Alon USA Energy (ALJ) 10-Q 2006 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2006

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM                    TO                    

Commission file number: 001-32567

Alon USA Energy, Inc.

(Exact name of Registrant as specified in its charter)

Delaware	74-2966572
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

7616 LBJ Freeway, Suite 300, Dallas, Texas 75251
(Address of principal executive offices) (Zip Code)

(972) 367-3600
(Registrant’s telephone number, including area code)

     Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

     Indicate by check whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

     The number of shares of the Registrant’s common stock, par value $0.01 per share, outstanding as of May 5, 2006 was 46,809,857.

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION	1
ITEM 1. FINANCIAL STATEMENTS	1
CONSOLIDATED BALANCE SHEETS	1
CONSOLIDATED STATEMENTS OF OPERATIONS	2
CONSOLIDATED STATEMENTS OF CASH FLOW	3
NOTES TO CONSOLIDATED STATEMENTS OF OPERATIONS	5
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	14
FORWARD-LOOKING STATEMENTS	14
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK	32
ITEM 4. CONTROLS AND PROCEDURES	33
PART II. OTHER INFORMATION	34
ITEM 6. EXHIBITS	34
SIGNATURES
EXHIBITS
Certifications of CEO Pursuant to Section 302
Certifications of CFO Pursuant to Section 302
Certifications of CEO & CFO Pursuant to Section 906

-i-

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(dollars in thousands except per share data)

	March 31,			December 31,
	2006			2005
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	136,824		$	136,820
Short-term investments		118,000			185,320
Accounts and other receivables, net		85,027			89,529
Inventories		112,699			79,181
Prepaid expenses and other current assets		12,131			6,264
Total current assets		464,681			497,114
Investment in HEP		22,746			22,754
Property, plant and equipment, net		196,802			211,410
Other assets		28,348			27,502
Total assets	$	712,577		$	758,780
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	148,801		$	157,076
Accrued liabilities		51,288			48,128
Current portion of deferred gain on disposition of assets		11,427			11,427
Current portion of long-term debt		2,024			4,487
Total current liabilities		213,540			221,118
Other non-current liabilities		18,068			18,345
Deferred gain on disposition of assets		49,577			52,433
Long-term debt		29,898			127,903
Deferred income tax liability		76,673			52,422
Total liabilities		387,756			472,221
Commitments and contingencies (note 13)
Minority interest in subsidiaries		10,217			7,066
Stockholders’ equity:
Preferred stock, par value $0.01, 10,000,000 shares authorized; no shares issued and outstanding		—			—
Common stock, par value $0.01, 100,000,000 shares authorized; 46,809,857 shares issued and outstanding at March 31, 2006 and December 31, 2005		468			468
Additional paid-in capital		181,247			181,108
Accumulated other comprehensive loss, net of income tax		(2,596	)		(2,596	)
Retained earnings		135,485			100,513
Total stockholders’ equity		314,604			279,493
Total liabilities and stockholders’ equity	$	712,577		$	758,780

The accompanying footnotes are an integral part of these financial statements.

1

ALON USA ENERGY, INC., AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands except per share data)

	For the Three Months Ended
	March 31,
	2006			2005
Net sales	$	584,701		$	407,974
Operating costs and expenses:
Cost of sales		497,827			351,554
Direct operating expenses		23,271			18,336
Selling, general and administrative expenses		17,453			16,665
Depreciation and amortization		5,523			4,834
Total operating costs and expenses		544,074			391,389
Gain on disposition of assets		55,386			27,693
Operating income		96,013			44,278
Interest expense		(9,047	)		(5,007	)
Equity earnings in HEP		577			135
Other income, net		1,927			250
Income before income tax expense and minority interest in income of subsidiaries		89,470			39,656
Income tax expense		32,526			15,655
Income before minority interest in income of subsidiaries		56,944			24,001
Minority interest in income of subsidiaries		2,780			1,565
Net income	$	54,164		$	22,436
Earnings per share, basic and diluted	$	1.16		$	.64
Weighted average shares outstanding		46,731,120			35,001,120

The accompanying footnotes are an integral part of these financial statements.

2

ALON USA ENERGY, INC., AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW
(unaudited, dollars in thousands)

	For the Three Months Ended
	March 31,
	2006			2005
Cash flows from operating activities:
Net income	$	54,164		$	22,436
Adjustments to reconcile net income to cash used in operating activities
Depreciation and amortization		5,523			4,834
Stock compensation		510			95
Deferred income tax expense		21,990			6,915
Minority interest in income of subsidiaries		2,780			1,565
Accrued interest on subordinated notes to stockholders		—			701
Gain on disposition of assets		(55,386	)		(27,693	)
Equity earnings in HEP		—			(135	)
Changes in operating assets and liabilities:
Accounts and other receivables, net		4,502			(10,882	)
Inventories		(33,518	)		(20,468	)
Prepaid expenses and other current assets		(3,606	)		(2,339	)
Other assets		(1,415	)		355
Accounts payable		(8,275	)		14,244
Accrued liabilities		3,160			(6,102	)
Other non-current liabilities		(152	)		37
Net cash used in operating activities		(9,723	)		(16,437	)
Cash flows from investing activities:
Capital expenditures		(4,638	)		(11,098	)
Turnaround and chemical catalyst expenditures		(1,303	)		(10,382	)
Proceeds from disposition of assets, net		68,000			118,000
Sale of short-term investments, net		67,320			—
Dividends from investment in HEP (net of equity earnings in HEP)		8			—
Minority interest shares purchased		—			(2,717	)
Net cash provided by investing activities		129,387			93,803
Cash flows from financing activities:
Dividends paid to minority interest stockholders		—			(1,482	)
Dividends paid to stockholders		(19,192	)		—
Additions to long-term debt		—			2,932
Payments on long-term debt		(100,468	)		(33,184	)
Net cash used in financing activities		(119,660	)		(31,734	)
Net change in cash and cash equivalents		4			45,632
Cash and cash equivalents, beginning of period		136,820			63,357
Cash and cash equivalents, end of period	$	136,824		$	108,989
Supplemental cash flow information:
Cash paid for interest	$	5,506		$	3,250
Cash paid for income tax	$	255		$	263

The accompanying footnotes are an integral part of these financial statements.

3

ALON USA ENERGY, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW
(unaudited, dollars in thousands)

	For the Three Months Ended
	March 31,
	2006		2005
Non-cash activities:
Financing activity — receipt of Class B HEP subordinated units as proceeds from disposition of assets	$	—	$	30,000

The accompanying footnotes are an integral part of these financial statements.

4

ALON USA ENERGY, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands except as noted)

(1) Basis of Presentation and Certain Significant Accounting Policies

     (a) Basis of Presentation

     The consolidated financial statements include the accounts of Alon USA Energy, Inc. and its subsidiaries (collectively, “Alon”). All significant intercompany balances and transactions have been eliminated. These consolidated financial statements of Alon and its subsidiaries are unaudited and have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements. In the opinion of Alon’s management, the information included in these consolidated financial statements reflects all adjustments, consisting of normal and recurring adjustments, which are necessary for a fair presentation of Alon’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 that may be obtained for the year ending December 31, 2006.

     The consolidated balance sheet as of December 31, 2005 has been derived from the audited financial statements as of that date. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in Alon’s Annual Report on Form 10-K for the year ended December 31, 2005.

     (b) Revenue Recognition

     In September 2005, the Emerging Issues Task Force, (EITF) reached a consensus concerning 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 EITF concluded that non-monetary exchanges of finished goods inventory within the same line of business be recognized at the carrying value of the inventory transferred. Alon began applying this consensus for new buy/sell arrangements beginning January 1, 2006.

     Alon occasionally enters into refined product buy/sell arrangements, which involve linked purchases and sales related to refined product sales contracts entered into to address location, quality or grade requirements. As of January 1, 2006, such buy/sell transactions are included on a net basis in sales in the consolidated statements of operations. Prior to the adoption of EITF Issue No. 04-13, the results of these linked refined product buy/sell transactions were recorded separately in sales and cost of sales in the consolidated statement of operations. 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, currently and historically, are recorded on a net basis, in cost of sales in the accompanying statement of operations.

     (c) New Accounting Standards

     Effective January 1, 2006, Alon adopted Statement of Accounting Standards No. 123R,Share-Based Payment(SFAS No. 123R), which requires use of the fair-value based method and expensing of stock options and other share-based compensation payments to employees, net of estimated forfeitures, over the requisite service period and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing proforma disclosure only. As a private company, Alon used the minimum value method of measuring equity share options for pro forma disclosure purposes under SFAS No. 123. Accordingly, Alon applied SFAS No. 123R prospectively to new awards and to awards modified, repurchased or cancelled after January 1, 2006. Alon applied the modified prospective transition method to any unvested stock-based awards issued after the initial public offering (“IPO”). The adoption of SFAS No. 123R did not have a significant effect on Alon’s financial position or results of operations.

     Alon previously accounted 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 (Opinion 25). Accordingly, compensation cost for stock options was measured as the excess of the estimated fair value of the common stock over the exercise price and was recognized over the scheduled vesting

5

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands except as noted)

period on an accelerated basis. Stock compensation expense is presented as selling, general and administrative expenses in the accompanying statements of operations. All pre-IPO stock-based awards will continue to be accounted for under Opinion 25.

     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. The adoption of Statement No. 151 did not have a material effect on Alon’s financial position or results of operations.

     In December 2004, the FASB issued FASB Staff Position (“FSP”) FAS 109-1,Application of FASB Statement No. 109, Accounting for Income Taxes, for the Tax Deduction Provided to U.S. Based Manufacturers by the American Jobs Creation Act of 2004(“Jobs Creation Act”) which requires a company that qualifies for the deduction for domestic production activities under the Jobs Creation Act to account for it as a special deduction under FASB Statement No. 109,Accounting for Income Taxes, as opposed to an adjustment of recorded deferred tax assets and liabilities.

(2) Sale of Amdel and White Oil Pipelines

     On March 1, 2006, Alon sold its Amdel and White Oil pipelines, which had been inactive since December 2002, to an affiliate of Sunoco Logistics Partners L.P., (“Sunoco”) for a total consideration of approximately $68,000. In conjunction with this transaction, Alon entered into a 10-year pipeline Throughput and Deficiency Agreement with options to extend the agreement by four additional thirty-month periods. The Throughput and Deficiency Agreement will allow Alon to maintain its physically integrated system by retaining crude oil transportation rights on the pipelines from the Gulf Coast. Pursuant to the Throughput and Deficiency Agreement, Alon has agreed to ship a minimum of 15,000 barrels per day (“bpd”) on the pipelines during the term of the agreement. Alon recognized a $52,500 pre-tax gain on disposition of assets in connection with this transaction in the first quarter of 2006.

(3) Segment Data

     Alon’s revenues are derived from two operating segments: (i) Refining and Marketing and (ii) Retail. The operating segments adhere to the accounting policies used for Alon’s consolidated financial statements as described in Note 1. The reportable operating segments are strategic business units that offer different products and services. The segments are managed separately as each segment requires unique technology, marketing strategies and distinct operational emphasis. Each operating segment’s performance is evaluated primarily on operating income.

     (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. Alon’s refinery produces 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. Alon primarily markets gasoline and diesel under the FINA brand name, through a network of approximately 1,230 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

     Alon’s retail segment operates 167 owned and leased 7-Eleven branded convenience store sites operating primarily in West Texas and New Mexico. These convenience stores typically offer various grades of gasoline,

6

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands except as noted)

diesel fuel, general merchandise and food and beverage products to the general public under the 7-Eleven and FINA brand names.

     (c) Corporate

     Operations that are not included in either of the two segments are included in the category Corporate. These operations consist primarily of corporate headquarter operating and depreciation expenses.

     Segment data as of and for the three-month periods ended March 31, 2006 and 2005 are presented below.

	Refining and
Three Months ended March 31, 2006	Marketing		Retail			Corporate			Total
Net sales to external customers	$	512,086	$	72,615		$	—		$	584,701
Intersegment sales/purchases		31,390		(31,390	)		—			—
Depreciation and amortization		3,845		1,154			524			5,523
Operating income (loss)		96,620		44			(651	)		96,013
Total assets		621,713		68,822			22,042			712,577
Turnaround, chemical catalyst and capital expenditures		5,699		223			19			5,941

	Refining and
Three Months ended March 31, 2005	Marketing		Retail			Corporate			Total
Net sales to external customers	$	334,078	$	73,896		$	—		$	407,974
Intersegment sales/purchases		32,856		(32,856	)		—			—
Depreciation and amortization		3,311		1,052			471			4,834
Operating income (loss)		44,788		89			(599	)		44,278
Total assets		471,751		69,625			12,425			553,801
Turnaround, chemical catalyst and capital expenditures		20,327		1,009			144			21,480

     Operating income for each segment consists of net revenues less cost of sales, direct operating expenses, selling, general and administrative expenses, depreciation and amortization and gain on disposition of assets. 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, investment in subsidiaries, inventories, short-term investments, cash and cash equivalents, accounts receivables and other assets directly associated with the segment’s operations. Corporate assets consist primarily of corporate headquarters information technology and administrative equipment, net of accumulated depreciation.

(4) Cash, Cash Equivalents and Short-Term Investments

     All highly-liquid instruments with a short-term maturity of three months or less at the time of purchase are considered to be cash equivalents.

     Short-term investments primarily consist of highly-rated auction rate securities (“ARS”). Although ARS may have long-term stated maturities, generally 10 to 30 years, Alon has designated these securities as available-for-sale and has classified them as current because it views them as available to support its current operations. ARS may be liquidated at par on the rate reset date, which is in intervals of 7 to 49 days, depending on the terms of the security. These securities are carried at cost, which approximates market value.

     For the three months ended March 31, 2006, significant transactions affecting Alon’s cash balance included, Alon’s January 19, 2006 payment of approximately $100,000 in satisfaction of its outstanding borrowings under the secured term loan agreement (see Note 9) and Alon’s sale of its Amdel and White Oil pipelines for a total consideration of approximately $68,000 (see Note 2).

7

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands except as noted)

(5) Derivatives and Hedging Activities

     (a) Fair Value of Financial Instruments

     The carrying amounts of Alon’s cash and cash equivalents, short-term investments, receivables, payables and accrued expenses approximate fair value due to the short-term maturities of these assets and liabilities. The reported amount of long-term debt approximates fair value. Derivative financial instruments are carried at fair value, which is based on quoted market prices.

     (b) Derivative Financial Instruments

     Alon 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. Alon does not enter into derivative instruments for any purpose other than cash flow hedging purposes. Accordingly, Alon does not speculate using derivative instruments. Alon 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. There is not a significant credit risk on Alon’s derivative instruments which are transacted through counterparties meeting established collateral and credit criteria.

     Alon occasionally uses crude oil and refined product commodity derivative contracts to reduce financial exposure related to price changes on anticipated transactions. Crude oil and refined product forward contracts are used to facilitate the supply of crude oil to the refinery and the sale of refined products while managing price exposure.

     At March 31, 2006, Alon held net forward contracts for purchases of 60 thousand barrels of refined products at an average price of $83.42 per barrel with a fair value of $5,054. At March 31, 2005, Alon held net forward contracts for sales of 50 thousand barrels of refined products at an average price of $65.56 per barrel with a fair value of $3,418. These contracts were not designated as hedges for accounting purposes. Accordingly, net unrealized gains of $47 and losses of $140 were recorded as an adjustment to net sales in the consolidated statement of operations for the three months ended March 31, 2006 and 2005, respectively.

     In accordance with SFAS No. 133, all commodity derivative contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section of Alon’s consolidated financial statements.

(6) Inventories

     Inventories for Alon 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.

8

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands except as noted)

     Carrying value of inventories consisted of the following:

	March 31,		December 31,
	2006		2005
Crude oil, refined products, and blendstocks	$	90,492	$	57,822
Materials and supplies		6,007		5,880
Store merchandise		12,714		12,977
Store fuel		3,486		2,502
Total inventories	$	112,699	$	79,181

Market values exceeded LIFO costs by $60,427 and $52,198 at March 31, 2006 and December 31, 2005, respectively.

(7) Property, Plant, and Equipment

     Property, plant, and equipment consisted of the following:

	March 31,			December 31,
	2006			2005
Refining facilities	$	175,412		$	171,346
Pipelines and terminals		9,126			27,237
Retail		63,823			63,486
Other		10,532			10,691
Property, plant, and equipment, gross		258,893			272,760
Less accumulated depreciation		(62,091	)		(61,350	)
Property, plant, and equipment, net	$	196,802		$	211,410

On March 1, 2006, Alon sold its Amdel and White Oil pipelines to an affiliate of Sunoco (See Note 2).

(8) Employee and Postretirement Benefits

     Alon has two defined benefit pension plans covering substantially all of its refining and market segment employees. Alon’s policy is to make contributions annually of not less than the minimum funding requirements under the Employee Retirement Income Security Act of 1974. Alon’s anticipated contributions to its pension plans during 2006 have not changed significantly from amounts previously disclosed in Alon’s consolidated financial statements for the year ended December 31, 2005. For the three months ended March 31, 2006 and 2005, the Company contributed $535 and $401, respectively, to its qualified pension plan.

     The components of net periodic benefit cost related to the Company’s benefit plans were as follows for the three months ended March 31, 2006 and 2005.

	For the Three Months Ended
	March 31,
	2006			2005
Components of net periodic benefit cost:
Service cost	$	478		$	382
Interest cost		608			535
Expected return on plan assets		(593	)		(414	)
Amortization of net loss		83			181
Net periodic benefit cost	$	576		$	684

9

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands except as noted)

(9) Long-Term Debt

     (a) Revolving Credit Facility

     On February 15, 2006 Alon entered into an amended revolving credit agreement with its lenders. The total commitment under the facility was increased from $141,600 to $240,000 and is available for, among other things, working capital, acquisitions and other general corporate purposes. The initial size of the facility is $160,000 with options to increase the size to $240,000 if crude oil prices increase above certain levels or Alon increases its throughput capacity.

     Under this amended facility, the term has been extended through January 2010; existing borrowing costs and letter of credit fees have been reduced; most covenants have been eased; there are substantially no limitations on incurrence of debt, distribution of dividends or investment activities absent existing or resulting default; and the retail subsidiaries have been excluded from the facility. The facility is secured by cash, accounts receivable, inventory and related assets. All fixed assets previously securing the facility have been released.

     No borrowings were outstanding under the revolving credit facility at March 31, 2006 and December 31, 2005. As of March 31, 2006 and December 31, 2005, there were $105,526 and $131,727, respectively, of outstanding letters of credit under the revolving credit facility.

     (b) Debt Repayment

     On January 19, 2006, Alon made a payment of approximately $103,900 in satisfaction of its outstanding borrowings under its secured term loan agreement, including applicable accrued interest and prepayment premiums, with available cash on hand. $100,000 represents a voluntary prepayment of the outstanding principal under the term loan agreement, approximately $3,000 represents a prepayment premium and $900 represents accrued and unpaid interest on the principal balance. The $3,000 prepayment premium and $3,894 of unamortized debt issuance costs are included as interest expense in Alon’s consolidated statement of operations for the first quarter of 2006.

(10) Stock Based Compensation

     Alon has two employee incentive compensation plans, (i) the 2005 Incentive Compensation Plan and (ii) the 2000 Incentive Stock Compensation Plan.

     (a) 2005 Incentive Compensation Plan

     The 2005 Incentive Compensation Plan was approved by the Board of Directors in November 2005, and is a component of Alon’s overall executive incentive compensation program. The Incentive Compensation Plan permits the granting of awards in the form of options to purchase common stock, stock appreciation rights, restricted shares of common stock, restricted common stock units, performance shares, performance units and senior executive plan bonuses to Alon’s directors, officers and key employees. Other than the restricted share grants discussed below, there have been no other awards granted under this program.

     In August 2005, Alon granted an award of 10,791 shares of restricted stock to certain directors, officers and key employees in connection with Alon’s initial public offering in July 2005. The participants were allowed to acquire shares at a discounted price of $12.00 per share with a grant date fair value of $16.00 per share. In November 2005, Alon granted an award of 65,172 shares of restricted stock to certain directors, officers and key employees with a grant date fair value of $20.42 per share. Non-employee directors are awarded an annual grant of Alon’s common stock valued at $25,000. In 2005, 2,774 shares of restricted stock were awarded to two of Alon’s non-employee directors with a stock grant date fair value of $18.03 per share. All restricted shares granted under the Incentive Compensation Plan vest over a period of three years, assuming continued service at vesting.

10

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands except as noted)

     Compensation expense for the restricted stock grants amounted to $76 for the three months ended March 31, 2006. There is no material difference between intrinsic value under Opinion 25 and fair value under SFAS No. 123R for pro forma disclosure purposes.

			Weighted-Average
Nonvested Shares	Shares		Grant-Date Fair Value
Nonvested at January 1, 2006		78,736	$	19.73
Granted		0		0
Vested		0		0
Forfeited		0		0
Nonvested at March 31, 2006		78,736	$	19.73

     As of March 31 2006, there was $1,035 of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 2.6 years.

     (b) 2000 Incentive Stock Compensation Plan

     On August 1, 2000, Alon USA Operating, Inc. (“Alon Operating”) and Alon Assets, Inc (“Alon Assets”), majority owned, fully consolidated subsidiaries of Alon, adopted an Incentive Stock Compensation Plan pursuant to which Alon’s board of directors may grant stock options to certain officers and executive management. The Incentive Stock Compensation 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 and there have been no additional options granted under this plan. All stock options have ten-year terms. The options are subject to accelerated vesting and become fully exercisable if Alon achieves certain financial performance and debt service criteria. Upon exercise, Alon 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). This plan was closed to new participants subsequent to August 1, 2000, the initial grant date. Total compensation expense recognized under this plan was $510 and $95 for the three months ended March 31, 2006 and 2005, respectively.

     The following table summarized the stock option activity for Alon Assets and Alon Operating for the three months ended March 31, 2006 and for the years ended December 31, 2005 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, 2004		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
Granted		—			—		—			—
Exercised		(1,212	)		100		(455	)		100
Outstanding at December 31, 2005		8,060			100		3,027			100
Granted		—			—		—			—
Exercised		—			—		—			—
Outstanding at March 31, 2006		8,060		$	100		3,027		$	100

     At March 31, 2006, the number of options exercisable was 1,212 for Alon Assets and 455 for Alon Operating.

11

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands except as noted)

(11) Stockholders Equity

     (a) Stock Split

     On July 6, 2005, the Company (i) increased its authorized common shares to 100,000,000 and (ii) effected a 33,600-for-1 stock split of its common shares, resulting in 35,001,120 common shares outstanding. The earnings per share information and all common share information have been retroactively restated for the 2005 periods presented to reflect this stock split.

     (b) Common Stock Dividends

     On March 21, 2006 Alon paid a regular quarterly cash dividend of $0.04 per share and a special cash dividend of $0.37 per share on Alon’s common stock, to stockholders of record at the close of business on March 1, 2006. In connection with Alon’s cash dividend payment to stockholders on March 21, 2006, the minority interest owners of Alon Assets and Alon Operating will receive an aggregate cash dividend of approximately $1,078.

(12) Earnings Per Share

     Basic earnings per share are calculated as net income divided by the average number of shares of common stock outstanding. Diluted earnings per share includes the dilutive effective of restricted shares using the treasury stock method.

	Three Months Ended
	March 31,
	2006		2005
Net income	$	54,164	$	22,436
Average number of shares of common stock outstanding		46,731		35,001
Effect of dilutive restricted shares		29		—
Average number of shares of common stock outstanding assuming dilution		46,760		35,001
Earnings per share — basic	$	1.16	$	.64
Earnings per share — diluted	$	1.16	$	.64

(13) Commitments and Contingencies

     (a) 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.

     (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 (i) to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites, (ii) to remediate or restore these sites, (iii) to compensate others for damage to

12

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands except as noted)

property and natural resources, and (iv) 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. In the future, the Company may 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 $4,479 ($1,750 current payable and $2,729 non-current liability) at March 31, 2006 and $4,736 ($1,750 current payable and $2,986 non-current liability) at December 31, 2005.

(14) Subsequent Events

     (a) Retail Convenience Stores Acquisition

     On March 28, 2006, Alon entered into an agreement with Good Time Stores, Inc. to acquire up to 55 Good Time Stores in El Paso, Texas for total consideration of approximately $30,000 in cash and $7,000 in assumed debt. Alon currently operates 49 stores in El Paso and expects to convert the acquired stores to the 7-Eleven and FINA brands and to supply motor fuels to the stores using its long-term rights to pipeline capacity connecting its Big Spring refinery directly to the El Paso market. The closing date of the acquisition is expected to occur in the second or third quarter of 2006, subject to a right of first refusal option in favor of the current fuel supplier, receipt of lender consents by Good Time Stores and other closing conditions.

     (b) Refinery Acquisitions

     Paramount Acquisition

     On May 1, 2006, Alon entered into an agreement to purchase Paramount Petroleum Corporation, excluding certain real estate assets. The acquisition includes Paramount’s 54,000 bpd refinery located in Paramount, California; its 12,000 bpd heavy crude refinery in Portland, Oregon; seven asphalt terminals located in Seattle, Washington, Elk Grove and Mojave, California, Reno, Nevada, Phoenix, Fredonia and Flagstaff, Arizona; and Paramount’s 50% interest in Wright Asphalt Products Company, which specializes in patented tire rubber and modified asphalt products. Total consideration for the acquisition consists of $307,000 in cash, subject to adjustment based on changes in specified balance sheet items between December 31, 2005 and the closing date, and the assumption of approximately $100,000 of debt, net of cash. The transaction is expected to close during the second or third quarter 2006, subject to regulatory approvals and other standard closing conditions.

     Edgington Acquisition

     On May 1, 2006, Alon entered into an agreement to purchase the assets of Edgington Oil Company, a heavy crude refining company located in Long Beach, California. The acquisition includes Edgington’s topping refinery with a nameplate capacity of approximately 40,000 bpd. Total consideration for the acquisition consists of $52,000 in cash plus an amount to be determined for the value of certain inventories at closing. The transaction is expected to close during the second quarter 2006, subject to regulatory approvals and other standard closing conditions.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     The following discussion of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements and notes thereto included in Alon’s Annual Report onForm 10-K for the year ended December 31, 2005. “Alon,” “the Company,” “we” and “our” refer to Alon USA Energy, Inc. and its subsidiaries.

FORWARD-LOOKING STATEMENTS

     Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements 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.

     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 crude oil 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 our annual report on Form 10-K for the year ended December 31, 2005, under the caption “Risk Factors.”

     Any one of these factors or a combination of these factors could materially affect our future results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. Our

14

forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.

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.

     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 barrels per day (“bpd”). 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 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 supply our branded and unbranded distributors in this region with refined products produced at our Big Spring refinery and distributed through a network of product pipelines and terminals which we own or access through leases or long-term throughput agreements. 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. As of March 31, 2006, we operated 167 convenience stores in West Texas and New Mexico. Our convenience stores typically offer merchandise, food and beverage products and motor fuels under the 7-Eleven and FINA brand names. We supply our stores with substantially all of their motor fuel needs with gasoline and diesel produced at our Big Spring refinery.

First Quarter 2006 Results and Second Quarter 2006 Developments

First Quarter 2006 Results

     The first quarter of 2006 continued to reflect the positive refinery fundamentals experienced in 2005. These positive fundamentals, including strong refining margins and favorable differentials between WTI and WTS crude oil, resulted in significantly enhanced results of operations reported for the three month period ended March 31, 2006 compared to the three month period ended March 31, 2005. We also benefited from the increase in refinery throughput in the three months ended March 31, 2006 as a result of the 8,000 bpd crude oil capacity expansion completed in the first quarter of 2005. See “— Factors Affecting Comparability” for additional information. Results of our operations are further described below and under “— Results of Operations” and “— Liquidity and Capital Resources”:

• Net sales increased $176.7 million to $584.7 million and operating income increased $51.7 million to $96.0 million for the first three months of 2006, compared to the first three months of 2005.

• Our average refinery operating margin increased $1.13 per barrel to $11.69 per barrel for the first three months of 2006, compared to the first three months of 2005.

• Our capital expenditures and turnaround spending for the three months ended March 31, 2006 totaled approximately $5.9 million, of which $1.3 million was spent on a chemical catalyst.

• Refinery throughput increased approximately 23,000 bpd to 70,529 bpd for the first three months of 2006, compared to 47,447 bpd for the first three months of 2005. In the first quarter of 2005, we completed a planned major turnaround and expanded the crude oil throughput capacity at the refinery.

     On January 19, 2006, we prepaid our $100 million term loan due January 14, 2009 with available cash on hand. This loan bore an interest rate of 10.6% per annum.

15

     On February 15, 2006, we entered into an amended revolving credit agreement which increased our borrowing capacity from $142 million to $160 million with an option to further increase our borrowing capacity to up to $240 million if we increase our throughput capacity or experience prolonged increased crude oil prices. Pursuant to this amendment, we extended the term of our revolving facility to January 2010, reduced our borrowing costs and letter of credit fees and obtained greater flexibility by significantly relaxing covenant restrictions.

     On March 1, 2006 we sold our Amdel and White Oil pipelines, which had been inactive since December 2002, to an affiliate of Sunoco Logistics Partners L.P., (“Sunoco”) for a total consideration of approximately $68 million. In conjunction with this transaction, we entered into a 10-year pipeline Throughput and Deficiency Agreement with Sunoco, with an option to extend the agreement by four additional thirty-month periods. The Throughput and Deficiency Agreement will allow us to maintain our physically integrated system by retaining crude oil transportation rights on the pipelines from the Gulf Coast. Pursuant to the Throughput and Deficiency Agreement, we have agreed to ship a minimum of 15,000 bpd on the pipelines during the term of the agreement

     On March 21, 2006 we paid our regular quarterly cash dividend of $0.04 per share and a special cash dividend of $0.37 per share of our common stock, to stockholders of record at the close of business on March 1, 2006. In connection with our cash dividend payment to stockholders on March 21, 2006, the minority interest owners of Alon Assets and Alon Operating will receive an aggregate cash dividend of approximately $1.1 million.

Second Quarter 2006 Developments

     Retail Convenience Stores Acquisition

     On March 28, 2006, we entered into an agreement with Good Time Stores, Inc. to acquire up to 55 Good Time Stores in El Paso, Texas for total consideration of approximately $30 million in cash and $7.0 million in assumed debt. We currently operate 49 stores in El Paso and expect to convert the acquired stores to the 7-Eleven and FINA brands and to supply motor fuels to the stores through our long-term pipeline capacity connecting our Big Spring refinery directly to the El Paso market. The closing date of the acquisition is expected to occur in the second or third quarter of 2006, subject to a right of first refusal option in favor of the current fuel supplier, receipt of lender consents by Good Time Stores and other closing conditions.

     Refinery Acquisitions

     Paramount Acquisition. On May 1, 2006, we entered into an agreement to purchase Paramount Petroleum Corporation, excluding certain real estate assets. The acquisition includes Paramount’s 54,000 bpd refinery located in Paramount, California, its 12,000 bpd heavy crude refinery in Portland, Oregon, seven asphalt terminals located in Seattle, Washington, Elk Grove and Mojave, California, Reno, Nevada, Phoenix, Fredonia and Flagstaff, Arizona, and Paramount’s 50% interest in Wright Asphalt Products Company, which specializes in patented tire rubber and modified asphalt products. Total consideration for the acquisition consists of $307.0 million in cash, subject to adjustment based on changes in specified balance sheet items between December 31, 2005 and the closing date, and the assumption of approximately $100.0 million of debt, net of cash. The transaction is expected to close during the second or third quarter 2006, subject to regulatory approvals and other standard closing conditions.

     Edgington Acquisition.On May 1, 2006, we entered into an agreement to purchase the assets of Edgington Oil Company, a heavy crude refining company located in Long Beach, California. The acquisition includes Edgington’s topping refinery with a nameplate capacity of approximately 40,000 bpd. Total consideration for the acquisition consists of $52.0 million in cash plus an amount to be determined for the value of certain inventories at closing. The transaction is expected to close during the second quarter 2006, subject to regulatory approvals and other standard closing conditions.

Major Influences on Results of Operations

Refining and Marketing

     Refining and Marketing Margins. 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

16

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.

     3/2/1 Crack Spread.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 our per barrel 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.

     Sweet/Sour Spread.Our refinery is capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate and sweet crude oils. We measure the cost advantage of refining sour crude oil by calculating the difference between the values 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 favorably influence our refinery operating margin.

     Operating Costs.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 $6.55 and $10.63 per MMBTU in the first three months of 2006. Over the first three months of 2005, natural gas prices ranged between $5.79 and $7.65 per MMBTU. Typically, electricity prices fluctuate with natural gas prices.

     Seasonality.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 and Reliability.Safety, reliability and the environmental performance of our refinery operations are critical to our financial performance. 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.

     Inventory.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.

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 cents per gallon, or cpg, basis. Our motor fuel margins are driven by local supply, demand and competitor pricing. 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.

17

Factors Affecting Comparability

     Our financial condition and operating results over the three-month period ended March 31, 2006 have been influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.

     Increased Crude Oil Throughput Capacity. 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. Our expanded crude oil processing capability will 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 capacity will result in increased production and higher sales volumes, which should affect the comparability of our future operating results to periods prior to the expansion. Our average refinery production was 69,603 bpd for the first quarter of 2006, reflecting effects of the crude oil throughput expansion completed in the first quarter of 2005. Average refinery production was 47,060 bpd for the first quarter of 2005.

     Amdel and White Oil Pipeline Transaction. The sale of assets in connection with the Amdel and White Oil pipeline transaction on March 1, 2006, reduced property, plant and equipment, net, by approximately $15.2 million.

     In connection with the Amdel transaction we recognized pre-tax gain of $52.5 million in the three months ended March 31, 2006. Gain on disposition of assets for the three months ended March 31, 2005, included the $27.7 million initial pre-tax gain and one month’s recognition of deferred gain recorded in connection with the HEP transaction.

Results of Operations

     Net Sales. Net sales consist 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, 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 includes 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, 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.

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ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED

     Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for Alon and our two operating segments for the three months ended March 31, 2006 and 2005. The summary financial data for our two operating segments does not include certain SG&A expenses and depreciation and amortization related to our corporate headquarters. The following data should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this Form 10-Q.

	For the Three Months Ended
	March 31,
	2006			2005
	(dollars in thousands,
	except per share data)
STATEMENT OF OPERATIONS DATA:
Net sales	$	584,701		$	407,974
Operating costs and expenses:
Cost of sales		497,827			351,554
Direct operating expenses		23,271			18,336
Selling, general and administrative expenses (1)		17,453			16,665
Depreciation and amortization (2)		5,523			4,834
Total operating costs and expenses		544,074			391,389
Gain on disposition of assets (3)		55,386			27,693
Operating income		96,013			44,278
Interest expense (4)		(9,047	)		(5,007	)
Equity earnings in HEP		577			135
Other income, net		1,927			250
Income before income tax expense and minority interest in income of subsidiaries		89,470			39,656
Income tax expense		32,526			15,655
Income before minority interest in income of subsidiaries		56,944			24,001
Minority interest in income of subsidiaries		2,780			1,565
Net income	$	54,164		$	22,436
Earnings per share, basic and diluted (5)	$	1.16		$	.64
Weighted average shares outstanding (5)		46,731,120			35,001,120
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	(9,723	)	$	(16,437	)
Investing activities		129,387			93,803
Financing activities		(119,660	)		(31,734	)
OTHER DATA:
Adjusted EBITDA (6)	$	48,654		$	21,804
Capital expenditures (7)		4,638			11,098
Capital expenditures for turnarounds and catalysts		1,303			10,382
	March 31,			December 31,
	2006			2005
BALANCE SHEET DATA (end of period):
Cash, cash equivalents and short-term investments	$	254,824		$	322,140
Working capital		251,141			275,996
Total assets		712,577			758,780
Total debt		31,922			132,390
Stockholders’ equity		314,604			279,493

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(1)	Includes corporate headquarters selling, general and administrative expenses of $127 and $128 for the three months ended March 31, 2006 and 2005, respectively.
(2)	Includes corporate depreciation and amortization of $524 and $471 for the three months ended March 31, 2006 and 2005, respectively.
(3)	Gain on disposition of assets reported in the three months ended March 31, 2006, reflects the $52.5 million pre-tax gain on disposition of assets, recorded in connection with the Amdel transaction and the recognition of $2.9 million deferred gain recorded in connection with the HEP transaction. Gain on disposition of assets reported in the three months ended March 31, 2005, reflects the $26.7 million initial pre-tax gain and one month’s recognition of deferred gain recorded in connection with the HEP transaction.
(4)	Includes $3.0 million prepayment premium and $3.9 million of unamortized debt issuance costs written off as a result of the prepayment of the $100 million term loan in January 2006.
(5)	Weighted average common shares outstanding and earnings per common share amounts for the three months ended March 31, 2005 have been restated to reflect the effect of the 33,600-for-one split of our common stock which was effected on July 6, 2005.
(6)	EBITDA represents earnings before minority interest, income tax expense, interest expense, depreciation and amortization. Adjusted EBITDA represents EBITDA, exclusive of gain on disposition of assets. EBITDA and Adjusted EBITDA are not recognized measurements under GAAP; however, the amounts included in EBITDA and Adjusted EBITDA are derived from amounts included in our consolidated financial statements. 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, interest expense, income taxes, gain on disposition 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. EBITDA is the basis for calculating selected financial ratios as required in the debt covenants in our revolving credit agreement. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Cash, Cash Equivalents and Short-Term Investment 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 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, EBITDA and 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 EBITDA and Adjusted EBITDA only supplementally.

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     The following table reconciles net income to Adjusted EBITDA for the three months ended March 31, 2006 and 2005, respectively:

	For the Three Months Ended
	March 31,
	2006			2005
	(dollars in thousands)
Net income	$	54,164		$	22,436
Minority interest		2,780			1,565
Income tax expense		32,526			15,655
Interest expense		9,047			5,007
Depreciation and amortization		5,523			4,834
EBITDA		104,040			49,497
Gain on disposition of assets		(55,386	)		(27,693	)
Adjusted EBITDA	$	48,654		$	21,804

(7) Includes corporate capital expenditures of $19 and $144 for the three months ended March 31, 2006 and 2005 respectively, which are not included in the capital expenditures of our other two operating segments.

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REFINING AND MARKETING SEGMENT

	For the Three Months Ended
	March 31,
	2006			2005
	(dollars in thousands except per
	barrel data and pricing statistics)
STATEMENT OF OPERATIONS DATA:
Net sales (1) (2)	$	543,476		$	366,934
Operating costs and expenses:
Cost of sales (2)		470,250			323,514
Direct operating expenses		23,271			18,336
Selling, general and administrative expenses		4,876			4,678
Depreciation and amortization		3,845			3,311
Total operating costs and expenses		502,242			349,839
Gain on disposition of assets (3)		55,386			27,693
Operating income	$	96,620		$	44,788
KEY OPERATING STATISTICS:
Total sales volume (bpd)		85,370			72,253
Non-integrated marketing sales volume (bpd) (4)		19,347			20,061
Non-integrated marketing margin (per barrel sales volume) (4)	$	(.56	)	$	(.93	)
Per barrel of throughput:
Refinery operating margin (5)	$	11.69		$	10.56
Refinery direct operating expenses		3.67			4.29
Capital expenditures		4,396			9,945
Capital expenditures for turnaround and chemical catalyst		1,303			10,382
PRICING STATISTICS:
WTI crude oil (per barrel)	$	63.34		$	49.70
WTS crude oil (per barrel)		56.77			44.62
Crack spreads (3/2/1) (per barrel):
Gulf Coast	$	9.70		$	6.62
Group III		9.66			7.94
Crude differentials (per barrel):
WTI less WTS	$	6.57		$	5.08
Product price (per gallon):
Gulf Coast unleaded gasoline		170.2	¢		132.2	¢
Gulf Coast low-sulfur diesel		181.3			137.9
Group III unleaded gasoline		170.7			135.7
Group III low-sulfur diesel		180.1			140.4
Natural gas (per MMBTU)	$	7.84		$	6.50

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	For the Three Months Ended
	March 31,
	2006					2005
THROUGHPUT AND YIELD DATA:	Bpd		%			Bpd		%
Refinery crude throughput:
Sour crude		62,720		88.9			41,096		86.6
Sweet crude		3,191		4.5			2,829		6.0
Blendstocks		4,618		6.6			3,522		7.4
Total refinery throughput (6)		70,529		100.0			47,447		100.0
Refinery production:
Gasoline		32,846		47.2			21,562		45.8
Diesel/jet		23,701		34.1			15,232		32.4
Asphalt		6,444		9.3			4,297		9.1
Petrochemicals		4,266		6.0			3,617		7.7
Other		2,346		3.4			2,352		5.0
Total refinery production (7)		69,603		100.0			47,060		100.0
Refinery utilization (8)				94.2	%				88.9	%

(1)	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.
(2)	Our buy/sell arrangements involve linked purchases and sales related to refined product contracts entered into to address location or grade requirements. As of January 1, 2006, such buy/sell transactions are included on a net basis in sales in the consolidated statement of operations and profits are recognized when the exchanged product is sold. Prior to January 1, 2006, the results of buy/sell transactions were recorded separately in sales and cost of sales in the consolidated statement of operations.
(3)	Gain on disposition of assets reported in the three months ended March 31, 2006, reflects the $52.5 million pre-tax gain on disposition of assets, recorded in connection with the Amdel transaction and the recognition of $2.9 million deferred gain recorded in connection with the HEP transaction. Gain on disposition of assets reported in the three months ended March 31, 2005, reflects the $26.7 million initial pre-tax gain and one month’s recognition of deferred gain recorded in connection with the HEP transaction.
(4)	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.
(5)	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.
(6)	Total refinery throughput represents the total of crude oil and blendstock inputs in the refinery production process.
(7)	Total refinery production represents the barrels per day of various finished products produced from processing crude and other refinery feedstocks through the crude units and other conversion units at the refinery.
(8)	Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.

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RETAIL SEGMENT

	For the Three Months Ended
	March 31,
	2006			2005
	(dollars in thousands)
STATEMENT OF OPERATIONS DATA:
Net sales	$	72,615		$	73,896
Operating costs and expenses:
Cost of sales (1)		58,967			60,896
Selling, general and administrative expenses		12,450			11,859
Depreciation and amortization		1,154			1,052
Total operating costs and expenses		72,571			73,807
Operating income	$	44		$	89
KEY OPERATING STATISTICS:
Number of stores (end of period)		167			167
Fuel sales (thousands of gallons)		17,133			23,387
Fuel sales (thousands of gallons per site per month)		34			48
Fuel margin (cents per gallon) (2)		17.2	¢		12.9	¢
Fuel sales price (dollars per gallon) (3)	$	2.33		$	1.88
Merchandise sales	$	32,414		$	29,994
Merchandise sales (per site per month)		65			60
Merchandise margin (4)		33.2	%		33.3	%
Capital expenditures		223			1,009

(1)	Cost of sales includes intersegment purchases of motor fuels from our refining and marketing segment at prices which approximate market prices. These intersegment purchases are eliminated through consolidation of our financial statements.
(2)	Fuel margin represents the difference between motor fuel revenues and the net cost of purchased motor 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.
(3)	Fuel sales price per gallon represents the average sales price for motor fuels sold through our retail segment.
(4)	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.

Three Months Ended March 31, 2006 Compared to the Three Months Ended March 31, 2005

Net Sales

     Consolidated. Net sales for the three months ended March 31, 2006 were $584.7 million, compared to $408.0 million for the three months ended March 31, 2005, an increase of $176.7 million or 43.3%. This increase was primarily due to higher than average refined product prices over the comparable period in 2005 as well as the refinery operating at less than full capacity due to the major turnaround and 8,000 bpd crude oil capacity expansion in the first quarter of 2005.

     Refining and Marketing Segment. Net sales for our refining and marketing segment were $543.5 million for the three months ended March 31, 2006, compared to $366.9 million for the three months ended March 31, 2005, an increase of $176.6 million or 48.1%. This increase was primarily due to significantly higher refined product prices. The increase in refined product prices that we experienced was similar to the price increases experienced in the Gulf Coast markets. The average price of Gulf Coast gasoline for the first quarter of 2006 increased 38.0 cents per gallon

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(“cpg”) to 170.2 cpg, compared to 132.2 cpg in the first quarter of 2005, an increase of 28.7%. The average Gulf Coast diesel price increased by approximately 43.4 cpg to 181.3 cpg in the first quarter of 2006 as compared to 137.9 cpg in the first quarter of 2005, an increase of 31.5%. Also contributing to the increase in sales was an increase in sales volume. Our sales volume increased by 13,117 bpd, or 18.2%, to 85,370 bpd for the three months ended March 31, 2006 compared to 72,253 bpd for the three months ended March 31, 2005. This increase in sales volume resulted primarily from the 8,000 bpd throughput capacity expansion completed in the first quarter of 2005, which resulted in average refinery production of 69,603 bpd for the first quarter of 2006 compared to an average refinery production of 47,060 bpd for the first quarter of 2005.

     Retail Segment. Net sales for our retail segment were $72.6 million for the three months ended March 31, 2006 compared to $73.9 million for the three months ended March 31, 2005, a decrease of $1.3 million or 1.8%. This decrease was primarily attributable to lower fuel sales volumes as a result of a higher fuel prices and competition from our high volume competitors. Fuel sales volume decreased by 6.3 million gallons, or 26.9% to 17.1 million gallons for the three months ended March 31, 2006 compared to fuel sales volumes of 23.4 million gallons for the three months ended March 31, 2005. Partially offsetting this decrease were the increases in fuel prices and in-store merchandise sales in the first quarter of 2006, compared to the first quarter of 2005. Average retail fuel prices were $2.33 per gallon for the first quarter of 2006, compared to average retail fuel prices of $1.88 per gallon for the first quarter of 2005. Merchandise sales increased by $2.4 million, or 8.0% to $32.4 million for the first quarter of 2006, compared to $30.0 million for the first quarter of 2005.

Cost of Sales

     Consolidated. Cost of sales was $497.8 million for the three months ended March 31, 2006, compared to $351.6 million for the three months ended March 31, 2005, an increase of $146.2 million or 41.6%. This increase resulted primarily from increased throughput capacity related to the 8,000 bpd capacity expansion completed in the first quarter of 2005 and from higher crude oil prices.

     Refining and Marketing Segment. Cost of sales for our refining and marketing segment was $470.3 million for the three months ended March 31, 2006, compared to $323.5 million for the three months ended March 31, 2005, an increase of $146.8 million or 45.4%. This increase was primarily due to the increase in refinery production in the first quarter of 2006 compared to first quarter of 2005 and due to higher crude oil prices. Average refinery throughput increased to 70,529 bpd, or 48.7% for the first quarter of 2006, compared to an average refinery throughput of 47,447 bpd for the first quarter of 2005. The average price per barrel of WTS for the first quarter of 2006 increased $12.15 per barrel to $56.77 per barrel, compared to $44.62 per barrel for the first quarter of 2005, an increase of 27.2%.

     Retail Segment. Cost of sales for our retail segment was $59.0 million for the three months ended March 31, 2006, compared to $60.9 million for the three months ended March 31, 2005, a decrease of $1.9 million or 3.1%. This decrease was primarily to higher fuel prices and competition from our high volume competitors, partially offset by higher fuel prices and costs of goods for merchandise sold.

Direct Operating Expenses

     Direct operating expenses were $23.3 million for the three months ended March 31, 2006, compared to $18.3 million for the three months ended March 31, 2005, an increase of $5.0 million or 27.3%. This increase was primarily attributable to an increase in natural gas and electricity prices in the first quarter of 2006 compared to the first quarter of 2005. The average price of natural gas was $7.84 per MMBTU in the first quarter of 2006, compared to $6.50 per MMBTU for the first quarter of 2005. In addition, overall energy usage increased as a result of the 8,000 bpd crude oil throughput capacity expansion at our refinery in the first quarter of 2005. Efficiencies gained as a result of the first quarter 2005 turnaround partially offset the effects of increased prices and energy usage.

Selling, General and Administrative Expenses

     Consolidated. SG&A expenses for the three months ended March 31, 2006 were $17.5 million, compared to $16.7 million for the three months ended March 31, 2005, an increase of $.8 million or 4.8%.

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     Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the three months ended March 31, 2006 were $4.9 million, compared to $4.7 million for the three-month period ended March 31, 2005, an increase of $0.2 million or 4.3%. This increase resulted from higher corporate costs associated with becoming a public company in the third quarter 2005, partially offset by lower selling and advertising expenses.

     Retail Segment. SG&A expenses for our retail segment for the three months ended March 31, 2006 were $12.5 million, compared to $11.9 million for the three months ended March 31, 2005, an increase of $.6 million or 5.0%. This increase was primarily attributable to higher energy costs as a result of the increase in electricity prices, which were partially offset by decreased healthcare and workers compensation costs.

Depreciation and Amortization

     Depreciation and amortization for the three months ended March 31, 2006 was $5.5 million, compared to $4.8 million for the three months ended March 31, 2005. This increase was primarily attributable to the completion of the various capital projects in late 2005 and the first three months of 2006. Partially offsetting this increase was the reduction in depreciation due to the disposition of assets in the HEP and Amdel transactions.

Operating Income

     Consolidated. Operating income for the three months ended March 31, 2006 was $96.0 million. Excluding $52.5 million of net gain on disposition of assets resulting from the Amdel transaction and $2.9 million amortization of deferred gain relating to the 2005 HEP transaction, operating income for the three months ended March 31, 2006 was $40.6 million, compared to $16.6 million operating income (excluding the $27.7 million for gain resulting from the HEP transaction) for the three months ended March 31, 2005, an increase of $24.0 million or 144.6%. 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 for the three months ended March 31, 2006 was $96.6 million compared to operating income of $44.8 million for the three months ended March 31, 2005. Excluding $52.5 million of net gain on disposition of assets resulting from the Amdel transaction and $2.9 million amortization of deferred gain relating to the 2005 HEP transaction, operating income for the three months ended March 31, 2006 was $41.2 million, compared to $17.1 million (excluding the $27.7 million for gain resulting from the HEP transaction) for the three months ended March 31, 2005, an increase of $24.1 million or 140.9%. This increase was primarily attributable to the increase in our refinery operating margins and increased sales volumes as a result of the 8,000 bpd crude oil throughput capacity expansion completed in the first quarter of 2005. Our refinery operating margin for the first quarter of 2006 increased $1.13 per barrel to $11.69 per barrel, compared to $10.56 per barrel in the first quarter of 2005. This increase was attributable, in part, to higher differentials between refined product prices and crude oil prices resulting from continued concern over adequate refinery capacity to meet demand and supply. Also contributing to the higher refinery margins were the supply constraints associated with the logistics of the introduction of new reformulated fuels in the first quarter of 2006. The Gulf Coast 3/2/1 crack spread increased by 46.5% to an average of $9.70 per barrel in the first quarter of 2006 compared to an average of $6.62 per barrel in the first quarter of 2005. In addition, our refinery operating margins benefited from a widening of the sweet/sour crude oil spread. The average sweet/sour spread increased $1.49 per barrel to $6.57 per barrel for the first quarter of 2006 compared to the average sweet/sour spread of $5.08 per barrel for the first quarter of 2005, an increase of 29.3%.

     Retail Segment. Operating income for our retail segment was $0.04 million for the three months ended March 31, 2006, compared to $0.09 million, a decrease of $0.05 million. This decrease was primarily attributable to higher SG&A and depreciation expenses, partially offset by higher fuel margins and increased merchandise sales.

Interest Expense

     Interest expense was $9.0 million for the three months ended March 31, 2006, compared to $5.0 million for the three months ended March 31, 2005, an increase of $4.0 million or 80.0%. This increase was primarily attributable to a $3.0 million prepayment premium and the write-off of $3.9 million of unamortized debt issuance costs resulting from the prepayment of our $100 million term loan in January 2006. Partially offsetting this increase was the reduction of the regular interest expense associated with this term loan.

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Income Tax Expense

     Income tax expense was $32.5 million for the three months ended March 31, 2006, compared to $15.7 million for the three months ended March 31, 2005, an increase of $16.8 million. This increase resulted from our higher taxable income in the first quarter of 2006 compared to the first quarter of 2005. Our effective tax rate was 36.4% for the first quarter of 2006, compared to an effective tax rate of 39.5% for the first quarter of 2005. This decrease in the effective tax rate is primarily related to expected tax credits associated with the American Jobs Creation Act of 2004.

Minority Interest

     Minority interest represents the proportional share of net income related to non-voting common stock owned by minority stockholders in two of our subsidiaries, Alon Assets and Alon Operating. Minority interest was $2.8 million for the three months ended March 31, 2006, compared to $1.6 million for the three months ended March 31, 2005, an increase of $1.2 million. This increase was attributable to our increased after-tax income in the first quarter of 2006 as a result of the factors discussed above.

Net Income

     Net income was $54.2 million for the three months ended March 31, 2006, compared to $22.4 million for the three months ended March 31, 2004, an increase of $31.8 million or 142.0%. This increase was attributable to the factors discussed above.

Liquidity and Capital Resources

     Our primary sources of liquidity are cash on hand, cash generated from our operating activities and borrowings under our revolving credit facility. In addition, our liquidity was enhanced during the first quarter of 2006 by the receipt of $68.0 million net cash proceeds received from the sale of our inactive Amdel and White Oil pipelines. We believe that our cash on hand, cash flows from operations, borrowings under our revolving credit facility, 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 or acquisitions that we complete.

     Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or equity securities, or other possible capital markets transactions, the proceeds of which could be used to refinance current indebtedness or for other corporate purposes. Pursuant to our growth strategy, we will also consider from time to time additional acquisitions of, and investments in, assets or businesses that complement our existing assets and businesses. Acquisition transactions, if any, are expected to be financed through cash on hand and from operations, bank borrowings, the issuance of debt or equity securities or a combination of two or more of those sources.

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Cash Flow

     The following table sets forth our consolidated cash flows for the three months ended March 31, 2006 and 2005:

	For the Three Months Ended
	March 31,
	2006			2005
	(dollars in thousands)
Non cash provided by (used in):
Operating activities	$	(9,723	)	$	(16,437	)
Investing activities (1)		129,387			93,803
Financing activities		(119,660	)		(31,734	)
Net increase in cash and cash equivalents	$	4		$	45,632

(1) 2006 cash provided by investing activities include $67.3 million sales of short-term investments and $68.0 million net proceeds received in the Amdel transaction. 2005 cash provided by investing activities includes $118.0 million net proceeds received in the HEP transaction, partially offset by capital expenditures and turnaround costs.

Cash Flows Used In Operating Activities

     Net cash used in operating activities during the three months ended March 31, 2006 was $9.7 million, compared to net cash used in operating activities of $16.4 million during the three months ended March 31, 2005. The $6.7 million net decrease in cash used in operating activities was primarily due to increased net income (excluding after-tax gains on dispositions of assets), resulting from higher refinery operating margins and increased refinery production as a result of the expansion of the Big Spring refinery’s crude oil throughput capacity and the major turnaround in the first quarter of 2005. Working capital, net of cash and short-term investments, was $(3.7) million at March 31, 2006 compared to working capital, net of cash and short-term investments of $7.9 million at March 31, 2005, a decrease of $11.6 million. This decrease was primarily attributable to the net increase in accrued liabilities as a result of higher accrued income taxes associated with increased income, partially offset by a planned increase in refined product and crude oil inventories built in anticipation of the planned refinery downtime to complete the low-sulfur diesel conversion project begun in April 2006. This inventory increase represents a temporary use of cash which will be recovered as the inventories are drawn to normal levels in May and June of 2006.

     Net cash used in operating activities during the three months ended March 31, 2005 was $16.4 million. Cash flow used in operating activities during the three months ended March 31, 2005 was primarily attributable to the temporary build of refined products and crude oil inventories in preparation for the major turnaround and refinery throughput expansion completed in the first quarter of 2005. Working capital, net of cash, was $7.9 million at March 31, 2005. The increased use of working capital due to the temporary increase in inventory levels was partially offset by the net increase in trade payables as a result of higher crude prices in the first quarter of 2005.

Cash Flows Provided By Investing Activities

     Net cash provided by investing activities increased to $129.4 million during the three months ended March 31, 2006 from $93.8 million provided by investing activities during the three months ended March 31, 2005. This increase was primarily attributable to the receipt of $68.0 million in net proceeds received in the Amdel transaction and the proceeds from the sale of $67.3 million of short-term investments. Capital expenditures in the first quarter of 2006 totaled $5.9 million and included $2.7 million for regulatory and compliance projects, $1.3 million for chemical catalyst and $1.9 million for various sustaining and capital improvement projects.

     Net cash provided by investing activities was $93.8 million during the three months ended March 31, 2005. This cash provided by investing activities was attributable to the receipt of $118.0 of net cash proceeds in connection with the HEP transaction, partially offset by capital, turnaround and chemical catalyst expenditures. Capital expenditures for the first quarter of 2005 totaled $21.5 million and included $5.6 million for regulatory and

28

compliance projects, $0.8 million for the completion of our throughput capacity expansion project, $10.4 million for turnaround and chemical catalyst costs and $4.7 million for various sustaining and capital improvement projects.

Cash Flows Used In Financing Activities

     Net cash used in financing activities was $119.7 million during the three months ended March 31, 2006, compared to net cash used in financing activities of $31.7 million during the three months ended March 31, 2005. Cash used in financing activities in the first quarter of 2006 included the prepayment of our $100.0 million term loan and $19.2 million of dividends paid to our stockholders.

     Net cash used in financing activities was $31.7 million for the three months ended March 31, 2005. Cash used in financing activities in the first quarter of 2005 included $30.2 million net debt repayments and the payment of $1.5 million of dividends to our minority interest stockholders.

Cash Position and Indebtedness

     We consider all highly liquid instruments with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value and are invested in conservative, highly rated instruments issued by financial institutions or government entities with strong credit standings. Short-term investments primarily consist of highly-rated auction rate securities, or ARS. Although ARS may have long-term stated maturities, generally 10 to 30 years, we have designated these securities as available-for-sale and have classified them as current because we view them as available to support our current operations. ARS may be liquidated at par on the rate reset date, which is in intervals of seven to 49 days, depending on the terms of the security. These securities are carried at cost, which approximates market value. As of March 31, 2006, our total cash and cash equivalents were $136.8 million, our short-term investments were $118.0 million and we had total debt of approximately $31.9 million. On January 19, 2006, we used cash of approximately $103.9 million to repay our term loan, including a $3.0 million prepayment premium and $0.9 million of accrued interest.

     Summary of Indebtedness. The following table sets forth the principal amounts outstanding under our bank credit facilities, retail mortgages and equipment loans at March 31, 2006:

	As of March 31, 2006
	(dollars in thousands)
Debt, including current portion
Bank credit facilities:
Revolving credit facility	$	—
Retail mortgages and equipment loans		31,922
Total debt	$	31,922

     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 and restated on February 15, 2006. The Israel Discount Bank of New York, or Israel Discount Bank, acts as administrative agent, co-arranger, collateral agent and lender and Bank Leumi act as co-arranger and lender under the revolving credit facility. The initial size of the revolving credit facility is $160.0 million with options to increase the size of the facility to $240.0 million if crude oil prices increase above certain levels or we increase our throughput capacity.

     Borrowing availability under the revolving credit facility is limited at any time to the lower of the total current size of the revolving credit facility at that time, which is initially $160.0 million, or the amount of the borrowing base under the revolving credit agreement. As of March 31, 2006, the borrowing base under the revolving credit facility was $295.0 million. The entire revolving credit facility is available in the form of letters of credit and revolving loans. The borrowings under the revolving credit facility bear interest at the Eurodollar rate plus 1.50% per annum. The revolving credit facility is jointly and severally guaranteed by all of our subsidiaries except for our retail subsidiaries. The revolving credit facility is secured by cash, accounts receivable, inventory and related assets. All fixed assets previously securing the facility were released in conjunction with the amendment of the facility on February 15, 2006.

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     No borrowings were outstanding under the revolving credit facility at March 31, 2006 and 2005. As of March 31, 2006 and 2005, there were $105,526 and $108,607, respectively, of outstanding letters of credit under the revolving credit facility.

     Our revolving credit facility contains restrictive covenants, such as restrictions on change of control, 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 and making certain dividend, debt and other restricted payments. However, these covenants do not restrict our activities so long as we maintain the financial covenants described below, on a pro-forma basis after giving effect to these activities. Our revolving credit facility also contains covenants that restrict us from compromising or adjusting receivables, engaging in certain transactions with affiliates and amending or waiving certain material agreements. The revolving credit facility contains financial covenants requiring Alon USA to maintain:

• a minimum consolidated tangible net worth equal to the sum of $106.0 million plus an amount determined on a cumulative basis equal to the sum of 50% of any positive net income for each fiscal year after December 31, 2004 (as of March 31, 2006, the minimum consolidated tangible net worth was $185.0 million and our actual consolidated tangible net worth was $231.0 million);

• 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 for the last four fiscal quarters of no greater than 4.0 to 1.0 (the ratio as of March 31, 2006 was (0.6) to 1.00);

• a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0 (the ratio as of March 31, 2006 was 1.8 to 1.0); and

• a ratio of total consolidated EBITDA to consolidated interest expense, in each case as of the end of any period of four fiscal quarters, to be not less than 2.0 to 1.0 (the ratio as of March 31, 2006 was 11.7 to 1.0).

     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. As of March 31, 2006, we were in compliance with all of these covenants.

Capital Spending

     Each year our board of directors approves capital projects, including regulatory and planned turnaround projects that our management is authorized to undertake in our annual capital budget. Additionally, at times when conditions warrant or as new opportunities arise, other projects or the expansion of existing projects may be approved. Our total capital expenditure and turnaround/chemical catalyst budget for 2006 is $38.2 million, of which $2.7 million related to regulatory and compliance projects, $1.3 million related to turnaround and chemical catalysts, and $1.9 for various improvement and sustaining projects, had been spent as of March 31, 2006.

     Clean Air Capital Expenditures. We expect to spend approximately $25.3 million over the next five years to comply with the Federal Clean Air Act regulations requiring a reduction in sulfur content in gasoline and diesel fuels, including $9.9 million for low-sulfur diesel compliance in 2006, the majority of which is expected to be expended in the second quarter of 2006.

     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 and chemical catalyst replacement in the first week of March 2005, at a cost of approximately $10.4 million. We expect to spend approximately $4.4 million for chemical catalyst replacement in 2006, including the $1.3 million chemical catalyst expenditures as of March 31, 2006 and the $1.9 million catalyst to be replaced in conjunction with the low-sulfur diesel compliance project scheduled for the second quarter 2006.

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Contractual Obligations and Commercial Commitments

     Information regarding our known contractual obligations of the types described below as of March 31, 2006 is set forth in the following table.

	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 (1)	$	2,024	$	6,535	$	5,023	$	18,340	$	31,922
Operating lease obligations		9,429		33,061		9,908		6,278		58,676
HEP Pipelines and Terminals Agreement (2)		14,716		58,863		39,242		160,238		273,059
Sunoco Throughput & Deficiency Agreement (3)		3,290		17,363		18,427		22,881		61,961
Other commitments (4)		2,120		8,483		5,654		28,981		45,238
Total obligations	$	31,579	$	124,305	$	78,254	$	236,718	$	470,856

(1)	On January 19, 2006, we prepaid our $100 million term loan due January 14, 2009 with available cash on hand.
(2)	Balances represent the minimum committed volume multiplied by the tariff rates pursuant to the terms of the Pipelines and Terminals agreement with HEP.
(3)	Balances represent the minimum committed volume multiplied by the tariff rates pursuant to the terms of the Throughput and Deficiency agreement with Sunoco.
(4)	Other commitments include refinery maintenance services agreement costs.

     As of March 31, 2006, 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, other than those included in the table above.

     Our “other non-current liabilities” are described in our consolidated financial statements included elsewhere in this Form 10-Q. For most of these liabilities, timing of the payment of such liabilities is not fixed and therefore cannot be determined as of March 31, 2006. However, certain expected payments related to our anticipated pension contributions in 2006 and other post-retirement benefits obligations are discussed in note 8 of our consolidated financial statements included elsewhere in this Form 10-Q.

Off-Balance Sheet Arrangements

     We have no off-balance sheet arrangements.

Critical Accounting Policies

     We prepare our consolidated financial statements in conformity with 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 described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies” included in our annual report on Form 10-K for the year ended December 31, 2005. Certain critical accounting policies that materially effect the amounts recorded in our consolidated financial statements are the use of LIFO method for valuing certain inventories and the deferral and subsequent amortization of costs associated with major turnarounds and chemical catalysts replacements. No significant changes to these accounting policies have occurred subsequent to December 31, 2005.

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New Accounting Standards and Disclosures

     Effective January 1, 2006, Alon adopted Statement of Accounting Standards No. 123R,Share-Based Payment(SFAS No. 123R), which requires use of the fair-value based method and expensing of stock options and other share-based compensation payments to employees, net of estimated forfeitures, over the requisite service period and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing proforma disclosure only. As a private company, Alon used the minimum value method of measuring equity share options for proforma disclosure purposes under SFAS No. 123. Accordingly, Alon applied SFAS No. 123R prospectively to new awards and to awards modified, repurchased or cancelled after January 1, 2006. Alon applied the modified prospective transition method to any unvested post-IPO stock-based awards. The adoption of SFAS No. 123R did not have a significant effect on Alon’s financial position or results of operations.

     Alon previously accounted 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 (Opinion 25). Accordingly, compensation cost for stock options was measured as the excess of the estimated fair value of the common stock over the exercise price and was recognized over the scheduled vesting period on an accelerated basis. Stock compensation expense is presented as selling, general and administrative expenses in the accompanying statements of operations. All pre-IPO stock-based awards will continue to be accounted for under Opinion 25.

     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. The adoption of Statement No. 151 did not have a material effect on Alon’s financial position or results of operations.

     In December 2004, the FASB issued FASB Staff Position (“FSP”) FAS 109-1,Application of FASB Statement No. 109, Accounting for Income Taxes, for the Tax Deduction Provided to U.S. Based Manufacturers by the American Jobs Creation Act of 2004(“Jobs Creation Act”) which requires a company that qualifies for the deduction for domestic production activities under the Jobs Creation Act to account for it as a special deduction under FASB Statement No. 109,Accounting for Income Taxes, as opposed to an adjustment of recorded deferred tax assets and liabilities.

ITEM 3. 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.

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     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, 2006, we held approximately 2.3 million barrels of crude and product inventories valued under the LIFO valuation method with an average cost of $37.04 per barrel. Market value exceeded carrying value of LIFO costs by $60.4 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 by $2.3 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. “Forwards” represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period. “Futures” represent trades which have been executed on the New York Mercantile Exchange (“NYMEX”) which have not been closed or settled at the end of the reporting period. A “long” represent an obligation to purchase product and a “short” represents an obligation to sell product.

     The following table provides information about our derivative commodity instruments as of March 31, 2006:

			Wtd Avg		Wtd Avg
Description	Contract		Purchase		Sales		Contract		Fair		Gain
of Activity	Volume		Price/BBL		Price		Value		Value		(Loss)
Futures-long		—	$	—	$	—	$	—	$	—	$	—
Futures-short		—		—		—		—		—		—
Forwards-long (refined products)		60,029		83.42		84.20		5,007		5,054		47
Forwards-short (refined products)		—		—		—		—		—		—

Interest Rate Risk.

     As of March 31, 2006, none of our outstanding debt was at floating interest rates.

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures.

     Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms.

(b) Changes in internal control over financial reporting.

     There has been no change in our internal control over financial reporting (as described in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 6. EXHIBITS

Exhibit
Number	Description of Exhibit
3.1	Amended Restated Certificate of Incorporation of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.1 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).
3.2	Amended and Restated Bylaws of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.2 to Form S-1, filed by the Company on July 14, 2005, SEC File No. 333-124797).
4.1	Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Form S-1, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.1	Stock Purchase Agreement by and among Alon USA Energy, Inc., The Craig C. Barto and Gisele M. Barto Living Trust, Dated April 5, 1991, The Jerrel C. Barto and Janice D. Barto Living Trust, Dated March 18, 1991, W. Scott Lovejoy, III and Mark R. Milano, dated April 28, 2006 (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on May 2, 2006, SEC File No. 001-32567).
10.2	Agreement and Plan of Merger by and among Alon USA Energy, Inc., Apex Oil Company, Inc., Edgington Oil Company, and EOC Acquisition, LLC, dated April 28, 2006 (incorporated by reference to Exhibit 10.2 to Form 8-K filed by the Company on May 2, 2006, SEC File No. 001-32567).
10.3	Purchase and Sale Agreements between Alon Petroleum Pipe Line, LP and Sunoco Pipelines, LP, dated February 13, 2006 (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on February 13, 2006, SEC File No. 001-32567).
10.4	Amending Revolving Credit Agreement, dated as of February 15, 2006, among Alon USA, LP, the guarantor companies and financial institutions named therein, Israel Discount Bank of New York and Bank Leumi USA (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on February 16, 2006, SEC File No. 001-32567).
31.1	Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2	Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.

* Furnished herewith.

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	By:	/s/ David Wiessman
Date: May 12, 2006		David Wiessman
		Executive Chairman
	By:	/s/ Jeff D. Morris
Date: May 12, 2006		Jeff D. Morris
		Chief Executive Officer
	By:	/s/ Shai Even
Date: May 12, 2006		Shai Even
		Chief Financial Officer

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EXHIBITS

Exhibit
Number	Description of Exhibit
3.1	Amended Restated Certificate of Incorporation of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.1 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).
3.2	Amended and Restated Bylaws of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.2 to Form S-1, filed by the Company on July 14, 2005, SEC File No. 333-124797).
4.1	Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Form S-1, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.1	Stock Purchase Agreement by and among Alon USA Energy, Inc., The Craig C. Barto and Gisele M. Barto Living Trust, Dated April 5, 1991, The Jerrel C. Barto and Janice D. Barto Living Trust, Dated March 18, 1991, W. Scott Lovejoy, III and Mark R. Milano, dated April 28, 2006 (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on May 2, 2006, SEC File No. 001-32567).
10.2	Agreement and Plan of Merger by and among Alon USA Energy, Inc., Apex Oil Company, Inc., Edgington Oil Company, and EOC Acquisition, LLC, dated April 28, 2006 (incorporated by reference to Exhibit 10.2 to Form 8-K filed by the Company on May 2, 2006, SEC File No. 001-32567).
10.3	Purchase and Sale Agreements between Alon Petroleum Pipe Line, LP and Sunoco Pipelines, LP, dated February 13, 2006 (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on February 13, 2006, SEC File No. 001-32567).
10.4	Amending Revolving Credit Agreement, dated as of February 15, 2006, among Alon USA, LP, the guarantor companies and financial institutions named therein, Israel Discount Bank of New York and Bank Leumi USA (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on February 16, 2006, SEC File No. 001-32567).
31.1	Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2	Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.

* Furnished herewith.

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