related regulations of the Securities and Exchange Commission, or SEC, and requirements of the New York Stock Exchange with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of the time of our board of directors and management and will increase our costs and expenses. We will need to:


	•	institute a more comprehensive compliance function;

	•	design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

	•	prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

	•	establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;


	•	involve and retain to a greater degree outside counsel and accountants in the above activities; and

	•	enhance our investor relations function.

In addition, we also expect that being a public company subject to these rules and regulations will make it more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit and compensation committees, and qualified executive officers.

We will be exposed to risks relating to evaluations of controls required by Section 404 of the Sarbanes-Oxley Act of 2002.

We are in the process of evaluating our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002. We are required to comply with Section 404 by no later than December 31, 2006. However, we cannot be certain as to the timing of completion of our evaluation, testing and remediation actions or the impact of the same on our operations. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board rules and regulations that remain unremediated. As a public company, we will be required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that, or are reasonably likely to, materially affect internal controls over financial reporting. A “material weakness” is a significant deficiency, or combination of significant deficiencies that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. If we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC or the New York Stock Exchange. Additionally, failure to comply with Section 404 or the report by us of a material weakness may cause investors to lose confidence in our financial statements and our stock price may be adversely affected. If we fail to remedy any material weakness, our financial statements may be inaccurate, we may face restricted access to the capital markets, and our stock price may be adversely affected.

Our controlling stockholder may have conflicts of interest with other stockholders in the future.

Alon Israel currently owns, directly or indirectly, all of our outstanding capital stock. After this offering, Alon Israel will own, directly or indirectly, 77.4% of our common stock, or 74.9% if the underwriters exercise their over-allotment option in full. As a result, Alon Israel will continue to be able to control the election of our directors, determine our corporate and management policies and determine, without the consent of our other stockholders, the outcome of any corporate transaction or other matter submitted to our stockholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. So long as Alon Israel continues to own a significant amount of the outstanding shares of our common stock, Alon Israel will continue to be able to strongly influence or effectively control our decisions, including whether to pursue or consummate potential mergers or acquisitions, asset sales and other significant corporate transactions. We cannot assure you that the interests of Alon Israel will coincide with the interests of other holders of our common stock.

Substantial distributions have been or will be made to our controlling stockholder and certain of our executive officers. We have been and are subject to various commercial arrangements and transactions with related parties.

In February 2005, our subsidiary, Alon Assets, used a substantial portion of the proceeds from the HEP transaction to pay a dividend to its stockholders (which consist of Alon Capital and three of our executive officers). As described in “Use of Proceeds,” a substantial portion of the proceeds of this offering will be used to pay a dividend to Alon Israel and Tabris Investments Inc., the pre-offering stockholders of Alon USA Energy, Inc., and to the stockholders of Alon Operating (which consist of Alon USA and three of our executive officers).

Alon Israel will participate ratably with our other stockholders in any future dividends that we may pay. So long as they continue to own shares of stock of Alon Assets or Alon Operating, certain of our executive officers will participate ratably with the other stockholders of these entities in any future dividends that they may pay. We have been and are, and may in the future be, subject to various commercial arrangements and transactions with related parties. We cannot assure you that the interests of the related parties to these arrangements and transactions will coincide with the interests of our stockholders generally. We have not adopted any formal policy governing related party transactions. See “Certain Relationships and Related Transactions — Future Transactions with Related Parties.”

You will incur immediate and substantial dilution.

The initial public offering price per share of our common stock is substantially higher than the net tangible book value per share of our outstanding common stock immediately after the offering. As a result, you will pay a price per share that substantially exceeds the tangible book value of our assets after subtracting our liabilities. You will incur immediate and substantial dilution in the amount of $11.92 per share. See “Dilution.”


	*Shares eligible for future sale may adversely affect our common stock price.*

Sales of substantial amounts of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. This could also impair our ability to raise additional capital through the sale of our equity securities. Under our certificate of incorporation, we are authorized to issue up to 100,000,000 shares of common stock, of which 45,201,120 shares of common stock will be outstanding following this offering. Of these shares, the shares of common stock sold in this offering will be freely transferable without restriction or further registration under the Securities Act by persons other than “affiliates,” as that term is defined in Rule 144 under the Securities Act. Alon Israel has entered into a lock-up agreement described under the caption “Underwriting,” pursuant to which it agreed, subject to certain exceptions, not to sell or transfer, directly or indirectly, any shares of our common stock for a period of 180 days from the date of this prospectus. However, after the lock-up period expires, Alon Israel will be able to register common stock it owns under the Securities Act pursuant to a registration rights agreement. The registration rights granted to Alon Israel apply to all shares of our common stock owned by Alon Israel. We cannot predict the size of future issuances of our common stock or the effect, if any, that future sales and issuances of shares of our common stock would have on the market price of our common stock. See “Shares Eligible for Future Sale.”


	*Delaware law and our organization documents may impede or discourage a takeover, which could adversely affect the value of our common stock.*

Provisions of Delaware law and our certificate of incorporation and bylaws may have the effect of discouraging a change of control of our company or deterring tender offers for our common stock. The anti-takeover provisions of Delaware law impose various impediments to the ability of a third party to acquire control of us, even if a change of control would be beneficial to our existing stockholders. We are currently subject to Delaware anti-takeover provisions. Additionally, provisions of our certificate of incorporation and bylaws impose various procedural and other requirements, which could make it more difficult for stockholders to effect some corporate actions. For example, our certificate of incorporation authorizes our board to determine the rights, preferences and privileges and restrictions of unissued shares of preferred stock without any vote or action by our stockholders. Thus our board is able to authorize and issue shares of preferred stock with voting or conversion rights that could adversely affect the voting or other rights of holders of our common stock. Our bylaws require advance notice for stockholders to nominate director candidates for election or to bring business before an annual meeting of stockholders. Moreover, stockholders are not permitted to call a special meeting or to require the board of directors to call a special meeting or to take action by written consent. These rights and provisions may have the effect of delaying or deterring a change of control of our company and may limit the price that investors might be willing to pay in the future for shares of our common stock. See “Description of Capital Stock.”

FORWARD-LOOKING STATEMENTS

This prospectus includes forward-looking statements in addition to historical information. These forward-looking statements are included throughout this prospectus, including in the sections entitled “Prospectus Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Refining Industry Overview” and “Business” and relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements in this prospectus.

Forward-looking statements reflect our current expectations regarding future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations and cash flows.

Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:


	•	changes in general economic conditions and capital markets;

	•	changes in the underlying demand for our products;

	•	the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;

	•	changes in the sweet/sour spread;

	•	actions of customers and competitors;

	•	changes in fuel and utility costs incurred by our facilities;

	•	disruptions due to equipment interruption, pipeline disruptions or failure at our or third-party facilities;

	•	the execution of planned capital projects;

	•	adverse changes in the credit ratings assigned to our trade credit and debt instruments;

	•	the effects of and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;

	•	operating hazards, natural disasters, casualty losses and other matters beyond our control; and

	•	the other factors discussed in more detail under “Risk Factors.”

Many of these factors are described in greater detail under “Risk Factors.” Potential investors are urged to consider these factors and the other factors described under “Risk Factors” carefully in evaluating any forward-looking statements and are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included herein are made only as of the date of this prospectus, and we undertake no obligation to update any information contained in this prospectus or to publicly release the results of any revisions to any forward-looking statements that may be made to reflect events or circumstances that occur, or that we become aware of, after the date of this prospectus.

USE OF PROCEEDS

We estimate that our net proceeds from the sale of 10,200,000 shares of our common stock in this offering will be approximately $149.8 million ($172.5 million if the underwriters’ option to purchase additional shares is exercised in full), after deducting the underwriting discounts and commissions and the offering expenses. We intend to use the net proceeds:


	•	to fully repay $20.3 million of outstanding subordinated notes payable to Alon Israel;

	•	to fully repay $3.8 million of deferred purchase price payable to Fina;

	•	to pay an aggregate dividend of $60.9 million to our stockholders of record immediately prior to this offering (of which $57.0 million will be paid to existing stockholders of Alon USA Energy, Inc. and $3.9 million will be paid to the minority stockholders of Alon Operating);

	•	if the underwriters’ option to purchase additional shares is exercised, to pay an additional dividend to our stockholders of record immediately prior to this offering (including the minority stockholders of Alon Operating) equal to 50% of the gross proceeds from the sale of such additional shares; and

	•	for general corporate purposes, including loans to our subsidiaries, discretionary and non-discretionary capital expenditures and the repayment of indebtedness.

The subordinated notes payable to Alon Israel mature on March 15, 2011 and accrue interest at a fixed rate of 7.0% per annum. The balance of the deferred purchase price payable to Fina is due on August 1, 2005 and accrues interest at an imputed interest rate of 10.0% per annum.

DIVIDEND POLICY

Alon USA Energy, Inc. historically has not paid dividends to its stockholders, but intends to pay a cash dividend to stockholders of record immediately prior to this offering as described in “Use of Proceeds.” Commencing in the first quarter of 2006, we intend to pay quarterly cash dividends on our common stock at an initial annual rate of $0.16 per share. The declaration and payment of future dividends to holders of our common stock will be at the discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, legal requirements, restrictions in our debt agreements and other factors our board of directors deems relevant. Our senior secured credit facilities contain restrictions on the ability of our subsidiaries to pay dividends to Alon USA Energy, Inc. However, we have amended our senior secured credit facilities to permit Alon USA Energy, Inc. to extend loans to our subsidiaries with the proceeds of this offering and our subsidiaries are permitted to repay such loans absent an event of default under our senior secured credit facilities. These amendments are intended to enable Alon USA Energy, Inc. to provide a portion of the proceeds of this offering to its subsidiaries for their use on an interim basis through loans, while preserving its ability to utilize such proceeds, upon repayment of such loans, to pay dividends to its stockholders. We anticipate that such provisions will result in Alon USA Energy, Inc. being able to pay dividends to its stockholders in an aggregate amount of up to $62.4 million, such amount representing the net proceeds of this offering less the use of proceeds described above. Based on the number of shares of our common stock outstanding after this offering, we anticipate that the $62.4 million of remaining net proceeds from this offering will be sufficient to pay dividends pursuant to our dividend policy through the December 2006 maturity of our revolving credit facility and through the January 2009 maturity of our term credit facility, which we intend to repay in the first quarter of 2006.

CAPITALIZATION

The following table sets forth our cash and cash equivalents and our consolidated capitalization as of March 31, 2005 on an actual basis and as adjusted to give effect to the sale by us of 10,200,000 shares of our common stock in this offering and the application of the net proceeds thereof as described in “Use of Proceeds.”

You should read this table in conjunction with “Use of Proceeds,” “Selected Historical Consolidated and Combined Financial and Operating Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the notes thereto included elsewhere in this prospectus.


				At March 31, 2005

				Actual			As Adjusted

				(dollars in thousands,
				except per share amounts)
Cash and cash equivalents				$	108,989		$	171,401

Debt, including current portion:
	Revolving credit facility(a)			$	—		$	—
	Term loan(b)				100,000			100,000
	Retail mortgage and equipment loans				34,063			34,063
	Subordinated notes payable				20,253			—
	Fina deferred purchase price				3,839			—

		Total debt			158,155			134,063

Minority interest in subsidiaries					5,638			1,765

Stockholders equity:
	Common stock, $0.01 par value, 100,000,000 shares authorized; 35,001,120 shares issued and outstanding, actual; 45,201,120 issued and outstanding, as adjusted				350			452
	Preferred stock, $0.01 par value, 10,000,000 shares authorized; no shares issued and outstanding				—			—
	Additional paid in capital				8,379			158,053
	Accumulated other comprehensive loss				(2,261	)		(2,261	)
	Retained earnings				87,440			30,422

		Total stockholders equity			93,908			186,666

			Total capitalization	$	257,701		$	322,494


(a)		Our revolving credit facility provides for letters of credit and revolving credit loans. As of March 31, 2005, we had $108.6 million of letters of credit outstanding, no revolving credit loans outstanding and additional availability of $33.0 million, which could be used for either additional letters of credit or revolving credit loans.

(b)		We have the right to prepay our term loan commencing in January 2006. We intend to repay all amounts outstanding under our term loan in the first quarter of 2006.

DILUTION

As of March 31, 2005, our net tangible book value was approximately $95.4 million, or approximately $2.73 per share of common stock. Net tangible book value per share represents the amount of tangible assets less total liabilities, divided by the number of shares of common stock outstanding.

On a pro forma basis, after giving effect to (1) the payment of the $60.9 million aggregate dividend to our stockholders of record immediately prior to this offering and (2) the sale of 10,200,000 shares of common stock in this offering and after deduction of the estimated underwriting discounts and commissions and estimated offering expenses payable by us, our pro forma net tangible book value as of March 31, 2005 would have been approximately $184.3 million, or $4.08 per share. This represents an immediate increase in net tangible book value of $1.35 per share to our existing stockholders and an immediate pro forma dilution of $11.92 per share to purchasers of common stock in this offering. The following table illustrates this dilution on a per share basis:


Initial public offering price per share				$	16.00
	Net tangible book value per share as of March 31, 2005	$	2.73
	Increase in net tangible book value per share attributable to new investors		1.35

Pro forma net tangible book value per share after the offering					4.08

Dilution per share to new investors				$	11.92

The following table summarizes on a pro forma basis as of March 31, 2005, after giving effect to the sale of 10,200,000 shares of common stock as described above, the differences between the number of shares of common stock purchased from us, the aggregate cash consideration paid to us and the average price per share paid by existing stockholders since our inception and new investors purchasing shares of common stock in this offering.


		Shares Purchased					Total Consideration
												Average Price
		Number		Percent			Amount		Percent			Per Share

Existing stockholders			35,001,120		77.4	%	$	8,729,000		5.1	%	$	0.25
New investors			10,200,000		22.6			163,200,000		94.9		$	16.00

	Total		45,201,120		100.0	%	$	171,929,000		100.0	%

Total consideration and average price per share paid by the existing stockholders in the table above do not give effect to the aggregate $60.9 million dividend we intend to pay our stockholders of record immediately prior to this offering (of which $57.0 million will be paid to existing stockholders of Alon Energy).

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION

The following unaudited pro forma condensed consolidated statements of operations for the year ended December 31, 2004 and the three months ended March 31, 2005, give effect to the HEP transaction and the repayment of $25 million of indebtedness with a portion of the proceeds therefrom as if each such transaction had occurred on January 1, 2004. The unaudited pro forma condensed consolidated statements of operations do not give effect to this offering or the application of the net proceeds thereof, including the effect of this offering on interest expense, the termination of our payment obligations under our management and consulting agreement with Alon Israel or the recent expansion of our Big Spring refinery’s crude oil throughput capacity from 62,000 bpd to 70,000 bpd. Earnings per share data are based upon the weighted average number of shares outstanding during the period presented, as adjusted for the 33,600-for-one stock split, and do not reflect the increase in outstanding shares that will result from this offering.

The pro forma adjustments, which are based on available information and certain assumptions that we believe are reasonable, are applied to our historical consolidated financial statements. The unaudited pro forma condensed consolidated statements of operations are provided for informational purposes only and do not purport to represent or be indicative of the results that actually would have been obtained had the transactions described above occurred on January 1, 2004 or that may be obtained for any future period.

The following unaudited pro forma condensed consolidated statements of operations should be read in conjunction with “Use of Proceeds,” “Capitalization,” “Selected Historical Consolidated and Combined Financial and Operating Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and notes thereto included elsewhere in this prospectus.


			Year Ended December 31, 2004

			Historical			Adjustments			Pro Forma

			(dollars in thousands, except
			per share data)
STATEMENT OF OPERATIONS:
Net sales			$	1,707,564		$	—		$	1,707,564
Operating costs and expenses:
	Cost of sales			1,469,940			15,406	(a)		1,485,346
	Direct operating expenses			75,742			—			75,742
	Selling, general and administrative expenses			73,554			—			73,554
	Depreciation and amortization			19,064			(1,650	)(b)		17,414

		Total operating costs and expenses		1,638,300			13,756			1,652,056

Gain on disposition of assets				175			—			175

Operating income				69,439			(13,756	)		55,683
Interest expense				23,704			(1,750	)(c)		21,954
Equity (earnings) in investee				—			(599	)(d)		(599	)
Other (income), net				(277	)		—			(277	)
Income tax expense				18,315			(4,505	)(e)		13,810
Minority interest in income of subsidiaries				2,565			(578	)(f)		1,987

Net income			$	25,132		$	(6,324	)	$	18,808

Earnings per share, basic and diluted			$	.72					$	.54
Weighted average shares, basic and diluted				35,001,120						35,001,120


			Three Months Ended March 31, 2005

			Historical			Adjustments			Pro Forma

			(dollars in thousands, except
			per share data)
STATEMENT OF OPERATIONS:
Net sales			$	407,974		$	—		$	407,974
Operating costs and expenses:
	Cost of sales			351,554			2,783	(a)		354,337
	Direct operating expenses			18,336			—			18,336
	Selling, general and administrative expenses			16,665			—			16,665
	Depreciation and amortization			4,834			(269	)(b)		4,565

		Total operating costs and expenses		391,389			2,514			393,903

Gain on disposition of assets				27,693			(27,693	)(g)		—

Operating income				44,278			(30,207	)		14,071
Interest expense				5,007			(312	)(c)		4,695
Equity (earnings) in investee				(135	)		(179	)(d)		(314	)
Other (income), net				(250	)		—			(250	)
Income tax expense				15,655			(11,738	)(e)		3,917
Minority interest in income of subsidiaries				1,565			(1,007	)(f)		558

Net income			$	22,436		$	(16,971	)	$	5,465

Earnings per share, basic and diluted			$	.64					$	.16
Weighted average shares, basic and diluted				35,001,120						35,001,120

(footnotes on following page)


(a)		The adjustment to cost of sales for 2004 reflects $21.0 million of tariff and throughput fees that would have been incurred under the terms of the HEP Pipelines and Terminals Agreement offset by $5.6 million of pipeline and terminal operating expenses that were incurred during 2004. The adjustment to cost of sales for the three months ended March 31, 2005 reflects $3.5 million of tariff and throughput fees that would have been incurred under the terms of the HEP Pipelines and Terminals Agreement offset by $0.7 million of pipeline and terminal operating expenses that were incurred during the two months ended February 28, 2005.

(b)		Represents the depreciation expense for the year ended December 31, 2004 and for the two months ended February 28, 2005 associated with the assets contributed in the HEP transaction. Pipeline and terminal assets are depreciated on a straight-line basis, generally over a 20-25 year period for financial reporting purposes.

(c)		Reflects the elimination of interest expense on the $25.0 million of debt to Alon Israel repaid with a portion of the proceeds received in the HEP transaction, which bore interest at the rate of 7.0% compounded annually.

(d)		Reflects the portion of HEP’s net income that we would have recorded as equity earnings in investee as a result of holding subordinated units in HEP. The equity earnings adjustment is calculated in accordance with the terms of the HEP limited partnership agreement and is based on historical net income for HEP.

(e)		Reflects the tax effect of the preceding pro forma adjustments calculated at a 39.5% effective tax rate.

(f)		Reflects the minority interest effects of the preceding pro forma adjustments at the minority ownership percentage in effect at December 31, 2004 and March 31, 2005.

(g)		Reflects the initial pre-tax gain recognized on the contribution of assets to HEP and one month’s recognition of the deferred gain recorded in connection with the HEP transaction. These gains are excluded from our pro forma results of operations.

SELECTED HISTORICAL CONSOLIDATED AND COMBINED

FINANCIAL AND OPERATING DATA

The following table sets forth selected historical consolidated and combined financial and operating data for our company and our predecessor. The selected historical combined financial data as of and for the period from January 1, 2000 to July 31, 2000 and as of July 31, 2000 are derived from the audited combined financial statements of our predecessor, which are not included in this prospectus. The selected historical consolidated and combined financial data as of December 31, 2000, 2001 and 2002, for the period from August 1, 2000 to December 31, 2000 and for the year ended December 31, 2001 are derived from our audited consolidated financial statements, which are not included in this prospectus. The selected historical consolidated statement of operations data for each of the three years ended December 31, 2002, 2003 and 2004, and the selected consolidated balance sheet data as of December 31, 2003 and 2004 are derived from our audited consolidated financial statements included elsewhere in this prospectus.

The selected historical consolidated financial data as of and for the three months ended March 31, 2004 and 2005 are derived from our unaudited consolidated financial statements included elsewhere in this prospectus. We have prepared our unaudited consolidated financial statements on the same basis as our audited consolidated financial statements and have included all adjustments, consisting of normal and recurring adjustments, that we consider necessary for a fair presentation of our financial position and operating results for the unaudited periods. The selected historical consolidated financial and operating data as of and for the three months ended March 31, 2005 are not necessarily indicative of the results that may be obtained for a full year. Earnings per share data are based upon the weighted average number of shares outstanding during the periods presented, as adjusted for the 33,600-for-one stock split, and do not reflect the increase in outstanding shares that will result from this offering.

We acquired our business, including a 34.4% interest in our subsidiary, SCS, and a 60% interest in our subsidiary, Alon Capital, effective August 1, 2000. We acquired the remaining 65.6% of SCS effective May 1, 2001. A portion of the financing for our acquisition of our business from Fina was in the form of the purchase by investors of 40% of the common stock of our subsidiary, Alon Capital, which holds our refining, pipeline and terminal assets. On August 21, 2002, we acquired this 40% interest in Alon Capital, which we refer to as the Alon Capital minority interest acquisition. As a result of these transactions, the financial and operating data for periods prior to the effective dates of these transactions may not be comparable to the data for periods after the effective dates of these transactions.

The following selected historical consolidated and combined financial and operating data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and notes thereto included elsewhere in this prospectus.


		Predecessor			Alon

		January 1,			August 1,															Three Months
		2000 to			2000 to			Year Ended December 31,												Ended March 31,
		July 31,			December 31,
		2000			2000			2001			2002			2003			2004			2004			2005

					(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
Net sales		$	682,453		$	616,741		$	1,210,366		$	1,207,723		$	1,410,766		$	1,707,564		$	352,723		$	407,974
Operating costs and expenses:
	Cost of sales (a)		588,254			565,610			1,033,741			1,044,675			1,215,032			1,469,940			302,980			351,554
	Direct operating expenses		45,405			26,242			62,587			53,696			66,113			75,742			18,912			18,336
	Selling, general and administrative expenses		9,018			8,253			56,397			69,439			69,066			73,554			17,318			16,665
	Deprecation and amortization		6,812			2,394			9,417			14,853			18,262			19,064			4,762			4,834

	Total operating costs and expenses		649,489			602,499			1,162,142			1,182,663			1,368,473			1,638,300			343,972			391,389

Gain on disposition of assets (b)			—			—			—			—			—			175			—			27,693

Operating income			32,964			14,242			48,224			25,060			42,293			69,439			8,751			44,278
Interest expense (c)			—			5,794			12,337			14,385			16,284			23,704			6,015			5,007
Equity (earnings) in investee			—			—			—			—			—			—			—			(135	)
Other (income) expense, net (d)			1,490			(717	)		(210	)		381			1,819			(277	)		(93	)		(250	)
Income tax expense (c)			—			3,399			13,356			3,913			9,105			18,315			1,119			15,655
Minority interest in income of subsidiaries			—			1,941			5,114			2,029			681			2,565			213			1,565

Net income before accounting change			31,474			3,825			17,627			4,352			14,404			25,132			1,497			22,436
Cumulative effect of adoption of accounting principle			—			—			—			—			336			—			—			—

Net income		$	31,474		$	3,825		$	17,627		$	4,352		$	14,068		$	25,132		$	1,497		$	22,436


Earnings per share, basic and diluted			N/A		$	.11		$	.50		$	.12		$	.40		$	.72		$	.04		$	.64
Weighted average shares, basic and diluted			N/A			35,001,120			35,001,120			35,001,120			35,001,120			35,001,120			35,001,120			35,001,120

CASH FLOW DATA:
Net cash provided by (used in):
	Operating activities	$	33,642		$	63,832		$	45,154		$	5,001		$	76,173		$	76,743		$	(11,200	)	$	(16,437	)
	Investing activities		(8,106	)		(157,061	)		(37,927	)		(70,918	)		(34,664	)		(39,886	)		(2,232	)		96,520
	Financing activities		(25,536	)		98,595			(3,500	)		62,238			(39,667	)		19,244			29,412			(34,451	)

OTHER DATA:
Adjusted EBITDA (e)			38,286			17,353			57,851			39,532			58,400			88,605			13,606			21,804
Capital expenditures, net of disposition proceeds (f)			3,257			157,061			36,183			66,967			33,117			37,564			1,142			(106,902	)
Capital expenditures for turnarounds and catalysts			4,849			—			1,744			3,951			1,547			2,322			1,090			10,382

BALANCE SHEET DATA (end of period):
Cash and cash equivalents		$	—		$	5,366		$	9,093		$	5,414		$	7,256		$	63,357		$	23,236		$	108,989
Working capital			18,377			26,397			19,500			30,962			5,071			44,443			53,991			116,924
Total assets			342,579			276,094			281,753			392,066			386,982			472,516			436,111			553,801
Total debt			—			115,152			126,721			214,539			166,816			187,706			202,481			158,155
Stockholders’ equity			—			10,744			29,961			33,128			46,923			71,472			48,560			93,908


		Predecessor		Alon

		January 1,		August 1,										Three Months
		2000 to		2000 to		Year Ended December 31,								Ended March 31,
		July 31,		December 31,
		2000		2000		2001		2002		2003		2004		2004		2005

				(dollars in thousands, except per barrel data)
KEY OPERATING STATISTICS:
Refining and marketing:
Total sales volume (bpd)			92,017		108,299		94,023		93,691		90,914		85,950		82,153		72,253
Non-integrated marketing sales volume (bpd) (g)			31,904		40,336		30,618		25,867		24,093		19,926		19,734		20,061
Non-integrated marketing margin (per barrel sales volume) (g)		$	0.65	$	0.78	$	0.80	$	0.44	$	0.52	$	0.03	$	0.03	$	(0.93	)
Total refinery throughput (bpd)(h)			58,879		63,689		61,556		60,906		64,354		61,664		61,851		47,447
Per barrel of throughput:
	Refinery operating margin (i)	$	7.16	$	4.76	$	6.84	$	4.65	$	5.80	$	8.03	$	6.58	$	10.56
	Direct operating expenses		3.31		3.24		2.79		2.42		2.81		3.36		3.36		4.29
Retail:
Number of stores (end of period)			174		173		172		170		170		167		168		167
Fuel sales (thousands of gallons)			47,370		32,333		86,047		91,882		100,389		97,541		24,001		23,387
Fuel sales (thousands of gallons per site per month)			40		38		42		45		50		49		48		48
Fuel margin (cents per gallon) (j)			12.8¢		11.6¢		12.8¢		10.1¢		11.9¢		12.9¢		10.9¢		12.9¢
Merchandise sales		$	67,223	$	45,906	$	117,400	$	128,260	$	130,413	$	130,117	$	30,652	$	29,994
Merchandise sales (per site per month)			55		53		57		63		64		65		61		60
Merchandise margin (k)			34.6%		38.3%		36.8%		36.1%		33.0%		33.5%		32.7%		33.3%


(a)		2002 cost of sales reflects an $18.6 million credit associated with our LIFO inventory valuation methodology. We account for our finished product and raw materials inventories under the LIFO inventory valuation method. In 2001, market prices fell below LIFO costs, resulting in a $23.2 million charge to cost of sales. In 2002, market prices recovered significantly, allowing us to recover $18.6 million of the 2001 inventories write-down. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies.”

(b)		Gain on disposition of assets reported in the three months ended March 31, 2005, reflects the initial pre-tax gain recognized in connection with assets contributed in the HEP transaction and one month’s recognition of the deferred gain recorded in connection with the HEP transaction. The transaction was recorded as a partial sale for accounting purposes. See “Business — Pipelines and Product Terminals — HEP Transaction” for additional information related to the HEP transaction.

(c)		Our predecessor did not allocate corporate income tax or interest expense to its individual business segments.

(d)		Represents equity in SCS’s net losses (for the year ended December 31, 2000 and the four months ended April 30, 2001), interest income and net miscellaneous expense.

(e)		Adjusted EBITDA represents earnings before minority interest, income tax expense, interest expense, depreciation, amortization and gain on dispositions of assets. However, Adjusted EBITDA is not a recognized measurement under GAAP. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of minority interests, financings, income taxes and dispositions of assets and the accounting effects of capital expenditures and acquisitions, items which may vary for different companies for reasons unrelated to overall operating performance. Adjusted EBITDA, with adjustments specified in our credit agreements, is also the basis for calculating selected financial ratios as required in the debt covenants in our credit agreements. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Cash Position and Indebtedness.”

		Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:

		• Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

		• Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;

		• Adjusted EBITDA does not reflect the prior claim that minority stockholders have on the income generated by our non-wholly-owned subsidiaries;

		• Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and

		• Our calculation of Adjusted EBITDA may differ from the EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.


		Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.

		The following table provides a reconciliation of net income to Adjusted EBITDA for the periods presented:


		Predecessor		Alon

		January 1,		August 1,											Three Months
		2000 to		2000 to		Year Ended December 31,									Ended March 31,
		July 31,		December 31,
		2000		2000		2001		2002		2003		2004			2004		2005

				(dollars in thousands)
Net income		$	31,474	$	3,825	$	17,627	$	4,352	$	14,068	$	25,132		$	1,497	$	22,436
	Minority interest		—		1,941		5,114		2,029		681		2,565			213		1,565
	Income tax expense		—		3,399		13,356		3,913		9,105		18,315			1,119		15,655
	Interest expense		—		5,794		12,337		14,385		16,284		23,704			6,015		5,007
	Depreciation and amortization		6,812		2,394		9,417		14,853		18,262		19,064			4,762		4,834
	Gain on disposition of assets		—		—		—		—		—		(175	)		—		(27,693	)

Adjusted EBITDA		$	38,286	$	17,353	$	57,851	$	39,532	$	58,400	$	88,605		$	13,606	$	21,804


(f)		Capital expenditures include $40.4 million, $10.0 million and $10.0 million paid in 2002, 2003 and 2004, respectively, in connection with our acquisition of the 40% equity interest in Alon Capital that was previously owned by third parties. Capital expenditures for the three months ended March 31, 2005 are net of $118.0 million of net cash proceeds received in the HEP transaction. See “Business — Pipelines and Product Terminals — HEP Transaction” for additional information related to the HEP transaction.

(g)		The non-integrated marketing sales volume represents refined products sales to our wholesale marketing customers located in our non-integrated region. The refined products we sell in this region are obtained from third-party suppliers. The non-integrated marketing margin represents the margin between the net sales and cost of sales attributable to our non-integrated refined products sales volume expressed on a per barrel basis.

(h)		Refinery throughput represents the total of crude oil and blendstock inputs in the refinery production process.

(i)		Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales attributable to our refining and marketing segment, exclusive of net sales and cost of sales relating to our non-integrated system, by our Big Spring refinery’s throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margin to these crack spreads to assess our operating performance relative to other participants in our industry.

(j)		Fuel margin represents the difference between motor fuel revenues and the net cost of purchased fuel, including transportation costs and associated motor fuel taxes, expressed on a cents per gallon basis. Motor fuel margins are frequently used in the retail industry to measure operating results related to motor fuel sales.

(k)		Merchandise margin represents the difference between merchandise sales revenues and the delivered cost of merchandise purchases, net of rebates and commissions, expressed as a percentage of merchandise sales revenues. Merchandise margins, also referred to as in-store margins, are commonly used in the retail industry to measure in-store, or non-fuel, operating results.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

You should read the following discussion together with the financial statements and the notes thereto included elsewhere in this prospectus. This discussion contains forward-looking statements that are based on management’s current expectations, estimates and projections about our business and operations. The cautionary statements made in this prospectus should be read as applying to all related forward-looking statements wherever they appear in this prospectus. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number of factors, including those we discuss under “Risk Factors” and elsewhere in this prospectus. You should read “Risk Factors” and “Forward-Looking Statements.”

Company Overview

We are an independent refiner and marketer of petroleum products operating primarily in the Southwestern and South Central regions of the United States. Our business consists of two segments: (1) refining and marketing and (2) retail. Our business is physically integrated, with the majority of our Big Spring refinery’s production distributed through our product pipeline and terminal network to our wholesale customers and our retail segment.

Refining and Marketing Segment. We own and operate a sophisticated sour crude oil refinery in Big Spring, Texas, with a crude oil throughput capacity of 70,000 bpd. Typically, over 90% of the crude oil processed by our Big Spring refinery is sour crude oil. We refine and market petroleum products, including gasoline, diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum products, primarily in the Southwestern and South Central regions of the United States.

We own a crude oil pipeline system totaling approximately 500 miles. Our product pipeline and terminal network consists of seven product pipelines totaling approximately 840 miles and six product terminals that we own or access through leases or long-term throughput agreements. We conduct the majority of our operations in West Texas, Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in this region as our physically integrated system because we are able to supply our branded and unbranded distributors in this region with refined products produced at our Big Spring refinery and distributed through our product pipeline and terminal network. Of the approximately 1,300 FINA branded retail sites we supply, more than 550 of these retail sites, including the sites operated by our retail segment, are part of our physically integrated system. We also operate in East Texas and Arkansas. We refer to our operations in this region as our non-integrated system because we supply our branded and unbranded distributors in this region with motor fuels obtained from third parties. We also market unbranded gasoline, diesel, jet fuel, asphalt and other petroleum products. We are one of the largest suppliers of asphalt in West Texas, New Mexico and Arizona.

Retail Segment. As of March 31, 2005, we operated 167 convenience stores in West Texas and New Mexico. Our convenience stores typically offer merchandise, food products and motor fuels under the 7-Eleven and FINA brand names. We are the largest 7-Eleven licensee in the United States and one of the top three convenience store operators, based on number of stores, in the cities of El Paso, Midland, Odessa, Big Spring and Lubbock, Texas. We also have a significant presence in Wichita Falls, Texas and Albuquerque, New Mexico. We supply our stores with substantially all of their motor fuel needs through our product pipeline and terminal network.

History

We acquired our Big Spring refinery and certain crude oil pipelines, product pipelines and product terminals from Fina in August 2000. A portion of the financing for the acquisition of our business from Fina was in the form of the purchase by investors of 40% of the common stock of our subsidiary, Alon Capital, which holds our refining, pipeline and terminal assets. On August 21, 2002, we acquired this 40% interest in Alon Capital for an aggregate purchase price of $57.1 million. We refer to this transaction as the Alon Capital minority interest acquisition. This acquisition was accounted for under the purchase

method. See “Certain Relationships and Related Transactions — The Alon Capital Minority Interest Acquisition” for a more detailed description of the Alon Capital minority acquisition and information regarding the relationships between the former minority interest holders and certain of our directors and officers.

On February 28, 2005, we completed the contribution of three of our product pipelines and three of our product terminals to HEP. In exchange for this contribution, we received $120 million in cash and 937,500 subordinated Class B limited partnership units in HEP. Simultaneously with this transaction, we entered into a Pipelines and Terminals Agreement with HEP with an initial term of 15 years and three subsequent five year renewal terms exercisable at our sole option. Pursuant to the Pipelines and Terminals Agreement, we have agreed to transport and store minimum volumes of refined products in these pipelines and terminals and to pay specified tariffs and fees for such transportation and storage during the term of such agreement. See “Business — Pipelines and Product Terminals — HEP Transaction.”

In March 2005, we successfully completed a major turnaround at our Big Spring refinery. We believe the completion of this project will enable us to operate our Big Spring refinery without significant planned maintenance shut downs for the next four to five years. In connection with this turnaround, we expanded our crude oil throughput capacity from 62,000 bpd to 70,000 bpd. The cost of the expansion project was approximately $6.4 million, or $800 per bpd of additional throughput capacity.

Major Influences on Results of Operations

Refining and Marketing. Our earnings and cash flow from our refining and marketing segment are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire feedstocks and the price of the refined products we ultimately sell depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation. While our sales and operating revenues fluctuate significantly with movements in crude oil and refined product prices, it is the spread between crude oil and refined product prices, and not necessarily fluctuations in those prices, that affects our earnings.

In order to measure our operating performance, we compare our per barrel refinery operating margin to certain industry benchmarks, specifically the Gulf Coast and Group III, or mid-continent, 3/2/1 crack spreads. A 3/2/1 crack spread in a given region is calculated assuming that three barrels of a benchmark crude oil are converted, or cracked, into two barrels of gasoline and one barrel of diesel. We calculate the Gulf Coast 3/2/1 crack spread using the market values of Gulf Coast conventional gasoline and low-sulfur diesel and the market value of WTI crude oil. We calculate the Group III 3/2/1 crack spread using the market values of Group III conventional gasoline and low-sulfur diesel and the market value of WTI crude oil. The Gulf Coast and Group III crack spreads are proxies for the per barrel refinery operating margin that a crude oil refiner situated in the Gulf Coast and Group III region, respectively, would expect to earn if it refined WTI crude oil and sold conventional gasoline and low-sulfur diesel. We calculate our refinery operating margin by dividing the margin between net sales and cost of sales attributable to our refining and marketing segment, exclusive of net sales and cost of sales relating to our non-integrated system, by our Big Spring refinery’s throughput volumes. We exclude net sales and cost of sales relating to our non-integrated system from our refinery operating margin because the refined products we sell in this region are obtained from third-party suppliers and are not produced at our Big Spring refinery.

Our refinery is capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate and sweet crude oils. In addition, we are able to access domestic and foreign crude oils available on the Gulf Coast through our Amdel pipeline, which enables us to better optimize our crude supply. As a result, our refinery operating margin generally exceeds the Gulf Coast 3/2/1 crack spread. However, our refinery operating margin is generally less than the Group III 3/2/1 crack spread. The Group III market area has experienced product supply constraints in recent years due to insufficient

pipeline capacity from the Gulf Coast to the Group III market area. The supply constraints have caused Group III products to be priced at a premium to Gulf Coast products. We measure the cost advantage of refining sour crude oil by calculating the difference between the value of WTI crude oil less the value of WTS crude oil. We refer to this differential as the sweet/ sour spread. A widening of the sweet/sour spread can cause our refinery operating margin to exceed the Group III 3/2/1 crack spread.

The results of operations from our refining and marketing segment are also significantly affected by our Big Spring refinery’s operating costs, particularly the cost of natural gas used for fuel and the cost of electricity. Natural gas prices have historically been volatile. For example, natural gas prices ranged between $4.57 and $8.75 per MMBTU in 2004. Over the first quarter of 2005, natural gas prices ranged between $5.79 and $7.65 per MMBTU. Typically, electricity prices fluctuate with natural gas prices.

Demand for gasoline and asphalt products is generally higher during summer months than during winter months due to seasonal increases in highway traffic and road construction work. As a result, the operating results for our refining and marketing segment for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters. The effects of seasonal demand for gasoline and asphalt are partially offset by seasonality in demand for diesel, which in our region is generally higher in winter months as east-west trucking traffic moves south to avoid winter conditions on northern routes.

Safety, reliability and the environmental performance of our refinery operations are critical to our financial performance. On September 11, 2002, we experienced a fire at our refinery resulting in a 12-day shutdown. After giving effect to insurance recoveries and repair costs, our net losses associated with the fire, including losses resulting from the interruption of our business, were approximately $4 million. Unplanned downtime of our refinery generally results in lost refinery operating margin opportunity, increased maintenance costs and a temporary increase in working capital investment and inventory. The financial impact of planned downtime, such as a turnaround or major maintenance project, is mitigated through a diligent planning process that considers product availability, margin environment and the availability of resources to perform the required maintenance.

The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Because crude oil and refined products are essentially commodities, we have no control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market value under the LIFO inventory valuation methodology, price fluctuations generally have little effect on our financial results, unless the market value of our inventory drops below LIFO costs. For periods in which the market price declines below our LIFO cost basis, we could be subject to significant fluctuations in the recorded value of our inventory and related cost of sales. For example, during 2001, inventory market prices declined significantly below our inventory cost determined under the LIFO valuation method, resulting in our recording a $23.2 million non-cash charge to cost of sales. In 2002 the market prices for our inventory increased significantly, allowing us to recover $18.6 million of the 2001 inventory write-down to market with a corresponding non-cash credit to cost of sales.

Retail. Our earnings and cash flows from our retail segment are primarily affected by the sales and margins of retail merchandise and the sales volumes and margins of motor fuels at our convenience stores. The gross margin of our retail merchandise is retail merchandise sales less the delivered cost of the retail merchandise, net of vendor discounts, measured as a percentage of total retail merchandise sales. Our retail merchandise sales are driven by convenience, branding and competitive pricing. Motor fuel margin is sales less the delivered cost of fuel and motor fuel taxes, measured on a cents per gallon, or cpg, basis. Our motor fuel margins are driven by local supply, demand and competitor pricing. Our goal is to enhance store profitability through new pricing strategies to increase both fuel sales volumes and retail merchandise sales. Our retail sales are seasonal and peak in the second and third quarters of the year, while the first and fourth quarters usually experience lower overall sales.

Market Trends

High demand for refined products and a strengthening economy resulted in increases in product prices that outpaced increases in crude oil prices in 2004 compared to 2003. The average Gulf Coast and Group III crack spreads for 2004 were $6.77 per barrel and $8.02 per barrel, respectively, as compared to the 2003 average of $4.73 per barrel and $6.74 per barrel, respectively. Crack spreads have remained strong in the first quarter of 2005 as year-on-year demand increases continue at above historical levels in the United States, China and India and refining capacity remained limited. During the first quarter of 2005, average Gulf Coast and Group III crack spreads were $6.62 and $7.94 per barrel, respectively, compared to the first quarter 2004 average Gulf Coast and Group III crack spreads of $6.73 and $6.82 per barrel, respectively.

The average sweet/sour spread was $5.08 per barrel in the first quarter of 2005, compared to $3.97 per barrel for 2004, and $2.75 per barrel for 2003. The sweet/sour spread widened in 2004 and the first quarter of 2005 as a result of increased demand for sweet crude oils due to low-sulfur gasoline regulations and higher incremental sour crude oil production. According to the Energy Information Administration, or EIA, the growth of sour crude oil production over the next several years is expected to exceed the growth of sweet crude oil production as new discoveries of sour crude oil reserves come to the market from areas such as the deepwater Gulf of Mexico, while sweet crude oil production declines in some major regions such as the North Sea. The need for compliance with low-sulfur fuels standards is also expected to keep demand for sweet crude oils strong relative to sour crude oils. Based on these trends, we believe refining margins will continue to be favorable.

Factors Affecting Comparability

Our financial condition and operating results over the three year period ended December 31, 2004 and the three month period ended March 31, 2005 have been influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.

In January 2004, we entered into a $100.0 million senior secured term loan facility. We used $70.6 million of the term loan proceeds to repay existing indebtedness and to pay related transaction costs. This net increase in debt, the higher interest rate paid under the term loan and the amortization of debt issuance costs resulted in increased interest expense in 2004 as compared to 2003.

The contribution of assets in connection with the HEP transaction on February 28, 2005 will result in decreased depreciation expense. Property, plant and equipment, net was reduced by approximately $37.8 million as a result of the HEP transaction.

Pursuant to our Pipelines and Terminals Agreement with HEP, we have agreed to transport and store minimum volumes of refined products in the pipelines and terminals contributed to HEP during the term of such agreement. Beginning March 1, 2005, tariff and terminalling fees associated with the Pipelines and Terminals Agreement are reflected as a component of cost of sales. In the periods prior to the HEP transaction, tariff and terminalling fees related to the contributed assets were eliminated through consolidation of our financial statements. As of March 1, 2005, the majority of all operating expenses related to the pipelines and terminals contributed to HEP will no longer be incurred by us, resulting in an offsetting decrease in cost of sales. However, we anticipate that the additional tariff and terminalling fees will be greater than the operating expenses that we will no longer incur, resulting in a net increase to cost of sales. This net increase to cost of sales will reduce our refinery operating margin. See “Unaudited Pro Forma Condensed Consolidated Financial Information” for pro forma financial data that give effect to the HEP transaction.

The HEP transaction was recorded as a partial sale for accounting purposes. We recognized pre-tax gain of $27.7 million in the first quarter of 2005 in connection with the transaction. We expect the remaining $75.1 million of deferred gain to be recognized between now and 2017. In addition, $6.7 million of pro-rata gain was deferred and is subtracted from the carrying value of our investment in HEP in our

consolidated balance sheet. See Note 2 of the consolidated financial statements for the three months ended March 31, 2005 included elsewhere in this prospectus.

In the first quarter of 2005, we successfully completed a major turnaround at our Big Spring refinery. In connection with this turnaround, we expanded our crude oil throughput capacity from 62,000 bpd to 70,000 bpd at a cost of $6.4 million. These efforts required us to discontinue or reduce production at our Big Spring refinery for a period of 25 days, which reduced our product availability and increased our working capital requirements. The expansion and turnaround was completed as scheduled and the refinery resumed full production capabilities on March 6, 2005. Our expanded crude oil processing capability should enable us to spread our fixed costs over a higher production base and, consequently, should lower our per barrel direct operating expense. In addition, the increased throughput and the completion of the turnaround should result in increased production and higher sales volumes, which will affect the comparability of our future operating results to periods prior to the turnaround and expansion. Our average refinery production was 61,372 bpd in 2004 compared to 70,316 bpd for the four months ended June 30, 2005.

Critical Accounting Policies

Our accounting policies are described in the notes to our audited consolidated financial statements included elsewhere in this prospectus. We prepare our consolidated financial statements in conformity with U.S. GAAP. In order to apply these principles, we must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events, some of which we may have little or no control over. Our critical accounting policies, which are discussed below, could materially affect the amounts recorded in our consolidated financial statements.

Inventory. Crude oil, refined products and blendstocks for the refining and marketing segment are priced at the lower of cost or market value. Cost is determined using the LIFO valuation method. Under the LIFO valuation method, we charge the most recent acquisition costs to cost of sales, and we value inventories at the earliest acquisition costs. We selected this method because we believe it more accurately reflects the cost of our current sales. If the market value of inventory is less than the inventory cost on a LIFO basis, then inventory is written down to market value. An inventory write-down to market value results in a non-cash accounting adjustment, decreasing the value of our crude oil and refined products inventory and increasing our cost of sales. For example, in the second half of 2001, market prices were significantly lower than our inventory cost determined under our LIFO valuation method, which resulted in our recording a non-cash charge of $23.2 million to cost of sales and a corresponding decrease in the value of our crude oil and refined products inventory. In 2002, market prices rose substantially, allowing us to recover $18.6 million of the 2001 inventory write-down to market value with a corresponding non-cash credit to cost of sales. Any such recovery results in a non-cash accounting adjustment, increasing the value of our crude oil and refined products inventory and decreasing our cost of sales. Our results of operations could continue to include such non-cash write-downs and recoveries of inventory if market prices for crude oil and refined products return to levels comparable to those in 2001. Market values of crude oil, refined products and blendstocks exceeded LIFO costs by $42.2 million at March 31, 2005.

Environmental and Other Loss Contingencies. We record liabilities for loss contingencies, including environmental remediation costs, when such losses are probable and can be reasonably estimated. Our environmental liabilities represent the estimated cost to investigate and remediate contamination at our properties. Our estimates are based upon internal and third-party assessments of contamination, available remediation technology and environmental regulations. Accruals for estimated liabilities from projected environmental remediation obligations are recognized no later than the completion of the remedial feasibility study. These accruals are adjusted as further information develops or circumstances change. We do not discount environmental liabilities to their present value unless payments are fixed and determinable, and we record them without considering potential recoveries from third parties. Recoveries of environmental remediation costs from third parties are recorded as assets when receipt is deemed probable.

We update our estimates to reflect changes in factual information, available technology or applicable laws and regulations.

Turnarounds and Chemical Catalyst Costs. We record the cost of planned major refinery maintenance, referred to as turnarounds, and catalysts used in refinery process units, which are typically replaced in conjunction with planned turnarounds, in “other assets” in our consolidated financial statements. Turnaround and catalyst costs are currently deferred and amortized on a straight-line basis beginning the month after the completion of the turnaround and ending immediately prior to the next scheduled turnaround. The amortization of turnaround costs is presented in “depreciation and amortization” in our consolidated financial statements. The amortization of catalyst costs is presented in “direct operating expenses” on our consolidated financial statements.

Impairment of Long-Lived Assets. We account for impairment of long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment of Disposal of Long-Lived Assets. The adoption of SFAS No. 144 did not have a material effect on our financial position or results of operations. In evaluating our assets, long-lived assets and certain identifiable intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of an asset to future net cash flows expected to be generated by the asset. If the carrying value of an asset exceeds its expected future cash flows, an impairment loss is recognized based on the excess of the carrying value of the impaired asset over its fair value. These future cash flows and fair values are estimates based on our judgment and assumptions. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs of disposition.

Deferred Income Taxes. Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date.

Asset Retirement Obligations. Effective January 1, 2003, we adopted Statement No. 143, Accounting for Asset Retirement Obligations, which established accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost. An entity is required to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability should be recognized when a reasonable estimate of fair value can be made.

In order to determine fair value, management must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free rate and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are subjective. See Note 9 to our consolidated financial statements included elsewhere in this prospectus for an explanation of the effect of our adoption of Statement No. 143.

Results of Operations

Net Sales. Net sales consists primarily of sales of refined petroleum products through our refining and marketing segment and sales of merchandise, including food products, and motor fuels through our retail segment. For the refining and marketing segment, net sales consist of gross sales, net of customer rebates or discounts and excise taxes. Net sales for our refining and marketing segment include intersegment sales to our retail segment, which are eliminated through consolidation of our financial statements. Retail net sales consist of gross merchandise sales, less rebates, commissions and discounts, and gross fuel sales, including motor fuel taxes. For our petroleum products, net sales are mainly affected

by crude oil and refined product prices and volume changes caused by operations. Our merchandise sales are affected primarily by competition and seasonal influences.

Cost of Sales. Refining and marketing cost of sales includes crude oil and other raw materials, inclusive of transportation costs. Retail cost of sales include cost of sales for motor fuels and for merchandise. Motor fuel cost of sales represents the net cost of purchased fuel, including transportation costs and associated motor fuel taxes. Merchandise cost of sales includes the delivered cost of merchandise purchases, net of merchandise rebates and commissions.

Direct Operating Expenses. Direct operating expenses, all of which relate to our refining and marketing segment, include costs associated with the actual operations of our refinery, such as energy and utility costs, routine maintenance, amortization of catalyst costs, labor, insurance and environmental compliance costs. Environmental compliance costs, including monitoring and routine maintenance, are expensed as incurred. All operating costs associated with our crude oil and product pipelines are considered to be transportation costs and are reflected as cost of sales.

Selling, General and Administrative Expenses. Selling, general and administrative, or SG&A, expenses consist primarily of costs relating to the operations of our convenience stores, including labor, utilities, maintenance and retail corporate overhead costs. Refining and marketing segment corporate overhead and marketing expenses are also included in SG&A expenses.

Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for us and our two operating segments. The summary financial data for our two operating segments does not include SG&A expenses and depreciation and amortization related to our corporate headquarters.

ALON USA ENERGY, INC. CONSOLIDATED


										Three Months Ended
			Year Ended December 31,							March 31,

			2002		2003		2004			2004			2005

			(dollars in thousands)
STATEMENT OF OPERATIONS DATA:
Net sales			$	1,207,723	$	1,410,766	$	1,707,564		$	352,723		$	407,974
Operating costs and expenses:
	Cost of sales			1,044,675		1,215,032		1,469,940			302,980			351,554
	Direct operating expenses			53,696		66,113		75,742			18,912			18,336
	Selling, general and administrative expenses(a)			69,439		69,066		73,554			17,318			16,665
	Depreciation and amortization(b)			14,853		18,262		19,064			4,762			4,834

		Total operating costs and expenses		1,182,663		1,368,473		1,638,300			343,972			391,389

Gain on disposition of assets				—		—		175			—			27,693

Operating income				25,060		42,293		69,439			8,751			44,278
Interest expense				14,385		16,284		23,704			6,015			5,007
Equity (earnings) in investee				—		—		—			—			(135	)
Other (income) expense, net				381		1,819		(277	)		(93	)		(250	)
Income tax expense				3,913		9,105		18,315			1,119			15,655
Minority interest in income of subsidiaries				2,029		681		2,565			213			1,565

Net income before accounting change				4,352		14,404		25,132			1,497			22,436
Cumulative effect of adoption of accounting principle				—		336		—			—			—

Net income			$	4,352	$	14,068	$	25,132		$	1,497		$	22,436


OTHER DATA:
Adjusted EBITDA(c)			$	39,532	$	58,400	$	88,605		$	13,606		$	21,804
Capital expenditures, net of disposition proceeds				66,967		33,117		37,564			1,142			(106,902	)
Capital expenditures for turnarounds and catalysts				3,951		1,547		2,322			1,090			10,382

BALANCE SHEET DATA (end of period):
Cash and cash equivalents			$	5,414	$	7,256	$	63,357		$	23,236		$	108,989
Working capital				30,962		5,071		44,443			53,991			116,924
Total assets				392,066		386,982		472,516			436,111			553,801
Total debt				214,539		166,816		187,706			202,481			158,155
Stockholders’ equity				33,128		46,923		71,472			48,560			93,908


(a)		Includes corporate headquarters selling, general and administrative expenses of $653, $622, $589, $127 and $128, for the years ended December 31, 2002, 2003 and 2004 and the three months ended March 31, 2004 and 2005, respectively, which are not allocated to our two operating segments.

(b)		Includes corporate depreciation and amortization of $1,208, $1,548, $1,480, $417 and $471, for the years ended December 31, 2002, 2003 and 2004 and the three months ended March 31, 2004 and 2005, respectively, which are not allocated to our two operating segments.

(c)		See footnote (e) on pages 32-33 for information regarding our definition of Adjusted EBITDA, its limitations as an analytical tool and a reconciliation of net income to Adjusted EBITDA for the periods presented.

REFINING AND MARKETING SEGMENT


												Three Months Ended
			Year Ended December 31,									March 31,

			2002			2003			2004			2004			2005

			(dollars in thousands, except per barrel data and pricing statistics)
STATEMENT OF OPERATIONS DATA:
Net sales(a)			$	1,030,903		$	1,225,045		$	1,523,850		$	309,692		$	366,934
Operating costs and expenses:
	Cost of sales			923,402			1,084,213			1,342,426			272,597			323,514
	Direct operating expenses			53,696			66,113			75,742			18,912			18,336
	Selling, general and administrative expenses			21,130			20,063			23,679			5,079			4,678
	Depreciation and amortization			9,949			12,636			13,392			3,287			3,311

		Total operating costs and expenses		1,008,177			1,183,025			1,455,239			299,875			349,839

Gain on disposition of assets(b)				—			—			—			—			27,693

Operating income			$	22,726		$	42,020		$	68,611		$	9,817		$	44,788


KEY OPERATING STATISTICS:
Total sales volume (bpd)				93,691			90,914			85,950			82,153			72,253
Non-integrated marketing sales volume (bpd)				25,867			24,093			19,926			19,734			20,061
Non-integrated marketing margin (per barrel sales volume)			$	0.44		$	0.52		$	0.03		$	0.03		$	(0.93	)
Total refinery throughput (bpd)				60,906			64,354			61,664			61,851			47,447
Per barrel of throughput:
	Refinery operating margin		$	4.65		$	5.80		$	8.03		$	6.58		$	10.56
	Direct operating expenses			2.42			2.81			3.36			3.36			4.29

PRICING STATISTICS:
WTI crude oil (per barrel)			$	26.10		$	31.11		$	41.42		$	35.23		$	49.70
WTS crude oil (per barrel)				24.56			28.36			37.45			31.71			44.62
Crack spreads (3/2/1) (per barrel):
	Gulf Coast		$	3.42		$	4.73		$	6.77		$	6.73		$	6.62
	Group III			4.96			6.74			8.02			6.82			7.94
Crude differentials (per barrel):
	WTI less WTS		$	1.54		$	2.75		$	3.97		$	3.52		$	5.08
Product price (per gallon):
	Gulf Coast unleaded			71.6	¢		86.9	¢		116.4	¢		103.2	¢		132.2	¢
	Gulf Coast low-sulfur diesel			67.5			82.2			111.0			93.3			137.9
	Group III unleaded			75.5			91.9			119.0			103.6			135.7
	Group III low-sulfur diesel			70.9			86.5			115.1			93.2			140.4
	Natural gas (per MMBTU)		$	3.35		$	5.50		$	6.19		$	5.71		$	6.50


(a)		Net sales include intersegment sales to our retail segment at prices which approximate market price. These intersegment sales are eliminated through consolidation of our financial statements.

(b)		Gain on disposition of assets in the first quarter 2005 reflects the initial pre-tax gain and one month’s recognition of deferred gain recorded in connection with the HEP transaction.

RETAIL SEGMENT


												Three Months
			Year Ended December 31,									Ended March 31,

			2002			2003			2004			2004			2005

			(dollars in thousands, except per gallon data)
STATEMENT OF OPERATIONS DATA:
Net sales			$	247,830		$	278,189		$	301,491		$	68,100		$	73,896
Operating costs and expenses:
	Cost of sales(a)			192,283			223,287			245,291			55,452			60,896
	Selling, general and administrative expenses			47,656			48,381			49,286			12,112			11,859
	Depreciation and amortization			3,696			4,078			4,192			1,058			1,052

		Total operating costs and expenses		243,635			275,746			298,769			68,622			73,807

Gain on disposition of assets				—			—			175			—			—

Operating income			$	4,195		$	2,443		$	2,897		$	(522	)	$	89


KEY OPERATING STATISTICS:
Number of stores (end of period)				170			170			167			168			167
Fuel sales (thousands of gallons)				91,882			100,389			97,541			24,001			23,387
Fuel sales (thousands of gallons per site per month)				45			50			49			48			48
Fuel margin (cents per gallon)				10.1	¢		11.9	¢		12.9	¢		10.9	¢		12.9	¢
Merchandise sales			$	128,260		$	130,413		$	130,117		$	30,652		$	29,994
Merchandise sales (per site per month)				63			64			65			61			60
Merchandise margin				36.1	%		33.0	%		33.5	%		32.7	%		33.3	%


(a)		Cost of sales include intersegment purchases of motor fuels from our refining and marketing segment at prices which approximate market prices. These intersegment sales are eliminated through consolidation of our financial statements.

Three Months Ended March 31, 2005 Compared to the Three Months Ended March 31, 2004

Net Sales

Consolidated. Net sales for the three months ended March 31, 2005 were $408.0 million, compared to $352.7 million for the three months ended March 31, 2004, an increase of $55.3 million or 15.7%. This increase resulted primarily from higher average prices for refined products over the comparable period in 2004. This increase was partially offset by reduced sales volume in the three months ended March 31, 2005, compared to the three months ended March 31, 2004, due to reduced production at the Big Spring refinery as a result of our February 2005 turnaround.

Refining and Marketing Segment. Net sales for our refining and marketing segment were $366.9 million for the three months ended March 31, 2005, compared to $309.7 million for the three months ended March 31, 2004, an increase of $57.2 million or 18.5%. This increase was primarily due to significantly higher refined product prices. The increase in refined product prices that we experienced were similar to the price increases experienced in the Gulf Coast markets. The average price of Gulf Coast gasoline for the first quarter 2005 increased 29.0 cpg to 132.2 cpg, compared to 103.2 cpg in the first quarter 2004, an increase of 28.1%. The average Gulf Coast diesel price increased by approximately 44.6 cpg to 137.9 cpg in the first quarter 2005, as compared to 93.3 cpg in the first quarter 2004, an increase of 47.8%. This increase in net sales was partially offset by a decline in sales volume. Our sales volume declined by 40.9 million gallons, or 13.0%, to 273.1 million gallons for the three months ended March 31, 2005 compared to 314.0 million gallons for the three months ended March 31, 2004. This decline in volume resulted from reduced production due to our turnaround in February 2005.

Retail Segment. Net sales for our retail segment were $73.9 million for the three months ended March 31, 2005 compared to $68.1 million for the three months ended March 31, 2004, an increase of $5.8 million or 8.5%. This increase was primarily attributable to higher average retail fuel prices. Average retail fuel prices were $1.88 per gallon for the first quarter 2005, compared to average retail fuel prices of

$1.56 per gallon for the first quarter 2004. Fuel sales volumes for our retail segment in the first quarter 2005 were slightly less than fuel sales volumes in the first quarter 2004 as a result of operating one less store during the first quarter 2005.

Cost of Sales

Consolidated. Cost of sales was $351.6 million for the three months ended March 31, 2005, compared to $303.0 million for the three months ended March 31, 2004, an increase of $48.6 million or 16.0%. This increase resulted primarily from higher crude oil prices, partially offset by reduced crude oil purchases in the first quarter of 2005, due to our February 2005 turnaround.

Refining and Marketing Segment. Cost of sales for our refining and marketing segment was $323.5 million for the three months ended March 31, 2005, compared to $272.6 million for the three months ended March 31, 2004, an increase of $50.9 million or 18.7%. This increase was primarily due to significantly higher crude oil prices. The average price per barrel of WTS for the first quarter of 2005 increased $12.91 per barrel to $44.62 per barrel, compared to $31.71 per barrel for the first quarter of 2004, an increase of 40.7%. The increase in cost of sales was partially offset by a decline in our crude oil purchases in the first quarter of 2005, due to our February 2005 turnaround.

Retail Segment. Cost of sales for our retail segment was $60.9 million for the three months ended March 31, 2005, compared to $55.5 million for the three months ended March 31, 2004, an increase of $5.4 million or 9.7%. This increase was primarily attributable to higher motor fuel costs.

Direct Operating Expenses

Direct operating expenses, were $18.3 million for the three months ended March 31, 2005, compared to $18.9 million for the three months ended March 31, 2004, a decrease of $0.6 million or 3.2%. This decrease was primarily attributable to lower overall energy usage as a result of reduced production at the Big Spring refinery due to the February 2005 turnaround. The decrease in energy usage was partially offset by an increase in natural gas prices. The average price of natural gas was $6.50 per MMBTU in the first quarter 2005, compared to $5.71 per MMBTU for the first quarter 2004.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for the three months ended March 31, 2005 were $16.7 million, compared to $17.3 million for the three months ended March 31, 2004, a decrease of $0.6 million or 3.5%. This decrease resulted primarily from lower advertising expenses and professional fees.

Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the three months ended March 31, 2005 were $4.7 million, compared to $5.1 million for the three month period ended March 31, 2004, a decrease of $0.4 million or 7.8%. This decrease resulted from lower advertising expenditures, a decrease in professional fees and lower net credit card related costs.

Retail Segment. SG&A expenses for our retail segment for the three months ended March 31, 2005 were $11.9 million, compared to $12.1 million for the three months ended March 31, 2004, a decrease of $0.2 million or 1.7%. This decrease was primarily attributable to reduced healthcare and workers compensation costs, which were partially offset by higher utility and credit card brokerage fees.

Depreciation and Amortization

Depreciation and amortization for the three months ended March 31, 2005 was $4.8 million, compared to $4.8 million for the three months ended March 31, 2004. The reduction in depreciation due to the disposition of assets in the HEP transaction was offset by additional depreciation resulting from the completion of various capital projects in 2004 and the first quarter 2005.

Gain on Disposition of Assets

The HEP transaction was recorded as a partial sale for accounting purposes. We recognized pre-tax gain of $27.7 million in the first quarter of 2005 in connection with this transaction.

Operating Income

Consolidated. Operating income (excluding $27.7 million of gain on disposition of assets resulting from the HEP transaction) for the three months ended March 31, 2005 was $16.6 million, compared to $8.8 million for the three months ended March 31, 2004, an increase of $7.8 million or 88.6%. This increase was primarily attributable to higher operating income in our refining and marketing segment.

Refining and Marketing Segment. Operating income for our refining and marketing segment (excluding $27.7 million of gain on disposition of assets resulting from the HEP transaction) for the three months ended March 31, 2005 was $17.1 million, compared to operating income for the three months ended March 31, 2004 of $9.8 million, an increase of $7.3 million or 74.5%. This increase was attributable to the significant increase in our refinery operating margins, partially offset by lower throughput volumes due to our February 2005 turnaround. Our refinery operating margin for the first quarter of 2005 increased $3.98 per barrel to $10.56 per barrel, compared to $6.58 per barrel in the first quarter of 2004. This increase was attributable, in part, to the continued widening of the sweet/ sour spread. The average sweet/ sour spread increased $1.56 per barrel to $5.08 per barrel for the first quarter of 2005 compared to the average sweet/ sour spread of $3.52 per barrel for the first quarter of 2004. The increase in our refinery operating margin was also due to increased production volumes in March 2005 compared to January and February 2005 due to our major turnaround in February 2005. Refinery operating margins in March increased significantly over January and February levels, which resulted in our average refinery operating margins for the quarter being weighted toward the higher margins realized in March.

Retail Segment. Operating income for our retail segment was $0.1 million for the three months ended March 31, 2005, compared to an operating loss of $0.5 million for three months ended March 31, 2004, an increase of $0.6 million. This increase resulted from higher merchandise and motor fuel margins and reduced healthcare and workers compensation costs. Our merchandise margin increased to 33.3% in the first quarter of 2005, compared to 32.7% in the first quarter of 2004. Our average retail motor fuel margin increased 2.0 cpg to 12.9 cpg in the first quarter of 2005, compared to 10.9 cpg for the first quarter of 2004.

Interest Expense

Interest expense was $5.0 million for the three months ended March 31, 2005, compared to $6.0 million for the three months ended March 31, 2004, a decrease of $1.0 million or 16.7%. This decrease was primarily attributable to $0.7 million of non-cash debt issuance costs incurred in the first quarter 2004 as a result of entering into our secured term loan facility and repaying our existing term debt and to reduced letter of credit fees for crude oil purchases in the first quarter 2005 due to the February 2005 turnaround at our Big Spring refinery.

Income Tax Expense

Income tax expense was $15.7 million for the three months ended March 31, 2005, compared to $1.1 million for the three months ended March 31, 2004, an increase of $14.6 million. This increase resulted from our higher taxable income in the first quarter 2005, which included the recognition of $27.7 million of pre-tax gain on disposition of assets in connection with the HEP transaction. Our effective tax rate was 39.5% for the first quarter 2005 and the first quarter 2004.

Minority Interest

Minority interest represents the proportional share of net income related to the non-voting common stock of two of our subsidiaries, Alon Assets and Alon Operating, not owned by us. Minority interest was

$1.6 million for the three months ended March 31, 2005, compared to $0.2 million for the three months ended March 31, 2004, an increase of $1.4 million. This increase was primarily attributable to the increase in net income as a result of the factors discussed above. The increase was partially offset by the reduction in minority interest ownership to 5.6% in the first quarter 2005 compared to 7.6% in the first quarter 2004 as a result of the repurchase of outstanding shares from one of the minority interest holders.

Net Income

Net income was $22.4 million for the three months ended March 31, 2005, compared to $1.5 million for the three months ended March 31, 2004, an increase of $20.9 million. This increase was attributable to the factors discussed above.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

Net Sales

Consolidated. Net sales for 2004 were $1,707.6 million, compared to $1,410.8 million for 2003, an increase of $296.8 million or 21.0%. This increase was primarily due to favorable market conditions resulting from higher refined product prices, partially offset by a decrease in sales volume.

Refining and Marketing Segment. Net sales for our refining and marketing segment were $1,523.9 million for 2004, compared to $1,225.0 million for 2003, an increase of $298.9 million or 24.4%. The increase in net sales was primarily the result of significantly higher refined product prices in 2004 compared to 2003. The average price of Gulf Coast gasoline in 2004 increased 29.5 cpg, or 34.0%, to 116.4 cpg, compared to 86.9 cpg in 2003. The average Gulf Coast diesel price in 2004 increased 28.8 cpg, or 35.0%, to 111.0 cpg compared to 82.2 cpg in 2003. The increase in net sales was partially offset by a 5.5%, or 76.1 million gallons, decrease in sales volumes in 2004 compared to 2003. This decrease was due, in part, to the non-renewal of several distributor supply contracts in our non-integrated system that expired in late 2003 and early 2004. The decrease was also due to reduced production resulting from unplanned downtime and repairs to our catalytic cracking unit as we neared the end of our major turnaround cycle.

Retail Segment. Net sales for our retail segment were $301.5 million for 2004 compared to $278.2 million for 2003, an increase of $23.3 million or 8.4%. This increase was primarily due to higher average retail fuel prices. Average retail fuel prices were $1.76 per gallon for 2004, compared to the average retail fuel prices of $1.47 per gallon for 2003. This increase was partially offset by a decrease in fuel sales volume of 2.9 million gallons, or 3.0%, to 97.5 million gallons in 2004 as compared to 100.4 million gallons in 2003 and a decrease in merchandise sales. The decrease in fuel sales volume and merchandise sales was primarily related to closing three stores in 2004.

Cost of Sales

Consolidated. Cost of sales was $1,470.0 million for 2004, compared to $1,215.0 million for 2003, an increase of $255.0 million or 21.0%. This increase resulted primarily from higher crude oil prices, partially offset by reduced crude oil purchases in 2004, due to slightly reduced crude throughput at our Big Spring refinery.

Refining and Marketing Segment. Cost of sales for our refining and marketing segment was $1,342.4 million for 2004, compared to $1,084.2 million for 2003, an increase of $258.2 million or 23.8%. This increase was primarily due to significantly higher crude oil prices. The average price per barrel of WTS for 2004 increased $9.09 per barrel to $37.45 per barrel, compared to $28.36 per barrel for 2003, an increase of 32.1%. The increase in cost of sales was partially offset by a decline in our crude oil purchases as a result of reduced crude throughput at the Big Spring refinery.

Retail Segment. Cost of sales for our retail segment was $245.3 million for 2004, compared to $223.3 million for 2003, an increase of $22.0 million or 9.9%. This increase was primarily attributable to higher motor fuel costs, partially offset by a decrease in fuel sales volume as a result of closing three stores in 2004.

Direct Operating Expenses

Direct operating expenses were $75.7 million for 2004, compared to $66.1 million for 2003, an increase of $9.6 million or 14.5%. This increase was primarily attributable to increased energy costs resulting from higher natural gas prices. The average price of natural gas was $6.19 per MMBTU in 2004, compared to $5.50 per MMBTU in 2003, an increase of 12.5%. In addition, increased maintenance labor costs and maintenance expenditures contributed to the increase in direct operating expenses.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for 2004 were $73.6 million, compared to $69.1 million in 2003, an increase of $4.5 million or 6.5%. This increase was attributable to higher professional fees and employment related costs in our refining and marketing segment and higher insurance premiums and utility prices in our retail segment.

Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for 2004 were $23.7 million, compared to $20.1 million for 2003, an increase of $3.6 million or 17.9%. This increase was primarily attributable to higher legal and consulting fees and higher employee incentive awards.

Retail Segment. SG&A expenses for 2004 were $49.3 million, compared to $48.4 million for 2003, an increase of $0.9 million or 1.9%. This increase was primarily due to increased workers compensation and health insurance costs.

Depreciation and Amortization

Depreciation and amortization for 2004 was $19.1 million, compared to $18.3 million for 2003, an increase of $0.8 million or 4.4%. This increase resulted from additions to property, plant and equipment as a result of capital expenditures in 2004 and a full year of depreciation associated with 2003 capital expenditures.

Operating Income

Consolidated. Operating income for 2004 was $69.4 million, compared to $42.3 million for 2003, an increase of $27.1 million or 64.1%. This increase was primarily attributable to higher operating income in our refining and marketing segment.

Refining and Marketing Segment. Operating income for our refining and marketing segment for 2004 was $68.6 million, compared to $42.0 million for 2003, an increase of $26.6 million or 63.3%. This increase was attributable to the significant increase in our refinery operating margins, partially offset by higher direct operating expenses and SG&A expenses. Our refinery operating margin increased $2.23 per barrel to $8.03 per barrel in 2004, compared to $5.80 per barrel in 2003. This increase was attributable, in part, to higher differentials between refined product prices and crude oil prices. The Gulf Coast 3/2/1 crack spread increased by 43.1% from an average of $4.73 per barrel in 2003 to an average of $6.77 per barrel in 2004. Also contributing to this increase was a widening of the sweet/sour spread which increased to an average of $3.97 per barrel in 2004 compared to $2.75 per barrel in 2003, an increase of 44.4%.

Retail Segment. Operating income for our retail segment was $2.9 million for 2004, compared to $2.4 million for 2003, an increase of $0.5 million or 20.8%. The increase in merchandise and motor fuel margins were partially offset by increased SG&A expenses. Our merchandise margin increased to 33.5% in 2004, compared to 33.0% in 2003. Our average retail motor fuel margin increased 1.0 cpg to 12.9 cpg in 2004, compared to 11.9 cpg in 2003, an increase of 8.4%.

Interest Expense

Interest expense was $23.7 million in 2004, compared to $16.3 million in 2003, an increase of $7.4 million or 45.4%. Interest expense for 2004 reflects a net increase of $34.7 million in outstanding term loan debt resulting from our incurrence of $100.0 million of indebtedness under our senior secured term

loan in January 2004, as well as $0.7 million of non-cash debt issuance costs associated with this transaction and the application of the proceeds to repay our existing term debt. In addition, higher crude oil prices in 2004 compared to 2003 resulted in increased letter of credit fees relating to our crude oil purchases.

Income Tax Expense

Income tax expense was $18.3 million in 2004 compared to $9.1 million in 2003, an increase of $9.2 million. The increase in income tax expense was attributable to our increased 2004 taxable income compared to 2003. Our effective tax rate for 2004 was 39.8% as compared to 37.6% for 2003.

Minority Interest

Minority interest was $2.6 million for 2004, compared to $0.7 million for 2003, an increase of $1.9 million. This increase was primarily attributable to the increase in net income as a result of the factors discussed above and the issuance of additional stock under the Alon Assets and Alon Operating stock option plans.

Net Income

Net income was $25.1 million for 2004, compared to $14.1 million for 2003, an increase of $11.0 million or 78.0%. This increase was attributable to the factors discussed above.

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

Net Sales

Consolidated. Net sales for 2003 were $1,410.8 million, compared to $1,207.7 million for 2002, an increase of $203.1 million or 16.8%. This increase was primarily attributable to higher gross refining and marketing margins in 2003 over 2002 as refined product prices increased and refined product demand strengthened. This increase was partially offset by a 3.0% decrease in sales volume in our refining and marketing segment in 2003.

Refining and Marketing Segment. Net sales for our refining and marketing segment were $1,225.0 million for 2003, compared to $1,030.9 million for 2002, an increase of $194.1 million or 18.8%. The increase in net sales was due to higher refined product prices in 2003 compared to 2002, resulting from increased demand for refined products and low industry-wide refined product inventory levels. The average price of Gulf Coast gasoline increased by 15.3 cpg, or 21.4%, to 86.9 cpg in 2003, compared to 71.6 cpg in 2002. The average Gulf Coast diesel price increased by 14.7 cpg, or 21.8%, to 82.2 cpg in 2003, compared to 67.5 cpg in 2002. This increase was partially offset by a 3.0%, or 42.6 million gallon decrease in sales volumes in 2003 compared to 2002, due in part to our continued emphasis on restrictive credit controls, which resulted in a slight decrease in our distributor base.

Retail Segment. Net sales for our retail segment were $278.2 million in 2003 compared to $247.8 million in 2002, an increase of $30.4 million or 12.3%. This increase was due primarily to higher average retail fuel prices of $1.47 per gallon for 2003, compared to average retail fuel prices of $1.33 per gallon in 2002.

Cost of Sales

Consolidated. Cost of sales was $1,215.0 million for 2003, compared to $1,044.7 million for 2002, an increase of $170.3 million or 16.3%. This increase resulted primarily from higher crude oil prices and increased crude oil purchases in 2003.

Refining and Marketing Segment. Cost of sales for our refining and marketing segment was $1,084.2 million for 2003, compared to $923.4 million for 2002, an increase of $160.8 million or 17.4%. This increase was primarily due to higher crude oil prices. The average price per barrel of WTS for 2003

increased $3.80 per barrel to $28.36 per barrel, compared to $24.56 per barrel for 2002, an increase of 15.5%. In addition, our crude oil purchases in 2003 were higher than in 2002, due to reduced throughput in 2002 resulting from 12 days of downtime associated with a fire at our Big Spring refinery.

Retail Segment. Cost of sales of our retail segment was $223.3 million for 2003, compared to $192.3 million for 2002, an increase of $31.0 million or 16.1%. This increase was primarily attributable to higher motor fuel costs and an increase in fuel sales volume as a result of competitive fuel pricing strategies.

Direct Operating Expenses

Direct operating expenses were $66.1 million in 2003, compared to $53.7 million in 2002, an increase of $12.4 million or 23.1%. This increase was primarily attributable to higher refinery fuel consumption and increased energy costs resulting from higher natural gas prices. The average price of natural gas was $5.50 per MMBTU in 2003, compared to $3.35 per MMBTU in 2002, an increase of 64.2%. Improvements in refinery reliability resulted in a reduction in maintenance and related labor costs, which partially offset the increase in energy costs.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for 2003 were $69.1 million, compared to $69.4 million in 2002, a decrease of $0.3 million or 0.4%. The decrease was attributable to reduced advertising costs and consulting fees, partially offset by increased employee benefit expenses.

Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for 2003 were $20.1 million, compared to $21.1 million for 2002, a decrease of $1.0 million or 4.7%. This decrease was due primarily to lower advertising costs and consulting fees and reduced write-offs of bad debt as a result of the implementation of stricter credit controls.

Retail Segment. SG&A expenses for our retail segment were $48.4 million in 2003, compared to $47.7 million in 2002, an increase of $0.7 million or 1.5%. Increased healthcare, workers compensation insurance costs and employee related costs, including increased wages and benefits, contributed to the increase in SG&A expenses for 2003.

Depreciation and Amortization

Depreciation and amortization for 2003 was $18.3 million, compared to $14.9 million for 2002, an increase of $3.4 million or 22.8%. This increase reflects a full year of depreciation on the increase in property, plant and equipment related to our acquisition of the Alon Capital minority interest in August 2002.

Operating Income

Consolidated. Operating income for 2003 was $42.3 million, compared to $25.1 million for 2002, an increase of $17.2 million or 68.5%. This increase was primarily attributable to higher operating income in our refining and marketing segment.

Refining and Marketing Segment. Operating income for our refining and marketing segment for 2003 was $42.0 million, compared to $22.7 million for 2002, an increase of $19.3 million or 85.0%. This increase was attributable to the improvement in our refinery operating margins, partially offset by higher direct operating expenses and depreciation. Our refinery operating margin increased $1.15 per barrel to $5.80 per barrel in 2003, compared to $4.65 per barrel in 2002. This increase was attributable to higher differentials between refined product prices and crude oil prices. The Gulf Coast 3/2/1 crackspread increased by 38.3% from an average of $3.42 per barrel in 2002 to an average of $4.73 per barrel in 2003. Also contributing to this increase was a widening of the sweet/sour spread which increased to an average of $2.75 per barrel in 2003 compared to $1.54 per barrel in 2002, an increase of 78.6%. In addition, our refinery production

levels increased as a result of higher refinery utilization in 2003 compared to 2002, when we experienced 12 days of downtime due to a fire at our Big Spring refinery.

Retail Segment. Operating income for our retail segment was $2.4 million in 2003, compared to $4.2 million in 2002, a decrease of $1.8 million or 42.9%. Competitive pressures from high volume retailers and increases in SG&A expenses contributed to lower operating income in 2003. Our merchandise margin decreased to 33.0% in 2003, compared to 36.1% in 2002, as a result of increased competition from high volume retailers as well as changes in vendor rebate and commission programs. Increases in fuel sales volume and motor fuel margins resulting from competitive retail fuel pricing strategies partially offset this decrease. Our average retail motor fuel margin increased 1.8 cpg to 11.9 cpg in 2003, compared to 10.1 cpg in 2002, an increase of 17.8%.

Interest Expense

Interest expense was $16.3 million in 2003, compared to $14.4 million in 2002, an increase of $1.9 million or 13.2%. This increase in interest expense was related primarily to $25.0 million of subordinated debt incurred in connection with the Alon Capital minority interest acquisition in August 2002.

Income Tax Expense

Income tax expense was $9.1 million in 2003 compared to $3.9 million in 2002, an increase of $5.2 million. The increase in income tax expense was attributable to our increased 2003 taxable income. Our effective tax rate for 2003 was 37.6% compared to 38.0% for 2002.

Minority Interest

Minority interest was $0.7 million for 2003, compared to $2.0 million for 2002, a decrease of $1.3 million. This decrease in 2003 was primarily attributable to our acquisition of the Alon Capital minority interest in August 2002 and the subsequent elimination of the related minority interest.

Net Income

Net income was $14.1 million for 2003, compared to $4.4 million for 2002, an increase of $9.7 million, or 220.5%. This increase was attributable to the factors discussed above.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operating activities and borrowings under our revolving credit facility. We believe that our cash flows from operations, borrowings under our revolving credit facility, proceeds from this offering and other capital resources will be sufficient to satisfy the anticipated cash requirements associated with our existing operations during the next 12 months. Our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive and other factors beyond our control. In addition, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors, including any expansion of our business that we complete.

Cash Flows

The following table sets forth our consolidated cash flows for the years ended December 31, 2002, 2003 and 2004 and the three months ended March 31, 2004 and 2005:


										Three Months Ended
	Year Ended December 31,									March 31,

	2002			2003			2004			2004			2005

	(dollars in thousands)
Cash flows provided by (used in) operating activities	$	5,001		$	76,173		$	76,743		$	(11,200	)	$	(16,437	)
Cash flows provided by (used in) investing activities		(70,918	)		(34,664	)		(39,886	)		(2,232	)		96,520
Cash flows provided by (used in) financing activities		62,238			(39,667	)		19,244			29,412			(34,451	)

Net (decrease) increase in cash and cash equivalents	$	(3,679	)	$	1,842		$	56,101		$	15,980		$	45,632

Cash Flows Provided By (Used In) Operating Activities

Net cash used in operating activities for the three months ended March 31, 2005 was $16.4 million compared to net cash used in operating activities of $11.2 million for the three months ended March 31, 2004. The most significant use of cash for operating activities in the first quarter 2005 was to fund an increase in crude oil and unfinished product inventories during the major turnaround at our Big Spring refinery in February 2005. Working capital, net of cash, was $7.9 million at March 31, 2005 compared to $(18.9) million at December 31, 2004, an increase of $26.8 million. This increase was partially offset by increased operating income in the first quarter as a result of higher refinery operating margins. The most significant uses of cash in operating activities in the first quarter 2004 were increases in accounts receivable and prepaid purchases for crude oil which were temporary and related to timing of customer drafts and crude purchases. Working capital, net of cash, was $30.8 million at March 31, 2004 compared to $(2.2) million at December 31, 2003, an increase of $33.0 million.

Net cash provided by operating activities for 2004 was $76.7 million compared to net cash provided by operating activities of $76.2 million for 2003. Operating cash flows for 2004 were primarily attributable to operating income of $69.4 million, resulting from higher refinery operating margins. Operating cash flows for 2003 were primarily attributable to improved operating income of $42.3 million and an increase in trade payables due to the increase in crude oil prices. Working capital, net of cash, was $(18.9) million at December 31, 2004 compared to $(2.2) million at December 31, 2003, a decrease of $16.7 million. This decrease was primarily attributable to the net increase in trade payables as a result of higher crude prices in 2004, partially offset by increased accounts receivable balance resulting from higher product prices.

Net cash provided by operating activities for 2003 was $76.2 million compared to net cash provided by operating activities of $5.0 million for 2002. Operating cash flows for 2003 were primarily attributable to operating income of $42.3 million, resulting from higher refinery operating margins and an increase in trade payables due to the increase in crude oil prices. Operating cash flows for 2002 were primarily attributable to operating income of $25.1 million, partially offset by an increase in crude oil inventories in the fourth quarter 2002. Working capital, net of cash, was $(2.2) million at December 31, 2003 compared to $25.5 million at December 31, 2002, a decrease of $27.7 million. This decrease was primarily attributable to reduced inventories from 2002 levels and an increase in trade payables as a result of higher crude oil prices.

Cash Flows Provided By (Used In) Investing Activities

Net cash provided by investing activities for the three months ended March 31, 2005 was $96.5 million compared to net cash used in investing activities of $2.2 million for the three months ended March 31, 2004. This difference was primarily due to the receipt of $118.0 of net cash proceeds in connection with the HEP transaction, which was partially offset by capital expenditures of $21.5 million in the first quarter 2005. Capital expenditures in the three months ended March 31, 2005 included

approximately $10.4 million for turnaround and catalyst replacement costs, $1.7 million for our crude unit expansion and $5.2 million for the completion of our MACTII and VERP regulatory compliance projects.

Net cash used in investing activities increased to $39.9 million in 2004 from $34.7 million during 2003. Our primary investments in 2004 included $10.0 million of deferred payment for the 2002 Alon Capital minority interest acquisition, $9.4 million for the acquisition of the Trust and River pipeline systems, $5.0 million for the initial phase of our Big Spring refinery’s crude unit expansion, $4.0 million for EPA low-sulfur fuel projects, $2.3 million for chemical catalysts and turnaround preparations and $4.3 million for retail acquisitions and improvements. The remaining $4.9 million was spent on sustaining capital needs and growth opportunities, including the acquisition of our asphalt facility in Bakersfield, California.

Net cash used in investing activities decreased to $34.7 million in 2003 from $70.9 million during 2002. Our primary investments in 2003 included $13.6 million for our low-sulfur gasoline project, $10.0 million of deferred payment for the 2002 Alon Capital minority interest acquisition and $4.1 million for the acquisition of three retail locations. The remaining $7.0 million was spent on sustaining capital needs and growth opportunities. Net cash used in investing activities in 2002 included $40.4 million for the acquisition of the Alon Capital minority interest, excluding the $20.0 million of deferred payments. Other significant investments in 2002 included $5.5 million for the acquisition of the Carswell pipeline system and certain refinery assets from Pride Refining, Inc., $7.5 million for the construction of our GTR asphalt plant, $4.7 million for the upgrade of equipment utilized in our wastewater treatment activities and $3.9 million for chemical catalyst replacement and naptha hydrotreater turnaround expenditures. The remaining $8.9 million was spent on sustaining capital needs and growth opportunities.

Cash Flows Provided By (Used In) Financing Activities

Net cash used in financing activities was $34.5 million during the three months ended March 31, 2005 compared to net cash provided by financing activities of $29.4 million during the three months ended March 31, 2004. Cash used in financing activities in the first quarter 2005 included the payment of $1.5 million of dividends to our minority stockholders and $33.2 million of debt repayments. Cash provided by financing activities in the first quarter 2004 included the net proceeds received in connection with our $100.0 million senior secured term loan.

Net cash provided by financing activities was $19.2 million in 2004 compared to net cash used in financing activities of $39.7 million in 2003. This difference was primarily attributable to the $100.0 million in new borrowings under our term loan in January 2004. Approximately $43.7 million of existing term debt and $21.6 million of borrowings under our revolving credit facilities were retired with the term loan proceeds.

Net cash used in financing activities in 2003 was $39.7 million compared to net cash provided by financing activities of $62.2 million in 2002. The use of cash in 2003 reflected the reduction in our net borrowings under our revolving credit facility due to increased operating income and decreased working capital needs. Cash provided by financing activities in 2002 reflected an increase in our net borrowings under our revolving credit facilities due primarily to a $23.1 million decline in operating income and an increase in net working capital of $11.5 million. Cash provided by financing activities in 2002 also reflected the subordinated loan of $25.0 million received from Alon Israel.

Cash Position and Indebtedness

As of March 31, 2005, our total cash and cash equivalents were $109.0 million, and we had total indebtedness of approximately $158.2 million.

Summary of Indebtedness. The following table sets forth the principal amounts outstanding as of March 31, 2005 under our bank credit facilities, our retail mortgage and equipment loans and our other material indebtedness.


			As of March 31, 2005

			(dollars in thousands)
Debt, including current portion
	Bank credit facilities:
		Revolving credit facility	$	—
		Term loan		100,000
	Retail mortgage and equipment loans			34,063
	Subordinated notes payable to Alon Israel			20,253
	Fina deferred purchase price			3,839

		Total debt	$	158,155

In addition to the amounts shown in the table, at March 31, 2005 we had $108.6 million face value of letters of credit outstanding.

The following is a summary of our bank credit facilities, our retail mortgage and equipment loans and our other material indebtedness, as such indebtedness will exist after the completion of this offering.

Revolving Credit Facility. We entered into a revolving credit facility on July 31, 2000, which was amended and restated on January 14, 2004 and further amended on February 10, 2005. The Israel Discount Bank of New York, or Israel Discount Bank, acts as agent and a lender under the revolving credit facility. Borrowing availability under the revolving credit facility is limited at any time to an amount equal to the lower of $141.6 million and the amount of the borrowing base (as defined in the revolving credit agreement). As of March 31, 2005, the borrowing base under the revolving credit facility exceeded the $141.6 million maximum borrowing capacity by $90.1 million. The entire revolving credit facility is available in the form of letters of credit, and $82.0 million of the revolving credit facility is available in the form of revolving loans. The borrowings under the revolving credit facility bear interest at the Eurodollar rate plus 2.50% per annum. The borrowings under the revolving credit facility are jointly and severally guaranteed by substantially all of our subsidiaries, and such borrowings are secured by a pledge of substantially all of our and our subsidiaries’ assets, including cash, accounts receivable and inventory.

Our revolving credit facility contains covenants that restrict our activities, including restrictions on creating liens, engaging in mergers, consolidations and sales of assets, incurring additional indebtedness, giving guaranties, engaging in different businesses, making loans and investments, entering into certain lease obligations, making certain capital expenditures, making certain dividend, debt and other restricted payments, compromising or adjusting receivables, engaging in certain transactions with affiliates and amending or waiving certain material agreements. The facility also contains certain financial covenants, including covenants requiring us to maintain:


	•	a minimum consolidated tangible net worth of $85.0 million through June 30, 2005, with such amount increasing periodically thereafter to $95.0 million (actual as of March 31, 2005 was $112.4 million);

	•	a minimum ratio of consolidated tangible net worth to consolidated total assets of 18.0% through December 31, 2005, with such percentage increasing periodically thereafter to 22.0% (actual as of March 31, 2005 was 20%);

	•	a ratio of total consolidated indebtedness less freely transferable cash and permitted investments not subject to any lien (other than liens in favor of Israel Discount Bank) to consolidated EBITDA of no greater than 4.5 to 1.00 through December 31, 2005, with such ratio decreasing thereafter to no greater than 4.0 to 1.00 (actual as of March 31, 2005 was 0.4 to 1.00);


	•	a ratio of total consolidated indebtedness to consolidated tangible net worth no greater than 3.33 to 1.00 (actual as of March 31, 2005 was 1.21 to 1.00);

	•	a minimum ratio of consolidated current assets to consolidated current liabilities of 1.00 to 1.00 (actual as of March 31, 2005 was 1.62 to 1.00); and

	•	a minimum projected debt service coverage ratio of 1.25 to 1.00 (because our cash on deposit with the agent bank as of March 31, 2005 was significantly higher than interest for the twelve months ended March 31, 2005 and principal due for the four quarters ended March 31, 2006, the calculation required by this covenant was not meaningful).

Compliance with these covenants is determined in the manner specified in the documentation governing the revolving credit facility. Consolidated EBITDA under our revolving credit facility represents net income plus minority interest, income tax expense, interest expense, depreciation and amortization and is measured each quarter on a rolling twelve-month basis. This calculation of consolidated EBITDA differs from the calculation of Adjusted EBITDA presented elsewhere in this prospectus. As of March 31, 2005, we were in compliance with all of these covenants.

Under our revolving credit facility, a change of control will be deemed to occur, and an event of default will result, if Mr. Wiessman ceases to be our chairman or Mr. Morris ceases to be involved in the operations and management of our business and, in either case, an acceptable successor is not appointed within 180 days, or if Alon Israel ceases to own at least 51% of the aggregate voting power represented by our outstanding capital stock. The revolving credit facility expires on December 31, 2006. As of March 31, 2005, we had $108.6 million face value of letters of credit and no amounts in the form of revolving loans outstanding under the revolving credit facility.

Term Loan. We entered into a term credit facility, or term loan, on December 16, 2003, which was amended and restated as of January 14, 2004, and further amended on February 10, 2005 and May 6, 2005. Credit Suisse First Boston acts as administrative agent and collateral agent under the term loan. Borrowings under the term loan bear interest, at our option, at either adjusted LIBOR plus 6.5% per annum, or at the alternate base rate plus 5.5% per annum, but not less than 10% per annum. The borrowings outstanding under the term loan will mature on January 14, 2009. The borrowings under the term loan are jointly and severally guaranteed by a significant number of our subsidiaries and are secured by a pledge of substantially all of our and our subsidiaries’ assets. Our term loan contains covenants that restrict our activities, including restrictions on creating liens, engaging in mergers, consolidations and sales of assets, incurring additional indebtedness, giving guaranties, engaging in different businesses, making loans and investments, entering into certain lease obligations, making certain capital expenditures, making certain dividend, debt and other restricted payments, compromising or adjusting receivables, engaging in certain transactions with affiliates and amending or waiving certain material agreements. The term loan contains financial covenants that are identical to those contained in our revolving credit facility and also contains financial covenants requiring us to maintain:


	•	a minimum ratio of consolidated EBITDA to consolidated interest equal to 2.00 to 1.00 through December 31, 2005, with such ratio increasing periodically thereafter to 2.50 to 1.00 (actual as of March 31, 2005 was 5.10 to 1.00);

	•	a ratio of total debt to consolidated EBITDA of no greater than 4.50 to 1.00 in 2005, and thereafter no greater than 4.0 to 1.0 (actual as of March 31, 2005 was 1.17 to 1.00);

	•	a minimum net worth of $70 million plus 50% of aggregate, cumulative consolidated net income accruing for all fiscal quarters ended after March 31, 2004 (as of March 31, 2005 our actual minimum net worth was $109.4 million compared to the $93.9 million minimum net worth required at such date); and

	•	a minimum ratio of consolidated current assets to consolidated current liabilities of 1.00 to 1.00 (actual as of March 31, 2005 was 1.64 to 1.00).

Compliance with these covenants is determined in the manner specified in the documentation governing the term loan. Consolidated EBITDA under our term loan represents net income plus minority interest, income tax expense, interest expense, depreciation, amortization and any non-cash charges, less any non-cash items of income and gains attributable to disposition of assets and is measured each quarter on a rolling twelve-month basis. This calculation of consolidated EBITDA differs from the calculation of Adjusted EBITDA presented elsewhere in the prospectus. As of March 31, 2005, we were in compliance with all of these covenants.

Under our term loan, a change of control will be deemed to occur, and an event of default will result, if Mr. Wiessman ceases to be the chairman or Mr. Morris ceases to be the president and chief executive officer of Alon USA and, in either case, an acceptable successor is not appointed within 180 days, or if Alon Israel ceases to own at least 51% of the aggregate voting power represented by our outstanding capital stock. As of March 31, 2005, we had $100.0 million aggregate principal amount outstanding under the term loan.

We have the right to prepay our term loan commencing in January 2006. We intend to repay all amounts outstanding under the term loan in the first quarter of 2006.

Mortgage Loans and Equipment Loans. We entered into mortgage and equipment loan agreements with GE Capital Franchise Finance Corporation on October 1, 2002. Pursuant to these agreements, we formed two new retail finance subsidiaries, which received $22.3 million in mortgage loans and $12.7 million in equipment loans. The mortgage loans and equipment loans bear interest at a fixed rate of 8.06% per annum and 8.30% per annum, respectively. The loans are guaranteed by Alon USA and secured by liens on the properties and equipment owned by the retail finance subsidiaries. The loans contain representations and warranties, affirmative, negative and financial covenants and events of default that we believe are customary for financings of this kind. The mortgage loans are payable on a 20-year amortization schedule, and the equipment loans are payable on a ten-year amortization schedule. As of March 31, 2005, we had $31.8 million aggregate principal amount outstanding under the GE mortgage loans and equipment loans. In 2003 and 2004, we obtained $2.3 million in mortgage and equipment loans to finance the acquisition of new retail locations and equipment. The interest rates on these loans range from 5.5% to 9.7% with five to 15-year payment terms.

Capital Spending

Our capital expenditure budget for 2005 is $24.2 million, of which $9.4 million, primarily related to the crude unit expansion and regulatory compliance, had been spent as of March 31, 2005. Our capital expenditure budget for 2006 is $23.3 million. The following table summarizes our expected capital expenditures for 2005 and 2006 by operating segment and major category:


			2005		2006

			(dollars in thousands)
Refining and Marketing Segment:
	Sustaining maintenance		$	2,618	$	9,129
	Growth/profit improvement/other			5,594		3,687
	Low-sulfur diesel compliance			6,500		7,500
	MACT II/ VERP			6,762		—

				21,474		20,316

Retail Segment:
	Sustaining maintenance			1,516		2,307
	Growth/profit improvement			1,191		660

				2,707		2,967

		Total	$	24,181	$	23,283

Clean Air Capital Expenditures. We expect to spend approximately $29.4 million over the next six years to comply with the Federal Clean Air Act regulations requiring a reduction in sulfur content in gasoline and diesel fuels, including $6.5 million for low-sulfur diesel compliance in 2005.

As of March 31, 2005, we had completed substantially all of the expenditures required to meet regulatory requirements under the Voluntary Emission Reduction Permit program, or VERP, sponsored by the Texas Commission on Environmental Quality, or TCEQ, and for Maximum Achievable Control Technologies for petroleum refineries, or MACT II, which required additional air emission controls for certain processing units at our Big Spring refinery.

The estimated capital expenditures described above are summarized in the table below. If we were to lose our status as a small refiner, expenditures for the low-sulfur gasoline requirements would be accelerated.


		2005		2006		2007		2008		2009		2010 and Thereafter		Total

		(dollars in thousands)
Low-sulfur gasoline		$	—	$	—	$	500	$	1,000	$	4,877	$	9,000	$	15,377
Low-sulfur diesel			6,500		7,500		—		—		—		—		14,000
MACT II/ VERP			6,762		—		—		—		—		—		6,762

	Total	$	13,262	$	7,500	$	500	$	1,000	$	4,877	$	9,000	$	36,139

Turnaround and Chemical Catalyst Costs. We completed a major turnaround on substantially all of our major processing units, including the crude unit and the fluid catalytic cracking unit, in the first week of March 2005, at a cost of approximately $7.6 million. Chemical catalyst replacement costs associated with the turnaround were approximately $3.5 million. Between our major turnarounds, we also perform periodic scheduled turnaround projects on various units at our Big Spring refinery.


		2005		2006		2007		2008		2009		2010

		(dollars in thousands)
Scheduled turnaround costs		$	7,552	$	400	$	700	$	400	$	700	$	7,350
Chemical catalyst costs			3,468		3,750		2,305		4,201		3,096		3,900

	Total	$	11,020	$	4,150	$	3,005	$	4,601	$	3,796	$	11,250

Contractual Obligations and Commercial Commitments

Information regarding our known contractual obligations of the types described below as of March 31, 2005 is set forth in the following table. As of March 31, 2005, we did not have any capital lease obligations or any agreements to purchase goods or services that were binding on us and that specified all significant terms.


		Payments Due by Period

		Less Than							More Than
Contractual Obligations		1 Year		1-3 Years		3-5 Years			5 Years		Total

		(dollars in thousands)
Long-term debt obligations(a)		$	5,512	$	13,873	$	97,122	(b)	$	41,648	$	158,155
Operating lease obligations			8,710		28,070		14,182			7,540		58,502
Pipelines and Terminals Agreement(c)			14,716		58,863		39,242			179,859		292,680
Other commitments(d)			6,120		11,783		5,654			34,636		58,193

	Total obligations	$	35,058	$	112,589	$	156,200		$	263,683	$	567,530


(a)		We expect to repay approximately $24.2 million of outstanding debt with a portion of the proceeds received in this offering, of which $3.8 million is due within one year and $20.4 million is due within five years.


(b)		Includes $92.5 million of indebtedness owed under our term loan. We have the right to prepay our term loan commencing in January 2006. We intend to repay all amounts outstanding under the term loan in the first quarter of 2006.

(c)		Balances represent the minimum committed volume multiplied by the tariff and terminal rates pursuant to the terms of the Pipelines and Terminals Agreement with HEP. See “Business — Pipelines and Product Terminals — HEP transaction.”

(d)		Other commitments include refinery maintenance services costs and management fees to our parent. These management fees will be terminated in connection with the offering for an aggregate payment of $6.0 million.

Our “other non-current liabilities” are described in Note 9 of our consolidated financial statements included elsewhere in this prospectus. For most of these liabilities, timing of the payment of such liabilities is not fixed and therefore cannot be determined as of March 31, 2005. However, certain expected payments related to our anticipated pension contributions in 2005 and other post-retirement benefits obligations are discussed in Note 10 of our consolidated financial statements included elsewhere in this prospectus.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Quantitative and Qualitative Disclosure About Market Risk

Changes in commodity prices, purchased fuel prices and interest rates are our primary sources of market risk. Our risk management committee oversees all activities associated with the identification, assessment and management of our market risk exposure.

Commodity Price Risk

We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refinery operations. Our financial results can be affected significantly by fluctuations in these prices, which depend on many factors, including demand for crude oil, gasoline and other refined products, changes in the economy, worldwide production levels, worldwide inventory levels and governmental regulatory initiatives. Our risk management strategy identifies circumstances in which we may utilize the commodity futures market to manage risk associated with these price fluctuations.

In order to manage the uncertainty relating to inventory price volatility, we have consistently applied a policy of maintaining inventories at or below a targeted operating level. In the past, circumstances have occurred, such as timing of crude oil cargo deliveries, turnaround schedules or shifts in market demand that have resulted in variances between our actual inventory level and our desired target level. Upon the review and approval of our risk management committee, we may utilize the commodity futures market to manage these anticipated inventory variances.

We maintain inventories of crude oil, feedstocks and refined products, the values of which are subject to wide fluctuations in market prices driven by world economic conditions, regional and global inventory levels and seasonal conditions. As of March 31, 2005, we held approximately 2.2 million barrels of crude and product inventories valued under the LIFO valuation method with an average cost of $32.33 per barrel. Market value exceeded carrying value of LIFO costs by $42.2 million. We refer to this excess as our LIFO reserve. If the market value of these inventories had been $1.00 per barrel lower, our LIFO reserve would have been reduced to $40.0 million.

In accordance with SFAS No. 133, all commodity futures contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section of our consolidated financial statements. As of March 31, 2005, we held no commodity futures contracts.

Interest Rate Risk

As of March 31, 2005, $100.6 million of our outstanding debt was at floating interest rates. Outstanding borrowings under our term loan bear interest at a rate per annum equal to an alternate base rate, not to be less than 4.50%, plus 5.50%, or LIBOR, not to be less than 3.50%, plus 6.50%. Consequently, we are exposed with respect to this loan to interest rate risk during periods in which the alternate base rate and LIBOR are higher than 4.50% and 3.50%, respectively. An increase of 1.0% in the alternate base rate above 4.5% or in LIBOR above 3.5% would result in an increase in our interest expense of approximately $1.0 million per year.

New Accounting Standards and Disclosures

In December 2004, the FASB issued Statement of Accounting Standards No. 123R, “Share-Based Payment” (SFAS No. 123R), which requires expensing stock options and other share-based compensation payments to employees and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing proforma disclosure only. This standard is effective for us as of January 1, 2006 and will apply to all awards granted, modified, cancelled or repurchased after that date as well as the unvested portion of prior awards. Because we use the minimum value method of measuring equity share options for pro forma disclosure purposes under SFAS No. 123, we will apply SFAS 123R prospectively to new awards and to awards modified, repurchased or cancelled after January 1, 2006.

In November 2004, the FASB issued Statement No. 151, “Inventory Costs,” which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material, and requires that those items be recognized as current-period charges. Statement No. 151 also requires that allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. Statement No. 151 is effective for fiscal years beginning after June 15, 2005, and is not expected to affect our financial position or results of operations.

In December 2004, the FASB issued Statement No. 153, “Exchanges of Nonmonetary Assets,” which addresses the measurement of exchanges of nonmonetary assets. Statement No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets, which was previously provided by APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” and replaces it with an exception for exchanges that do not have commercial substance. Statement No. 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement No. 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The adoption of Statement No. 153 is not expected to affect our financial position or results of operations.

Currently, the Emerging Issues Task Force, or EITF, is addressing the accounting for linked purchase and sale arrangements in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” At its March 17, 2005 meeting, EITF reached a tentative conclusion that generally requires non-monetary exchanges of inventory within the same line of business be recognized at the carrying value of the inventory transferred. We will monitor the progress of EITF Issue No. 04-13 to ensure our accounting for linked purchases and sales complies with the EITF’s final consensus opinion.

In March of 2005, FASB issued FASB Interpretation No. 47, “Accounting for Conditional Retirement Obligations,” or FIN 47, which requires companies to recognize a liability for the fair value of a legal obligation to perform asset-retirement activities that are conditional on a future event, if the amount can be reasonably estimated. We must adopt FIN 47 by the end of 2005. The impact of adoption on our consolidated financial statements is still being evaluated.

REFINING INDUSTRY OVERVIEW

Oil refining is the process of separating hydrocarbon atoms present in crude oil and converting them into marketable finished petroleum products, such as gasoline and diesel fuel. Refining is primarily a margin-based business where both the feedstocks and refined finished petroleum products are commodities. Refiners create value by selling refined petroleum products at prices higher than the costs of acquiring crude oil and converting it into finished products.

The fundamental drivers of profitability in the refining industry have improved since the late 1990s, which has resulted in a general widening between the prices for finished petroleum products and the costs of crude oil. By way of demonstrating the improved industry environment, the Gulf Coast 3/2/1 crack spread averaged $2.82 per barrel between 1992 and 1999. As a result of the improvement in underlying fundamental factors, these margins averaged $4.79 per barrel from 2000 to 2004, and first quarter 2005 margins averaged $6.62 per barrel.

The following chart shows the Gulf Coast 3/2/1 crack spreads since 1992, together with the average margins per barrel stated above for the periods from 1992 to 1999 and 2000 to 2004:


	Data calculated based upon information obtained from Platt’s Oilgram News

The current U.S. refining industry is characterized by limited refinery capacity, high utilization rates, strong demand for finished products, increased reliance on imported products and higher differentials between sour and sweet crude oil prices.

Limited U.S. Refining Capacity

Decreasing petroleum product demand and deregulation of the domestic refining industry in the 1980s, along with new fuel standards introduced in the early 1990s, contributed to decreasing domestic refining capacity in the United States. According to the Department of Energy Information

Administration, or EIA, and the Oil and Gas Journal’s 2004 Worldwide Refining Survey, the number of U.S. refineries has decreased from a peak of 324 in 1981 to 132 in January 2005. The last major new oil refinery in the United States was built in 1976. According to the EIA, while domestic refining capacity has decreased approximately 10%, from 6.8 billion barrels in 1981 to 6.1 billion barrels in 2003, domestic demand for refined fuels has increased approximately 24.8%, from 5.9 billion barrels to 7.3 billion barrels, over the same period.

High Utilization Rates

Between 1982 and 2003, refinery utilization increased from 69% to over 92% and is approaching an effective maximum rate. The EIA projects that utilization will remain high relative to historic levels, ranging from 92% to 95% of design capacity. The trend toward greater capacity utilization has been driven by several factors, including (1) no new major refineries having been built in the United States since 1976, (2) increasing demand for refined products, (3) many small refineries having been closed and (4) Tier 2 low sulfur fuel regulations having consumed capital, thus constraining potential investments in capacity increases.

Number of U.S. Refineries vs. Utilization

Strong Demand Fundamentals

While growth in refining capacity is expected by the EIA to average 1.3% per year over the next two decades, the EIA projects demand for petroleum products to outpace capacity growth and continue to grow at an average of 1.5% per year over this period. Approximately 92% of the projected demand growth is expected to come from the increased consumption of light petroleum products, including gasoline, diesel, jet fuel and liquefied petroleum gas, which are more difficult and costly to produce than heavy products.

According to the EIA, total U.S. products demand increased 2.4% in 2004 compared to 2003, due primarily to an improving economy and a continued increase in the number of higher gas consumption vehicles utilized by U.S. consumers. At the same time, gasoline supplies have tightened due to more stringent fuel specifications. This has caused refining margins to substantially exceed those experienced in 2003, and we expect margins to continue to be favorable.

Dependence on Imports

Due to lack of sufficient domestic refining capacity, the United States is a net petroleum product importer. Imports of petroleum products, largely from northwest Europe and Asia, accounted for almost 14% of total U.S. consumption in 2004. Increased imports generally occur primarily during periods when refined product prices in the United States are materially higher than in Europe and Asia. However, products meeting new and evolving fuel specifications are expected to account for an increasing share of

total fuel demand, foreign refiners will need to meet these specifications in order to export directly into the U.S. market. Many foreign refineries do not currently possess the capabilities to blend and process fuels that meet these specifications, which could put further pressure on the domestic supply and demand environment.

Increased Sweet/Sour Price Differentials

As the global economy has improved, world-wide crude oil demand has increased, and the incremental production from OPEC and other producers has tended to be sour crude oils. At the same time, many refiners have turned to sweeter crude oils to meet lower sulfur fuel specifications, resulting in increased supplies of sour crude oils. These factors have caused the discounts for sour crude oils, relative to the prices of sweet crude oils, to increase. The average sweet/sour differential between WTI and WTS increased 45.1% from 2003 to 2004. We believe that increasing worldwide supplies of lower-cost sour crude oils and increased demand for sweet crude oils will continue to provide a cost advantage to refineries with complex configurations that are able to process sour crude oils.

BUSINESS

Company Overview

We own and operate a sophisticated sour crude oil refinery in Big Spring, Texas, which we recently expanded from a crude oil throughput capacity of 62,000 barrels per day, or bpd, to 70,000 bpd. We own a crude oil pipeline system totaling approximately 500 miles. Our product pipeline and terminal network consists of seven product pipelines totaling approximately 840 miles and six product terminals, which we own or access through leases or long-term throughput agreements. We market our gasoline and diesel products under the FINA brand name to approximately 1,300 retail sites. We also market unbranded gasoline, diesel, jet fuel and other refinery products, and we are one of the largest suppliers of asphalt in West Texas, New Mexico and Arizona.

We conduct the majority of our operations in West Texas, Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in this region as our physically integrated system because we are able to supply our branded and unbranded distributors in this region with motor fuels produced at our Big Spring refinery and distributed through our product pipeline and terminal network. Our physically integrated system includes more than 550 of the approximately 1,300 FINA branded retail sites that we supply, including our retail segment convenience stores. We also operate in East Texas and Arkansas. We refer to our operations in this region as our non-integrated system because we supply our branded and unbranded distributors in this region with motor fuels obtained from third parties.

Corporate History and Development of the Business

We are a Delaware corporation formed in 2000. We acquired our Big Spring refinery and certain crude oil pipelines, product pipelines and product terminals from Fina in August 2000. This acquisition also included Fina’s 34.4% interest in SCS. We acquired the remaining 65.6% interest in SCS in May 2001.

A portion of the financing for our acquisition from Fina was provided by investors who purchased 40% of the common stock of Alon Capital, our subsidiary which owns substantially all of our refinery, pipeline and terminal assets. On August 2002, we consolidated our business and operations under a new subsidiary holding company, Alon USA. In connection with this restructuring, we acquired the 40% minority interest in Alon Capital for a purchase price of $57.1 million. See “Certain Relationships and Related Transactions — The Alon Capital Minority Interest Acquisition” for a more detailed description of the Alon Capital minority acquisition and information regarding the relationships between the former minority interest holders and certain of our directors and officers.

In January 2002, we acquired our Carswell product pipeline system and certain refinery equipment from Pride Refining, Inc., or Pride, for $5.5 million. The Carswell pipeline, which runs from Abilene to Fort Worth, Texas, is presently inactive. We have integrated the refinery equipment acquired from Pride into our Big Spring refinery.

In August 2002, we completed construction of a $7.5 million GTR asphalt plant adjacent to our Big Spring refinery. Our GTR plant has enabled us to penetrate new asphalt markets and expand sales in existing markets, particularly to contractors involved with major highway projects in the State of Texas for which GTR asphalt is increasingly required. We sold over 250,000 barrels of GTR asphalt in 2003, exceeding our initial forecast by approximately 25%. Sales volumes have continued to increase with approximately 421,000 barrels of GTR asphalt sold in 2004.

In June 2004, we purchased the Trust and River product pipelines and Duncan product terminal for a purchase price of approximately $9.4 million pursuant to a put/call option entered into in 2000 in connection with our acquisition from Fina. We had previously leased these assets from subsidiaries held by Fina’s pension plan.

In July 2004, we acquired an 85% interest in a 100,000 tons per year, or 1,500 bpd, asphalt blending facility in Bakersfield, California for a purchase price of approximately $3.9 million. The addition of this facility increased our asphalt blending capabilities by over 25%.

In February 2005, we successfully completed a major turnaround of our key processing units at our Big Spring refinery. In connection with this turnaround, we expanded our refinery’s crude oil throughput capacity from 62,000 bpd to 70,000 bpd at a cost of $6.4 million.

Competitive Strengths


	•	our ability to process substantial volumes of sour crude oil;

	•	our low relative transportation cost to source WTS crude oil due to the refinery’s location in the Permian Basin;

	•	our ability to access domestic and foreign crude oils through our Amdel pipeline when processing such crude oils allows us to improve our margins; and

	•	the higher value we are able to realize from our asphalt production as compared to the value of alternative products, such as No. 6 Fuel Oil.

Ability to Process Substantial Volumes of Sour Crude Oil. Typically, over 90% of the crude oil processed at our Big Spring refinery is sour crude oil. Sour crude oils cost less than sweet crude oils, such as WTI, which results in lower feedstock costs and provides us with a competitive advantage over refineries that lack the ability to process substantial volumes of sour crude oil.

asphalt, PMA and GTR, which are increasingly specified by government agencies for use in highway projects in the State of Texas. Our refinery can produce up to 23 different asphalt product formulations.

Strategy

Our objective is to increase stockholder value through sustained earnings and cash flow growth. Our principal strategies to achieve this objective are to:

Increase the Capacity and Yields of Our Refinery. We regularly evaluate ways to improve the profitability of our Big Spring refinery through cost-effective upgrades and expansions. We have identified a project to further expand our Big Spring refinery’s crude oil throughput capacity to 75,000 bpd and are evaluating other projects to increase our light product yields.

Refining and Marketing Segment

Refinery Overview

Our Big Spring refinery has a crude oil throughput capacity of 70,000 bpd. In industry terms, our refinery is characterized as a “cracking refinery.” Our Big Spring refinery is located on 1,306 acres in the

Permian Basin in West Texas. Our refinery has undergone numerous expansions and upgrades over the last 15 years, with aggregate capital expenditures of more than $172.7 million above our annual sustaining capital requirements.

Our Big Spring refinery has the capability to process substantial volumes of less expensive sour crude oils to produce a high percentage of light, high-value refined products. Our Big Spring refinery’s primary products are gasoline, distillates, petrochemicals, petrochemical feedstocks, asphalt and other petroleum products. Our refinery typically converts approximately 86% of its feedstock into higher value products such as gasoline, diesel, jet fuel and petrochemicals, with the remaining 14% primarily converted to asphalt and liquefied petroleum gas.

During each full year of operations since our acquisition from Fina, we have averaged over 96% utilization of our Big Spring refinery’s crude oil throughput capacity. The following table provides information concerning the historical throughput and production of our Big Spring refinery:


		Year Ended December 31,												Three Months Ended March 31,

		2002				2003				2004				2004				2005

		Bpd		%		Bpd		%		Bpd		%		Bpd		%		Bpd		%

Refinery crude throughput:
	Sweet crude		4,725		8.2		5,398		8.8		4,321		7.5		4,777		8.2		2,829		6.4
	Sour crude		53,159		91.8		55,676		91.2		53,646		92.5		53,524		91.8		41,096		93.6

			57,884		100.0		61,074		100.0		57,967		100.0		58,301		100.0		43,925		100.0

Blendstocks			3,022				3,280				3,697				3,550				3,522

Refinery throughput			60,906				64,354				61,664				61,851				47,447

Refinery products:
	Gasoline		28,840		47.4		30,700		47.7		28,711		46.8		29,410		47.4		21,562		45.8
	Diesel/jet		20,434		33.6		21,554		33.5		19,939		32.5		19,774		31.9		15,232		32.4
	Asphalt		5,209		8.5		5,746		8.9		5,781		9.4		5,102		8.2		4,297		9.1
	Petrochemicals		3,908		6.4		4,536		7.1		4,492		7.3		4,537		7.3		3,617		7.7
	Other		2,486		4.1		1,804		2.8		2,449		4.0		3,257		5.2		2,352		5.0

Total refined products manufactured			60,877		100.0		64,340		100.0		61,372		100.0		62,080		100.0		47,060		100.0

Raw Material Supply

Sour crude oil has typically accounted for over 90% of our crude oil input, of which approximately 99% has been WTS crude oil. We receive WTS and WTI crude oil from regional common carrier pipelines. In addition, our Amdel pipeline gives us the ability to optimize our refinery crude slate by transporting foreign and domestic crude oils to our refinery from the Gulf Coast when the economics for processing those crude oils are more favorable than processing locally sourced crude oils. Other feedstocks, including butane, isobutane and asphalt blending components, are delivered by truck and railcar, and a majority of our natural gas is delivered by a pipeline in which we own a 63.0% interest.

Big Spring Refinery Production

Gasoline. Gasoline has typically accounted for approximately 47% of our refinery’s production. We produce various grades of gasoline, ranging from 84 sub-octane regular unleaded to 93 octane premium unleaded, and use a computerized component blending system to optimize gasoline blending. Our refinery is capable of producing specially formulated fuels, such as those required in the El Paso, Dallas/ Fort Worth and Arizona markets.

Distillates. Diesel and jet fuel has typically accounted for approximately 33% of our refinery’s production. All of the diesel fuel we produce is low-sulfur, while our jet fuel production conforms to the JP-8 grade military specifications required by the Air Force bases to which we market our jet fuel.

Asphalt. Asphalt has typically accounted for approximately 9% of our refinery’s production. Approximately 57% of our asphalt production is paving grades and 43% is asphalt blendstocks. We have an exclusive license to use Fina’s asphalt blending technology in West Texas, Arizona, New Mexico and Colorado and a non-exclusive license in Idaho, Montana, Nevada, North Dakota, South Dakota, Utah and Wyoming. Exclusivity under this fully-paid license remains in effect as long as we continue to purchase our rubber modifiers from Fina, Inc., although we may purchase rubber modifiers from other sources and maintain such exclusivity if Fina, Inc. does not provide competitive pricing on rubber modifiers. Our refinery’s asphalt facilities are capable of producing up to 23 different grades of asphalt base stock, including both PMA and GTR asphalt. Paving grades are predominantly sold from April through October for government projects. Our other asphalt blendstocks are sold to roofing companies and asphalt blenders throughout the United States.

Petrochemical Feedstocks and Other. We produce propane, propylene, certain aromatics, specialty solvents and benzene for use as petrochemical feedstocks, along with other by-products such as sulfur and carbon black oil. We have sulfur processing capabilities of approximately two tons per thousand bpd of crude oil capacity, which is above the average for cracking refineries and aids in our ability to produce low-sulfur motor fuels with relatively low investment while continuing to process significant amounts of sour crude oil.

Transportation Fuel Marketing

Our marketing of transportation fuels is focused on five states in the Southwestern and South Central regions of the United States through our physically integrated and non-integrated systems, respectively.

Branded Transportation Fuel Marketing. Our branded fuels are marketed through our retail segment and to independently-owned FINA branded retail distributors. During 2004, we sold 33,291 bpd of gasoline and 5,401 bpd of diesel fuel as branded fuels. Approximately 70% of our branded fuel sales are in West Texas and Central Texas.

The FINA brand is a well recognized trade name in the Southwestern and South Central United States. Our retail segment operates up to 20% of the convenience stores selling motor fuels in several key cities in these regions. We have an exclusive license through July 2012 to use the FINA name and related trademarks in connection with the manufacture and sale (including resale by distributors) of gasoline, diesel and other fuels within Texas, Oklahoma, New Mexico, Arizona, Arkansas, Louisiana, Colorado and Utah. Prior to the expiration of this license, we intend to review our alternatives for branding our transportation fuel, including seeking to extend our license with FINA or developing our own brand. Aside from the inconvenience of changing brands, including costs of new signage, we do not believe that transitioning to our own brand would materially affect our business or operations.

While retailers continue to utilize major brands for name recognition, recent consolidations of major brands and the emergence of independent convenience store brands with enhanced food and merchandise offerings have influenced retail customers who previously made purchases based primarily on brand name. Due to the growth of new convenience store brands and our market density, store locations and benefits provided to our distributors, including secure fuel product supply, credit card processing systems, advertising programs and loyalty programs, we believe we would be able to retain a substantial number of our wholesale customers while developing a new brand in the event we are unable to renew our license with Fina.

Unbranded Transportation Fuel Marketing. We presently sell a majority of our diesel fuel, and a nominal volume of gasoline, on an unbranded basis. During 2004, we sold an average of 4,976 bpd of gasoline and 11,254 bpd of diesel fuel as unbranded fuels, which were largely sold through our physically integrated system.

Jet Fuel Marketing. We market substantially all our jet fuel as JP-8 grade to the Defense Energy Supply Center, or DESC. All DESC contracts are for a one-year term and are awarded through a competitive bidding process. We have traditionally bid for contracts to supply Dyess Air Force Base in

Abilene, Texas and Sheppard Air Force Base in Wichita Falls, Texas. Our annual contract with Dyess Air Force Base was renewed for 2005. Our bid for the 2005 contract with Sheppard Air Force Base was not successful, although we did retain 5% of this business, which was reserved for small refiners. We intend to bid for the 2006 contracts with each of these Air Force bases.

Asphalt Marketing

Our Big Spring refinery produces approximately 5,500 bpd of asphalt that is sold in up to 23 different product formulations. Other cracking refineries which cannot produce asphalt from residual oil produce No. 6 Fuel Oil. We measure the value of producing asphalt rather than No. 6 Fuel Oil by calculating the incremental netback of asphalt. The asphalt netback is the sales price of asphalt less the cost of the additives and blendstock needed to produce this asphalt, divided by the percent of residual oil in the asphalt produced. Our asphalt netback has ranged from $14 to over $20 per barrel since 2000 and is significantly higher than the $4 to over $12 per barrel netback of No. 6 Fuel Oil over the same period. We sell the majority of our asphalt to contractors involved with government projects. We have increased our production capabilities for latex and rubber modified grades that meet the stringent and varied state highway road paving specifications for use in Texas, New Mexico and Arizona. This improved product mix has increased our weighted average asphalt price by over $7 per barrel during the last three years.

Pipelines and Product Terminals

Our pipeline and terminal network utilizes approximately 500 miles of crude oil pipelines, nearly 840 miles of product pipelines and six product terminals and provides us with access to four additional product terminals.

Our pipeline and terminal network allows us to optimize our inventory by allowing us to control the movement and the timing of our refinery’s feedstock supply and the distribution of our refined products. Specifically, this network provides us with the flexibility to (1) access a variety of crude oils, thereby allowing us to optimize our refinery’s crude supply at any given time, (2) efficiently distribute our transportation fuel products to markets in West Texas, Central Texas and Oklahoma and (3) access other markets, including New Mexico and Arizona, through interconnections with third-party transportation systems.

Crude Oil and Natural Gas Pipelines. Our crude oil pipeline system provides our refinery access to Permian Basin crude oil and foreign and domestic crude oil from the Gulf Coast and consists of the following pipelines:


Crude Oil Pipelines	Status		Miles		Connections

Amdel		Owned		504	Midland and Nederland
White Oil		Owned		25	Garden City (Amdel) and Big Spring
Mesa Interconnect		Owned		4	Mesa pipeline and Big Spring

Our 504 mile bi-directional Amdel pipeline and our 25 mile White Oil pipeline connect our refinery to Nederland, Texas, which is located on the Gulf Coast. Permian Basin crude oil is delivered to our refinery through the two-mile long, 16-inch diameter Mesa Interconnect pipeline which is connected to the Mesa pipeline, a common carrier. Because prices for WTS and other locally sourced crude oils have been favorable compared to crude oils available from the Gulf Coast over the last three years, we have not utilized our Amdel pipeline for crude oil shipments since 2002. We continuously monitor prices for crude oils available from the Gulf Coast and intend to utilize our Amdel pipeline to access such crude oils when their prices, together with our costs of transportation on our Amdel pipeline, are favorable compared to the cost of acquiring and delivering WTS and other locally sourced crude oils to our Big Spring refinery.

Our refinery is the closest in proximity to Midland, Texas, which is the largest origination terminal for West Texas crude oil. We believe this location provides us with the lowest transportation cost differential for West Texas crude oil of any refinery. A small amount of locally gathered crude oil is also delivered directly to our refinery. We own a 63% interest in the pipeline that supplies a majority of the natural gas to our refinery.

Product Pipelines. The product pipelines we utilize are linked to the major third-party product pipelines in the geographic area around our refinery, which provides us flexibility to optimize product flows into multiple regional markets. Our network can also (1) receive additional transportation fuel products from the Gulf Coast through the Pride Product terminal and Magellan pipelines, (2) deliver and receive product to and from the Williams system, our connection to the Group III, or mid-continent, markets, and (3) deliver to the New Mexico and Arizona markets through third-party systems. The following table sets forth our product pipelines:

Termination

Product Pipelines

Access

Miles

Connections

Date

Chevron(a)

Lease

Coahoma and Midland

2006

Fin-Tex

HEP throughput

137

Midland and Orla (Holly)

2020

Holly

Lease

133

Orla and El Paso

2018

Trust

HEP throughput

332

Big Spring/Abilene/Wichita Falls

2020

Dyess JP-8

HEP throughput

Abilene and Dyess Air Force Base

2020

River

HEP throughput

Wichita Falls and Duncan (Williams)

2020

Carswell

Owned

148

Abilene and Fort Worth

N/A


(a)		The Chevron pipeline description does not include a four-mile pipeline that we own that connects Big Spring and Coahoma.

The Chevron, Fin-Tex and Holly pipelines make up our Fin-Tex system. Our access to the Chevron and Holly pipelines is secured by long-term leases, while our access to the Fin-Tex pipeline is provided through our Pipelines and Terminals Agreement with HEP. The Fin-Tex system transports product from our refinery to El Paso, Texas and allows it to be placed in Tucson and Phoenix, Arizona through the third-party Kinder Morgan pipeline. Our Fin-Tex system also gives us access to the Albuquerque and Bloomfield, New Mexico markets. We deliver physical barrels to El Paso and receive, through an exchange agreement with Navajo Refining Company, physical barrels in Albuquerque and Bloomfield, New Mexico.

The Trust pipeline connects our refinery to terminals in Abilene and Wichita Falls, while the River pipeline connects the terminal in Wichita Falls to our Duncan terminal. At Duncan, the River pipeline connects into the Magellan pipeline system for sales into Group III markets. The Trust and River pipeline system is a bi-directional pipeline system which we access through our Pipelines and Terminals Agreement with HEP. Our access to the Trust and River pipelines is now provided through our Pipelines and Terminals Agreement with HEP.

The Dyess JP-8 pipeline connects the Abilene terminal to Dyess Air Force Base. Our access to this pipeline is also provided through our Pipelines and Terminals Agreement with HEP.

Our Carswell pipeline system runs from Abilene, Texas to Fort Worth, Texas. The Carswell pipeline is currently inactive as we evaluate alternatives to link our physically integrated system to the Dallas/ Fort Worth area.

Product Terminals. We primarily utilize the following six product terminals, of which three are owned and three are accessed through our Pipelines and Terminal Agreement with HEP:


			Working
Terminals		Access	Capacity(a)		Supply Source	Mode of Delivery

Big Spring, Texas(b)		Owned		331	Pipeline/refinery	Pipeline/truck
Abilene, Texas		HEP		111	Pipeline	Pipeline/truck
Wichita Falls, Texas		HEP		155	Pipeline	Truck
Duncan, Oklahoma		Owned(c)		154	Pipeline	Pipeline
Orla, Texas		HEP		116	Pipeline	Pipeline
Southlake, Texas		Owned		212	Pipeline	Truck

	Total			1,079


	(a)	Measured in thousands of barrels.


	(b)	Includes the tankage located at our refinery.


	(c)	The terminals are owned but the underlying real property is leased.

Five of our six terminals are physically integrated with our Big Spring refinery through our product pipeline system. Three of the five terminals in our physically integrated system, Big Spring, Abilene and Wichita Falls, Texas, are also equipped with truck loading racks. The other two terminals in our physically integrated system, Duncan, Oklahoma and Orla, Texas, are used for delivering shipments into third-party pipeline systems. Our Southlake, Texas terminal is located between Fort Worth and Dallas, part of our non-integrated system, and supplied with purchased or exchanged products. Our Southlake terminal is equipped with a truck loading rack and operates as a wholesale outlet for our distributors in the Dallas/ Fort Worth area. We also directly access four other terminals located in Wichita Falls and El Paso, Texas and Tucson and Phoenix, Arizona.

HEP Transaction. On February 28, 2005, we completed the contribution of three product pipelines and three product terminals to HEP in exchange for $120 million in cash and 937,500 subordinated Class B limited partnership units in HEP. HEP financed the cash consideration for the HEP transaction by issuing high yield debt, or HEP Debt. Alon Pipeline Logistics, LLC, our subsidiary, entered into an agreement with the general partner of HEP providing for Alon Logistics to indemnify the general partner for cash payments it has to perform toward satisfaction of the principal or interest under the HEP Debt following a default by HEP (provided that such cash payments exceed the difference between the amount of HEP Debt over the indemnity amount). The indemnity amount is limited to the lower of (a) $110.9 million or (b) the outstanding amount of HEP Debt, and Alon Logistics may reduce the indemnity amount from time to time. The indemnity terminates at such time as Alon Logistics no longer holds any HEP units and extends only to Alon Logistics and not to any other Alon entities, even if the units are transferred to such other entities.

Pursuant to the Contribution Agreement with HEP, we retained any liabilities in existence prior to February 28, 2005 relating to the operation of the pipelines and terminals, and we also retained responsibility for any repairs required to be made to the Trust and River pipelines to comply with legally required mechanical integrity and other standards of the Department of Transportation and the Environmental Protection Agency, provided that HEP notifies us of such repairs prior to February 28, 2006. We provided customary representations and warranties to HEP regarding the pipelines and terminals in the Contribution Agreement and we have agreed to indemnify HEP for any breaches of these representations and warranties. In general, our representations and warranties under the Contribution Agreement expire on February 28, 2006, except for breaches of our representations and warranties relating to our corporate organization and authority, potential conflicts or violations resulting from our entering into the Contribution Agreement, our title to the pipelines and terminals, and taxes, all of which will expire on February 28, 2015. Our indemnity obligations for breaches of representations and warranties are subject to HEP first incurring $750,000 of damages as a result of breaches of our representations and warranties. In addition, our indemnity obligations for breaches of representations and warranties are limited to an

aggregate indemnification amount of $20 million, including any amounts paid by us to HEP with respect to indemnification for environmental liabilities under the separate Environmental Agreement we entered into with HEP. We describe the Environmental Agreement in more detail under “— Environmental Regulation — Environmental Indemnity to HEP.”

Simultaneously with this transaction, we entered into a Pipelines and Terminals Agreement with HEP with an initial term of 15 years and three additional five-year renewal terms exercisable at our option. If the Pipelines and Terminals Agreement expires without renewal, we have the right to enter into a new agreement with HEP at any time within one year after the expiration on terms that both parties agree are substantially similar to the terms on which HEP could enter into an agreement with a third party for similar services. In the event HEP decides to sell the pipelines and terminals during the term of the Pipelines and Terminals Agreement, we have a right of first refusal to purchase the pipelines and terminals from HEP.

Pursuant to the Pipelines and Terminals Agreement, we have committed to transport and store minimum volumes of refined products in these pipelines and terminals. The tariff rates applicable to our transportation of refined products on the pipelines are at fixed rates subject to annual increase or decrease based on the percentage change in the producer price index for finished goods as published by the Department of Labor, but the tariff rates may not decrease below the initial tariff rates set forth in the Pipelines and Terminals Agreement. In addition, if we transport and store refined products in the pipelines and terminals during a contract year at certain levels above our committed yearly volumes, we will receive a 50% discount on the tariff rates applicable to the incremental volumes.

The service fees for our storage of refined products in the terminals are initially set at rates competitive in the marketplace and will be adjusted annually based on the percentage change in the preceding two contract years in an index of comparable fees posted by other terminal owners in the same geographical location as the terminals.

Pursuant to the Pipelines and Terminals Agreement, neither HEP nor its affiliates are permitted to transport refined products through the pipelines and terminals without our prior written consent and HEP is restricted from building any competing refined products pipelines on the existing rights-of-ways for the pipelines and terminals until after the initial term of the Pipelines and Terminals Agreement.

Retail Segment

As of March 31, 2005, we had 167 retail sites operating under the 7-Eleven brand, of which 164 sold motor fuels under the FINA brand.


Location		Owned		Leased		Total

Big Spring, Texas			6		1		7
El Paso, Texas			13		36		49
Lubbock, Texas			17		5		22
Midland, Texas			9		10		19
Odessa, Texas			10		25		35
Wichita Falls, Texas			8		4		12
Albuquerque, New Mexico			12		11		23

	Total stores		75		92		167

Our convenience stores typically offer merchandise, food products and motor fuels. Substantially all of the motor fuel sold though our retail segment is produced at our Big Spring refinery and transported to our retail fuel sites through our product pipeline and terminal network.

We are one of the top three independent convenience store chains in each of the cities of El Paso, Midland, Odessa, Big Spring and Lubbock, Texas, with approximately 20% of the convenience stores in each city. We also have a significant presence in Wichita Falls, Texas and Albuquerque, New Mexico.

Convenience Store Management and Employees. Each of our stores has a store manager who supervises a staff of full-time and part-time employees. The number of employees at each convenience store varies based on the store’s size, sales volume and hours of operation. Typically, a geographic group of six to 10 stores is managed by a supervisor who reports to a district manager. Seven district managers are responsible for a varying number of stores depending on the geographic size of each market and the experience of each district manager. These district managers report to our retail management headquarters in Odessa. Our retail segment’s headquarters, located in Odessa, Texas, consists of 49 employees.

Distribution and Supply. The merchandise requirements of our convenience stores are serviced at least weekly by multiple direct-store delivery, or DSD, vendors. In order to minimize costs and facilitate deliveries, we utilize a single wholesale distributor, McLane Company Inc., for non-DSD products. We purchase the products from McLane at cost plus an agreed upon percentage mark-up. Our current contract with McLane expires at the end of November 2006. We purchase approximately 55% to 60% of our merchandise for resale from McLane. We also have more than 100 additional DSD and non-DSD vendors with whom we do not have written contracts.

7-Eleven License Agreement. We are party to a license agreement with 7-Eleven which gives us a license to use the 7-Eleven trademark, service name and trade name in connection with our convenience store operations in West Texas and a majority of the counties in New Mexico. This license agreement may be terminated by 7-Eleven if we fail to perform our obligations under the agreement.

Technology and Store Automation. We are installing a point of sale information system for our convenience stores and anticipate completion of this project in 2005. This point of sale system is a checkout system to be used in our convenience stores, which includes scanning, pump control, peripheral device integration and daily operations reporting. This system will enhance our ability to offer a greater variety of promotions with a high degree of flexibility with regard to definition (store, group of stores, region, etc.) and duration. We will also be able to receive enhanced management reports that will assist our decision-making processes. We believe the point of sale system will allow our convenience store managers to spend less time preparing reports and more time analyzing these reports to improve convenience store operations. This system also includes shortage-control tools. This point of sale system will be used as the platform to support other marketing technology projects, including interactive video at the pump and bar code coupons at the pump.

Competition

Petroleum refining and marketing is highly competitive. With respect to our wholesale gasoline and distillate sales and marketing, we compete with Valero, Koch, ChevronTexaco, ExxonMobil, Holly, ConocoPhillips and other major refiners. Many of our principal competitors are integrated, multinational oil companies that are substantially larger and more recognized than we are. Because of their diversity, integration of operations, larger capitalization and greater resources, these major competitors may be better able to withstand volatile market conditions. The principal competitive factors affecting our wholesale marketing business are price and quality of product, reliability and availability of supply and location of distribution points.

The principal competitive factors affecting our refining and marketing segment are costs of crude oil and other feedstocks, refinery efficiency, refinery product mix and costs of product distribution and transportation. Because of the diversity, integration of operations, larger capitalization, larger and more complex refineries and greater resources of many of our competitors, these companies may be better able to withstand volatile market conditions, to compete on the basis of price and to obtain crude oil more readily in times of shortage. We have no crude oil reserves and are not engaged in the exploration or production of crude oil. However, we believe that we will be able to obtain adequate crude oil and other feedstocks at generally competitive prices for the foreseeable future. We believe that the location of our refinery provides us with a secure supply of crude oil and a transportation cost advantage over many of our competitors.

The recently completed Longhorn pipeline runs approximately 700 miles from the Houston area of the Gulf Coast to El Paso and has an estimated maximum capacity of 225,000 bpd. This pipeline provides Gulf Coast refiners and other shippers with improved access to markets in West Texas and New Mexico. We anticipate that any additional supply provided by this pipeline will lower prices and increase price volatility in El Paso and could adversely affect our sales and profitability in this market. We do not expect our remaining shipments of refined products to be affected, since they are shipped directly for distribution through our retail segment or to other FINA branded customers or are exchange paybacks for sales in Albuquerque and Bloomfield, New Mexico markets, to which the Longhorn pipeline does not have access.

Our major retail competitors include Valero, ChevronTexaco, ConocoPhillips and Shell. The principal competitive factors affecting our retail segment are location of stores, product price and quality, appearance and cleanliness of stores and brand identification. We expect to continue to face competition from large, integrated oil companies, as well as from other convenience stores that sell motor fuels. Increasingly, grocery and dry goods retailers such as Albertson’s, Wal-Mart and HEB are entering the motor fuel retailing business. Many of these competitors are substantially larger than we are. Because of their diversity, integration of operations and greater resources, these companies may be better able to withstand volatile market conditions or levels of low or no profitability.

We compete with Valero, ChevronTexaco, Holly and Paramount in the regional asphalt market. The principal factors affecting competitiveness in asphalt markets are consistency of product quality, transportation cost to the construction site and capability to produce the range of high performance products necessary to meet the requirements of customers.

Environmental Regulation

Environmental Capital Expenditures. All of our operations are subject to extensive environmental regulations. While we believe our operations are generally in substantial compliance with current requirements, over the next several years our operations will have to meet new requirements being promulgated by the EPA and the states in which we operate. For example, the EPA has adopted regulations that will require several significant reductions in the sulfur content in gasoline and diesel fuel. These regulations required most refineries to reduce sulfur content in gasoline to 30 ppm by January 1, 2004. The regulations allow small refiners to meet the 30 ppm gasoline standard by January 2008, or January 2011 if the small refiner implements the new diesel sulfur content standard of 15 ppm by June 1, 2006, which we intend to do. Otherwise, the new diesel standard allows small refiners to delay implementation of the 15 ppm standard until June 1, 2010. We have been certified by the EPA as a small refiner for both gasoline and diesel. We could lose our small refiner certification if, as the result of a merger or acquisition, we employ more than 1,500 employees or increase our production capacity to more than 155,000 bpd. We anticipate that the new gasoline and diesel standards will require capital expenditures of approximately $29.4 million through 2010, of which approximately $6.5 is expected to be spent in the remainder of 2005. If we lose our status as a small refiner, we would be required to incur the capital expenditures for the gasoline and diesel standards at an earlier date than would be required for a small refiner.

As of March 31, 2005, we had substantially completed our expenditures required for compliance with the Voluntary Emissions Reduction Program, or VERP, sponsored by the Texas Commission on Environmental Quality, or TCEQ, including regulations establishing Maximum Achievable Control Technologies for petroleum refineries, or MACT II.

We may have to make additional capital expenditures at our refinery, terminals, retail gasoline stations (operating and closed locations) and petroleum product terminals to comply with the Federal Clean Air Act and other state and federal regulations.

Remediation Efforts. We are currently investigating and remediating historical soil and groundwater contamination at our Big Spring refinery pursuant to a compliance plan issued by the TCEQ. The compliance plan requires us to investigate and, if necessary, remediate fifty-nine potentially contaminated areas on our refinery property. We expect to complete the investigation of these areas by the end of 2006.

The compliance plan also requires us to monitor and treat contaminated groundwater at our Big Spring refinery and some of our terminals, which is currently underway. We estimate that we will be required to spend approximately $6.7 million with respect to the investigation and remediation of our Big Spring refinery and our terminals. The costs incurred to comply with the compliance plan are covered, with certain limitations, by an environmental indemnity provided by Fina, which we discuss below.

In addition, we operate convenience stores with underground gasoline and diesel fuel storage tanks in various states. Compliance with federal and state regulations that govern these storage tanks can be costly. The operation of underground storage tanks also poses various risks, including soil and groundwater contamination. We are currently investigating and remediating leaks from underground storage tanks at some of our convenience stores, and it is possible that we may identify more leaks or contamination in the future that could result in fines or civil liability for us. We have established reserves in our financial statements in respect of these matters to the extent that the associated costs are both probable and reasonably estimable. We cannot assure you, however, that these reserves will prove to be adequate.

Environmental Indemnity from Fina. In connection with the acquisition of our Big Spring refinery and other operating assets from Fina in August 2000, Fina agreed, within prescribed limitations, to indemnify us against costs incurred in connection with any remediation that is required as a result of environmental conditions that existed on the acquired properties prior to the closing date of our acquisition. Fina’s indemnification obligations for these remediation costs run through August 2010, have a ceiling of $5.0 million per year (with carryover of unused ceiling amounts and unreimbursed environmental costs into subsequent years) and have an aggregate indemnification cap of $20.0 million. Thereafter, we are solely responsible for all additional remediation costs. As of March 31, 2005, the remediation of the properties is on schedule, and we have expended approximately $10.3 million in connection with that remediation and approximately $3.0 million in environmental insurance premiums, all of which has been covered by the Fina indemnity. Subject to a $25,000 deductible per claim up to an aggregate deductible of $2.0 million, Fina is additionally obligated to indemnify us for third-party claims with respect to environmental matters received by us within ten years of the closing date to the extent such matters relate to Fina’s operations on the acquired properties prior to the closing date. Fina is further obligated to indemnify us for environmental fines imposed as a result of Fina’s operations on the acquired properties prior to the closing date, provided that such claims are asserted no later than the earlier of ten years from the closing date and the date that the applicable statute of limitations expires. Fina’s aggregate indemnification obligations for environmental fines and third-party claims are not subject to a monetary cap. Excluding liabilities retained by Fina as described above, we assumed the environmental liabilities associated with the acquired properties and agreed to indemnify Fina for any environmental claims or costs in connection with our operations at the acquired properties after the closing date.

We have also purchased two environmental insurance policies to cover expenditures not covered by the Fina indemnification agreement. Under an environmental clean-up cost containment, or cost cap, policy, we are insured for remediation costs for known conditions at the time of our acquisition of our assets from Fina. This policy has a $20.0 million deductible during the first ten years after the acquisition (coinciding with the Fina indemnity) and a $1.0 million annual deductible for the remainder of the term of the policy. Under an environmental response, compensation and liability insurance policy, or ERCLIP, we are covered for bodily injury, property damage, clean-up costs, legal defense expenses and civil fines and penalties relating to unknown conditions and incidents. The ERCLIP policy is subject to a $1.0 million sublimit on liability for civil fines and penalties and a deductible of $150,000, or $100,000 in the case of civil fines or penalties, per incident. Both the cost cap and ERCLIP policies have a term of twenty years and share a maximum aggregate coverage of $40.0 million. The insurer under these policies is The Kemper Insurance Companies, which has experienced significant downgrades of its credit ratings in recent years. Our insurance broker has advised us that environmental insurance policies with terms in excess of ten years are not currently generally available and that policies with shorter terms are available only at premiums substantially in excess of the premiums paid for our policies with Kemper.

Environmental Indemnity to HEP. In connection with the HEP transaction, we entered into an Environmental Agreement with HEP pursuant to which we agreed to indemnify HEP against costs and

liabilities incurred by HEP to the extent resulting from the existence of environmental conditions at the pipelines or terminals prior to February 28, 2005 or from violations of environmental laws with respect to the pipelines and terminals occurring prior to February 28, 2005. Our environmental indemnification obligations under the Environmental Agreement expire after February 28, 2015. In addition, our indemnity obligations are subject to HEP first incurring $100,000 of damages as a result of pre-existing environmental conditions or violations. Our environmental indemnity obligations are further limited to an aggregate indemnification amount of $20 million, including any amounts paid by us to HEP with respect to indemnification for breaches of our representations and warranties under the Contribution Agreement.

With respect to any remediation required for environmental conditions existing prior to February 28, 2005, we have the option under the Environmental Agreement to perform such remediation ourselves in lieu of indemnifying HEP for their costs of performing such remediation. Pursuant to this option, we are continuing to perform the ongoing remediation at the Wichita Falls terminal which is subject to our environmental indemnity from Fina. Any remediation required under the terms of the Environmental Agreement is limited to the standards under the applicable environmental laws as in effect at February 28, 2005.

Other Government Regulation

Our Amdel pipeline is regulated by the Federal Energy Regulatory Commission. All of our pipelines are regulated by Department of Transportation rules and our intrastate pipelines are regulated by the Texas Railroad Commission. Within the Texas Railroad Commission, the Pipeline Safety Section of the Gas Services Division administers and enforces the federal and state requirements on our intrastate pipelines. All of our pipelines within Texas are permitted and certified by the Texas Railroad Commission’s Gas Services Division.

Both the State of Texas and the Federal Department of Transportation have recently promulgated new regulations on pipeline safety. These regulations require pipelines that are located in populated or environmentally sensitive areas to prepare and implement a program for managing the integrity of these pipelines, including the repair of any defects identified as a result of ongoing pipeline integrity assessments. We estimate that compliance with these new regulations will require us to invest $1.3 million over the next five years.

The Petroleum Marketing Practices Act, or PMPA, is a federal law that governs the relationship between a refiner and a distributor pursuant to which the refiner permits a distributor to use a trademark in connection with the sale or distribution of motor fuel. We are subject to the provisions of the PMPA because we sublicense the Fina brand to our distributors in connection with their distribution and sale of motor fuels. The PMPA provides that we may not terminate or fail to renew our distributor contracts unless certain enumerated preconditions or grounds for termination or nonrenewal are met and we also comply with prescribed notice requirements. The PMPA provides that our distributors may enforce the provisions of the act through civil actions against us. If we terminate or fail to renew one or more of our distributor contracts in the absence of the specific grounds permitted by the PMPA, or fail to comply with the prescribed notice requirements in effecting a termination or nonrenewal, those distributors may file lawsuits against us to compel continuation of their contracts or to recover damages from us.

Employees

As of April 30, 2005, we had approximately 1,415 employees. Approximately 250 employees worked in our refining and marketing segment, of which 170 were employed at our refinery and approximately 80 were employed at our corporate offices in Dallas. Approximately 120 of the 170 employees at our refinery are covered by collective bargaining agreements that expire on March 31, 2006. Approximately 1,165 employees worked in our retail segment. None of the employees in our retail segment or in our corporate offices are represented by a union. We consider our relations with our employees to be satisfactory.

Legal Proceedings

In the ordinary conduct of our business, we are subject to periodic lawsuits, investigations and claims, including, environmental claims and employee related matters. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, results of operations, cash flows or financial condition.

Corporate Structure

As of June 30, 2005, our corporate structure was as set forth in the following diagram:


(1)	Alon Israel owns 96% of Alon USA Energy, Inc. directly, and the remaining 4% indirectly through its wholly owned subsidiary, Tabris Investments Inc.

(2)	Alon USA, Inc. is the borrower under our term loan. The term loan is guaranteed by Alon USA Energy, Inc. and its subsidiaries other than the retail financing subsidiaries.


(3)	Alon Operating is a holding company with no independent operations. The 6.4% of equity interest not owned by Alon USA, Inc. consists of non-voting common stock held by certain of our executive officers. See “Principal Stockholders.”

(4)	Alon USA GP, LLC is the employer of our refining and marketing and corporate office employees and maintains the related benefit plans.

(5)	Our refining and marketing business and operations are conducted through Alon USA, LP. Alon USA, LP is the borrower under our revolving credit facility. The revolving credit facility is guaranteed by Alon USA Inc. and its subsidiaries other than the retail financing subsidiaries.

(6)	Southwest Convenience Stores, or SCS, conducts our retail business operations and owns or leases our retail locations and assets.

(7)	Alon Capital issued 40% of its equity interest to finance a portion of the acquisition price of our refining and marketing assets from Fina in 2000. We acquired this 40% interest in 2002 in the Alon Capital minority interest acquisition. See “Certain Relationships and Related Transactions — The Alon Capital Minority Interest Acquisition.”

(8)	Alon Assets is a holding company with no independent operations. The 6.4% equity interest not owned by Alon Capital consists of non-voting common stock held by certain of our executive officers. See “Principal Stockholders.” The direct and indirect subsidiaries of Alon Assets own or lease our refining and marketing assets and lease or sublease those assets to Alon USA, LP.

(9)	T & R Assets, Inc., Fin-Tex Pipe Line Company and Alon USA Refining, Inc. collectively own 100% of Alon Pipeline Logistics, LLC.

MANAGEMENT

Directors and Executive Officers

The following table sets forth the names and ages of each of our current directors and executive officers and certain of our other key employees, and the positions they held, as of May 2, 2005:


Name	Age		Position

David Wiessman		50	Executive Chairman of the Board of Directors
Pinchas Cohen		53	Director
Avraham Meron		65	Director
Itzhak Bader		59	Director
Ron W. Haddock		64	Director
Boaz Biran		42	Director
Yeshayahu Pery		71	Director
Zalman Segal		68	Director Nominee
Jeff D. Morris		53	Director, President and Chief Executive Officer
Claire A. Hart		49	Senior Vice President
Shai Even		36	Chief Financial Officer and Treasurer
Joseph A. Concienne		54	Vice President of Refining and Transportation
Kyle C. McKeen		41	Vice President of Marketing
Jimmy C. Crosby		46	Vice President of Supply and Planning
Joseph Israel		34	Vice President of Mergers and Acquisitions
Harlin R. Dean		38	Vice President, General Counsel and Secretary
Joseph Lipman		59	President and Chief Executive Officer of SCS

Set forth below is a brief description of the business experience of each of our directors, executive officers and key employees listed above. Prior to this offering, our executive officers, other than Messrs. Wiessman and Dean, served with our wholly-owned subsidiary, Alon USA, Inc., which has historically managed our operations. In May 2005, in contemplation of this offering, each of the executive officers of Alon USA, Inc., was elected to the same office or appointed to the same position with Alon USA Energy, Inc. in which he serves with Alon USA, Inc.

David Wiessman has served as Executive Chairman of the Board of Directors of Alon since July 2000 and served as President and Chief Executive Officer of Alon USA Energy, Inc. from its formation in 2000 until May 2005. Mr. Wiessman has over 25 years of oil industry and marketing experience. Since 1994, Mr. Wiessman has been Chief Executive Officer, President and a director of Alon Israel. In 1992, Bielsol Investments (1987) Ltd. acquired a 50% interest in Alon Israel. In 1987, Mr. Wiessman became Chief Executive Officer of, and a stockholder in, Bielsol Investments (1987) Ltd., a sister company of Bielsol Ltd. In 1976, after serving in the Israeli Air Force, he became Chief Executive Officer of Bielsol Ltd., a privately owned Israeli company that owns and operates gasoline stations and owns real estate in Israel. Mr. Wiessman is also Chairman of the Board of Directors of Blue Square Chain Properties and Investments, Ltd., which is listed on the Tel Aviv Stock Exchange, and Deputy and Vice Chairman of Blue Square Israel, Ltd., which is listed on the New York Stock Exchange and the Tel Aviv Stock Exchange. Mr. Wiessman also has served as Chairman of the Board and President of Dor Alon Energy since January 2005.

Pinchas Cohen has served as a director of Alon since May 2002. Mr. Cohen is the Chief Executive Officer of Africa Israel Investments Ltd., an investment company in Israel listed on the Tel Aviv Stock Exchange, a position he has held since 1999. From 1998 to 1999, he was Executive Vice President of Africa Israel Investments Ltd., and from 1994 to 1998, he was General Manager of ELDAN

Transportation and Tourism, a car rental and road service company in Israel. Mr. Cohen is also a director of Alon Israel and Blue Square Israel, Ltd.

Avraham Meron has served as a director of Alon since August 2000. Mr. Meron has also served as a director of Alon Israel since 1997. He is Senior Vice President – Finance of Africa Israel Investments, Ltd., a position he has held since 1995. Mr. Meron is also a director of Blue Square Israel, Ltd.

Itzhak Bader has served as a director of Alon since August 2000. Mr. Bader has also served as Chairman of the Board of Directors of Alon Israel since 1993. He is Chairman of Granot Cooperative Regional Organization Corporation, a purchasing organization of the Kibbutz movement, a position he has held since 1995. In addition, he is also Chairman of Gat, Givat Haim Agricultural Cooperative for Conservation of Agricultural Production Ltd., an Israeli beverage producer, a position he has held since 1999. Mr. Bader is also a director of Blue Square Israel, Ltd.

Ron W. Haddock has served as a director of Alon since August 2002. Mr. Haddock has also served as a consultant to Alon and certain of its subsidiaries since September 2000. From December 1989 to July 2000, Mr. Haddock served as Chief Executive Officer of Fina. Mr. Haddock currently serves as the Chairman of the Board and Chief Executive Officer of Prisma Energy International, a Houston-based international energy corporation and successor to the international energy infrastructure business of Enron Corp. Mr. Haddock also serves as a director of Southwest Securities, Inc., a financial services company; SepraDyne Corporation, a Dallas-based environmental technology company; Adea Solutions, Inc., a Dallas-based high-tech personnel and consulting firm; and Safety-Kleen Systems, Inc., a Dallas-based waste management, oil recycling and refining company.

Boaz Biran has served as director of Alon since May 2002. Mr. Biran has been a director of Bielsol Investments (1987) Ltd. since 1998, and a partner in Shraga F. Biran & Co., a law firm in Israel, since 1999. Mr. Biran has also served as Chairman of the Board of Directors of Rosebud Medical Ltd., an investment company in Israel listed on the Tel Aviv Stock Exchange, since November 2003.

Yeshayahu Pery has served as a director of Alon since August 2003. Mr. Pery has also served as a director of Alon Israel since 1997. He is Chairman of MIGAL INC., a technology institute in the biotechnology field, a position he has held since 1998. From 1997 until 2004 Mr. Pery served as Chairman and Chief Executive Officer of Galilee Cooperative Organisation, a purchasing and finance organization of the Kibutz movement. In addition, Mr. Pery served as Chairman of Agricultural Insurance Association and the Atudot pension fund between 1995 and 2004.

Zalman Segal is currently Vice Chairman of the board of directors of Bank Leumi USA and a director of its subsidiary, Leumi Investment Services. Mr. Segal served from 1989 through 2004 as Chief Executive Officer and as a director of Bank Leumi USA, where he was responsible for the commercial banking business of Bank Leumi USA in the Western Hemisphere.

Jeff D. Morris has served as a director and as our President and Chief Executive Officer since May 2005 and has served as the President and Chief Executive Officer of our subsidiary Alon USA since its inception in August 2002 and of our other operating subsidiaries since July 2000. Prior to joining Alon, he held various positions at Fina, where he began his career in 1974. Mr. Morris served as Vice President of Fina’s SouthEastern Business Unit from 1998 to 2000 and as Vice President of its SouthWestern Business Unit from 1995 to 1998. In these capacities, he was responsible for both the Big Spring refinery and Fina’s Port Arthur refinery and had responsibility for crude gathering assets and marketing activities for both business units.

Claire A. Hart has served as our Senior Vice President since January 2004 and served as our Chief Financial Officer and Vice President from August 2000 to January 2004. Prior to joining Alon, he held various positions in the Finance, Accounting and Operations Departments of Fina for 13 years, serving most recently as Treasurer from 1998 to August 2000 and as General Manager of Credit Operations from 1997 to 1998.

Shai Even has served as a Vice President since May 2005, as our Chief Financial Officer since December 2004 and as our Treasurer from August 2003 to May 2005. Prior to joining Alon, Mr. Even served as the Chief Financial Officer of DCL Technologies, Ltd. from 1996 to July 2003 and prior to that worked for KPMG from 1993 to 1996.

Joseph A. Concienne has served as our Vice President of Refining and Transportation since March 2001. His primary role is as site manager for our Big Spring refinery. Prior to joining Alon, Mr. Concienne served as Director of Operations/ General Manager for Polyone Corporation in Seabrook, Texas from 1998 to 2001. He served as Vice President/ General Manager for Valero Refining and Marketing, Inc. in 1998 and as Manager of Refinery Operations and Refinery Manager for Phibro Energy Refining, which became Valero Refining and Marketing, Inc. in 1998, from 1985 to 1998.

Kyle C. McKeen has served as our Vice President of Marketing since August 2002 with responsibilities for our retail technologies. From June 2001 to August 2002, Mr. McKeen served as General Manager of Marketing Support. From January 1999 until June 2001, he served as Manager of Market Development for Intermec Technologies.

Jimmy C. Crosby has served as our Vice President of Supply and Planning since March 2005, with responsibility for all terminal and refinery supply for our marketing and refinery operations. Mr. Crosby served as our General Manager of Business Development and Planning from August 2000 to March 2005. Prior to joining Alon, Mr. Crosby worked with Fina from 1996 to August 2000 where he last held the position of Manager of Planning and Economics for the Big Spring refinery.

Joseph Israel has served as our Vice President of Mergers & Acquisitions and Business Development since March 2005. Mr. Israel served as our General Manager of Economics and Commerce from September 2000 to March 2005. Prior to joining Alon, Mr. Israel held positions with several Israeli government entities beginning in 1998, including the Israeli Land Administration, the Israeli Fuel Administration and most recently as Commerce Vice President of Israel’s Petroleum Energy Infrastructure entity.

Harlin R. Dean has served as our General Counsel and Secretary since October 2002 and as Vice President since May 2005. Prior to joining Alon USA, Mr. Dean practiced corporate and securities laws, with a focus on public and private merger and acquisition transactions and public securities offerings, at Brobeck, Phleger & Harrison LLP, from April 2000 to September 2002, and at Weil, Gotshal & Manges, L.L.P., from September 1992 to March 2000.

Joseph Lipman has served as President and Chief Executive Officer of SCS since July 2001. From 1997 to July 2001, Mr. Lipman served as General Manager of Cosmos, a chain of supermarkets in Israel owned by Super-Sol Ltd., where he was responsible for marketing and store operations. Mr. Lipman also held general managerial posts at Tuoro College, in Jerusalem in 1997.

Board of Directors

Our board of directors currently consists of eight members, Messrs. Wiessman, Cohen, Meron, Bader, Haddock, Biran, Pery and Morris. Upon completion of this offering, Mr. Segal will become a director and our board of directors will consist of nine members.

Committees of the Board of Directors

Our board of directors does not have a nominating and corporate governance committee or a committee performing the functions of this committee. Our board of directors has determined that we are a “controlled company” for the purposes of Section 303A of the New York Stock Exchange Listed Company Manual because Alon Israel holds more than 50% of the voting power of our company. As such, we are relying on exemptions from the provisions of Section 303A that would otherwise require us, among other things, to have a board of directors composed of a majority of independent directors, to have a compensation committee composed of independent directors and to have a nominating and corporate governance committee.


	•	Audit Committee. Upon completion of this offering, our audit committee will be composed of Messrs. Segal, Meron and Haddock. Our board of directors has determined that each of these individuals is financially literate and that Mr. Segal has accounting or related financial management expertise, in each case as contemplated by applicable New York Stock Exchange requirements. Our board of directors has determined that Mr. Segal satisfies applicable New York Stock Exchange and SEC requirements relating to independence but that Messrs. Meron and Haddock currently do not. Because this offering is our initial public offering, we are permitted to phase in the independence of our audit committee. Upon completion of this offering, we will be required to have one independent audit committee member and will be required to have a majority of independent members approximately 90 days after the date of this prospectus and to have all independent audit committee members approximately one year after the date of this prospectus. The audit committee will oversee our accounting and financial reporting processes and the audits of our financial statements.

	•	Compensation Committee. Our compensation committee is composed of Messrs. Wiessman and Morris. The compensation committee establishes, administers and reviews our policies, programs and procedures for compensating our executive officers and directors.

Director Compensation

Except as described below, our directors historically have not been compensated for their services as such. Under an oral agreement we have with Ron W. Haddock, we have historically paid Mr. Haddock an annual fee of $50,000 for serving on the board of directors of Alon USA plus $1,500 for each board or committee meeting he attends. See “Certain Relationships and Related Transactions — Other Consulting and Service Relationships.” In addition, we have paid Mr. Wiessman compensation as our Executive Chairman as described under “— Executive Compensation.”

Effective upon consummation of this offering, our non-employee directors will receive an annual fee of $50,000 and an additional fee of $1,500 per meeting attended. The chairperson of our audit committee will also receive an annual fee of $10,000 and each member of our audit committee will receive a fee of $1,500 per meeting attended. In addition, each independent director and each other non-employee director who is not affiliated with Alon Israel will receive $25,000 per year in restricted stock which will vest in three equal installments on each of the first, second and third anniversaries of the grant date.

Executive Compensation

Summary Compensation Table. Mr. Wiessman served as Executive Chairman, President and Chief Executive Officer of Alon USA Energy, Inc. until May 2005. In 2004, there were two other officers of Alon USA Energy, Inc., neither of whom received total salary and bonus in excess of $100,000. In May 2005, the executive officers of our subsidiary, Alon USA, Inc. were elected as executive officers of Alon USA Energy, Inc. See “Management — Directors and Executive Officers.”

The following table provides a summary of the compensation awarded to, earned by or paid to Mr. Wiessman in 2004 and to Messrs. Morris, Hart, Concienne and Dean, the four most highly compensated executive officers of Alon USA, Inc., in 2004. The position of each of the individuals reflects his position held in 2004. We refer to these individuals as our named executive officers.


				Annual Compensation

Name and Position		Year		Salary		Bonus

David Wiessman(a)			2004	$	140,534	$	134,453
	Executive Chairman of the Board, President and Chief Executive Officer of Alon USA Energy, Inc.
Jeff D. Morris			2004	$	289,675	$	464,360	(b)
	President and Chief Executive Officer of Alon USA, Inc.
Claire A. Hart			2004	$	173,214	$	202,953	(b)
	Senior Vice President of Alon USA, Inc.
Joseph A. Concienne			2004	$	167,387	$	197,209	(b)
	Vice President of Refining and Transportation of Alon USA, Inc.
Harlin R. Dean			2004	$	245,001	$	163,890
	Vice President, General Counsel and Secretary of Alon USA, Inc.


(a)		Under an agreement between Alon Israel and David Wiessman relating to Mr. Wiessman’s service to Alon Israel and its subsidiaries, we have historically paid Mr. Wiessman, indirectly through a company owned by him, a fee of $11,583 per month for serving as Executive Chairman of the board of directors of Alon and have paid on behalf of Mr. Wiessman maintenance and utility costs associated with his Dallas, Texas residence, which were approximately $17,524 in 2004. See “Certain Relationships and Related Transactions — Other Consulting and Service Relationships.”

(b)		Bonus includes amounts paid under our stock option plans to cover the exercise price of options exercised in that year and reimbursement of related tax obligations.

Option Exercises in 2004 and December 31, 2004 Option Values. The following tables set forth information concerning option exercises for 2004 and the number of shares underlying both exercisable and non-exercisable stock options held by the named executive officers as of December 31, 2004, and the values for exercisable and unexercisable options. The shares acquired on exercise and the shares underlying options are shares of Alon Assets or Alon Operating, as indicated. Options are in the money if the value of the shares covered thereby is greater than the option exercise price. The calculation of the value realized on exercise is based on our estimates of the value of the shares of Alon Assets or Alon Operating, as

applicable. The calculation of the value of unexercised in-the-money options is based on our estimates of the value of the shares of Alon Assets or Alon Operating, as applicable, less the exercise price.

Alon Assets


					Number of Securities				Value of Unexercised
					Underlying Unexercised				In-the-Money Options at
	Shares				Options at Year End 2004				Year End 2004
	Acquired on		Value
Name	Exercise		Realized		Exercisable		Unexercisable		Exercisable		Unexercisable

David Wiessman		—	$	—		—		—	$	—	$	—
Jeff D. Morris		807.7		30,693		807.7		5,318.0		1,615		10,636
Claire A. Hart		201.9		7,672		201.9		1,329.3		404		2,659
Joseph A. Concienne		201.9		7,672		201.9		1,413.5		404		2,827
Harlin R. Dean		—		—		—		—		—		—

Alon Operating


					Number of Securities				Value of Unexercised
					Underlying Unexercised				In-the-Money Options at
	Shares				Options at Year End 2004				Year End 2004
	Acquired on		Value
Name	Exercise		Realized		Exercisable		Unexercisable		Exercisable		Unexercisable

David Wiessman		—	$	—		—		—	$	—	$	—
Jeff D. Morris		303.3		153,470		303.3		1,997.1		226,262		1,489,838
Claire A. Hart		75.8		38,355		75.8		499.2		56,547		372,403
Joseph A. Concienne		75.8		38,355		75.8		530.8		56,547		395,977
Harlin R. Dean		—		—		—		—		—		—

Bonus Plans

We maintain two bonus plans in which our refining and marketing employees participate, including our named executive officers.

Annual Incentive Cash Bonus Plan. Bonuses paid under our Annual Incentive Cash Bonus Plan are distributed to eligible employees in the first quarter of each year based on the previous year’s performance. Each bonus payment is based 75% on meeting or exceeding financial objectives and 25% on meeting or exceeding safety and environmental objectives. The bonus pool used to pay these bonuses is funded on a calendar basis and starts over at zero after each calendar year. This fund consists of one-third of our after-tax cash flow, after all planned capital expenditures and certain principal and interest payments under our indebtedness have been made. The funds available for bonuses are capped at $4.0 million per year. Individual bonus payments can be reduced by up to 25% upon the occurrence of certain environmental or safety problems. Furthermore, any fines for environmental or safety violations are deducted from the bonus pool.

Messrs. Wiessman, Morris, Hart and Concienne are eligible for bonuses up to 100% of their annual salary, and Mr. Dean is eligible for a bonus up to 65% of his annual salary, under our Annual Incentive Cash Bonus Plan. In 2004, our named executives received bonuses under this plan in the following amounts: Mr. Wiessman - $134,453; Mr. Morris - $284,747; Mr. Hart - $169,992; Mr. Concienne - $164,417; and Mr. Dean - $156,541.

Annual 10% Bonus Plan. Bonuses paid under the 10% Bonus Plan are distributed to our non-union refining and marketing employees in the second quarter of each year based on the previous year’s performance. Each participating employee is eligible to receive a bonus up to a maximum of 10% of his or her salary under the plan. Each participating employee is eligible to receive a bonus amount equal to 40% of the maximum bonus if we meet or are below our fixed costs operating budget. Each refinery employee is eligible to receive a bonus amount equal to 30% of the maximum bonus if certain refining margins are achieved. Each non-refinery employee is eligible to receive a bonus amount equal to 30% of the maximum

bonus if certain wholesale marketing margins are achieved. All participating employees are eligible to receive a bonus amount of up to 30% of the maximum bonus at the discretion of senior management.

In 2004, our named executives received bonuses under this plan in the following amounts: Mr. Wiessman - $0; Mr. Morris - $8,690; Mr. Hart - $5,191; Mr. Concienne - $5,022; and Mr. Dean - $7,350.

2000 Stock Option Plan of Alon Assets and Alon Operating

In 2000, the board of directors of each of Alon Assets and Alon Operating adopted a 2000 Stock Option Plan, which was approved by their respective stockholders in June 2001. The option plans for Alon Assets and Alon Operating are substantially identical. No further options will be granted under these plans.

As of December 31, 2004, there were 148,243.7 shares of capital stock of Alon Assets outstanding and 55,667.8 shares of capital stock of Alon Operating outstanding. All outstanding options expire no later than ten years after the date of grant. As of December 31, 2004, the following options were outstanding:


	Number of Shares
	Underlying		Per Share
2000 Stock Option Plan of:	Outstanding Options		Exercise Price

Alon Assets		9,272.3	$	100
Alon Operating		3,482.0		100

No options to purchase common stock of Alon Assets or Alon Operating were granted pursuant to these plans during 2004. Plan participants exercised options for 1,211.5 shares in Alon Assets and 454.9 shares in Alon Operating in 2004.

2005 Incentive Compensation Plan

Our board of directors and stockholders have approved our 2005 Incentive Compensation Plan, our Incentive Plan, which is described below. This summary is qualified in its entirety by the detailed provisions of the Incentive Plan, a copy of which will be filed as an exhibit to our registration statement of which this prospectus is a part.

The purpose of the Incentive Plan is to attract, reward and retain qualified personnel, and to provide incentives for our directors, officers and employees to set forth maximum efforts for the success of our business. Our Incentive Plan permits the granting of awards in the form of options to purchase common stock, stock appreciation rights, restricted shares of common stock, restricted stock units, performance shares, performance units and senior executive plan bonuses.

Subject to certain adjustments that may be required from time to time to prevent dilution or enlargement of the rights of participants in the Incentive Plan, a maximum of 2,200,000 shares will be available for grants of all equity awards under the Incentive Plan. The shares of common stock to be issued under the Incentive Plan consist of authorized but unissued shares of our common stock. If any shares are subject to an award that expires or are forfeited, then such shares will, to the extent of any forfeiture or termination, again be available for making awards under the Incentive Plan.

The Incentive Plan will be administered, in the case of awards to participants subject to Section 16 of the Securities Exchange Act of 1934, by the incentive compensation plan committee to be formed following this offering, and in all other cases, by the compensation committee of our board of directors. Subject to the terms of the Incentive Plan, the applicable committee has the full authority to select participants to receive awards, determine the types of awards and terms and conditions of awards, and interpret provisions of the Incentive Plan. Awards may be made under the Incentive Plan to eligible directors, officers and employees of Alon USA Energy, Inc. and its subsidiaries, provided that awards qualifying as incentive stock options, as defined under the Internal Revenue Code of 1986, as amended, or

the Code, may only be granted to employees. In addition, each non-employee director who is not affiliated with Alon Israel will receive annual restricted stock grants.

While our board of directors may terminate or amend the Incentive Plan at any time, no amendment may adversely impair the rights of grantees with respect to outstanding awards. In addition, an amendment will be contingent on approval of our stockholders to the extent required by law. Unless terminated earlier, the Incentive Plan will terminate on the tenth anniversary of the date on which it is approved by our stockholders, after which no further awards may be made under the Incentive Plan, but will continue to govern unexpired awards.

Pension Plans

The following table provides the estimated annual benefits payable to eligible employees upon retirement under our pension plan, based on the eligible employee’s average annual compensation level at retirement and credited years of service.


			Pension Plan Table(a)(b)

	Years of Service

Compensation Level	15		20		25		30		35

$125,000	$	30,938	$	41,250	$	51,563	$	61,875	$	72,188
150,000		37,125		49,500		61,875		74,250		86,625
175,000		43,313		57,750		72,188		86,625		101,063
200,000		49,500		66,000		82,500		99,000		115,500
225,000		55,688		74,250		92,813		111,375		129,938
250,000		61,875		82,500		103,125		123,750		144,375
300,000		74,250		99,000		123,750		148,500		173,250
400,000		99,000		132,000		165,000		198,000		231,000
450,000		111,375		148,500		185,625		222,750		259,875
500,000		123,750		165,000		206,250		247,500		288,750

(a) Pension plan benefits are computed on a straight-line annuity basis.


(b)	The benefits listed in the pension plan table above are subject to a deduction for Social Security benefits.

Employees who participate in the pension plan make no contributions. A participating employee becomes vested in the pension plan once that employee has completed five full years of employment, assuming a minimum of 1,000 hours of service per year. After becoming vested, a participating employee has a non-forfeitable right to his vested retirement benefit. A participant’s compensation for purposes of determining benefits under the pension plan includes salary, bonus and overtime pay. The bonus amount does not include bonuses paid to our executives in connection with the Alon Assets or Alon Operating option plans. The compensation covered by the pension plan and the credited years of service with respect to Messrs. Wiessman, Morris, Hart, Concienne and Dean as of March 31, 2005 are set forth in the table below, assuming retirement at the normal retirement age under the pension plan of 65:


	Compensation Covered		Credited Years
Name	by Pension Plan		of Service

David Wiessman	$	—		—
Jeff D. Morris		526,261		30.8
Claire A. Hart		252,294		4.5
Joseph A. Concienne		243,788		3.9
Harlin R. Dean		319,944		2.3

We also provide additional pension benefits to our highly compensated employees through our Pension Restoration Plan. If an employee is a participant in our pension plan and is subject to the limitation on compensation pursuant to Section 401(a)17 or 415 of the Code, then the employee can participate in the

Pension Restoration Plan and is eligible for a benefit equal to his benefit payable under our pension plan without regard to any limitations on compensation less his benefit payable under our pension plan with regard to the limitations on compensation. This Pension Restoration Plan is unfunded and vests on the same schedule as our pension plan.

Employment Agreements

Jeff D. Morris. We are party to an Executive Employment Agreement with Jeff Morris which provides for Mr. Morris to serve as our President and Chief Executive Officer through April 30, 2010 and which automatically renews for one-year terms unless terminated by either party. Mr. Morris currently receives a base salary of $289,674 per year and is eligible for annual merit increases. Under his employment agreement, Mr. Morris is entitled to participate in our annual cash bonus plans, pension plan and benefits restoration plan and our 2000 stock option plans. Additionally, we are required to provide Mr. Morris with additional benefits, including disability, hospitalization, medical and retiree health benefits and life insurance. Mr. Morris is subject to a covenant not to compete during the term of his employment for nine months after the date of his termination. This agreement also prohibits Mr. Morris from disclosing our proprietary information received through his employment.

In the event of a change in control of Alon Assets or Alon Operating in which the equity securities owned by Mr. Morris in Alon Assets or Alon Operating (whether actually or contingently owned) are included and such change of control occurs either (i) prior to the earlier of July 31, 2010 or the date of vesting of Mr. Morris’ shares of common stock of Alon Assets and Alon Operating or (ii) after the termination of Mr. Morris’ employment by us without cause or by Mr. Morris for good reason, Mr. Morris is entitled to receive a cash bonus in the amount of 8% of the amount by which the aggregate implied equity value of Alon Assets and Alon Operating exceeds $20 million. The percentage due to Mr. Morris is subject to adjustment based on the number of shares of common stock owned by Mr. Morris that vest prior to any change of control transaction, and the implied equity value of Alon Assets or Alon Operating, as the case may be, is subject to a minimum estimated value based on the year in which the change of control occurs.

Claire A. Hart. We are party to an Executive Employment Agreement with Claire Hart which provides for Mr. Hart to serve as our Senior Vice President through April 30, 2010 and which automatically renews for one-year terms unless terminated by either party. Mr. Hart currently receives a base salary of $177,900 per year and is eligible for annual merit increases. Under his employment agreement, Mr. Hart is entitled to participate in our annual cash bonus plans, pension plan and benefits restoration plan and our 2000 stock option plans. Additionally, we are required to provide Mr. Hart with additional benefits, including disability, hospitalization, medical and retiree health benefits and life insurance. Mr. Hart is subject to a covenant not to compete during the term of his employment and for nine months after the date of his termination. This agreement also prohibits Mr. Hart from disclosing our proprietary information received through his employment.

Joseph A. Concienne. We are party to an Executive Employment Agreement with Joseph Concienne which provides for Mr. Concienne to serve as Vice President of Refining and Transportation through April 30, 2010 and which automatically renews for one-year terms unless terminated by either party. Mr. Concienne currently receives a base salary of $175,000 per year and is eligible for annual merit increases. Under his employment agreement, Mr. Concienne is entitled to participate in our annual cash bonus plans, pension plan and benefits restoration plan and our 2000 stock option plans. Additionally, we are required to provide Mr. Concienne with additional benefits, including disability, hospitalization, medical and retiree health benefits and life insurance. Mr. Concienne is subject to a covenant not to compete during the term of his employment and for nine months after the date of his termination. This agreement also prohibits Mr. Concienne from disclosing our proprietary information received through his employment.

Harlin R. Dean. We are party to an Management Employment Agreement with Harlin Dean which provides for Mr. Dean to serve as our Vice President, General Counsel and Secretary through April 30, 2010 and which automatically renews for one-year terms unless terminated by either party. Mr. Dean

currently receives a base salary of $250,700 per year and is eligible for annual merit increases. Under his employment agreement, Mr. Dean is entitled to participate in our annual cash bonus plans, pension plan and benefits restoration plan. Additionally, we are required to provide Mr. Dean with additional benefits, including disability, hospitalization, medical and retiree health benefits and life insurance. Mr. Dean is subject to a covenant not to compete during the term of his employment and for nine months after the date of his termination. This agreement also prohibits Mr. Dean from disclosing our proprietary information received through his employment.

Compensation Committee Interlocks and Insider Participation

Neither Alon USA Energy, Inc. or Alon USA, Inc. had a compensation committee during 2004. In connection with this offering, Alon USA Energy, Inc. established a compensation committee consisting of Messrs. Wiessman and Morris. In 2004, compensation for our executive officers other than Messrs. Wiessman and Morris was determined by Messrs. Wiessman and Morris, with Mr. Morris’ compensation being determined by Mr. Wiessman. Mr. Wiessman’s compensation is determined by the board of directors of Alon Israel, excluding Mr. Wiessman, and approved by the shareholders of Alon Israel. For a discussion of the shareholders and directors Alon Israel and related board and shareholder approval requirements, see note 3 of “Principal Stockholders.” The portion of Mr. Wiessman’s compensation to be paid by Alon USA Energy, Inc. for his services as our Executive Chairman is subject to the approval of our board of directors, excluding Mr. Wiessman. See “Certain Relationships and Related Transactions” for information regarding relationships and transactions involving Alon in which Messrs. Wiessman and Morris had interests.

None of our executive officers serves as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our board of directors.

PRINCIPAL STOCKHOLDERS

The following table sets forth information regarding the beneficial ownership of our common stock as of June 30, 2005, on both a historical basis and as adjusted to reflect the sale of common stock offered by us pursuant to this prospectus, for:


	•	each person known by us to beneficially own more than 5% of our common stock;

	•	each executive officer named in the Summary Compensation Table under “Management”;

	•	each of our directors; and

	•	all of our executive officers and directors as a group.

Beneficial ownership is determined in accordance with the rules of the SEC and includes voting and investment power with respect to securities. Except as indicated by footnote, and subject to applicable community property laws, the persons named in the table below have sole voting and investment power with respect to all shares of common stock shown as beneficially owned by them. The number of shares of common stock used to calculate the percentage ownership of each listed person includes the shares of common stock underlying options or warrants held by such person that are exercisable within 60 days of this offering. The percentage of beneficial ownership before the offering is based on 35,001,120 shares of common stock outstanding as of June 30, 2005 (after giving effect to the 33,600-for-one stock split of our common stock effected on July 6, 2005). Percentage of beneficial ownership after the offering is based on 45,201,120 shares, including the 10,200,000 shares of common stock to be sold in this offering. The post-offering ownership percentages in the table below do not take into account any exercise of the underwriters’ over-allotment option.


			Percentage of Common
			Stock Beneficially Owned
	Shares
	Beneficially		Before			After
Name of Beneficial Owner	Owned		Offering			Offering

Directors and Executive Officers:
David Wiessman(1)		700,022		2.0	%		1.55	%
Pinchas Cohen		—		—			—
Avraham Meron		—		—			—
Itzhak Bader		—		—			—
Ron W. Haddock		—		—			—
Boaz Biran		—		—			—
Yeshayahu Pery		—		—			—
Jeff D. Morris(2)		—		—			—
Claire A. Hart(2)		—		—			—
Joseph A. Concienne(2)		—		—			—
Harlin R. Dean		—		—			—
All directors and officers as a group(1) (15 persons)		700,022		2.0			1.55
Other 5% Stockholders:
Alon Israel Oil Company, Ltd.(3)		35,001,120		100.0	%		77.4	%


	*	Indicates beneficial ownership of less than one percent of the total outstanding common stock.


	(1)	Consists of shares of common stock of Alon USA Energy, Inc. that Mr. Wiessman is entitled to receive, at Mr. Wiessman’s option, from Alon Israel in exchange for his 2% ownership interest in Alon Israel (held through a trust of which Mr. Wiessman is the sole beneficiary).


	(2)	As of June 30, 2005, there were 149,455.2 shares of capital stock of Alon Assets outstanding and 56,122.7 shares of capital stock of Alon Operating outstanding. Messrs. Morris, Hart and Concienne each own shares of non-voting stock of Alon Assets and Alon Operating as set forth in the following table:


		Alon Assets					Alon Operating

		Non-voting		Percent of all			Non-voting		Percent of all
Name of Beneficial Owner		Common Stock		Common Stock			Common Stock		Common Stock

Jeff D. Morris			7,121.6		4.8	%		2,674.3		4.8	%
Claire A. Hart			1,780.3		1.2			668.5		1.2
Joseph A. Concienne			605.7		0.4			227.4		0.4

	Total		9,507.6		6.4	%		3,570.2		6.4	%


	The individuals named in the table above hold options covering an aggregate of 8,060.8 shares of Alon Assets and 3,027.1 shares of Alon Operating. Subject to the satisfaction of specified performance targets, these options will become fully vested in 2010 (assuming the continued employment of the individuals). After giving effect to the issuance by Alon Assets and Alon Operating of additional shares in connection with this offering pursuant to the agreement described below, upon the full vesting and exercise of all of these options, the individuals would own an aggregate of 8.64% of the common stock of each of Alon Assets and Alon Operating, or 8.35% if the underwriters’ option to purchase additional shares is exercised in full.

	Pursuant to an agreement, dated as of July 6, 2005, among Alon USA Energy, Inc., Alon USA, Alon Capital, Alon Operating, Alon Assets, Jeff D. Morris, Claire A. Hart and Joseph A. Concienne, upon the issuance by Alon USA Energy, Inc. of shares of its common stock (including shares to be issued pursuant to this offering) and upon issuance of shares to Messrs. Morris, Hart and Concienne pursuant to exercise of their options described above, each of Alon Assets and Alon Operating will issue a number of shares of voting common stock to its parent company sufficient to dilute the ownership percentage of Messrs. Morris, Hart and Concienne in the outstanding common stock of Alon Assets and Alon Operating by an amount equal to the percentage which the aggregate shares of common stock issued by Alon USA Energy, Inc. since the date of the agreement represent of the common stock of Alon USA Energy, Inc. then outstanding. As consideration for the issuance of the shares by Alon Assets and Alon Operating, each company will receive a price per share equal to the total stockholders equity of Alon Assets or Alon Operating, as applicable, divided by the total number of shares of voting and non-voting common stock of Alon Operating and Alon Assets, as applicable, outstanding immediately prior to such issuance. The purpose of this agreement is to dilute the ownership percentage of Messrs. Morris, Hart and Concienne in Alon Asset and Alon Operating in the same proportion as the ownership percentage of stockholders of Alon USA Energy, Inc. is diluted as a result of future issuances of common stock by Alon USA Energy, Inc. Following the issuance of 43,554.1 shares (or 50,087.2 shares if the underwriters’ option is exercised in full) by Alon Assets, and 16,355.2 shares (or 18,808.5 shares if the underwriters’ option is exercised in full) of Alon Operating pursuant to this agreement in connection with this offering, the shares of non-voting common stock of Alon Assets and Alon Operating currently held by Messrs. Morris, Hart and Concienne will represent an aggregate of 4.93% of the common stock of each of Alon Assets and Alon Operating, or 4.76% if the underwriters’ option to purchase additional shares is exercised in full.


	(3)	As of June 15, 2005, (1) Alon Israel beneficially owned 35,001,120 shares of common stock of Alon, representing 100.0% of the outstanding shares of common stock of Alon, including 1,401,120 shares of common stock of Alon owned by Tabris Investments Inc., a wholly owned subsidiary of Alon Israel. The address of Alon Israel is Europark (France Building), Kibbutz Yakum 60972, Israel.


		As of March 31, 2005, Alon Israel had 8,415,613 ordinary shares outstanding, which were owned of record as follows:


				Percent of
		Number of		Outstanding
Record Holder		Shares		Shares

Bielsol Investments (1987) Ltd. (a)			3,131,375		37.21	%
Africa Israel Trade & Agencies Ltd. (b)			2,200,428		26.14
Several Purchase Organizations of the Kibbutz Movement (c)			2,915,497		34.65
Mr. Eitan Shmueli, as trustee (d)			168,313		2.00

	Total		8,415,613		100.0	%


(a)		Bielsol Investments (1987) Ltd. is a privately held Israeli limited liability company that is owned (1) 80.0% by Shebug Ltd., an Israeli limited liability company that is wholly owned by the family of Shraga Biran, the father of Boaz Biran, one of our directors, and (2) 20.0% by David Wiessman, the Executive Chairman of our Board of Directors. The address of Bielsol Investments (1987) Ltd. is 1 Denmark St., Petak-Tivka, Israel.

(b)		Africa Israel Trade & Agencies Ltd. is an Israeli limited liability company that is a wholly owned subsidiary of Africa Israel Investments Ltd., a publicly held Israeli limited liability company that is listed on the Tel Aviv Stock Exchange. Based on information available to us, Africa Israel Investments Ltd. is beneficially owned (1) 64.65% by Lev Leviev, an Israeli citizen, (2) 16.35% by Bank Leumi le-Israel B.M., a publicly held limited liability company listed on the Tel Aviv Stock Exchange, and (3) 19.0% by public shareholders. Mr. Pinchas Cohen and Mr. Avraham Meron, each one of our directors, are the Chief Executive Officer and Senior Vice President – Finance, respectively, of Africa Israel Investments Ltd. The address of Africa Israel Investments Ltd. is 4 Derech Hahoresh, Yahud, Israel.

(c)		The Kibbutz Movement is a combination of approximately 300 economic cooperatives, or purchase organizations, engaged in agriculture, industry and commerce in Israel. The shares of Alon Israel shown in the table above as owned by several purchase organizations of the Kibbutz Movement are owned of record by ten such purchase organizations. Each of the purchase organizations that owns of record 5% or more of the outstanding shares of Alon Israel is shown on the following table:


	Number of		Percent of
Purchase Organization	Shares		Outstanding Shares

Granot Cooperative Regional Organization Corporation		505,172		6.0	%
Mishkey Emek Hayarden Ltd.		489,012		5.8
Mishkey Hanegev Export Ltd.		476,209		5.7


		Itzhak Bader, one of our directors, is Chairman of Granot Cooperative Regional Organization Corporation.

		The purchase organizations of the Kibbutz Movement have granted to Delek Holdings an irrevocable power of attorney to vote all of the shares of Alon Israel held by such purchase organizations. Delek Holdings is an Israeli limited liability company that is owned by nine organizations of the Kibbutz Movement, some of which are also stockholders of Alon Israel. One of our directors, Mr. Bader, is Chairman of Delek Holdings. The address of Delek Holdings is Derech Lod 298 Shalem Ranch, Tel Aviv, Israel.

(d)		The shares of Alon Israel held by Mr. Eitan Shmueli are held by him as trustee of a trust which David Wiessman, the Executive Chairman of our Board of Directors, is the sole beneficiary. These shares are treated as non-voting shares.


		Bielsol Investments (1987) Ltd., Africa Israel Trade & Agencies Ltd., the purchase organizations of the Kibbutz Movement and Delek Holdings are parties to a shareholders agreement. Under that agreement:


	•	Certain major decisions made by Alon Israel require the approval of more than 75.0% of the voting interests in Alon Israel or of more than 75% of the board of directors of Alon Israel, as applicable. The provisions of the shareholders agreement relating to approval of major

transactions involving Alon Israel also apply to approval of major transactions involving significant subsidiaries of Alon Israel, including Alon.


	•	The number of directors of Alon Israel must be between three and 12, with each 8.0% of the shares of Alon Israel entitling the holder thereof to elect one director. This provision currently allows Bielsol Investments (1987) Ltd. to elect four directors, Africa Israel Trade & Agencies Ltd. to elect three directors, and the purchase organizations of the Kibbutz Movement to elect four directors.

	•	There are various rights of first refusal among the shareholders who are party to the agreement.

Warrants to Purchase Non-Voting Common Stock of Alon Assets and Alon Operating

Discount Bank Corp. Inc. holds warrants to purchase 1,435 shares of non-voting common stock of Alon Assets and 538 shares non-voting of common stock of Alon Operating for an aggregate exercise price of $659,039. These warrants were initially issued to Israel Discount Bank, a subsidiary of Discount Bank Corp. Inc.

We have entered into an agreement with Discount Bank Corp. Inc. pursuant to which Discount Bank Corp. Inc. will exercise the warrants to purchase shares of Alon Assets and Alon Operating upon completion of this offering. Following such exercise, we will acquire the shares of Alon Assets and Alon Operating from Discount Bank Corp. Inc. for an aggregate payment of $3,040,000.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Management and Consulting Agreement with Alon Israel

Alon Israel provides strategic planning and management consulting services to us pursuant to a management and consulting agreement dated as of August 1, 2003. In particular, Alon Israel advises our management regarding policy initiatives, financial planning and strategic planning relating to our operations. The management and consulting agreement has an initial term of three years and provides that we pay Alon Israel an annual management and consulting fee which is currently $4.0 million per year. We paid Alon Israel $2.1 million and $4.0 million in each of 2003 and 2004, respectively, in accordance with the agreement. As of July 1, 2005 we have paid Alon Israel $2.0 million under this agreement. Upon completion of this offering the term of the agreement will be extended until December 31, 2009 and our payment obligations under the agreement will be terminated in exchange for an aggregate payment by us to Alon Israel of $6.0 million, $2.0 million of which will be paid upon completion of this offering and the remainder of which will be paid no later than March 15, 2006. Alon Israel’s obligations to provide consulting services under the amended agreement will remain in effect through the end of the term of the agreement.

As of the date of this prospectus and without giving effect to this offering, Alon Israel is the beneficial owner of 100% of our outstanding common stock. David Wiessman, our Executive Chairman of the Board, is the Chief Executive Officer, President and a director of Alon Israel. Mr. Wiessman also is the sole beneficiary of a trust which owns 2.0% of Alon Israel in the form of non-voting shares. Mr. Wiessman owns 20% of Bielsol Investments (1987) Ltd., which owns 37.21% of Alon Israel. The remaining 80% of Bielsol Investments (1987) Ltd. is owned by Shebug Ltd., which is wholly-owned by the family of Shraga Biran, the father of Boaz Biran, one our directors.

Service Relationships with Directors

From September 2002 until May 2005, Mr. Ron W. Haddock, one of our directors, provided us with consulting services related to the U.S. oil and gas industry and new business opportunities. These consulting services were provided pursuant to an oral arrangement that became effective in September 2002. Pursuant to that consulting arrangement, we paid Mr. Haddock an annual consulting fee of $50,000 in each of 2002, 2003 and 2004 and paid Mr. Haddock $12,500 in 2005. We also paid Mr. Haddock a $50,000 consulting bonus in August 2003. The terms of our oral consulting arrangement are based on the terms of a written consulting agreement with Mr. Haddock that expired in September 2002. Our oral consulting arrangement with Mr. Haddock and all obligations with respect to consulting fees will be terminated immediately prior to the consummation of the offering.

Mr. Boaz Biran, one of our directors, and the law firm in which he is a partner, Shraga F. Biran & Company, provide legal services to Alon Israel and its subsidiaries and are paid legal fees comparable to fees which would be paid to a third-party performing similar services on an arm’s length basis.

Under an agreement between Alon Israel and David Wiessman relating to Mr. Wiessman’s service to Alon Israel and its subsidiaries, we have historically paid Mr. Wiessman, indirectly through a company owned by him, a fee of $11,583 per month for serving as Executive Chairman of the board of directors of Alon and have paid on behalf of Mr. Wiessman maintenance and utility costs associated with his Dallas, Texas residence, which were approximately $18,942, $16,740, $17,524 and $4,544 in 2002, 2003, 2004 and the first quarter of 2005, respectively. The maintenance and utility costs consisted of homeowners’ fees associated with his ownership of a condominium unit and cable, electric, phone and cleaning services.

We have entered into a new agreement with Mr. Wiessman, dated July 6, 2005, pursuant to which he will serve as our Executive Chairman of the Board through December 31, 2009. Pursuant to this agreement, we will pay Mr. Wiessman, through a company owned by him, a fee of $24,000 per month, and Mr. Wiessman will be entitled to participate in our employee bonus plan at the same level as our Chief Executive Officer. Mr. Wiessman will be entitled to a 5% fee increase at the end of each of the second, third and fourth year of the new agreement. We will also continue to pay the maintenance and

utility costs associated with Mr. Wiessman’s Dallas, Texas residence, will provide medical insurance benefits to Mr. Wiessman and will reimburse Mr. Wiessman for airfare incurred to transport his family members between Israel and the United States (up to a maximum of eight tickets per year). Alon may terminate this agreement on six month’s notice and Mr. Wiessman will be entitled to receive his full compensation and benefits during the notice period. Upon termination of this agreement following the notice period, we will be required to pay Mr. Wiessman a fee equal to the product of (1) 200% of his monthly fee multiplied by (2) the number of years of Mr. Wiessman’s service with Alon since August 2000. We will also be required to pay Mr. Wiessman twelve months of severance.

Payment of Certain Expenses on Behalf of Certain Related Parties

Rosebud Medical Ltd., an affiliate of Bielsol Investments (1987) Ltd. (a beneficial owner of Alon Israel), and Africa Israel Investments Ltd., a beneficial owner of Alon Israel, have utilized consultants to assist in evaluating commercial real estate investments in the United States. From June 2001 through January 2003, we facilitated these consulting arrangements by paying consulting fees on behalf of Rosebud Medical Ltd. and Africa Israel Investments Ltd., for which these entities subsequently reimbursed us. Under these consulting arrangements, we paid consulting fees of $190,000 to Mr. Ron W. Haddock, one of our directors, and $194,459 to an unaffiliated third party. The amounts paid to Mr. Haddock were $70,000, $110,000 and $10,000 in 2001, 2002 and 2003, respectively. Rosebud Medical Ltd. and Africa Israel Investments Ltd. reimbursed us for $251,460 of these consulting payments in July 2002 and the balance of these consulting payments in May 2003.

Rosebud Medical Ltd., a public company listed on the Tel Aviv Stock Exchange, is owned 75.4% by Tani-Pan Ltd and 24.6% by public shareholders. Tani-Pan Ltd. is owned 24.5% by Bielsol Investments, 51.0% by Mandelboum Gate Ltd. and 24.5% by unrelated third parties. Mr. Wiessman, through a company wholly-owned by him, owns 21.3% of Mandelboum Gate Ltd. and the family of Shraga Biran (the father of Boaz Biran, one of our directors) beneficially owns the remaining 78.7% of Mandelboum Gate Ltd.

Africa Israel Investments Ltd., a public company listed on the Tel Aviv Stock Exchange, is the sole stockholder of Africa Israel Trade & Agencies Ltd., which owns 26.4% of Alon Israel. Pinchas Cohen, one of our directors, is the Chief Executive Officer of Africa Israel Investment Ltd. Mr. Cohen is also a director of Alon Israel. Avraham Meron, one of our directors and an initial member of our audit committee, is the Senior Vice President — Finance of Africa Israel Investments Ltd. Mr. Meron is also a director of Alon Israel.

Repayment of Indebtedness

We intend to use a portion of the net proceeds of this offering to repay outstanding subordinated notes payable to Alon Israel. As of March 31, 2005, the outstanding principal and accrued interest under these notes was $20.3 million. See “Use of Proceeds.”

On February 28, 2005, we repaid $25.0 million of outstanding indebtedness borrowed from Alon Israel in August 2002 in connection with the Alon Capital minority interest acquisition. This indebtedness bore interest at a rate of 7.0% per annum.

Dividends

On February 28, 2005, Messrs. Morris, Hart and Concienne, each of whom is an executive officer of Alon, were paid cash dividends of $1,127,913, $281,967, and $72,134, respectively, in their capacities as stockholders of Alon Assets. These dividends were funded from the cash proceeds we received in the HEP transaction.

Of the $60.9 million aggregate dividend to be paid to our stockholders of record immediately prior to this offering, Messrs. Morris, Hart and Concienne will receive dividend payments from Alon USA Operating, Inc. in the respective amounts of $2,901,495, $725,781 and $246,721. In connection with the

contingent dividend to be paid to our stockholders of record immediately prior to this offering if the underwriters’ option to purchase additional shares is exercised, Messrs. Morris, Hart and Concienne will receive dividend payments from Alon USA Operating, Inc. in the respective amounts of $3,484,738, $871,073 and $296,315, assuming that such option is exercised in full, or the proportion of the applicable amount that is equal to the proportional extent to which such option is exercised. See “Use of Proceeds” for a description of the dividends to be paid to our stockholders of record immediately prior to this offering.

Guaranties by Related Parties

Alon Israel, Bielsol Investments (1987) Ltd., Africa Israel Investments Ltd. and Sha’ar Mandelbaum Ltd., an affiliate of Bielsol Investments (1987) Ltd., have historically provided limited guarantees of our revolving credit facility.

The Alon Capital Minority Interest Acquisition

On August 21, 2002, we acquired the 40% interest in Alon Capital that we previously did not own from the entities listed in the table below for a purchase price of $57.1 million. At the closing of the transaction, we paid the investors $37.1 million in cash and issued promissory notes to the investors for the remaining $20.0 million of purchase price. We repaid the promissory notes in two installments of $10.0 million, plus accrued interest, on each of June 30, 2003 and June 30, 2004. The promissory notes bore interest at 7.0% compounded annually. We refer to this transaction as the Alon Capital minority interest acquisition. The following table sets forth the payment to each of the investors:


		Proceeds
		Paid at Closing
		of Alon Capital		Payments at
		Minority Interest		June 30, 2003
Investor		Acquisition		and 2004

		(dollars in millions)
Rosebud Medical Ltd.		$	16.9	$	4.6
Africa Israel Energy Ltd.			18.7		5.0
Tabris Investments Inc.			1.5		0.4

	Total	$	37.1	$	10.0

Africa Israel Energy Ltd. is owned 51.0% by Africa Israel Investments Ltd. Tabris Investments Inc. was wholly-owned by Mr. Wiessman from July 2001 to December 2003. Tabris Investments Inc. acquired 4.0% of Alon Energy in August 2001. In December 2003, Alon Israel acquired 100.0% of Tabris Investments Inc. from Mr. Wiessman, the assets of which consisted solely of 1,401,120 shares of common stock of Alon Energy, for an aggregate purchase price of $5.68 million, or $4.05 per share of Alon Energy. Upon the end of each year of service under his five-year employment agreement with Alon Israel, Mr. Wiessman has the option to re-acquire 175,140 shares of Alon Energy (up to 875,700 shares) from Tabris Investments, Inc. at a price per share equal to $4.05, plus accrued interest on such per share price from December 2003.

Other Indebtedness

A portion of the financing for our acquisition from Fina was provided by issuing an aggregate of $11.2 million of promissory notes to Rosebud Medical Ltd. and Africa Israel Energy Ltd., each of which subsequently assigned a 4.0% interest in such notes to Springer Investments S.A., an investment company

wholly owned by David Wiessman. The promissory notes bore interest at a rate of 7.0% per annum. We paid all principal and accrued interest on such notes as follows:


		2004		2005		Total

Rosebud Medical Ltd.		$	3.4	$	3.5	$	6.9
Africa Israel Energy Ltd.			3.8		3.8		7.6
Springer Investments S.A.			0.3		0.3		0.6

	Total	$	7.5	$	7.6	$	15.1

In connection with our acquisition from Fina, Alon Assets issued subordinated promissory notes to Mr. Morris and Mr. Hart in principal amounts of $369,364 and $92,341, respectively, bearing interest at 7.0% per annum. In 2002, we repaid $236,097 and $59,024 of the principal and accrued interest owed to Mr. Morris and Mr. Hart, respectively. In 2003, we repaid $199,725 and $49,931 of the principal and interest owed to Mr. Morris and Mr. Hart, respectively. In April 2005, we repaid $10,369 and $1,444 to Mr. Morris and Mr. Hart in full payment of these notes.

Stockholders’ Agreements with Mr. Morris, Mr. Hart and Mr. Concienne

Jeff D. Morris, a director and our President and Chief Executive Officer, Claire A. Hart, our Senior Vice President, and Joseph A. Concienne, our Vice President of Refining and Transportation, each referred to in this description as a stockholder, are parties to stockholders’ agreements with both Alon Operating and Alon Assets, each referred to in this description as an issuer. The agreements relate to shares of non-voting common stock of the issuers held by, or issuable upon exercise of options held by, the stockholders.

These agreements provide that if a stockholder proposes to make a voluntary transfer of shares in an issuer, the issuer has a right of first refusal to purchase the shares on the same terms as the proposed voluntary transfer. If a stockholder makes an involuntary transfer of shares upon divorce or the death of the spouse of the stockholder, in certain cases, the stockholder has a right of first refusal to purchase the shares from the acquiring person. If this right of first refusal is not exercised by the stockholder, or if there is any involuntary transfer of shares of the stockholder due to bankruptcy or a similar proceeding, the issuer has a right of first refusal to purchase the shares from the acquiring person. In each such involuntary transfer, the purchase price for the shares will be based on formulas set forth in the stockholders’ agreements.

The stockholders’ agreements also provide for put options in favor of the stockholders and call options in favor of the issuers that may be exercised with respect to a stockholder’s shares in each issuer at such time as the stockholder ceases to be employed by any entity controlled by Alon Israel. Upon such cessation of employment, the put option entitles the stockholder to require the issuer to repurchase the stockholder’s shares in the issuer, and the call option entitles the issuer to require the stockholder to sell the shares to the issuer, generally at a price determined in accordance with formulas set forth in the stockholders’ agreements. After July 31, 2010, under certain circumstances the price would be equal to the fair market value of these shares.

The stockholders’ agreements also provide for tag-along rights in favor of the stockholders. Under these tag-along rights, in the event that the holders of capital stock in an issuer propose to transfer for consideration more than 50% of the outstanding capital stock of an issuer to an unaffiliated third party, the stockholders will have the right to require the transferee of such capital stock to purchase a pro rata portion of the stockholders’ shares in the issuer on the same terms as the proposed transfer of the other shares of capital stock in the issuer.

Registration Rights Agreement with Alon Israel

For a description of the registration rights agreement with, and the registration rights granted to, Alon Israel, see “Shares Eligible for Future Sale — Registration Rights.”

SCS Beverage

On February 29, 2004, we sold 17 licenses for the sale of alcoholic beverages at 17 stores in New Mexico to SCS Beverage, Inc., a corporation treated as a pass-through entity that is wholly-owned by Jeff D. Morris, our President and Chief Executive Officer. Under rules and regulations of the New Mexico Alcohol and Gaming Division, or AGD, a holder of a license to sell alcoholic beverages in New Mexico must provide substantial documentation in the application for and annual renewal of the license, including detailed questionnaires and fingerprints of the officers and directors of each entity beneficially owning 10% or more of the holder of the license. We engaged in this transaction to expedite the process of renewing the licenses by limiting the required disclosures to one individual stockholder. The purchase price paid by SCS Beverage consisted of approximately $2.6 million for the 17 licenses and approximately $0.2 million for the inventory of alcoholic beverages on the closing date. The purchase price was paid by SCS Beverage issuing to us a demand promissory note in the amount of $2.8 million. The demand note is payable solely by transferring the licenses and inventory existing at the time of payment back to us. The demand note is secured by a pledge of the licenses and the inventory and a pledge of 100% of the stock of SCS Beverage. Pursuant to the purchase and sale agreement, SCS Beverage granted us an option to re-acquire the licenses at any time at a purchase price equal to the same purchase price paid by SCS Beverage to acquire the licenses.

As the holder of the New Mexico licenses, SCS Beverage is the only party entitled to purchase alcoholic beverages to be sold at the locations covered by the licenses and to receive revenues from the sale of alcoholic beverages at those locations. Simultaneously with the transfer of the licenses, SCS Beverage entered into a premises lease with us to lease space at each of the locations covered by the licenses for the purpose of conducting the alcoholic beverages concessions. The total annual payments by SCS Beverage to us under this premises lease agreement are approximately $1.85 million, subject to adjustment by us based on the volume of sales of alcoholic beverages at the locations covered by the licenses. To date, the profits realized by SCS Beverage from the sale of alcoholic beverages at these locations have not exceeded lease payments by SCS Beverage to us and we anticipate that this will continue to be the case in the future. As a result, Mr. Morris has not received any economic benefit from the ownership of SCS Beverage, and we do not anticipate that Mr. Morris will derive any economic benefit from his ownership of SCS Beverage in the future.

Future Transactions with Related Parties

We have not adopted any formal policy governing related party transactions. Consequently, our board of directors will utilize such procedures in evaluating the terms of any future material transactions between us and Alon Israel or other related parties as our board may deem appropriate in light of its fiduciary duties under state law.

DESCRIPTION OF CAPITAL STOCK

Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.01 per share, and 10,000,000 shares of preferred stock, par value $0.01 per share, the rights and preferences of which may be established from time to time by our board of directors. Upon completion of this offering, there will be 45,201,120 outstanding shares of common stock and no outstanding shares of preferred stock. The following description of our capital stock is only a summary, does not purport to be complete and is subject to and qualified by our certificate of incorporation and bylaws, which are included as exhibits to the registration statement of which this prospectus forms a part, and by the provisions of applicable Delaware law.

Common Stock

Holders of our common stock are entitled to one vote for each share on all matters voted upon by our stockholders, including the election of directors, and do not have cumulative voting rights. Subject to the rights of holders of any then outstanding shares of our preferred stock, our common stockholders are entitled to receive ratably any dividends that may be declared by our board of directors out of funds legally available therefor. Holders of our common stock are entitled to share ratably in our net assets upon our dissolution or liquidation after payment or provision for all liabilities and any preferential liquidation rights of our preferred stock then outstanding. Holders of our common stock do not have preemptive rights to purchase shares of our stock. The shares of our common stock are not subject to any redemption provisions and are not convertible into any other shares of our capital stock. All outstanding shares of our common stock are, and the shares of common stock to be issued in the offering will be, upon payment therefor, fully paid and nonassessable. The rights, preferences and privileges of holders of our common stock will be subject to those of the holders of any shares of our preferred stock we may issue in the future.

Blank Check Preferred Stock

Our board of directors may, from time to time, authorize the issuance of one or more classes or series of preferred stock without stockholder approval. We have no current intention to issue any shares of preferred stock.

Our certificate of incorporation permits us to issue up to 10,000,000 shares of preferred stock from time to time. Subject to the provisions of our certificate of incorporation and limitations prescribed by law, our board of directors is authorized to adopt resolutions to issue shares, establish the number of shares, change the number of shares constituting any series, and provide or change the voting powers, designations, preferences and relative rights, qualifications, limitations or restrictions on shares of our preferred stock, including dividend rights, terms of redemption, conversion rights and liquidation preferences, in each case without any action or vote by our stockholders.

The issuance of preferred stock may adversely affect the rights of our common stockholders by, among other things:


	•	restricting dividends on the common stock;

	•	diluting the voting power of the common stock;

	•	impairing the liquidation rights of the common stock; or

	•	delaying or preventing a change in control without further action by the stockholders.

As a result of these or other factors, the issuance of preferred stock could have an adverse impact on the market price of our common stock.

Anti-takeover Effects of Certain Provisions of Our Certificate of Incorporation and Bylaws

General

Our certificate of incorporation and bylaws contain provisions that are intended to enhance the likelihood of continuity and stability in the composition of our board of directors and that could make it more difficult to acquire control of our company by means of a tender offer, open market purchases, a proxy contest or otherwise. A description of these provisions is set forth below.

Preferred Stock

We believe that the availability of the preferred stock under our certificate of incorporation provides us with flexibility in addressing corporate issues that may arise. Having these authorized shares available for issuance will allow us to issue shares of preferred stock without the expense and delay of a special stockholders’ meeting. The authorized shares of preferred stock, as well as shares of common stock, will be available for issuance without further action by our stockholders, unless action is required by applicable law or the rules of any stock exchange on which our securities may be listed. The board of directors has the power, subject to applicable law, to issue series of preferred stock that could, depending on the terms of the series, impede the completion of a merger, tender offer or other takeover attempt. For instance, subject to applicable law, series of preferred stock might impede a business combination by including class voting rights which would enable the holder or holders of such series to block a proposed transaction. Our board of directors will make any determination to issue shares based on its judgment as to our and our stockholders’ best interests. Our board of directors, in so acting, could issue preferred stock having terms which could discourage an acquisition attempt or other transaction that some, or a majority, of the stockholders might believe to be in their best interests or in which stockholders might receive a premium for their stock over the then prevailing market price of the stock.

No Stockholder Action by Written Consent

Our certificate of incorporation provides that any action required or permitted to be taken at any annual or special meeting of stockholders may be taken only at a duly called annual or special meeting of stockholders and may not be effected by any written consent of stockholders in lieu of a meeting of stockholders. This prevents stockholders from initiating or effecting any action by written consent, thereby limiting the ability of stockholders to take actions opposed by our board of directors.

Advance Notice Procedure

Our bylaws provide an advance notice procedure for stockholders to nominate director candidates for election or to bring business before an annual meeting of stockholders, including proposed nominations of persons for election to the board of directors. Only persons nominated by, or at the direction of, our board of directors or by a stockholder who has given proper and timely notice to our secretary prior to the meeting, will be eligible for election as a director. In addition, any proposed business other than the nomination of persons for election to our board of directors must constitute a proper matter for stockholder action pursuant to the notice of meeting delivered to us. For notice to be timely, it must be received by our secretary not less than 60 nor more than 90 calendar days prior to the first anniversary of the previous year’s annual meeting (or if the date of the annual meeting is advanced more than 30 calendar days or delayed by more than 30 calendar days from such anniversary date, not earlier than the 90th calendar day prior to such meeting or the 10th calendar day after public disclosure of the date of such meeting is first made). These advance notice provisions may have the effect of precluding the conduct of certain business at a meeting if the proper procedures are not followed or may discourage or deter a potential acquirer from conducting a solicitation of proxies to elect its own slate of directors or otherwise attempt to obtain control of us.

Special Meetings of Stockholders

Our bylaws provide that special meetings of stockholders may be called only by our chairman of the board, president or secretary after written request of a majority of our board of directors.

Delaware Anti-Takeover Law

Section 203 of the Delaware General Corporation Law provides that, subject to exceptions specified therein, an “interested stockholder” of a Delaware corporation shall not engage in any “business combination,” including general mergers or consolidations or acquisitions of additional shares of the corporation, with the corporation for a three-year period following the time that such stockholder becomes an interested stockholder unless:


	•	prior to such time, the board of directors of the corporation approved either the business combination or the transaction which resulted in the stockholder becoming an interested stockholder;

	•	upon consummation of the transaction which resulted in the stockholder becoming an “interested stockholder,” the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced (excluding specified shares); or

	•	on or subsequent to such time, the business combination is approved by the board of directors of the corporation and authorized at an annual or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 66²/3% of the outstanding voting stock not owned by the interested stockholder.

Under Section 203, the restrictions described above also do not apply to specified business combinations proposed by an interested stockholder following the announcement or notification of one of specified transactions involving the corporation and a person who had not been an interested stockholder during the previous three years or who became an interested stockholder with the approval of a majority of the corporation’s directors, if such transaction is approved or not opposed by a majority of the directors who were directors prior to any person becoming an interested stockholder during the previous three years or were recommended for election or elected to succeed such directors by a majority of such directors.

Except as otherwise specified in Section 203, an “interested stockholder” is defined to include:


	•	any person that is the owner of 15% or more of the outstanding voting stock of the corporation, or is an affiliate or associate of the corporation and was the owner of 15% or more of the outstanding voting stock of the corporation at any time within three years immediately prior to the date of determination; and

	•	the affiliates and associates of any such person.

Under some circumstances, Section 203 makes it more difficult for a person who is an interested stockholder to effect various business combinations with us for a three-year period. We have not elected to be exempt from the restrictions imposed under Section 203.

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Limitation of Liability of Officers and Directors

Our certificate of incorporation limits the liability of directors to the fullest extent permitted by Delaware law. The effect of these provisions is to eliminate the rights of our company and our stockholders, through stockholders’ derivative suits on behalf of our company, to recover monetary damages against a director for breach of fiduciary duty as a director, including breaches resulting from grossly negligent behavior. However, exculpation does not apply if the directors acted in bad faith, knowingly or intentionally violated the law, authorized illegal dividends or redemptions or derived an improper benefit from their actions as directors. In addition, our certificate of incorporation provides that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. We expect to enter into indemnification agreements with our current directors and executive officers prior to the completion of this offering. We also maintain directors and officers insurance.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is Mellon Investor Services LLC.

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there was no market for our common stock. We can make no predictions as to the effect, if any, that sales of shares or the availability of shares for sale will have on the market price prevailing from time to time. Nevertheless, sales of significant amounts of our common stock in the public market, or the perception that those sales may occur, could adversely affect prevailing market prices and impair our future ability to raise capital through the sale of our equity at a time and price we deem appropriate.

Upon the completion of this offering, based upon the number of shares of our common stock outstanding as of June 30, 2005, we will have 45,201,120 shares (or in the event the underwriters’ over-allotment option is exercised, 46,731,120 shares) of our common stock outstanding. Of these shares, 10,200,000 shares (or in the event the underwriters’ over-allotment option is exercised, 11,730,000 shares) of our common stock sold in this offering will be freely tradable without restriction under the Securities Act of 1933 (the “Securities Act”), except for any shares of our common stock purchased by our “affiliates,” as that term is defined in Rule 144 under the Securities Act, which would be subject to the limitations and restrictions described below.

The remaining 35,001,120 shares of our common stock outstanding upon completion of this offering are deemed “restricted securities,” as that term is defined under Rule 144 of the Securities Act, and are subject to the lock-up agreements described in “Underwriting.”

Restricted securities may be sold in the United States public market only if registered or if they qualify for an exemption from registration under Rule 144 or 144(k) under the Securities Act, which rules are described below.

Subject to the provisions of the lock-up agreements, the 35,001,120 shares subject thereto will be eligible for sale at various times pursuant to Rules 144 or 144(k) or registration effected under the registration rights agreement described in “— Registration Rights.”

Rule 144

In general, under Rule 144 as currently in effect, a person, or persons whose shares must be aggregated, who has beneficially owned restricted shares of our common stock for at least one year is entitled to sell within any three-month period a number of shares that does not exceed the greater of the following:


	•	one percent of the number of shares of common stock then outstanding, which will equal approximately 452,011 shares immediately after this offering, or

	•	the average weekly trading volume of our common stock on the New York Stock Exchange during the four calendar weeks preceding the date of filing of a notice on Form 144 with respect to the sale.

Sales under Rule 144 are also generally subject to certain manner of sale provisions and notice requirements and to the availability of current public information about us.

Rule 144(k)

Under Rule 144(k), a person, or persons whose shares must be aggregated, who is not deemed to have been one of our affiliates at any time during the 90 days preceding a sale and who has beneficially owned the shares proposed to be sold for at least two years would be entitled to sell the shares under Rule 144(k) without complying with the manner of sale, public information, volume limitations or notice or public information requirements of Rule 144. Therefore, unless otherwise restricted, the shares eligible for sale under Rule 144(k) may be sold immediately upon the completion of this offering.

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Lock-Up Agreement

For a description of the lock-up agreement with the underwriters that restrict sales of shares by Alon Israel and Tabris Investments Inc., our parents, see “Underwriting.”

Registration Rights

Pursuant to the terms of a Registration Rights Agreement with Alon Israel, we have provided Alon Israel with registration rights, including demand registration rights and “piggy-back” registration rights, with respect to our common stock owned by Alon Israel after this offering. Our obligations are subject to limitations relating to a minimum amount of common stock required for registration, the timing of registration and other similar matters. We are obligated to pay all expenses incidental to such registration, excluding underwriters’ discounts and commissions and certain legal fees and expenses.

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U.S. FEDERAL TAX CONSEQUENCES

TO NON-U.S. HOLDERS OF COMMON STOCK

The following is a general discussion of the material U.S. federal income and estate tax consequences to non-U.S. Holders with respect to the acquisition, ownership and disposition of our common stock. In general, a “Non-U.S. Holder” is any holder of our common stock other than the following:


	•	a citizen or resident of the United States, including an alien individual who is a lawful permanent resident of the United States or meets the “substantial presence” test under section 7701(b)(3) of the Code;

	•	a corporation (or an entity treated as a corporation) created or organized in the United States or under the laws of the United States, any state thereof, or the District of Columbia;

	•	an estate, the income of which is subject to U.S. federal income tax regardless of its source; or

	•	a trust, if a U.S. court can exercise primary supervision over the administration of the trust and one or more U.S. persons can control all substantial decisions of the trust, or certain other trusts that have a valid election to be treated as a U.S. person pursuant to the applicable Treasury Regulations.

This discussion is based on current provisions of the Internal Revenue Code, Treasury Regulations, judicial opinions, published positions of the Internal Revenue Service (“IRS”), and all other applicable administrative and judicial authorities, all of which are subject to change, possibly with retroactive effect. This discussion does not address all aspects of U.S. federal income and estate taxation or any aspects of state, local, or non-U.S. taxation, nor does it consider any specific facts or circumstances that may apply to particular Non-U.S. Holders that may be subject to special treatment under the U.S. federal income tax laws including, but not limited to, insurance companies, tax-exempt organizations, pass-through entities, financial institutions, brokers, dealers in securities, and U.S. expatriates. If a partnership or other entity treated as a partnership for U.S. federal income tax purposes is a beneficial owner of our common stock, the treatment of a partner in the partnership will generally depend upon the status of the partner and the activities of the partnership. This discussion assumes that the Non-U.S. Holder will hold our common stock as a capital asset, which generally is property held for investment.

Prospective investors are urged to consult their tax advisors regarding the U.S. federal, state and local, and non-U.S. income and other tax considerations of acquiring, holding and disposing of shares of common stock.

Dividends

In general, dividends paid to a Non-U.S. Holder (to the extent paid out of our current or accumulated earnings and profits, as determined under U.S. federal income tax principles) will be subject to U.S. withholding tax at a rate equal to 30% of the gross amount of the dividend, or a lower rate prescribed by an applicable income tax treaty, unless the dividends are effectively connected with a trade or business carried on by the Non-U.S. Holder within the United States. Under applicable Treasury Regulations, a Non-U.S. Holder will be required to satisfy certain certification requirements, generally on IRS Form W-8BEN, directly or through an intermediary, in order to claim a reduced rate of withholding under an applicable income tax treaty. If tax is withheld in an amount in excess of the amount applicable under an income tax treaty, a refund of the excess amount may generally be obtained by filing an appropriate claim for refund with the IRS.

Dividends that are effectively connected with such a U.S. trade or business generally will not be subject to U.S. withholding tax if the Non-U.S. Holder files the required forms, including IRS Form W-8ECI, or any successor form, with the payor of the dividend, but instead generally will be subject to U.S. federal income tax on a net income basis in the same manner as if the Non-U.S. Holder were a resident of the United States. A corporate Non-U.S. Holder that receives effectively connected dividends may be subject to an additional branch profits tax at a rate of 30%, or a lower rate prescribed by an

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applicable income tax treaty, on the repatriation from the United States of its “effectively connected earnings and profits,” subject to adjustments.

Gain on Sale or Other Disposition of Common Stock

In general, a Non-U.S. Holder will not be subject to U.S. federal income tax on any gain realized upon the sale or other taxable disposition of the Non-U.S. Holder’s shares of common stock unless:


	•	the gain is effectively connected with a trade or business carried on by the Non-U.S. Holder within the United States (and, where an income tax treaty applies, is attributable to a U.S. permanent establishment of the Non-U.S. Holders), in which case the branch profits tax discussed above may also apply if the Non-U.S. Holder is a corporation;

	•	the Non-U.S. Holder is an individual who holds shares of common stock as capital assets and is present in the United States for 183 days or more in the taxable year of disposition and certain other conditions are met; or

	•	we are or have been a “U.S. real property holding corporation” for U.S. federal income tax purposes.

Because of the real property, refinery assets and convenience stores we own, we may be a “U.S. real property holding corporation.” The determination of whether we are a “U.S. real property holding corporation” is fact specific and depends on the composition of our assets. If we are, have been, or become, a U.S. real property holding corporation in the future, and our common stock is regularly traded on an established securities market, a Non-U.S. Holder who (actually or constructively) holds or held (at anytime during the shorter of the five year period preceding the date of dispositions or the holder’s holding period) more than five percent of our common stock would be subject to U.S. federal income tax on a disposition of our common stock but other Non-U.S. Holders generally would not be. If our common stock is not so traded, all Non-U.S. Holders would be subject to U.S. federal income tax on disposition of our common stock.

You should consult your own tax advisor regarding our possible status as a “U.S. real property holding corporation” and its possible consequences in your particular circumstances.

Information Reporting and Backup Withholding

Generally, we must report annually to the IRS the amount of dividends paid, the name and address of the recipient, and the amount, if any, of tax withheld. A similar report is sent to the recipient. These information reporting requirements apply even if withholding was not required because the dividends were effectively connected dividends or withholding was reduced by an applicable income tax treaty. Under income tax treaties or other agreements, the IRS may make its reports available to tax authorities in the recipient’s country of residence.

Dividends paid made to a Non-U.S. Holder that is not an exempt recipient generally will be subject to backup withholding, currently at a rate of 28% of the gross proceeds, unless a Non-U.S. Holder certifies as to its foreign status, which certification may be made on IRS Form W-8BEN.

Proceeds from the disposition of common stock by a Non-U.S. Holder effected by or through a U.S. office of a broker will be subject to information reporting and backup withholding, currently at a rate of 28% of the gross proceeds, unless the Non-U.S. Holder certifies to the payor under penalties of perjury as to, among other things, its address and status as a Non-U.S. Holder or otherwise establishes an exemption. Generally, U.S. information reporting and backup withholding will not apply to a payment of disposition proceeds if the transaction is effected outside the United States by or through a non-U.S. office. However, if the broker is, for U.S. federal income tax purposes, a U.S. person, a controlled foreign corporation, a foreign person who derives 50% or more of its gross income for specified periods from the conduct of a U.S. trade or business, specified U.S. branches of foreign banks or insurance

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companies or a foreign partnership with various connections to the United States, information reporting but not backup withholding will apply unless:


	•	the broker has documentary evidence in its files that the holder is a Non-U.S. Holder and certain other conditions are met; or

	•	the holder otherwise establishes an exemption.

Backup withholding is not an additional tax. Rather, the amount of tax withheld is applied as a credit to the U.S. federal income tax liability of persons subject to backup withholding. If backup withholding results in an overpayment of U.S. federal income taxes, a refund may be obtained, provided the required documents are timely filed with the IRS.

Estate Tax

Our common stock owned or treated as owned by an individual who is not a citizen or resident of the United States (as specifically defined for U.S. federal estate tax purposes) at the time of death will be includible in the individual’s gross estate for U.S. federal estate tax purposes, unless an applicable estate tax treaty provides otherwise.

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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement dated July 28, 2005, we have agreed to sell to the underwriters named below, for whom Credit Suisse First Boston LLC is acting as the representative, the following respective numbers of shares of common stock:


Underwriter		Number of Shares

Credit Suisse First Boston LLC			4,080,000
Deutsche Bank Securities Inc.			3,060,000
Lehman Brothers Inc.			3,060,000

	Total		10,200,000

The underwriting agreement provides that the underwriters are obligated to purchase all the shares of common stock in the offering if any are purchased, other than those shares covered by the over-allotment option described below. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated.

We have granted to the underwriters a 30-day option to purchase on a pro rata basis up to 1,530,000 additional shares from us at the initial public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common stock.

The underwriters propose to offer the shares of common stock initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $0.672 per share. The underwriters and selling group members may allow a discount of $0.10 per share 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.

The following table summarizes the compensation and estimated expenses we will pay:


	Per Share				Total

	Without				Without
	Over-		With Over-		Over-		With Over-
	allotment		allotment		allotment		allotment

Underwriting discounts and commissions paid by us	$	1.12	$	1.12	$	11,424,000	$	13,137,600
Expenses payable by us	$	0.1961	$	0.1705	$	2,000,000	$	2,000,000

The representative has informed us that it does not expect sales to accounts over which the underwriters have discretionary authority to exceed 5% of the shares of common stock being offered.

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 relating to, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, without the prior written consent of Credit Suisse First Boston LLC, for a period of 180 days after the date of this prospectus. However, in the event that either (1) during the last 17 days of the “lock-up” period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the “lock-up” period, we announce that we will release earnings results during the 16-day period beginning on the last day of the “lock-up” period, then in either case the expiration of the “lock-up” will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse First Boston LLC waives such extension in writing.

Our stockholders have agreed that they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, enter into a transaction that would have the same effect,

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or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common stock, whether any of these transactions is to be settled by delivery of our common stock or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of Credit Suisse First Boston LLC, for a period of 180 days after the date of this prospectus. However, in the event that either (1) during the last 17 days of the “lock-up” period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the “lock-up” period, we announce that we will release earnings results during the 16-day period beginning on the last day of the “lock-up” period, then in either case the expiration of the “lock-up” will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse First Boston LLC waives such extension in writing. However, the “lock-up” period will not be extended at any time which our common stock are “actively traded securities,” as defined in Regulation M under the Securities and Exchange Act of 1934 and research reports under Rule 139 of the Securities Act may otherwise be issued with respect to Alon.

The underwriters have reserved for sale at the initial public offering price up to 170,000 shares of the common stock for employees, directors and other persons associated with us who have expressed an interest in purchasing common stock in the offering. The number of shares available for sale to the general public in the offering will be reduced to the extent these persons purchase the reserved shares. Any reserved shares not so purchased will be offered by the underwriters to the general public on the same terms as the other shares.

We have agreed to indemnify the underwriters against liabilities under the Securities Act of 1933, or contribute to payments that the underwriters may be required to make in that respect.

Our common stock has been approved for listing on the New York Stock Exchange under the symbol “ALJ.”

Certain of the underwriters and their respective affiliates have from time to time performed, and may in the future perform, various financial advisory, commercial banking and investment banking services for us and our affiliates in the ordinary course of business, for which they received, or will receive, customary fees and expenses. In addition, an affiliate of Credit Suisse First Boston LLC serves as the administrative agent and collateral agent under our existing term loan.

Prior to the offering, there has been no market for our common stock. The initial public offering price was determined by negotiations between us and the underwriters and will not necessarily reflect the market price of the common stock following the offering. The principal factors that were considered in determining the initial public offering price included:


	•	the information presented in this prospectus and otherwise available to the underwriters;

	•	the history of and the prospects for the industry in which we will compete;

	•	the ability of our management;

	•	the prospects for our future earning;

	•	the present state of our development and our current financial condition;

	•	the recent market prices of, and the demand for, publicly traded common stock of generally comparable companies; and

	•	the general condition of the securities markets at the time of the offering.

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We offer no assurances that the initial public offering price will correspond to the price at which our common stock will trade in the public market subsequent to the offering or that an active trading market for our common stock will develop and continue after the offering.

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.


	•	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 shares in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is equal to or less than the number of shares that they may purchase in the over-allotment option. In a naked short position, the number of shares involved is greater than the number of shares in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing shares in the open market.

	•	Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. If the underwriters sell more shares than could be covered by the over- allotment option, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares 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 common stock originally sold by the syndicate member is purchased in a stabilizing or 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 our common stock or preventing or retarding a decline in the market price of the common stock. As a result the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

A prospectus in electronic format may be made available on the websites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering, and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representative may agree to allocate a number of shares to the underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make Internet distributions on the same basis as other allocations.

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NOTICE TO CANADIAN RESIDENTS

Resale Restrictions

The distribution of the common stock 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 common stock are made. Any resale of the common stock 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 our common stock.

Representations of Purchasers

By purchasing our common stock 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 common stock 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 our common stock 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 common stock, for rescission against us, in the event that this prospectus contains a misrepresentation without regard to whether the purchaser 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 our common stock. The right of action for rescission is exercisable not later than 180 days from the date on which payment is made for our common stock. 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 prices at which our common stock was 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 common stock 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 our common stock should consult their own legal and tax advisors with respect to the tax consequences of an investment in the common stock in their particular circumstances

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and about the eligibility of our common stock for investment by the purchaser under relevant Canadian legislation.

LEGAL MATTERS

The validity of the shares of common stock offered by this prospectus will be passed upon for our company by Jones Day, Dallas, Texas. The underwriters have been represented by Cravath, Swaine & Moore LLP, New York, New York.

EXPERTS

The consolidated financial statements of Alon and its subsidiaries as of December 31, 2003 and 2004 and for each of the years in the three year period ended December 31, 2004 have been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing. The audit report refers to a change in the method of accounting for asset retirement obligations in 2003.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1, Registration No. 333-124797, under the Securities Act with respect to the common stock being sold in this offering. This prospectus, which forms part of the registration statement, does not contain all of the information set forth in the registration statement and the exhibits and schedule to the registration statement. For further information with respect to us and our common stock being sold in this offering, we refer you to the registration statement and the exhibits and schedules filed as a part of the registration statement. Statements contained in this prospectus concerning the contents of any contract or any other document are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed as an exhibit is qualified in all respects by the filed exhibit. The registration statement, including exhibits and schedules filed, may be inspected without charge at the Public Reference Room of the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549, and copies of all or any part of it may be obtained from that office after payment of fees prescribed by the SEC. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains a Web site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. The other information we file with the SEC is not part of the registration statement of which this prospectus forms a part.

After we have completed this offering, we will file annual, quarterly and current reports, proxy statements and other information with the SEC. We intend to make these filings available on our website once the offering is completed. In addition, we will provide copies of our filings free of charge to our stockholders upon request.

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GLOSSARY OF SELECTED TERMS

The following are definitions of certain industry terms used in this prospectus.


Barrel		Common unit of measure in the oil industry which equates to 42 gallons.

Blendstocks		Various hydrocarbon streams produced from crude oil, refined products and additives, which when blended together produce finished gasoline and diesel fuel; these may include natural gasoline, FCC unit gasoline, ethanol, reformate or butane, among others.

bpd		Barrels per day.

By-products		Products, other than gasoline and diesel, that are produced from refining crude oil to gasoline and diesel.

Catalyst		A substance that affects a chemical change, but itself remains unchanged.

Catalytic cracking unit		Converts gas oil from the crude unit into liquefied petroleum gas, distillate and gasoline blendstocks by applying heat in the presence of a catalyst.

Crack spread		A simplified model that measures the difference between the price for light products and crude oil. For example, 3/2/1 crack spread is often referenced and represents the approximate gross margin resulting from processing one barrel of crude oil, assuming that three barrels of a benchmark crude oil are converted, or cracked, into two barrels of gasoline and one barrel of diesel.

Crude oil throughput capacity		The amount of crude oil that can be processed by separating the crude oil according to boiling point under high heat and low pressure to recover various hydrocarbon fractions.

Distillates		Primarily diesel fuel, kerosene and jet fuel.

Feedstocks		Hydrocarbon compounds, such as crude oil and natural gas liquids, that are processed and blended into refined products.

GTR (ground tire rubber) asphalt		Recycled tire rubber blended with liquid asphalt to produce homogenous asphalt, which has improved performance over conventional asphalt.

Independent refiner		A refiner that does not have crude oil exploration or production operations. An independent refiner purchases the crude oil used as feedstock in its refinery operations from third parties.

Liquefied petroleum gas		Light hydrocarbon material gaseous at atmospheric temperature and pressure, held in the liquid state by pressure to facilitate storage, transport and handling.

MMBTU		Million British thermal units: a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree Fahrenheit.

Naptha		The major constituent of gasoline fractionated from crude oil during the refining process, which is later processed in the reformer unit to increase octane.

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No. 6 Fuel Oil		Consists of petroleum residues and residual oils that are generally blended with more refined petroleum products to produce a fuel to meet industry specifications.

PMA (polymer modified asphalt)		Asphalt that has been blended with a polymer like styrene-butadiene copolymer to improve properties.

Refined products		Hydrocarbon compounds, such as gasoline, diesel fuel, jet fuel and residual fuel, that are produced by a refinery.

Rubberized asphalt		Non-homogenous mixture of rubber and asphalt, produced using either a wet or dry process.

Solomon Associates		Solomon Associates, LLC, a Dallas, Texas-based company that provides benchmarking and consulting services to the energy industry.

Sour crude oil		A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.

Sweet crude oil		A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil.

Throughput		The volume per day processed through a unit or a refinery.

Turnaround		A periodically required standard procedure to refurbish and maintain a refinery that involves the shutdown and inspection of major processing units and occurs every three to five years.

Unbranded		A term used in connection with fuel or the sale of fuel into the spot or wholesale markets, rather than fuel or the sale of fuel directly to branded retail outlets.

Utilization		Ratio of total refinery throughput to the rated capacity of the refinery.

WTI		West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an API gravity between 38 and 40 and a sulfur content of less than 0.4 weight percent that is used as a benchmark for other crude oils.

WTS		West Texas sour crude oil, a medium, sour crude oil, characterized by an API gravity between 31 and 33 and a sulfur content of approximately 2.0 weight percent.

Yield		The percentage of refined products that are produced from feedstocks.

113

ALON USA ENERGY, INC. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS


	Page

Audited Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2003 and 2004		F-3
Consolidated Statements of Operations for the Years Ended December 31, 2002, 2003 and 2004		F-4
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2002, 2003 and 2004		F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2003 and 2004		F-6
Notes to Consolidated Financial Statements		F-7

Interim Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2004 and March 31, 2005 (unaudited)		F-30
Consolidated Statements of Operations for the Three Months Ended March 31, 2004 and 2005 (unaudited)		F-31
Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 2005 (unaudited)		F-32
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2004 and 2005 (unaudited)		F-33
Notes to Consolidated Financial Statements (unaudited)		F-34

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Alon USA Energy, Inc.:

We have audited the accompanying consolidated balance sheets of Alon USA Energy, Inc. and subsidiaries (the Company) as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2004. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Alon USA Energy, Inc. and subsidiaries as of December 31, 2004 and 2003, and the results of their operations, and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 9 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, in 2003.


	/s/ KPMG LLP

Dallas, Texas

February 22, 2005, except as

to note 16a, which is as of

February 28, 2005 and

note 16b, which is as of

July 27, 2005, and

note 16c, which is as of

July 6, 2005

F-2

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(dollars in thousands, except share and per share data)


			As of December 31,

			2003			2004

ASSETS
Current assets:
	Cash and cash equivalents		$	7,256		$	63,357
	Accounts and other receivables, net			59,825			69,328
	Inventories			74,765			79,329
	Prepaid expenses and other current assets			5,016			2,441

		Total current assets		146,862			214,455

Property, plant, and equipment, net				220,913			236,228
Other assets				19,207			21,833

		Total assets	$	386,982		$	472,516


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable and accrued liabilities		$	117,846		$	153,897
	Current portion of long-term debt			23,945			16,115

		Total current liabilities		141,791			170,012

Other non-current liabilities				19,896			19,436
Long-term debt				142,871			171,591
Deferred income tax liability, net				30,420			31,829

		Total liabilities		334,978			392,868

Commitments and contingencies (note 15) Minority interest in subsidiaries				5,081			8,176

Stockholders’ equity:
	Common stock, par value $0.01, 100,000,000 shares authorized; 35,001,120 shares issued and outstanding			350			350
	Preferred stock par value $0.01, 10,000,000 shares authorized; no shares issued and outstanding			—			—
	Additional paid-in capital			8,379			8,379
	Receivable for common shares issued			(140	)		—
	Other comprehensive loss, net of income tax			(1,538	)		(2,261	)
	Retained earnings			39,872			65,004

		Total stockholders’ equity		46,923			71,472

		Total liabilities and stockholders’ equity	$	386,982		$	472,516

The accompanying notes are an integral part of these consolidated financial statements.

F-3

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(dollars in thousands, except share and per share data)


			Year Ended December 31,

			2002		2003		2004

Net sales			$	1,207,723	$	1,410,766	$	1,707,564
Operating costs and expenses:
	Cost of sales			1,044,675		1,215,032		1,469,940
	Direct operating expenses			53,696		66,113		75,742
	Selling, general and administrative expenses			69,439		69,066		73,554
	Depreciation and amortization			14,853		18,262		19,064

		Total operating costs and expenses		1,182,663		1,368,473		1,638,300

Gain on disposition of assets				—		—		175

Operating income				25,060		42,293		69,439
Interest expense				14,385		16,284		23,704
Other expense (income), net				381		1,819		(277	)

Income before income tax expense, minority interest in income of subsidiaries, and accounting change				10,294		24,190		46,012
Income tax expense				3,913		9,105		18,315

Income before minority interest in income of subsidiaries and accounting change				6,381		15,085		27,697
Minority interest in income of subsidiaries				2,029		681		2,565

Income before accounting change				4,352		14,404		25,132
Cumulative effect of adoption of accounting principle (note 9)				—		336		—

Net income			$	4,352	$	14,068	$	25,132

Earnings per share			$	.12	$	.40	$	.72

Weighted average shares outstanding				35,001,120		35,001,120		35,001,120

Pro forma earnings per share (note 3(o))							$	.67

Pro forma weighted average shares outstanding (note 3(o))								37,236,057

The accompanying notes are an integral part of these consolidated financial statements.

F-4

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(dollars in thousands)


										Accumulated
					Additional		Receivable for			Other
			Common		Paid-In		Common Shares			Comprehensive			Retained
			Stock		Capital		Issued			Loss			Earnings		Total

Balance at January 1, 2002			$	350	$	8,339	$	(180	)	$	—		$	21,452	$	29,961
Received for shares issued				—		40		—			—			—		40
Net income				—		—		—			—			4,352		4,352
Other comprehensive loss:
	Minimum pension liability, net of income tax			—		—		—			(1,225	)		—		(1,225	)

		Total comprehensive income														3,127

Balance at December 31, 2002				350		8,379		(180	)		(1,225	)		25,804		33,128
Received for shares issued				—		—		40			—			—		40
Net income				—		—		—			—			14,068		14,068
Other comprehensive loss:
	Minimum pension liability, net of income tax			—		—		—			(313	)		—		(313	)

		Total comprehensive income														13,755

Balance at December 31, 2003				350		8,379		(140	)		(1,538	)		39,872		46,923
Received for shares issued				—		—		140			—			—		140
Net income				—		—		—			—			25,132		25,132
Other comprehensive loss:
	Minimum pension liability, net of income tax			—		—		—			(723	)		—		(723	)

		Total comprehensive income														24,409

Balance at December 31, 2004			$	350	$	8,379	$	—		$	(2,261	)	$	65,004	$	71,472

The accompanying notes are an integral part of these consolidated financial statements.

F-5

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)


				Year Ended December 31,

				2002			2003			2004

Cash flows from operating activities:
	Net income			$	4,352		$	14,068		$	25,132
	Adjustments:
		Depreciation and amortization			14,853			18,262			19,064
		Stock option plan compensation			640			683			530
		Deferred income tax expense			7,457			6,241			1,669
		Minority interest in income of subsidiaries			2,029			681			2,565
		Accrued interest on subordinated notes to stockholders			2,447			3,665			3,815
		Gain on sale of assets			—			—			(175	)
		Cumulative effect of adoption of accounting principle			—			336			—
	Changes in operating assets and liabilities:
		Accounts and other receivables, net			(8,826	)		3,177			(9,514	)
		Inventories			(14,898	)		8,970			(4,256	)
		Prepaid expenses and other current assets			(3,185	)		1,816			2,575
		Other assets			1,021			1,158			1,871
		Accounts payable and accrued liabilities			503			13,107			35,147
		Other non-current liabilities			(1,392	)		4,009			(1,680	)

			Net cash provided by operating activities		5,001			76,173			76,743

Cash flows from investing activities:
	Capital expenditures				(26,587	)		(23,391	)		(27,301	)
	Turnaround and chemical catalyst expenditures				(3,951	)		(1,547	)		(2,322	)
	Proceeds from sale of assets				—			274			317
	Acquisition of minority interest in subsidiary				(40,380	)		(10,000	)		(10,000	)
	Acquisition of asphalt business				—			—			(580	)

			Net cash used in investing activities		(70,918	)		(34,664	)		(39,886	)

Cash flows from financing activities:
	Stock issuance and payments received from shares issued				40			1,721			140
	Deferred debt issuance costs				(3,268	)		—			(1,885	)
	Net borrowings (payments) on revolving credit facilities				43,500			(29,400	)		(19,600	)
	Additions to long-term debt				61,815			1,546			100,671
	Payments on long-term debt				(39,849	)		(13,534	)		(60,082	)

			Net cash provided by (used in) financing activities		62,238			(39,667	)		19,244


Net (decrease) increase in cash and cash equivalents					(3,679	)		1,842			56,101
Cash and cash equivalents, beginning of period					9,093			5,414			7,256

Cash and cash equivalents, end of period				$	5,414		$	7,256		$	63,357

Supplemental cash flow information:
	Cash paid for interest			$	11,056		$	15,196		$	20,536

	Cash paid for income tax, net of tax refunds of $7,306 in 2003			$	7,449		$	(1,562	)	$	15,701

Non-cash activities:
Asphalt Business Acquisition
	Property, plant and equipment acquired			$	—		$	—		$	(3,917	)
	Net working capital acquired (accounts and other receivables, net, inventories, accounts payable)				—			—			817
	Net debt assumed				—			—			2,520

		Cash used in acquisition of asphalt business		$	—		$	—		$	(580	)

The accompanying notes are an integral part of these consolidated financial statements.

F-6

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)


(1)	Description and Nature of Business

Alon USA Energy, Inc. (“Alon Energy”) and its subsidiaries (collectively, the “Company”) engage in the business of refining and marketing of petroleum products, primarily in the Southwestern and South Central regions of the United States. Our business consists of two operating segments: (1) Refining and Marketing and (2) Retail.

Refining and Marketing Segment. The Company owns and operates a refinery in Big Spring, Texas. The refinery can process a variety of crude oils, including regionally produced sour crude oil or Gulf Coast and imported crude oils transported on the Company’s crude oil pipelines, which connect the refinery to the Gulf Coast. The refinery primarily manufactures various grades of gasoline, diesel fuel, petrochemical feedstocks, asphalt and specialty blended asphalts. The Company primarily markets its gasoline and diesel under the Fina brand name at approximately 1,300 locations in five states. The Company’s product distribution network includes seven owned or leased product pipelines and accesses six owned or leased product terminals.

Retail Segment. The Company operates 167 co-branded 7-Eleven and Fina convenience stores, offering motor fuels and merchandise throughout West Texas and New Mexico. Substantially all of the fuel sold by these stores is produced by the Company’s refinery and is transported to the stores through the Company’s pipeline and terminal networks.


(2)	Minority Interest Acquisition

On August 21, 2002, the Company acquired from the outside investors the remaining 40% minority interest in Alon Capital, a subsidiary of the Company, which held substantially all of the refinery, pipeline and terminal assets, for a total purchase price of $57,100, consisting of a $37,100 cash payment and the remaining $20,000 in the form of deferred payments, of which $10,000 was paid in 2003 and the remaining $10,000 was paid in 2004.


(3)	Summary of Significant Accounting Policies


*(a)*	*Basis of Presentation*

The consolidated financial statements include the accounts of Alon Energy and its subsidiaries. All significant intercompany balances and transactions have been eliminated. Minority interest in the Company’s subsidiaries is reported separately in the accompanying consolidated balance sheets. Minority interest in income of subsidiaries is reported net of income taxes and after elimination of significant intercompany transactions.


*(b)*	*Use of Estimates*

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


*(c)*	*Revenue Recognition*

F-7

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

been received or collection is reasonably assured. Transportation, shipping and handling costs incurred are reported in cost of sales.

Revenues include the sales of certain buy/sell arrangements, which involve linked purchases and sales related to product sales contracts entered into to address location, quality or grade requirements. The results of these linked refined product buy/sell transactions are recorded in sales and cost of sales in the accompanying statement of operations at fair value. In the ordinary course of business, logistical and refinery production schedules necessitate the occasional sale of crude oil to third parties. All purchases and sales of crude oil, are recorded net, in cost of sales in the accompanying statement of operations. Such sales are infrequent and the effects of the sales on the Company’s operating results are not significant.

For the year’s ended December 31, 2002, 2003 and 2004, the Company recorded revenues related to linked refined product sales of $38,187, $21,783 and $72,354, respectively. For the years ended December 31, 2002, 2003 and 2004, the Company recorded costs related to linked refined product sales of $39,148, $22,414 and $72,651, respectively.


*(d)*	*Vendor Rebates*

The Company’s retail segment receives rebates and commissions from certain vendor incentive programs. These rebates are recorded as a reduction of cost of sales in the period the Company earns the rebates and commissions.


*(e)*	*Cash and Cash Equivalents*

Cash and cash equivalents include demand deposits and money market accounts with maturities of three months or less when purchased.


*(f)*	*Inventories*

Crude oil, refined products and blend stocks for the refining and marketing segment are stated at the lower of cost or market. Cost is determined under the last-in, first-out (LIFO) valuation method. Cost of crude oil, refined product, and blendstock inventories in excess of market value are charged to cost of sales. Such charges are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. Materials and supplies are stated at average cost. Cost for the retail segment merchandise inventories is determined under the retail inventory method and cost for retail segment fuel inventories is determined under the first-in, first-out (FIFO) method.


*(g)*	*Hedging Activity*

The Company follows Statement of Financial Accountings Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, effective January 1, 2001. The Company considers all forwards, futures, and option contracts to be part of its risk management strategy. The Company has elected not to designate derivative contracts as cash flow hedges for financial accounting purposes. Accordingly, net unrealized gains and losses for changes in the fair value on open derivative contracts are recognized in current cost of sales.


*(h)*	*Property, Plant, and Equipment*

The carrying value of property, plant, and equipment includes the fair value of the asset retirement obligation and have been reflected in the accompanying consolidated balance sheets at cost, net of accumulated depreciation.

F-8

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

Property, plant, and equipment, net of salvage value, are depreciated using the straight-line method at rates based on the estimated useful lives for the assets or groups of assets, beginning in the month following acquisition or completion. The Company capitalizes interest costs associated with major construction projects based on the effective interest rate on aggregate borrowings.

Leasehold improvements are depreciated on the straight-line method over the shorter of the contractual lease terms or the estimated useful lives.

Expenditures for major replacements and additions are capitalized. Expenditures for routine repairs and maintenance costs are charged to direct operating expense as incurred. The applicable costs and accumulated depreciation of assets that are sold, retired, or otherwise disposed of are removed from the accounts and the resulting gain or loss is recognized.


*(i)*	*Impairment of Long-Lived Assets and Assets to Be Disposed Of*

Long-lived assets and certain identifiable intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of an asset to future net cash flows expected to be generated by the asset. If the carrying value of an asset exceeds its expected future cash flows, an impairment loss is recognized based on the excess of the carrying value of the impaired asset over its fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. These future cash flows and fair values are estimates based on the Company’s judgment and assumptions.


*(j)*	*Asset Retirement Obligations*

Effective January 1, 2003, the Company adopted Statement No. 143, Accounting for Asset Retirement Obligations, which established accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement costs. The provisions of this statement apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of a long lived asset. Associated with the adoption of the standard the Company recorded a long-term asset retirement obligation of $2,297 (note 9).


*(k)*	*Turnarounds and Chemical Catalyst Costs*

We record the cost of planned major refinery maintenance, referred to as turnarounds, and chemical catalyst used in the refinery process units, which are typically replaced in conjunction with planned turnarounds, in “other assets” in our consolidated balance sheet. Turnaround and catalyst costs are currently deferred and amortized on a straight-line basis beginning the month after the completion of the turnaround and ending immediately prior to the next scheduled turnaround. Amortization of turnaround costs is presented in “depreciation and amortization” in our consolidated statement of operations. The amortization of catalyst costs is presented in “direct operating expense” on our consolidated statement of operations.


*(l)*	*Income Taxes*

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or

F-9

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.


*(m)*	*Stock-Based Compensation*

The Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Accordingly, compensation cost for stock options is measured as the excess of the estimated fair value of the common stock over the exercise price and is generally recognized pro rata over the scheduled vesting period. Stock compensation expense is presented as selling, general and administrative expenses in the accompanying statements of operations (note 14).

The Company uses the minimum value method for calculating the fair value impact of SFAS No. 123, Accounting for Stock-Based Compensation (SFAS No. 123). Accordingly, there is no significant pro forma impact on net earnings and earnings per share from adoption of SFAS No. 123.


*(n)*	*Environmental Expenditures*

The Company accrues for costs associated with environmental remediation obligations when such costs are probable and can be reasonably estimated. Environmental liabilities represent the estimated costs to investigate and remediate contamination at the Company’s properties. This estimate is based on internal and third-party assessments of the extent of the contaminations, the selected remediation technology and review of applicable environmental regulations. Accruals for estimated costs from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environment remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded as assets when the receipt is deemed probable (note 8). Estimates are updated to reflect changes in factual information, available technology or applicable laws and regulations.


*(o)*	*Earnings Per Share*

Basic earnings per share is computed by dividing net income by the weighted average of the common shares outstanding. There are no dilutive potential common shares outstanding.

The pro forma earnings per share provides supplemental information in connection with the Company’s proposed initial public offering (see note 16). The pro forma earnings per share gives effect to the additional number of shares necessary to pay the portion of the dividend that exceeds net income for the year ended December 31, 2004.

The Company has granted the underwriters an option to purchase up to 1,530,000 additional shares of common stock to cover over-allotments of shares. If the underwriters exercise this option, the Company will pay an additional dividend to its stockholders of record immediately prior to this offering in an amount equal to 50% of the gross proceeds from the sale of such additional shares (note 16). Assuming full exercise of the underwriters over-allotment option, the Company will pay an additional dividend of $12,240, resulting in pro forma weighted average shares outstanding of 38,001,057 and pro forma earnings per share of $.66.

F-10

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)


*(p)*	*New Accounting Standards and Disclosures*

In December 2004, the FASB issued Statement of Accounting Standards No. 123R, Share-Based Payment (SFAS No. 123R), which requires expensing of stock options and other share-based compensation payments to employees and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing proforma disclosure only. This standard is effective for the Company as of January 1, 2006 and will apply to all awards granted, modified, cancelled or repurchased after that date as well as the unvested portion of prior rewards. Because the Company uses the minimum value method of measuring equity share options for pro forma disclosure purposes under SFAS No. 123, the Company will apply SFAS No. 123R prospectively to new awards and to awards modified, repurchased or cancelled after January 1, 2006.

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51. This interpretation addresses the consolidation by business enterprises of variable interest entities as defined in the interpretation. The interpretation applies immediately to interests in variable interest entities created after December 31, 2003, and to interests in variable interest entities obtained after December 31, 2003. The adoption of this interpretation in the first quarter of 2004 had no impact on the Company’s consolidated financial statements.

Currently, the Emerging Issues Task Force (EITF) is addressing the accounting for linked purchase and sale arrangements in EITF Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. The Company will monitor the progress of EITF Issue No. 04-13 to ensure the Company’s accounting for its linked purchases and sales complies with the EITF’s final consensus opinion.

In November 2004, the FASB issued Statement No. 151, Inventory Costs, which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material and requires that those items be recognized as current-period charges. Statement No. 151 also requires that allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. Statement No. 151 is effective for fiscal years beginning after June 15, 2005, and is not expected to affect the Company’s financial position or results of operations.

In December 2004, the FASB issued Statement No. 153, Exchanges of Nonmonetary Assets, which addresses the measurement of exchanges of nonmonetary assets. Statement No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets, which was previously provided by APB Opinion No. 29, Accounting for Nonmonetary Transactions, and replaces it with an exception for exchanges that do not have commercial substance. Statement No. 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement No. 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The adoption of Statement No. 153 is not expected to affect the Company’s financial position or results of operations.

In March of 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Retirement Obligations” (“FIN 47”), which requires companies to recognize a liability for the fair value of a legal obligation to perform asset-retirement activities that are conditional on a future event, if the amount can be reasonably estimated. FIN 47 must be adopted by the Company by the end of fiscal 2005. The impact of adoption on the Company’s consolidated financial statements is still being evaluated.

F-11

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)


(4)	Segment Data

The Company’s revenues are derived from our two operating segments: (i) Refining and Marketing and (ii) Retail. Management has identified these segments for managing operations based on manufacturing and marketing criteria.


*(a)*	*Refining and Marketing Segment*

The refining and marketing segment includes a complex sour crude oil refinery, its crude oil and refined products pipeline systems and its refined products terminalling operations. The Company’s refinery manufactures petroleum products including various grades of gasoline, diesel fuel, jet fuel, petrochemical feedstocks, asphalt and other petroleum based products. In addition, finished products are acquired through exchange agreements and third-party suppliers. The Company primarily markets its gasoline and diesel under the Fina brand name, through a network of approximately 1,300 locations. Finished products and blendstocks are also marketed through sales and exchanges with other major oil companies, state and federal governmental entities, unbranded wholesale distributors and various other third parties.


*(b)*	*Retail Segment*

The Company’s retail segment operates 167 owned and leased convenience store sites operating primarily in West Texas and New Mexico. These convenience stores offer various grades of gasoline, diesel fuel, general merchandise and food products to the general public under the 7-Eleven and Fina brand names.


*(c)*	*Corporate/ Other*

Operations that are not included in either of the two segments are included in the category Corporate and Other. These operations consist primarily of corporate headquarter operating and depreciation expenses and interest income.

Operating income for each segment consists of net revenues less cost of sales, direct operating expenses, selling, general and administrative expenses and depreciation and amortization. Sales between segments are transferred at current market prices. Consolidated totals presented are after intersegment eliminations.

Total assets of each segment consist of net property, plant and equipment, inventories, accounts receivables and other assets directly associated with the segment’s operations. Corporate assets consist primarily of corporate headquarters information technology and administrative equipment.

F-12

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

Segment data as of and for the years ended December 31, 2004, 2003 and 2002 is presented below.


			December 31, 2004

			Refining and						Corporate
			Marketing			Retail			and Other			Eliminations			Consolidated

Net sales:
	Unaffiliated customers		$	1,406,073		$	301,491		$	—		$	—		$	1,707,564
	Intersegment			117,777			—			—			(117,777	)		—

		Total net sales	$	1,523,850		$	301,491		$	—		$	(117,777	)	$	1,707,564

Operating income (loss)			$	68,611		$	2,897		$	(2,069	)	$	—		$	69,439
Interest expense				(20,149	)		(3,555	)		—			—			(23,704	)
Other income (expense), net				(51	)		(3	)		331			—			277

	Income (loss) before income taxes and minority interest		$	48,411		$	(661	)	$	(1,738	)	$	—		$	46,012

Total assets			$	389,830		$	69,949		$	12,737		$	—		$	472,516
Depreciation and amortization				13,437			4,147			1,480			—			19,064
Capital investments				36,140			3,134			612			—			39,886


			December 31, 2003

			Refining and						Corporate
			Marketing			Retail			and Other			Eliminations			Consolidated

Net sales:
	Unaffiliated customers		$	1,132,577		$	278,189		$	—		$	—		$	1,410,766
	Intersegment			92,468			—			—			(92,468	)		—

		Total net sales	$	1,225,045		$	278,189		$	—		$	(92,468	)	$	1,410,766

Operating income (loss)			$	42,020		$	2,443		$	(2,170	)	$	—		$	42,293
Interest expense				(12,959	)		(3,325	)		—			—			(16,284	)
Other expense, net				(94	)		—			(1,725	)		—			(1,819	)

	Income (loss) before income taxes, minority interest and accounting change		$	28,967		$	(882	)	$	(3,895	)	$	—		$	24,190

Total assets			$	304,046		$	73,747		$	9,189		$	—		$	386,982
Depreciation and amortization				12,636			4,078			1,548			—			18,262
Capital investments				27,442			6,613			609			—			34,664

F-13

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)


			December 31, 2002

			Refining and						Corporate
			Marketing			Retail			and Other			Eliminations			Consolidated

Net sales:
	Unaffiliated customers		$	959,893		$	247,830		$	—		$	—		$	1,207,723
	Intersegment			71,010			—			—			(71,010	)		—

		Total net sales	$	1,030,903		$	247,830		$	—		$	(71,010	)	$	1,207,723

Operating income (loss)			$	22,726		$	4,195		$	(1,861	)	$	—		$	25,060
Interest expense				(11,301	)		(3,084	)		—			—			(14,385	)
Other expense, net				—			(23	)		(358	)		—			(381	)

	Income (loss) before income taxes, minority interest and accounting change		$	11,425		$	1,088		$	(2,219	)	$	—		$	10,294

Total assets			$	315,389		$	71,049		$	5,628		$	—		$	392,066
Depreciation and amortization				9,949			3,696			1,208			—			14,853
Capital investments				68,136			2,083			699			—			70,918


(5)	Financial Instruments


*(a)*	*Fair Value of Financial Instruments*

The carrying amounts of the Company’s cash and cash equivalents, receivables, payables and accrued expenses approximate fair value due to the short-term maturities of these assets and liabilities. The reported amounts of long-term debt approximate fair value as interest approximates market rates. Derivative financial instruments are carried at fair value, which is based on quoted market prices.


*(b)*	*Derivative Financial Instruments*

The Company selectively utilizes commodity derivatives to manage its exposure to commodity price fluctuations and interest rate-related derivative instruments to manage its exposure on its debt instruments. The Company does not enter into derivative instruments for any purpose other than cash flow hedging purposes. Accordingly, the Company does not speculate using derivative instruments. The Company has elected not to designate derivative instruments as cash flow hedges for financial accounting purposes. Therefore, changes in the fair value of the derivative instruments are included in income in the period of the change.


	Interest Rate Swap

The Company primarily uses variable-rate debt to finance its operations. To limit the variability of a portion of its interest payments, the Company entered into an interest rate swap agreement in December 2001 to manage fluctuations in cash flows resulting from interest rate risk. The swap was not designated as a hedge for accounting purposes. This swap was terminated as of December 15, 2003 resulting in a $318 charge to interest expense in the accompanying consolidated statement of operations.


	Commodity Instruments

The Company occasionally uses crude oil and refined product commodity futures contracts to reduce financial exposure related to price changes on anticipated transactions. Crude oil and refined product

F-14

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

forward contracts are used to facilitate the supply of crude oil to the refinery and the sale of refined products while managing price exposure. The Company closed all of its open futures contracts in 2003, recognizing a loss of $3,555 in cost of sales in the accompanying consolidated statement of operations. There were no futures contracts open at December 31, 2004.

At December 31, 2003, the Company held net forward contracts for purchases of 50 thousand barrels of refined products. The average price for these forward contracts at December 31, 2003 was $38.73 per barrel with a fair value of $1,954. At December 31, 2004, the Company held net forward contracts for sales of 5 thousand barrels of distillate. The average price for these forward contracts at December 31, 2004 was $48.38 per barrel with a fair value of $232. These contracts were not designated as hedges for accounting purposes. Accordingly, net unrealized gain of $18 and loss of $10 were recorded to income for the years ended December 31, 2003 and 2004, respectively.


*(c)*	*Concentrations of Credit Risk*

Financial instruments that potentially subject the Company to concentration of credit risk consist primarily of trade accounts receivables. Credit risk is minimized as a result of the credit quality of the Company’s customer base and the large number of customers comprising the Company’s customer base. The Company performs ongoing credit evaluations of its customers and requires letters of credit, prepayments or other collateral or guarantees as management deems appropriate. The Company’s allowance for doubtful accounts is reflected as a reduction of accounts receivable in the consolidated balance sheets. The balance in the allowance account was $1,104 and $1,322 at December 31, 2003 and 2004, respectively. For the three-year period ended December 31, 2004, no sales to a single customer accounted for more than 10% of the Company’s net sales.

There is not a significant credit risk on the Company’s derivative instruments which are transacted through counterparties meeting established collateral and credit criteria.


(6)	Inventories

Inventories for the Company are stated at the lower of cost or market. Cost is determined under the last-in, first-out (LIFO) method for crude oil, refined products, and blendstock inventories. Materials and supplies are stated at average cost. Cost for convenience store merchandise inventories is determined under the retail inventory method and cost for convenience store fuel inventories is determined under the first-in, first-out (FIFO) method.

Carrying value of inventories consisted of the following:


		December 31,

		2003		2004

Crude oil, refined products, and blendstocks		$	53,088	$	58,412
Materials and supplies			5,418		5,570
Store merchandise			14,059		12,860
Store fuel			2,200		2,487

	Total inventories	$	74,765	$	79,329

Market values of crude oil, refined products and blendstocks inventories exceeded LIFO costs by $7,057 and $25,756 at December 31, 2003 and 2004, respectively.

F-15

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

(7) Property, Plant, and Equipment

Property, plant, and equipment consisted of the following:


		December 31,

		2003			2004

Refining facilities		$	133,522		$	149,016
Pipelines and terminals			59,483			69,289
Retail			54,708			59,543
Other			8,465			9,323

	Property, plant, and equipment, gross		256,178			287,171
Less accumulated depreciation			(35,265	)		(50,943	)

	Property, plant, and equipment, net	$	220,913		$	236,228

The useful lives on depreciable assets used to determine depreciation expense were as follows:


Refining facilities		3 — 20 years; average 18 years
Pipelines and terminals		5 — 25 years; average 23 years
Retail		5 — 40 years; average 18 years
Other		3 — 15 years; average 5 years

The Company capitalized interest of $520, $297, and $301 for the years ended December 31, 2002, 2003, and 2004, respectively.


(8)	Other Assets

Other assets consisted of the following:


		December 31,

		2003		2004

Receivable from Fina for environmental costs		$	6,430	$	4,314
Deferred debt issuance costs			4,821		8,291
Deferred turnaround, chemical catalyst cost			2,852		2,399
Retail license fees			3,400		3,429
Other			1,704		3,400

	Total other assets	$	19,207	$	21,833

In connection with the acquisition of the refinery, pipeline and terminal assets from Atofina Petrochemicals, Inc. (“Fina”) in August 2000, Fina agreed to indemnify the Company for the costs of environmental investigations, assessments, and clean-ups of known conditions that existed at the acquisition date. Such indemnification is limited to an aggregate of $20,000 over a ten-year period. Annual indemnification is limited to a ceiling of $5,000 except that the ceiling may be increased by the amount (up to $5,000) in cases by which the previous year’s ceiling exceeded actual costs. Fina retains liability for third-party claims received within ten years of the acquisition alleging personal injury or property damage resulting from Fina’s use of the acquired assets prior to the acquisition. The Company’s management does not expect expenditures for remediation of existing contamination to exceed the indemnification limitations. The Company also has insurance coverage for amounts in excess of $20,000, up to $40,000

F-16

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

during the ten-year indemnification period. Accordingly, at December 31, 2003 and 2004, the Company has recorded a current receivable of $3,609 and $3,000 and a non-current receivable of $6,430 and $4,314 from Fina, respectively, and corresponding accrued environmental liabilities.

Debt issuance costs are amortized over the term of the related debt using the effective interest method. Amortization of deferred debt issuance costs is recorded as interest expense in the accompanying statements of operations. Amortization of debt issuance costs was $2,602, $902, and $1,329 for the years ended December 31, 2002, 2003, and 2004, respectively.


(9)	Non-current Liabilities

Non-current liabilities consist of the following:


		December 31,

		2003		2004

Pension and other postemployment benefit liabilities, net (note 10)		$	10,998	$	11,792
Environmental accrual (note 15)			5,879		4,058
Asset retirement obligation			2,349		2,524
Other			670		1,062

	Total non-current liabilities	$	19,896	$	19,436

The Company adopted the Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143), on January 1, 2003 and recognized a $336 cumulative effect of adoption, net of $173 of income tax benefit in connection with future estimated costs for dismantling certain refinery and pipeline assets. SFAS No. 143 requires that the Company record the fair value of liability associated with an asset retirement obligation. The Company’s asset retirement obligation relates to the removal of underground storage tanks and debranding costs at the Company’s owned and leased retail sites and the dismantlement and disposal of certain pipeline, terminal, and refinery assets. The asset retirement obligation for storage tank removal on leased retail sites is accreted over the expected life of the underground storage tank which approximates the average retail site lease term. The following table summarizes the activity relating to the Company’s asset retirement obligations for the years ended December 31, 2003 and 2004:


	December 31,

	2003			2004

Balance at beginning of year	$	2,297		$	2,349
Accretion expense		92			178
Retirements		(59	)		(28	)
Additions		19			25

Balance at end of year	$	2,349		$	2,524


(10)	Employee and Postretirement Benefits

The Company has two defined benefit pension plans covering substantially all of its refining and marketing segment employees. The benefits are based on years of service and the employee’s final average monthly compensation. The Company’s funding policy is to contribute annually not less than the minimum required nor more than the maximum amount that can be deducted for federal income tax purposes.

F-17

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future.

In addition to providing pension benefits, certain health care and life insurance benefits (other benefits) are provided to active and certain retired employees who meet eligibility requirements defined in the plan documents. The health care benefits in excess of certain limits and the life insurance benefits are insured.

The measurement date used to determine pension and other postretirement benefit measures for the pension plan and the postretirement benefit plan is December 31. Financial information related to the Company’s pension plans and other postretirement benefits is presented below.


			Pension Benefits						Postretirement Benefits

			2003			2004			2003			2004

Change in benefit obligation:
	Benefit obligation at beginning of year		$	21,656		$	27,356		$	4,347		$	3,435
	Service cost			1,142			1,326			231			160
	Interest cost			1,616			1,826			307			222
	Plan participants contributions			—			—			34			28
	Plan Amendments			—			—			(1,663	)		(2,119	)
	Actuarial loss			3,337			1,980			319			409
	Benefits paid			(395	)		(716	)		(140	)		(283	)

		Benefit obligations at end of year	$	27,356		$	31,772		$	3,435		$	1,852

Change in plan assets:
	Fair value of plan assets at beginning of period			12,698			16,172			—			—
	Actual gain on plan assets			3,629			1,929			—			—
	Employer contribution			240			2,729			106			255
	Plan participants contributions			—			—			34			28
	Benefits paid			(395	)		(716	)		(140	)		(283	)

		Fair value of plan assets at end of period	$	16,172		$	20,114		$	—		$	—

Reconciliation of funded status:
	Fair value of plan assets at end of year		$	16,172		$	20,114			—			—
	Less benefit obligation at end of year			27,356			31,772			3,435			1,852

		Funded status at end of year		(11,184	)		(11,658	)		(3,435	)		(1,852	)
	Unrecognized prior service costs			—			—			(2,156	)		(4,117	)
	Unrecognized net actuarial gain			7,424			8,300			804			1,183

		Accrued benefit costs	$	(3,760	)	$	(3,358	)	$	(4,787	)	$	(4,786	)

Amounts recognized in the consolidated balance sheets:
	Accrued benefit liability		$	(7,006	)	$	(5,808	)	$	(4,787	)	$	(4,786	)
	Accumulated other comprehensive loss			3,646			2,450			—			—

		Accrued pension cost	$	(3,360	)	$	(3,358	)	$	(4,787	)	$	(4,786	)

F-18

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

As of December 31, 2003 and 2004, the accumulated benefit obligation for each of the Company’s pension plans was in excess of plan assets. The aggregate benefit obligation, accumulated benefit obligation and fair value of plan assets for the pension plans were as follows:


	December 31,

	2003		2004

Projected benefit obligation	$	27,356	$	31,772
Accumulated benefit obligation		22,382		27,118
Fair value of plan assets		16,172		20,114

The weighted-average assumptions used to determine benefit obligations at December 31, 2002, 2003 and 2004 were as follows:


	Pension Benefits									Postretirement Benefits

	2002			2003			2004			2002			2003			2004

Discount rate		6.75	%		6.25	%		6.00	%		6.75	%		6.25	%		6.00	%
Rate of compensation increase		3.00	%		3.00	%		3.00	%		—			—			—

The weighted-average assumptions used to determine net periodic benefit costs for the years ended December 31, 2002, 2003 and 2004 were as follows:


	Pension Benefits									Postretirement Benefits

	2002			2003			2004			2002			2003			2004

Discount rate		7.25	%		6.75	%		6.25	%		7.25	%		6.75	%		6.25	%
Expected return on plan assets		9.00	%		9.00	%		9.00	%		—			—			—
Rate of compensation increase		3.00	%		3.00	%		3.00	%		—			—			—

The Company’s overall expected long-term rate of return on assets is 9.0%. The expected long-term rate of return is based on the portfolio as a whole and note on the sum of the returns on individual asset categories. The return is based exclusively on historical returns, without adjustments.

For measurement purposes, a 9.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2004 and thereafter. The components of net periodic benefit cost for the years and periods are as follows:


			Pension Benefits									Other Benefits

			Year Ended December 31									Year Ended December 31

			2002			2003			2004			2002		2003			2004

Components of net periodic benefit cost:
	Service cost		$	897		$	1,142		$	1,326		$	204	$	231		$	160
	Interest cost			1,394			1,616			1,826			305		307			222
	Amortization of prior service costs			—			—			—			—		(38	)		(157	)
	Expected return on plan assets			(1,447	)		(1,326	)		(1,388	)		—		—			—
	Recognized net actuarial loss			30			262			563			—		3			29

		Net periodic benefit cost	$	874		$	1,694		$	2,327		$	509	$	503		$	254

F-19

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)


	*Plan Assets*

The weighted-average asset allocation of the Company’s pension and postretirement benefits at December 31, 2003 and 2004 were as follows:


			Pension						Postretirement
			Benefits						Benefits

			Plan Assets						Plan Assets

			2003			2004			2003			2004

Asset Category:
	Equity Securities			70.0	%		70.0	%		70.0	%		70.0	%
	Fixed Income Securities			30.0	%		30.0	%		30.0	%		30.0	%

		Total		100	%		100	%		100	%		100	%

The investment policies and strategies for the assets of Company’s pension benefits and postretirement benefits plans is to provide returns in excess of the benchmark measured over a rolling five year period. The portfolio is expected to earn long-term returns from capital appreciation and a stable stream of current income. This approach recognizes that assets are exposed to risk and the market value of the plans’ assets may fluctuate from year to year. Risk tolerance is determined based on the Company’s specific risk management policies. In line with the investment return objective and risk parameters, the plans’ mix of assets includes a diversified portfolio of equity and fixed-income investments. Equity investments include a blend of domestic growth and value stocks of various sizes of capitalization. The aggregate asset allocation is reviewed on an annual basis.


	*Cash Flows*

The Company contributed $240 and $2,730 to the pension plan for the years ended December 31, 2003 and 2004, respectively, and expects to contribute $4,000 to the pension plan in 2005. There were no employee contributions to the plans.

The benefits expected to be paid in each year 2005 – 2009 are $801; $925; $1,089; $1,263; and $1,456, respectively. The aggregate benefits expected to be paid in the five years from 2010 – 2014 are $11,784. The expected benefits are based on the same assumptions used to measure the Company’s benefit obligation at December 31, and include estimated future employee service.

During the period from January 1, 2002 through December 31, 2004, the return on plan assets and plan contributions did not increase sufficiently to cover the increase in benefits to be paid to participants. This put the plan into an unfunded accumulated pension obligation position and, in accordance with SFAS No. 87, Employer’s Accounting for Pensions, the Company recorded an unfunded accrued pension cost of $1,944, $506 and $1,196 at December 31, 2002, 2003 and 2004, respectively. Of the unfunded pension cost $1,225, net of a $719 tax benefit, $313, net of a $193 tax benefit and $723, net of a $472 tax benefit, was reflected as a component of comprehensive income for the years ended December 31, 2002, 2003 and 2004, respectively.

Expected return on plan assets has a significant effect on the amounts reported for the pension plans. A 1% change in the expected return on plan assets will affect the total of service and interest cost components by approximately $138. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would affect the total of service and interest costs components by $14 and affect postretirement benefit obligations by $81.

F-20

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

The Company sponsors a 401(k) plan in which employees of the Company’s retail segment may participate by contributing up to 15% of their pay after completing one year of service. The Company matches from 25% to 75% of pay depending on the employee’s years of service. This match is limited to 6% of employee pay with full vesting of matching and contributions occurring after five years of service. The Company’s contribution for the years ended December 31, 2003 and 2004 was $147 and $164, respectively.


(11)	Long-Term Debt

A summary of the Company’s long-term debt follows:


		December 31,

		2003			2004

Secured term loan		$	—		$	100,000
Revolving credit facility			—			—
Refining revolving credit facility			14,000			—
Refining term loan			43,591			—
Retail revolving credit facility			5,600			—
Retail mortgage and equipment loans			35,095			33,610
Fina deferred purchase price			4,473			3,978
Subordinated notes payable			53,085			49,200
Deferred payments to investors (note 2)			10,353			—
Other debt			619			918

	Total debt		166,816			187,706
Less current portion			(23,945	)		(16,115	)

	Total long-term debt	$	142,871		$	171,591


*(a)*	*Secured Term Loan*

On January 14, 2004, the Company, through Alon USA, entered into a senior secured term loan facility (secured term loan) in the aggregate amount of $100,000 maturing in January 2009. The balance of the Refining term loan dated July 31, 2000 was paid in full with a portion of the proceeds of the secured term loan. The term loan accrues interest at LIBOR (2.56% at December 31, 2004) plus 6.5% per year, but not less than 10% per annum, and is subject to a minimum annual payment of $2,500 per year which can be increased under certain circumstances or declined by lenders as defined in the agreement. This facility includes certain restrictions and covenants, including, among other things, limitations on capital expenditures, dividend restrictions and minimum net worth and coverage ratios. Additionally, the terms of the loan requires either a letter of credit in favor of the lenders or maintenance of a separate unrestricted cash account equal to nine months interest payable on the secured term loan. The Company elected to establish a separate cash account totaling $7,500 which is classified as cash and cash equivalents in the balance sheet as of December 31, 2004.


*(b)*	*Revolving Credit Facility*

As of December 31, 2004, the Company had a revolving credit facility which provides for commitments of $141,600 for a three-year term. Subject to commitment amounts and terms, the revolving credit facility provides for the issuance of letters of credit and up to $82,000 of which is available for

F-21

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

revolving credit loans. The revolving credit facility is primarily used for issuance of letters of credit (principally for crude oil purchases). The Company is charged various fees and expenses in connection with this facility, including facility fees and various letter of credit fees. No amounts were outstanding under this revolving credit facility at December 31, 2004. Amounts outstanding under this revolving credit facility accrued interest at the Eurodollar plus 2.5%. This facility includes certain restrictions and covenants, including, among other things, limitations on capital expenditures, dividend restrictions and minimum net worth and coverage ratios.

Prior to January 14, 2004, the Company had two revolving credit facilities which provided commitments of $130,000 for our refining segment and $5,600 for our retail segment. These facilities were restructured into the single refining and retail revolving credit facility described above.

As of December 31, 2003 and 2004, the Company had $89,199 and $100,676, respectively, of outstanding letters of credit under the refining and retail revolving credit facility.


*(c)*	*Retail Mortgage and Equipment Loans*

On October 1, 2002, the Company replaced an existing retail term loan agreement with a new $35,000 term loan agreement. The agreement consists of a 20-year $22,300 mortgage loan bearing a fixed interest rate of 8.06% per annum and a 10-year $12,700 equipment loan at a fixed rate of 8.30% per annum, secured by certain property, plant, and equipment used in the Company’s retail segment.

These mortgage and equipment loans are to be repaid in monthly principal and interest installments of $346 beginning December 1, 2002, decreasing to $187 after December 1, 2012.

In 2003, the Company obtained $1,545 in mortgage loans to finance the acquisition of new retail locations. The interest rates on these loans range between 5.5% and 9.7%, with 5 to 15 year payment terms.


*(d)*	*Fina Deferred Purchase Price*

In connection with the Acquisition, the Company is required to make certain deferred payments to Fina. A summary of the amounts outstanding follows:


		December 31,

		2003			2004

Non-interest bearing due based on sales volumes over 60 months with remainder (if any) thereafter		$	4,690		$	4,016
Less discount – interest imputed at 10%			(217	)		(38	)

	Fina deferred purchase price	$	4,473		$	3,978


*(e)*	*Subordinated Notes Payable*

As of December 31, 2004, the Company had unsecured subordinated notes payable to Alon Israel of $36,300, subordinated notes payable to former minority interest owners of $3,700, and subordinated notes payable to certain members of executive management of $13. The secured term loan allows for principal and interest payments to Alon Israel under certain circumstances as defined in the agreement. Under the terms of the restructuring (note 2) and the secured term loan, the notes to the former minority interest owners are scheduled to be paid in July 2005. The subordinated notes accrue interest at 7% per annum ($5,573 and $9,187 accrued interest payable at December 31, 2003 and 2004, respectively).

F-22

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)


*(f)*	*Deferred Payments to Minority Investors*

In connection with the restructure described in note 2, the Company purchased the remaining 40% minority interest in Alon Capital in August 2002. The total purchase price was $57,100, consisting of a $37,100 cash payment and the remaining $20,000 in the form of deferred payments, of which $10,000 was paid June 30, 2003 and the remaining $10,000 was paid in 2004. The deferred purchase payment accrued interest at 7% per annum.


*(g)*	*Maturity of Long-Term Debt*

The aggregate maturities of long-term debt for each of the five years subsequent to December 31, 2004 are as follows: 2005 — $16,115; 2006 — $4,488; 2007 — $4,590; 2008 — $4,795; 2009 — $92,215 and 2010 and thereafter — $65,503.


*(h)*	*Guarantees and Restrictions*

Alon Israel and other related parties guaranteed the payment of the Company’s obligations under the refining and retail revolving credit facility if the Company defaults on such payments and there is a shortfall in the proceeds realized from collateral.


*(i)*	*Interest and Financing Expense*

Interest and finance expense included in the accompanying statements of operations consisted of the following:


		December 31,

		2002			2003			2004

Interest expense		$	8,897		$	12,868		$	19,261
Letters of credit and finance costs			4,684			2,811			3,415
Amortization of debt issuance costs			1,324			902			1,329
Capitalized interest			(520	)		(297	)		(301	)

	Total interest expense	$	14,385		$	16,284		$	23,704

F-23

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)


(12)	Income Taxes

Income tax expense included the following:


				December 31,

				2002			2003		2004

Current:
	Federal			$	(4,124	)	$	2,336	$	15,554
	State				580			528		1,092

		Total current			(3,544	)		2,864		16,646

Deferred:
	Federal				7,362			5,341		1,487
	State				95			900		182

		Total deferred			7,457			6,241		1,669

			Income tax expense	$	3,913		$	9,105	$	18,315

A reconciliation between the income tax expense computed on pretax income at the statutory federal rate and the actual provision for income taxes is as follows:


		December 31,

		2002		2003			2004

Computed expected tax expense		$	3,603	$	8,349		$	16,104
State and local income taxes, net of federal benefit			283		921			828
Other, net			27		(165	)		1,383

	Income tax expense	$	3,913	$	9,105		$	18,315

The following table sets forth the tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities.


			December 31,

			2003		2004

Deferred income tax assets:
	Accounts receivable, allowance		$	136	$	372
	Postretirement benefits			3,463		3,722
	Accrued liabilities and other			3,084		2,138

		Total deferred income tax assets		6,683		6,232

Deferred income tax liabilities:
	Deferred charges			1,829		1,821
	Inventories			1,849		1,510
	Property, plant, and equipment			33,300		34,619
	Other			125		111

		Total deferred income tax liabilities		37,103		38,061

		Net deferred income tax liability	$	30,420	$	31,829

F-24

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of taxable income and projections for future taxable income, over the periods which the deferred tax assets are deductible, management believes it is more likely than not the Company will realize the benefits of these deductible differences at December 31, 2003 and 2004.


(13)	Related-Party Transactions

The Company and Alon Israel are parties to a consulting agreement whereby Alon Israel provides strategic planning and management consulting services to the Company for an annual fee of $1,500 through September 30, 2003 and $4,000 a year beginning October 1, 2003.

The Company currently has a consulting agreement with a board member and recorded consulting fees of $100 and $50 for the years ended December 31, 2003 and 2004, respectively.

The Company currently pays two board members for services as board members and recorded board of director fees of $50 and $109 for the years ended December 31, 2003 and 2004.

The Company has subordinated notes payable to Alon Israel, the former minority owners of Alon USA Capital and certain members of executive management as described in note 11.


(14)	Stockholders’ Equity


*(a)*	*Common and preferred stock*

The authorized capital stock of the Company consists of 100,000,000 shares of common stock, $0.01 par value, and 10,000,000 shares of preferred stock, $0.01 par value. Issued and outstanding shares were 35,001,120 shares of common stock and no shares of preferred stock as of December 31, 2003 and 2004. The number of issued and outstanding shares give effect to the 33,600-for-1 stock split (note 16).


*(b)*	*Stock-Based Compensation*

At August 1, 2000 (inception), Alon USA Operating, Inc. (“Alon Operating”) and Alon Assets, Inc (“Alon Assets”), majority owned, fully consolidated subsidiaries of Alon Energy, adopted a stock option plan (the “Plan”) pursuant to which the company’s board of directors may grant stock options to certain officers and executive management. The Plan authorized grants of options to purchase up to 16,154 shares of common stock of Alon Assets and 6,066 shares of common stock of Alon Operating. All authorized options were granted in 2000. All stock options have ten-year terms. The options are subject to accelerated vesting and become fully exercisable if the Company achieves certain financial performance and debt service criteria. Upon exercise, the Company will reimburse the option holder for the exercise price of the shares and under certain circumstances the related federal and state taxes (gross up liability).

Pursuant to SFAS No. 123, Accounting for Stock-Based Compensation, the Company has elected to account for its stock-based compensation under APB Opinion No. 25. Under APB Opinion No. 25, the Company uses the intrinsic value method to account for compensation cost related to stock options. Accordingly, compensation expense is recorded over the vesting period based on the excess of the estimated fair value of the common stock over the exercise price. The Company recognizes stock compensation expense using the accelerated vesting method prescribed by FASB Interpretation No. 28. Such compensation expense, net of taxes, amounted to $640, $683, and $530 at December 31, 2002, 2003,

F-25

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

and 2004, respectively. Had compensation expense been determined as prescribed by SFAS No. 123 using the minimum value method, the Company’s net income would not have been significantly impacted for any of the three periods ended December 31, 2004.

The following table summarized the stock option activity for Alon Assets and Alon Operating for the years ended December 31, 2003 and 2004:


	Alon Assets					Alon Operating

				Weighted					Weighted
	Number of			Average		Number of			Average
	Options			Exercise		Options			Exercise
	Outstanding			Price		Outstanding			Price

Outstanding at January 1, 2003		12,217		$	100		4,587		$	100
Granted		—			—		—			—
Exercised		—			—		—			—
Forfeited and expired		—			—		—			—

Outstanding at December 31, 2003		12,217			100		4,587			100
Granted		—			—		—			—
Exercised		(1,212	)		100		(455	)		100
Forfeited and expired		(1,733	)		100		(650	)		100

Outstanding at December 31, 2004		9,272		$	100		3,482		$	100

At December 31, 2004, the number of options exercisable was 1,212 for Alon Assets and 455 for Alon Operating.


*(c)*	*Stock Warrants*

On August 1, 2000 (inception), the Company granted its two bank lenders warrants to purchase 5,274 shares of common stock of Alon Assets, representing approximately 3.5% of the outstanding common stock of Alon Assets, and 1,980 shares of common stock of Alon Operating, representing approximately 3.5% of the outstanding common stock of Alon Operating, for an aggregate exercise price of $2,975. The warrants were issued in August 2000 in connection with the financing of the acquisition. The estimated fair value of the warrants at the date of issuance was not material to the financial statements. The terms of the warrant agreements provide that the warrants were exercisable on or before August 8, 2005 and, if exercised by either bank, must be exercised in conjunction with a simultaneous exercise of that bank’s warrants in both Alon Assets and Alon Operating. The warrants contain anti-dilution provisions pursuant to which the exercise price and number of shares of common stock covered by the warrants are adjusted in certain events. In addition, Alon Assets and Alon Operating have each entered into stockholders agreements for the benefit of the banks.

In August 2002, the Company purchased the warrant rights for 3,839 of the 5,274 shares of Alon Assets available under the warrant rights and 1,442 of the 1,980 shares of Alon Operating available under the warrant rights, from one of its lenders for an aggregate purchase price of $2,292 (note 2). The other lender’s rights to purchase warrants remain in effect.

F-26

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)


(15)	Commitments and Contingencies


*(a)*	*Leases*

The Company accounts for leases with step rent provisions and escalation clauses on a straight-line basis over the minimum lease term. The Company has commitments under long-term operating leases for certain buildings, land, equipment, and pipelines expiring at various dates over the next ten years. Certain long-term operating leases relating to buildings, land and pipelines include options to renew for additional periods. At December 31, 2004, minimum lease payments on operating leases were as follows:


Year ending December 31:
2005		$	11,612
2006			9,776
2007			9,480
2008			8,811
2009			8,607
2010 and thereafter			13,113

	Total	$	61,399

Total rental expense was $13,785, $13,163, and $12,042 for the years ended December 31, 2002, 2003, and 2004, respectively. Contingent rentals and subleases were not significant.


*(b)*	*Other Commitments*

In the normal course of business, the Company has long-term commitments to purchase services, such as natural gas, electricity and water for use by its refinery, terminals, pipelines and retail locations. The Company is also party to various refined product and crude oil supply and exchange agreements. These agreements are short-term in nature or provide terms for cancellation.

The Company is involved in various other claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company’s financial position, results of operations or liquidity.


*(c)*	*Environmental*

Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future

F-27

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Substantially all amounts accrued are expected to be paid out over the next five to ten years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

The Company has accrued environmental remediation obligations of $9,488 ($3,609 current payable and $5,879 non-current liability), at December 31, 2003 and $7,058 ($3,000 current payable and $4,058 non-current liability), at December 31, 2004.

The Company completed the construction of a new $14,600 gasoline desulfurization facility in the fourth quarter 2003, ensuring compliance with the small refiner status regulations mandated by the Federal Clean Air Act, which requires a reduction of the sulfur content in gasoline by January 1, 2004. The Company continues to evaluate new Environmental Protection Agency standards that will require a reduction in sulfur content in diesel fuel manufactured for on-road consumption by 2010. The Company spent approximately $500 in 2004 and expects to spend approximately $29,400 over the next six years to comply with these regulations.

The Company has elected to join the Voluntary Emission Reduction Permit program, sponsored by the Texas Commission on Environmental Quality. This program allows facilities to permit grandfathered emission sources through a phased installation of emission control equipment using ten-year Best Available Control Technology. To qualify as a grandfathered source, the equipment must not have been modified since 1972. The Company’s emission control installation plan ends in December 2006. The completion cost of this plan and other regulatory spending will be approximately $6,700.


(16)	Subsequent Events


*(a)*	*HEP Transaction*

On February 28, 2005, the Company completed a sale transaction consisting of the contribution of the Fin-Tex, Trust and River product pipelines, the Wichita Falls and Abilene product terminals and the Orla tank farm to Holly Energy Partners, LP (“HEP”) (the “Transaction”) in exchange for $120,000 cash and 937,500 subordinated Class B limited partnership interests in HEP. The amendment to the limited partnership agreement of HEP sets forth the rights of the aforementioned subordinated units and among other things, states their conversion into common units to be five years from their issuance date and that available cash will be distributed to the common unit holders and to the general partner of HEP before distribution to the subordinated unit holders.

The entire cash consideration is financed by a high yield debt issued by HEP with a 10 year maturity (“HEP Debt”).

Alon Pipeline Logistics, LLC, a wholly owned subsidiary of the Company (“Alon Logistics”) entered into an agreement with the general partner of HEP providing for Alon Logistics to indemnify the general partner for cash payments such general partner has to perform toward satisfaction of the principal or interest under the HEP Debt following a default by HEP (provided that such cash payments exceed the difference between the amount of HEP Debt over the indemnity amount). The indemnity amount is limited to (i) the lower of (a) $110,850 or (b) outstanding amount of HEP Debt. The indemnity terminates at such time as Alon Logistics no longer holds any HEP units and per other terms as defined in the indemnification agreement. The indemnification amount may be reduced from time to time per terms defined in the indemnification agreement. Indemnity is specific to Alon Logistics and does not extend to other Alon entities, even if the HEP units are transferred to such other entities.

F-28

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands)

In conjunction with the Transaction, the Company entered into a Pipelines and Terminals Agreement (“PTA”) with HEP providing continued access to these assets for an initial term of 15 years and three additional five year renewal terms exercisable in our sole option. Pursuant to the PTA, the Company has committed to transport and store minimum volumes of refined products in these pipelines and terminals. The tariff rates applicable to our transportation of refined products on the pipelines are variable, with a base fee which is reduced for volumes exceeding defined volumetric targets. The PTA provides for the reduction of the minimum volume requirements under certain circumstances.


*(b)*	*Special Dividend*

On May 11, 2005, the Company filed a registration statement with the Securities and Exchange Commission relating to a proposed public offering of 10,200,000 shares of its common stock (“IPO”), and has from time to time thereafter amended such registration statement. The registration statement, as amended, reflects the intentions of the Company and Alon USA Operating, Inc. to use a portion of the net proceeds of the offering to pay special dividends to their respective pre-offering stockholders of record.

On June 16, 2005 and July 27, 2005, the boards of directors of the Company and Alon USA Operating, Inc. declared special dividends to be paid upon the completion of the offering. These dividends will be paid to the respective stockholders of record of these entities as of June 16, 2005 and July 27, 2005, respectively. Upon payment of these dividends, the applicable stockholders of record of the Company will receive an aggregate of $57,018 and the minority interest stockholders of record of Alon USA Operating, Inc. will receive an aggregate of $3,873.

If the underwriters’ option to purchase additional shares is exercised, the Company will pay an additional dividend of up to $12,240 to its stockholders of record immediately prior to the IPO in an amount equal to 50% of the gross proceeds from the sale of such additional shares.


*(c)*	*Stock Split*

On July 6, 2005 the board of directors of the Company approved a resolution to effect a 33,600-for-1 stock split of the Company’s common stock resulting in 35,001,120 shares of common stock outstanding and to increase the authorized common stock to 100,000,000 shares. The earnings per share information and all common stock information have been retroactively restated for all years presented to reflect this stock split.

F-29

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)


									Pro Forma
									March 31,
			December 31,			March 31,			2005
			2004			2005			(note 1)

						(Unaudited)
ASSETS
Current assets:
	Cash and cash equivalents		$	63,357		$	108,989		$	108,989
	Accounts and other receivables, net			69,328			80,210			80,210
	Inventories			79,329			99,797			99,797
	Prepaid expenses and other current assets			2,441			4,780			4,780

		Total current assets		214,455			293,776			293,776

Investment in HEP				—			23,420			23,420
Property, plant, and equipment, net				236,228			205,702			205,702
Other assets				21,833			30,903			30,903

		Total assets	$	472,516		$	553,801		$	553,801


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable and accrued liabilities		$	153,897		$	162,040		$	162,040
	Dividends payable			—			—			60,891
	Current portion of deferred gain on disposition of assets			—			6,310			6,310
	Current portion of long-term debt			16,115			8,502			8,502

		Total current liabilities		170,012			176,852			237,743

Other non-current liabilities				19,436			20,170			20,170
Deferred gain on disposition of assets				—			68,836			68,836
Long-term debt				171,591			149,653			149,653
Deferred income tax liability				31,829			38,744			38,744

		Total liabilities		392,868			454,255			515,146

Commitments and contingencies (note 14)
Minority interest in subsidiaries				8,176			5,638			1,765

Stockholders’ equity:
	Common stock, par value $0.01, 100,000,000 shares authorized; 35,001,120 shares issued and outstanding			350			350			350
	Preferred stock, par value $0.01, 10,000,000 shares authorized; no shares issued and outstanding			—			—			—
	Additional paid-in capital			8,379			8,379			8,379
	Other comprehensive loss, net of income tax			(2,261	)		(2,261	)		(2,261	)
	Retained earnings			65,004			87,440			30,422

		Total stockholders’ equity		71,472			93,908			36,890

		Total liabilities and stockholders’ equity	$	472,516		$	553,801		$	553,801

The accompanying notes are an integral part of these consolidated financial statements.

F-30

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, dollars in thousands, except share and per share data)


			For the Three Months Ended
			March 31,

			2004			2005

Net sales			$	352,723		$	407,974
Operating Costs and Expenses:
	Cost of sales			302,980			351,554
	Direct operating expenses			18,912			18,336
	Selling, general and administrative expenses			17,318			16,665
	Depreciation and amortization			4,762			4,834

		Total operating costs and expenses		343,972			391,389

Gain on disposition of assets				—			27,693

Operating income				8,751			44,278
Interest expense				6,015			5,007
Equity earnings in investee				—			(135	)
Other income, net				(93	)		(250	)

Income before tax expense, minority interest in income of subsidiaries, and accounting change				2,829			39,656
Income tax expense				1,119			15,655

Income before minority interest in income of subsidiaries and accounting change				1,710			24,001
Minority interest in income of subsidiaries				213			1,565

Net income			$	1,497		$	22,436


Earnings per share			$	.04		$	.64

Weighted average shares outstanding				35,001,120			35,001,120

Pro forma earnings per share (note 12)						$	.60

Pro forma weighted average shares outstanding (note 12)							37,404,557

The accompanying notes are an integral part of these consolidated financial statements.

F-31

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(unaudited, dollars in thousands)


					Accumulated
			Additional		Other
	Common		Paid-In		Comprehensive			Retained
	Stock		Capital		Loss			Earnings		Total

Balance at December 31, 2004	$	350	$	8,379	$	(2,261	)	$	65,004	$	71,472
Net income		—		—		—			22,436		22,436

Balance at March 31, 2005	$	350	$	8,379	$	(2,261	)	$	87,440	$	93,908

The accompanying notes are an integral part of these consolidated financial statements.

F-32

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, dollars in thousands)


				For the Three Months
				Ended March 31,

				2004			2005

Cash flows from operating activities:
	Net income			$	1,497		$	22,436
	Adjustments:
		Depreciation and amortization			4,762			4,834
		Stock option plan compensation			119			95
		Deferred income tax expense			—			6,915
		Minority interest in income of subsidiaries			213			1,565
		Accrued interest on subordinated notes to stockholders			1,106			701
		Gain on disposition of assets			—			(27,693	)
		Equity earnings in investee			—			(135	)
	Changes in operating assets and liabilities:
		Accounts and other receivables, net			(16,196	)		(10,882	)
		Inventories			(5,439	)		(20,468	)
		Prepaid expenses and other current assets			(10,142	)		(2,339	)
		Other assets			1,385			355
		Accounts payable and accrued liabilities			11,779			8,142
		Other non-current liabilities			(284	)		37

			Net cash used in operating activities		(11,200	)		(16,437	)


Cash flows from investing activities:
	Capital expenditures				(1,157	)		(11,098	)
	Turnaround and chemical catalyst expenditures				(1,090	)		(10,382	)
	Proceeds from disposition of assets, net				15			118,000

			Net cash provided by (used in) investing activities		(2,232	)		96,520


Cash flows from financing activities:
	Minority interest shares purchased				—			(2,717	)
	Payments received for shares issued				140			—
	Dividends paid				—			(1,482	)
	Net payments on revolving credit facilities				(19,600	)		—
	Deferred debt issuance costs				(1,885	)		—
	Additions to long-term debt				99,325			2,932
	Payments on long-term debt				(48,568	)		(33,184	)

			Net cash provided by (used in) financing activities		29,412			(34,451	)


Net increase in cash and cash equivalents					15,980			45,632
Cash and cash equivalents, beginning of period					7,256			63,357

Cash and cash equivalents, end of period				$	23,236		$	108,989

Supplemental cash flow information:
	Cash paid for interest			$	2,719		$	3,250

	Cash paid for income tax			$	8		$	263

	Financing activity – receipt of Class B HEP subordinated units as proceeds from disposition of assets			$	—		$	30,000

The accompanying notes are an integral part of these consolidated financial statements.

F-33

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited, dollars in thousands except as noted)


(1)	Basis of Presentation and Significant Accounting Policies

These consolidated financial statements of Alon USA Energy, Inc. and subsidiaries (“Alon Energy” or “the Company”) are unaudited and have been prepared in accordance with accounting principles generally accepted in the United States of America. In the opinion of management of the Company, the information included in these consolidated financial statements reflects all adjustments which are necessary for a fair presentation of the Company’s consolidated financial position and results of operations for the interim periods presented. The results of operations for the interim period are not necessarily indicative of the operating results for the year ending December 31, 2005.

The unaudited pro forma consolidated balance sheet as of March 31, 2005, gives effect to the accrual of dividends payable to stockholders of record as of June 16, 2005 in connection with the Company’s proposed initial public offering and the related effects to minority interest and stockholders’ equity as if the dividends had been declared as of March 31, 2005. See note 14.

The consolidated balance sheet as of December 31, 2004 has been derived from the audited financial statements as of that date. These unaudited financial statements should be read in conjunction with the audited financial statements and notes for the years ended December 31, 2003 and 2004.

Revenues, net of applicable excise taxes, for products sold by both the refining and marketing segment and the retail segment are recorded upon delivery of the products to their customers, which is the point at which title to the products is transferred, the customer has the assumed risk of loss, and when payment has either been received or collection is reasonably assured. Transportation, shipping and handling costs incurred are reported in cost of sales.

Revenues include the sales of certain buy/sell arrangements, which involve linked purchases and sales related to product sales contracts entered into to address location, quality or grade requirements. The results of these linked refined product buy/sell transactions are recorded in sales and cost of sales in the accompanying statements of operations at fair value. In the ordinary course of business, logistical and refinery production schedules necessitate the occasional sale of crude oil to third parties. All purchases and sales of crude oil are recorded on a net basis in cost of sales in the accompanying statements of operations. Such sales are infrequent and the effects of the sales on the Company’s operating results are not significant.

For the three months ended March 31, 2004 and 2005, the Company recorded revenues related to linked refined product sales of $10,986 and $7,474 respectively. For the three months ended March 31, 2004 and 2005, the Company recorded costs related to linked refined product sales of $11,025 and 7,570, respectively.


(2)	Sale of Pipelines and Terminals

HEP Transaction. On February 28, 2005, the Company completed the contribution of the Fin-Tex, Trust and River product pipelines, the Wichita Falls and Abilene product terminals and the Orla tank farm to Holly Energy Partners, LP (“HEP”). In exchange for this contribution, which is referred to as the HEP transaction, Alon received $120 million in cash and 937,500 subordinated Class B limited partnership interests in HEP (“units”).

Simultaneously with this transaction, the Company entered into a Pipelines and Terminals Agreement with HEP providing continued access to these assets for an initial term of 15 years and three additional five year renewal terms exercisable in our sole option. Pursuant to the Pipelines and Terminals Agreement, the Company has committed to transport and store minimum volumes of refined products in these pipelines and terminals. The tariff rates applicable to our transportation of refined products on the pipelines

F-34

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited, dollars in thousands except as noted)

are variable, with a base fee which is reduced for volumes exceeding defined volumetric targets. The agreement provides for the reduction of the minimum volume requirement under certain circumstances. The service fees for our storage of refined products in the terminals are initially set at rates competitive in the marketplace.

The entire cash consideration is financed by a high yield debt issued by HEP with a 10 year maturity (“HEP Debt”).

Alon Pipeline Logistics, LLC, a wholly owned subsidiary of Alon Energy (“Alon Logistics”) entered into an agreement with the general partner of HEP providing for Alon Logistics to indemnify the general partner for cash payments such general partner has to perform toward satisfaction of the principal or interest under the HEP Debt following a default by HEP (provided that such cash payments exceed the difference between the amount of HEP Debt over the indemnity amount). The indemnity amount is limited to (i) the lower of (a) $110,850 or (b) outstanding amount of HEP Debt. The indemnity terminates at such time as Alon Logistics no longer holds any HEP units and per other terms as defined in the indemnification agreement. The indemnification amount may be reduced from time to time per terms defined in the indemnification agreement. Indemnity is specific to Alon Logistics and does not extend to other Alon entities, even if the HEP units are transferred to such other entities. The fair value of this debt guarantee of $1,075 is recorded in other liabilities in the March 31, 2005 consolidated balance sheet.

The Transaction was recorded as a partial sale for accounting purposes resulting in a pre-tax gain of $102,461, net of transaction costs and the fair value of the HEP indemnity. The Company recognized an initial pre-tax gain of $26,742. The remaining $75,719 of the gain was deferred. As the HEP units received in the transaction are accounted for under the equity method of accounting for investments in limited partnerships, $6,715 of the pro rata gain was deferred and subtracted from the carrying value of the investment in the HEP units. The deferred gain of $75,146 will be recognized over a period of approximately 12 years or less depending on circumstances as defined in the indemnification agreement. The deferred gain is recorded $6,310 as a current liability and $68,836 as a long-term liability in the March 31, 2005 consolidated balance sheet.


(3)	New Accounting Standards

In December 2004, the FASB issued Statement of Accounting Standards No. 123R, “Share-Based Payment” (SFAS No. 123R), which requires expensing stock options and other share-based compensation payments to employees and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing proforma disclosure only. This standard is effective for the Company as of January 1, 2006 and will apply to all awards granted, modified, cancelled or repurchased after that date as well as the unvested portion of prior rewards. Because the Company uses the minimum value method of measuring equity share options for pro forma disclosure purposes under SFAS No. 123, the Company will apply SFAS 123R prospectively to new awards and to awards modified, repurchased or cancelled after January 1, 2006.

In November 2004, the FASB issued Statement No. 151, “Inventory Costs,” which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material and requires that those items be recognized as current-period charges. Statement No. 151 also requires that allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. Statement No. 151 is effective for fiscal years beginning after June 15, 2005, and is not expected to affect the Company’s financial position or results of operations.

In December 2004, the FASB issued Statement No. 153, “Exchanges of Nonmonetary Assets,” which addresses the measurement of exchanges of nonmonetary assets. Statement No. 153 eliminates the

F-35

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited, dollars in thousands except as noted)

exception from fair value measurement for nonmonetary exchanges of similar productive assets, which was previously provided by APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” and replaces it with an exception for exchanges that do not have commercial substance. Statement No. 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement No. 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The adoption of Statement No. 153 is not expected to affect the Company’s financial position or results of operations.

Currently, the Emerging Issues Task Force, (EITF) is addressing the accounting for linked purchase and sale arrangements in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” At its March 17, 2005 meeting, EITF reached a tentative conclusion that generally requires non-monetary exchanges of inventory within the same line of business be recognized at the carrying value of the inventory transferred. The Company will monitor the progress of EITF Issue No. 04-13 to ensure the Company’s accounting for its linked purchases and sales complies with the EITF’s final consensus opinion.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), that requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective for fiscal years ending after December 15, 2005. The Company is currently reviewing the applicability of FIN 47 to its operations and its potential impact on its consolidated financial statements.


(4)	Segment Data

The Company’s revenues are derived from two operating segments: (i) Refining and Marketing and (ii) Retail. Management has identified these segments for managing operations based on manufacturing and marketing criteria.


*(a)*	*Refining and Marketing Segment*

The refining and marketing segment includes a complex sour crude oil refinery, its crude oil and its owned and leased refined products pipeline systems and refined products terminals. The Company’s refinery manufactures petroleum products including various grades of gasoline, diesel fuel, jet fuel, petrochemical feedstocks, asphalt and other petroleum based products. In addition, finished products are acquired through exchange agreements and third-party suppliers. The Company primarily markets its gasoline and diesel under the Fina brand name, through a network of approximately 1,300 locations. Finished products and blendstocks are also marketed through sales and exchanges with other major oil companies, state and federal governmental entities, unbranded wholesale distributors and various other third parties.


*(b)*	*Retail Segment*

F-36

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited, dollars in thousands except as noted)


*(c)*	*Corporate/Other*

Total assets of each segment consist of net property, plant and equipment, inventories, accounts receivables and other assets directly associated with the segment’s operations. Corporate assets consist primarily of information technology and administrative equipment at the corporate headquarters.

Segment data as of and for the three-month periods ended March 31, 2005 and 2004 is presented below.


			March 31, 2005

			Refining and						Corporate
			marketing			Retail			and other			Eliminations			Consolidated

Net sales:
	Unaffiliated customers		$	334,078		$	73,896		$	—		$	—		$	407,974
	Intersegment			32,856			—			—			(32,856	)		—

		Total net sales	$	366,934		$	73,896		$	—		$	(32,856	)	$	407,974

Operating income (loss)			$	44,788		$	89		$	(599	)	$	—		$	44,278
Interest expense				(4,146	)		(861	)		—			—			(5,007	)
Other income, net				119			—			266			—			385

	Income (loss) before income taxes, minority interest and accounting change		$	40,761		$	(772	)	$	(333	)	$	—		$	39,656

Total assets			$	471,751		$	69,625		$	12,425		$	—		$	553,801
Depreciation and amortization				3,311			1,052			471			—			4,834
Capital expenditures				20,327			1,009			144			—			21,480

F-37

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited, dollars in thousands except as noted)


			March 31, 2004

			Refining and						Corporate
			marketing			Retail			and other			Eliminations			Consolidated

Net sales:
	Unaffiliated customers		$	284,623		$	68,100		$	—		$	—		$	352,723
	Intersegment			25,069			—			—			(25,069	)		—

		Total net sales	$	309,692		$	68,100		$	—		$	(25,069	)	$	352,723

Operating income (loss)			$	9,817		$	(522	)	$	(544	)	$	—		$	8,751
Interest expense				(5,187	)		(828	)		—			—			(6,015	)
Other (income) expense, net				—			(5	)		98			—			93

	Income (loss) before income taxes, minority interest and accounting change		$	4,630		$	(1,355	)	$	(446	)	$	—		$	2,829

Total assets			$	350,051		$	72,189		$	13,871		$	—		$	436,111
Depreciation and amortization				3,287			1,058			417			—			4,762
Capital expenditures				1,707			242			283			—			2,232


(5)	Cash and Cash Equivalents

On February 28, 2005, the Company completed the contribution of three pipelines and three product terminals to Holly Energy Partners, LP. Net cash proceeds of $118,000 were received in connection with the transaction. $25,000 of the cash received was paid to Alon Israel in the form of a loan repayment, and a dividend of $1,482 was paid to current minority interest owners. The remaining cash was invested in various highly liquid, low risk debt investments with maturities of three months or less, or held as cash on hand.


(6)	Inventories

Carrying value of inventories consisted of the following:


		December 31,		March 31,
		2004		2005

Crude oil, refined products, and blendstocks		$	58,412	$	78,637
Materials and supplies			5,570		5,567
Store merchandise			12,860		12,716
Store fuel			2,487		2,877

	Total inventories	$	79,329	$	99,797

Market values exceeded LIFO costs by $25,766 and $42,156 at December 31, 2004 and March 31, 2005, respectively.

F-38

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited, dollars in thousands except as noted)


(7)	Investment in HEP

On February 28, 2005, the Company completed the contribution of certain of its pipeline and terminal assets to HEP. In exchange for this contribution, which is referred to as the HEP transaction, the Company received $120 million in cash and 937,500 subordinated Class B limited partnership units in HEP. The units are accounted for under the equity method of accounting for investment in limited partnerships and the units were recorded at an initial fair value of $32 per unit, or $30,000. The investment in the units are recorded net of $6,715 of the related deferred pro rata gain in the consolidated balance sheet as of March 31, 2005. The Company recognized $135 in equity earnings in investee for the one month period ended March 31, 2005. See note 2 for discussion of HEP transaction.


(8)	Property, Plant, and Equipment

Property, plant, and equipment consisted of the following:


		December 31,			March 31,
		2004			2005

Refining facilities		$	149,016		$	158,539
Pipelines and terminals			69,289			26,208
Retail			59,543			60,607
Other			9,323			9,758

	Property, plant, and equipment, gross		287,171			255,112
Less accumulated depreciation			(50,943	)		(49,410	)

	Property, plant, and equipment, net	$	236,228		$	205,702

On February 28, 2005, the Company completed the contribution of three pipelines and three product terminals to Holly Energy Partners, LP.


(9)	Employee and Postretirement Benefits

The Company’s anticipated contributions to its pension plans during 2005 have not changed significantly from amounts previously disclosed in the Company’s consolidated financial statements for the year ended December 31, 2004. For the three months ended March 31, 2004 and 2005, Alon contributed $0 and $401, respectively, to its qualified pension plan.


(10)	Long-Term Debt


	*Revolving Credit Facility*

As of March 31, 2005, the Company had a revolving credit facility which provides for commitments of $141,600 for a three-year term. Subject to commitment amounts and terms, the revolving credit facility provides for the issuance of letters of credit and up to $82,000 of which is available for revolving credit loans. The revolving credit facility is primarily used for issuance of letters of credit (principally for crude oil purchases). The Company is charged various fees and expenses in connection with this facility, including facility fees and various letter of credit fees. No amounts were outstanding under this revolving credit facility at March 31, 2005. Amounts outstanding under this revolving credit facility accrued interest at the Eurodollar plus 2.5% per year. This facility includes certain restrictions and covenants, including, among other things, limitations on capital expenditures, dividend restrictions and minimum net worth and coverage ratios.

F-39

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited, dollars in thousands except as noted)

As of March 31, 2004 and 2005, the Company had $103,249 and $108,607, respectively, of outstanding letters of credit under the refining and retail revolving credit facility.


	*Debt Repayment*

On February 28, 2005 the Company made a $25,000 subordinated debt payment to Alon Israel (see notes 2 and 5).


	*Guarantees and Restrictions*

Alon Israel, the sole stockholder of Alon Energy, and other related parties guaranteed the payment of the Company’s obligations under its refining revolving credit facility if the Company defaults on such payments and there is a shortfall in the proceeds realized from collateral.


(11)	Stock Based Compensation

The Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Accordingly, compensation cost for stock options is measured as the excess of the estimated fair value of the common stock over the exercise price and is generally recognized over the scheduled accelerated vesting period. Current period stock compensation expense is presented as selling, general and administrative expenses in the accompanying statements of operations.

The Company uses the minimum value method for calculating the fair value impact of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). Accordingly, there is no significant pro forma impact on net earnings and earnings per share from adoption of SFAS No. 123. The Company recognizes stock compensation expense using the accelerated vesting method prescribed by FASB Interpretation No. 28.


(12)	Earnings Per Share

Basic earnings per share is computed by dividing net income by the weighted average of the common shares outstanding. There are no dilutive potential common shares outstanding.

The pro forma earnings per share provides supplemental information in connection with the Company’s proposed initial public offering (see note 14). The pro forma earnings per share gives effect to the additional number of shares necessary to pay the portion of the dividend that exceeds net income for the three months ended March 31, 2005.

The Company has granted the underwriters an option to purchase up to 1,530,000 additional shares of common stock to cover over-allotments of shares. If the underwriters exercise this option, the Company will pay an additional dividend to its stockholders of record immediately prior to this offering in an amount equal to 50% of the gross proceeds from the sale of such additional shares (note 14). Assuming full exercise of the underwriters over-allotment option, the Company will pay an additional dividend of $12,240, resulting in pro forma weighted average shares outstanding of 38,169,557 and pro forma earnings per share of $.59.


(13)	Commitments and Contingencies


*(a)*	*Other Commitments*

F-40

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited, dollars in thousands except as noted)

The Company is also party to various refined product and crude oil supply and exchange agreements. These agreements are short-term in nature or provide terms for cancellation.


*(b)*	*Other Contingencies*

The Company is involved in various other claims and legal actions arising in the ordinary course of business. The Company believes the ultimate disposition of these matters will not have a material adverse effect on the Company’s financial position, results of operations or liquidity.


*(c)*	*Environmental*

The Company is subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These rules regulate the discharge of materials into the environment and may require the Company to incur future obligations to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites; to remediate or restore these sites; to compensate others for damage to property and natural resources and for remediation and restoration costs. These possible obligations relate to sites owned by the Company and associated with past or present operations. The Company is currently participating in environmental investigations, assessments, and cleanups under these regulations at service stations, pipelines, and terminals. The Company may in the future be involved in additional environmental investigations, assessments, and cleanups. The magnitude of future costs will depend on factors such as the unknown nature and contamination at many sites, the unknown timing, extent and method of the remedial actions, which may be required, and the determination of the Company’s liability in proportion to other responsible parties. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Substantially all amounts accrued are expected to be paid out over the next five to ten years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

The Company had accrued environmental remediation obligations of $7,058 ($3,000 current payable and $4,058 non-current liability) at December 31, 2004 and $6,664 ($3,000 current payable and $3,664 non-current liability) at March 31, 2005.


(14)	Subsequent Events

(a) Special Dividend

On May 11, 2005, the Company filed a registration statement with the Securities and Exchange Commission relating to a proposed public offering of 10,200,000 shares of its common stock (“IPO”), and has from time to time thereafter amended such registration statement. The registration statement, as amended, reflects the intentions of the Company and Alon Assets, Inc. to use a portion of the net proceeds of the offering to pay special dividends to their respective pre-offering stockholders of record.

On June 16, 2005 and July 27, 2005, the boards of directors of the Company and Alon USA Operating, Inc. declared special dividends to be paid upon the completion of the offering. These dividends will be paid to the respective stockholders of record of these entities as of June 16, 2005 and July 27, 2005, respectively. Upon payment of these dividends, the applicable stockholders of record of the Company will receive an aggregate of $57,018 and the minority interest stockholders of record of Alon Assets, Inc. and Alon USA Operating, Inc. will receive an aggregate of $3,873.

F-41

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited, dollars in thousands except as noted)

(b) Stock Split

On July 6, 2005 the board of directors of the Company approved a resolution to effect a 33,600-for-1 stock split of the Company’s common shares, resulting in 35,001,120 common shares outstanding and to increase the authorized common shares to 100,000,000. The earnings per share information and all common share information have been retroactively restated for all years presented to reflect this stock split.

F-42