Alon USA Energy (ALJ) 10-Q 2005 Q2 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 JUNE 30, 2005

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. Yeso Noþ

     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 mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noo

     The number of shares of the Registrant’s common stock, par value $0.01 per share, outstanding as of August 15, 2005 was 46,733,894.

ALON USA ENERGY, INC.

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION		1
Item 1. (a) Financial Statements		1
Consolidated Balance Sheets		1
Consolidated Statements of Operations		2
Consolidated Statements of Cash Flow		3
Notes to Consolidated Financial Statements		4
Item 1. (b) Schedules to the Financial Statements (Parent Only) — Schedule I		13
Condensed Balance Sheets		13
Condensed Statements of Operations		14
Condensed Statements of Cash Flows		15
Notes to Condensed Financial Statements		16
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Forward-Looking Statements		17
Item 3. Quantitative and Qualitative Disclosure About Market Risk		36
Item 4. Controls and Procedures		37
PART II. OTHER INFORMATION		38
Item 2. Unregistered Sale of Equity Securities and Use of Proceeds		38
Item 4. Submission of Matters to a Vote Security Holders		38
Item 6. Exhibits		38
SIGNATURES		41
EXHIBITS		42
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO & CFO Pursuant to Section 906

i

PART I. FINANCIAL INFORMATION

Item 1. (a) Financial Statements

ALON USA ENERGY, INC. AND SUBSIDIARIES

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

	December 31,			June 30,
	2004			2005
				(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	63,357		$	168,546
Accounts and other receivables, net		69,328			92,569
Inventories		79,329			85,344
Prepaid expenses and other current assets		2,441			6,471
Total current assets		214,455			352,930
Investment in HEP		—			23,181
Property, plant and equipment, net		236,228			207,269
Other assets		21,833			29,502
Total assets	$	472,516		$	612,882
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	153,897		$	190,437
Current portion of deferred gain on disposition of assets		—			6,310
Current portion of long-term debt		16,115			8,377
Total current liabilities		170,012			205,124
Other non-current liabilities		19,436			19,076
Deferred gain on disposition of assets		—			67,306
Long-term debt		171,591			149,524
Deferred income tax liability		31,829			42,727
Total liabilities		392,868			483,757
Commitments and contingencies (note 14)
Minority interest in subsidiaries		8,176			7,735
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; 35,001,120 shares issued and outstanding		350			350
Additional paid-in capital		8,379			8,379
Accumulated other comprehensive loss		(2,261	)		(2,261	)
Retained earnings		65,004			114,922
Total stockholders’ equity		71,472			121,390
Total liabilities and stockholders’ equity	$	472,516		$	612,882

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 share and per share data)

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2004			2005			2004			2005
Net sales	$	440,179		$	590,366		$	792,902		$	998,340
Operating costs and expenses:
Cost of sales		365,046			498,047			668,026			849,601
Direct operating expenses		17,781			20,373			36,693			38,709
Selling, general and administrative expenses		19,208			18,983			36,526			35,648
Depreciation and amortization		4,504			5,018			9,266			9,852
Total operating costs and expenses		406,539			542,421			750,511			933,810
Gain on disposition of assets		175			1,530			175			29,223
Operating income		33,815			49,475			42,566			93,753
Interest expense		5,676			4,745			11,691			9,752
Equity earnings in investee		—			(277	)		—			(412	)
Other income, net		(51	)		(830	)		(144	)		(1,080	)
Income before income tax expense and minority interest in income of subsidiaries		28,190			45,837			31,019			85,493
Income tax expense		11,415			16,354			12,534			32,009
Income before minority interest in income of subsidiaries		16,775			29,483			18,485			53,484
Minority interest in income of subsidiaries		1,487			2,001			1,700			3,566
Net income	$	15,288		$	27,482		$	16,785		$	49,918
Earnings per share	$	.44		$	.79		$	.48		$	1.43
Weighted average shares outstanding		35,001,120			35,001,120			35,001,120			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 Six Months Ended
	June 30,
	2004			2005
Cash flows from operating activities:
Net income	$	16,785		$	49,918
Adjustments:
Depreciation and amortization		9,266			9,852
Stock option plan compensation		238			191
Deferred income tax expense		—			8,237
Minority interest in income of subsidiaries		1,700			3,566
Accrued interest on subordinated notes to stockholders		2,114			1,059
Gain on disposition of assets		(175	)		(29,223	)
Equity earnings in investee		—			(412	)
Changes in operating assets and liabilities:
Accounts and other receivables, net		(24,980	)		(23,241	)
Inventories		(9,276	)		(6,015	)
Prepaid expenses and other current assets		1,270			(1,369	)
Other assets		2,354			930
Accounts payable and accrued liabilities		25,612			36,540
Other non-current liabilities		(982	)		(1,057	)
Net cash provided by operating activities		23,926			48,976
Cash flows from investing activities:
Capital expenditures		(13,350	)		(16,459	)
Turnaround and chemical catalyst expenditures		(1,500	)		(10,781	)
Proceeds from disposition of assets, net		328			118,000
Acquisition in minority interest in subsidiary		(10,000	)		—
Distributions from investee		—			516
Net cash (used in) provided by investing activities		(24,522	)		91,276
Cash flows from financing activities:
Minority interest shares purchased		—			(2,717	)
Payments received for shares issued		140			—
Dividends paid to minority interest owners		—			(1,482	)
Net payments on revolving credit facilities		(19,600	)		—
Deferred debt issuance costs		(1,885	)		—
Additions to long-term debt		99,161			2,932
Payments on long-term debt		(45,133	)		(33,796	)
Net cash provided by (used in) financing activities		32,683			(35,063	)
Net increase in cash and cash equivalents		32,087			105,189
Cash and cash equivalents, beginning of period		7,256			63,357
Cash and cash equivalents, end of period	$	39,343		$	168,546
Supplemental cash flow information:
Cash paid for interest	$	6,552		$	7,782
Cash paid for income tax	$	1,802		$	12,447
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

3

ALON USA ENERGY, INC. AND SUBSIDIARIES

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

(1) Basis of Presentation and Certain Significant Accounting Policies

     These consolidated financial statements of Alon USA Energy, Inc. and subsidiaries (“Alon” or “the Company”) are unaudited and have been prepared in accordance with United States generally accepted accounting principles 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 United States generally accepted accounting principles (GAAP) for complete consolidated financial statements. In the opinion of management of the Company, 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 the Company’s consolidated financial position and results of operations for the interim periods presented. The results of operations for the interim period are not necessarily indicative of the operating results for the year ending December 31, 2005.

     The consolidated balance sheet as of December 31, 2004 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 for the year ended December 31, 2004 contained in our registration statement on Form S-1 (File No. 333-124797).

     Revenues, net of applicable excise taxes, for products sold by both the refining and marketing segment and the retail segment are recorded upon delivery of the products to their customers, which is the point at which title to the products is transferred, the customer has the assumed risk of loss, and when payment has either been received or collection is reasonably assured. Transportation, shipping and handling costs incurred are reported in cost of sales.

     Revenues include the sales of certain buy/sell arrangements, which involve linked purchases and sales related to product sales contracts entered into to address location, quality or grade requirements. The results of these linked refined product buy/sell transactions are recorded in sales and cost of sales in the accompanying statements of operations at fair value. In the ordinary course of business, logistical and refinery production schedules necessitate the occasional sale of crude oil to third parties. All purchases and sales of crude oil are recorded on a net basis in cost of sales in the accompanying statements of operations. Such sales are infrequent and the effects of the sales on the Company’s operating results are not significant.

     For the three months ended June 30, 2004 and 2005, the Company recorded revenues related to linked refined product sales of $30,293 and $12,338 respectively. For the three months ended June 30, 2004 and 2005, the Company recorded costs related to linked refined product sales of $30,473 and $12,544, respectively.

     For the six months ended June 30, 2004 and 2005, the Company recorded revenues related to linked refined product sales of $41,279 and $19,812 respectively. For the six months ended June 30, 2004 and 2005, the Company recorded costs related to linked refined product sales of $41,499 and $20,114, respectively.

(2) Sale of Pipelines and Terminals

     HEP Transaction.On February 28, 2005, the Company completed the contribution of the Fin-Tex, Trust and River product pipelines, the Wichita Falls and Abilene product terminals and the Orla tank farm to Holly Energy Partners, LP (“HEP”). In exchange for this contribution, which is referred to as the HEP transaction, the Company received $120,000 in cash, prior to closing costs of approximately $2,000, and 937,500 subordinated Class B limited partnership interests in HEP (“Units”).

     Simultaneously with this transaction, the Company entered into a Pipelines and Terminals Agreement with HEP providing continued access to these assets for an initial term of 15 years and three additional five year renewal terms exercisable at the Company’s sole option. Pursuant to the Pipelines and Terminals Agreement, the Company has committed to transport and store minimum volumes of refined products in these pipelines and terminals. The tariff rates applicable to the transportation of refined products on the pipelines are variable, with a base fee which is reduced for volumes exceeding defined volumetric targets. The agreement provides for the reduction of the

4

ALON USA ENERGY, INC. AND SUBSIDIARIES

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

minimum volume requirement under certain circumstances. The service fees for the storage of refined products in the terminals are initially set at rates competitive in the marketplace.

     The entire cash consideration was financed by high-yield debt issued by HEP with a 10-year maturity (“HEP Debt”). Alon Pipeline Logistics, LLC, a wholly owned subsidiary of Alon (“Alon Logistics”) entered into an agreement with the general partner of HEP providing for Alon Logistics to indemnify the general partner for cash payments such general partner has to make toward satisfaction of the principal or interest under the HEP Debt following a default by HEP (provided that such cash payments exceed the difference between the amount of HEP Debt over the indemnity amount). The indemnity amount is limited to the lower of (a) $110,850 or (b) the outstanding amount of HEP Debt. The indemnity terminates at such time as Alon Logistics no longer holds any HEP units and subject to other terms described in the indemnification agreement. The indemnification amount may be reduced from time to time per terms described in the indemnification agreement. The indemnification obligation is specific to Alon Logistics and does not extend to other Alon entities, even if the HEP units are transferred to such other entities. The fair value of this debt guarantee of $1,075 is recorded in other liabilities in the June 30, 2005 consolidated balance sheet.

     The HEP transaction was recorded as a partial sale for accounting purposes resulting in a pre-tax gain of $102,461, net of transaction costs and the fair value of the indemnity to the general partner of HEP. The Company recognized an initial pre-tax gain of $26,742. The remaining $75,719 of the gain was deferred. As the HEP units received in the transaction are accounted for under the equity method of accounting for investments in limited partnerships, $6,715 of the pro rata gain was deferred and subtracted from the carrying value of the investment in the HEP units. The deferred gain will be recognized over a period of approximately 12 years or less depending on circumstances described in the indemnification agreement. The deferred gain is recorded $6,310 as a current liability and $67,306 as a long-term liability in the June 30, 2005 consolidated balance sheet.

(3) New Accounting Standards

     In December 2004, the FASB issued Statement of Accounting Standards No. 123R, “Share-Based Payment” (SFAS No. 123R), which requires expensing stock options and other share-based compensation payments to employees and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing pro forma disclosure only. This standard is effective for the Company as of January 1, 2006 and will apply to all awards granted, modified, cancelled or repurchased after that date as well as the unvested portion of prior awards. The Company’s subsidiaries use the minimum value method of measuring equity share options for pro forma disclosure purposes under SFAS No. 123; the Company will apply SFAS 123R prospectively to new awards and to awards modified, repurchased or cancelled after January 1, 2006. The adoption of SFAS No. 123R is not expected to materially affect the Company’s financial position or results of operations.

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

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

5

ALON USA ENERGY, INC. AND SUBSIDIARIES

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

     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” which requires a company that qualifies for the deduction for domestic production activities under the 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. The Company is currently reviewing the effects of this FSP, but does not anticipate any tax contingencies or significant changes to the effective tax rate as a result of the application of this pronouncement.

     Currently, the Emerging Issues Task Force, (EITF) is addressing the accounting for linked purchase and sale arrangements in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” At its March and June, 2005 meetings, EITF reached a tentative conclusion that generally requires non-monetary exchanges of inventory within the same line of business be recognized at the carrying value of the inventory transferred. The Company will continue to monitor the progress of EITF Issue No. 04-13.

     In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), that requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective for fiscal years ending after December 15, 2005. The Company is currently reviewing the applicability of FIN 47 to its operations and its potential impact on its consolidated financial statements.

     In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3.” This statement changes the requirements for accounting for and reporting a change in accounting principles and applies to all voluntary changes in accounting principles. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. This statement requires retrospective application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of change. This statement becomes effective for fiscal years beginning after December 15, 2005.

(4) Segment Data

     The Company’s revenues are derived from two operating segments: (i) Refining and Marketing and (ii) Retail. Management has identified these segments for managing operations based on manufacturing and marketing criteria.

     (a) Refining and Marketing Segment

     The refining and marketing segment includes a complex sour crude oil refinery, its crude oil and its owned and leased refined products pipeline systems and refined products terminals. The Company’s refinery manufactures petroleum products including various grades of gasoline, diesel fuel, jet fuel, petrochemical feedstocks, asphalt and other petroleum based products. In addition, finished products are acquired through exchange agreements and third-party suppliers. The Company primarily markets its gasoline and diesel under the Fina brand name, through a network of branded retail locations. Finished products and blendstocks are also marketed through sales and exchanges with major oil companies, state and federal governmental entities, unbranded wholesale distributors and various other third parties.

     (b) Retail Segment

     The Company’s retail segment operates 167 owned and leased convenience store sites operating primarily in West Texas and New Mexico. These convenience stores offer various grades of gasoline, diesel fuel, general merchandise and food products to the general public under the 7-Eleven and Fina brand names.

6

ALON USA ENERGY, INC. AND SUBSIDIARIES

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

     (c) Corporate/Other

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

     Operating income for each segment consists of net revenues less cost of sales, direct operating expenses, selling, general and administrative expenses and depreciation and amortization. Sales between segments are transferred at current market prices. Consolidated totals presented are after intersegment eliminations.

     Total assets of each segment consist of net property, plant and equipment, inventories, accounts receivables and other assets directly associated with the segment’s operations. Corporate assets consist primarily of information technology and administrative equipment at the corporate headquarters.

     Segment data as of and for the three-month and six-month periods ended June 30, 2005 and 2004 is presented below.

	Three Months Ended June 30, 2005
	Refining and						Corporate
	Marketing			Retail			and other			Eliminations			Consolidated
Net sales:
Unaffiliated customers	$	503,182		$	87,184		$	—		$	—		$	590,366
Intersegment		39,592			—			—			(39,592	)		—
Total net sales	$	542,774		$	87,184		$	—		$	(39,592	)	$	590,366
Operating income (loss)	$	49,379		$	702		$	(606	)	$	—		$	49,475
Interest expense		(3,866	)		(879	)		—			—			(4,745	)
Other income, net		268			—			839			—			1,107
Income (loss) before income tax expense and minority interest	$	45,781		$	(177	)	$	233		$	—		$	45,837
Total assets	$	529,673		$	70,884		$	12,325		$	—		$	612,882
Depreciation and amortization		3,489			1,051			478			—			5,018
Capital expenditures		4,723			1,021			16			—			5,760

	Three Months Ended June 30, 2004
	Refining and						Corporate
	Marketing			Retail			and other			Eliminations			Consolidated
Net sales:
Unaffiliated customers	$	361,260		$	78,919		$	—		$	—		$	440,179
Intersegment		30,826			—			—			(30,826	)		—
Total net sales	$	392,086		$	78,919		$	—		$	(30,826	)	$	440,179
Operating income (loss)	$	33,335		$	1,040		$	(560	)	$	—		$	33,815
Interest expense		(4,870	)		(806	)		—			—			(5,676	)
Other income, net		64			—			(13	)		—			51
Income (loss) before income tax expense and minority interest	$	28,529		$	234		$	(573	)	$	—		$	28,190
Total assets	$	376,413		$	71,309		$	12,861		$	—		$	460,583
Depreciation and amortization		3,063			1,008			433			—			4,504
Capital expenditures		11,500			974			129			—			12,603

7

ALON USA ENERGY, INC. AND SUBSIDIARIES

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

	Six Months Ended June 30, 2005
	Refining and						Corporate
	Marketing			Retail			and other			Eliminations			Consolidated
Net sales:
Unaffiliated customers	$	837,260		$	161,080		$	—		$	—		$	998,340
Intersegment		72,448			—			—			(72,448	)		—
Total net sales	$	909,708		$	161,080		$	—		$	(72,448	)	$	998,340
Operating income (loss)	$	94,167		$	791		$	(1,205	)	$	—		$	93,753
Interest expense		(8,012	)		(1,740	)		—			—			(9,752	)
Other income, net		387			—			1,105			—			1,492
Income (loss) before income tax expense and minority interest	$	86,542		$	(949	)	$	(100	)	$	—		$	85,493
Total assets	$	529,673		$	70,884		$	12,325		$	—		$	612,882
Depreciation and amortization		6,800			2,103			949			—			9,852
Capital expenditures		25,050			2,030			160			—			27,240

	Six Months Ended June 30, 2004
	Refining and						Corporate
	Marketing			Retail			and other			Eliminations			Consolidated
Net sales:
Unaffiliated customers	$	645,883		$	147,019		$	—		$	—		$	792,902
Intersegment		55,895			—			—			(55,895	)		—
Total net sales	$	701,778		$	147,019		$	—		$	(55,895	)	$	792,902
Operating income (loss)	$	43,152		$	518		$	(1,104	)	$	—		$	42,566
Interest expense		(10,057	)		(1,634	)		—			—			(11,691	)
Other income, net		64			(5	)		85			—			144
Income (loss) before income tax expense and minority interest	$	33,159		$	(1,121	)	$	(1,019	)	$	—		$	31,019
Total assets	$	376,413		$	71,309		$	12,861		$	—		$	460,583
Depreciation and amortization		6,350			2,066			850			—			9,266
Capital expenditures		13,222			1,216			412			—			14,850

(5) Cash and Cash Equivalents

     On February 28, 2005, the Company completed the contribution of three pipelines and three product terminals to HEP. Net cash proceeds of $118,000 were received in connection with the transaction. The Company used $25,000 of the cash received to repay debt owing to the Company’s parent, Alon Israel Oil Company, Ltd., (“Alon Israel”), and the payment of a dividend of $1,482 to current minority interest owners.

(6) Inventories

     Inventories for the Company are stated at the lower of cost or market. Cost is determined under the last-in, first-out (LIFO) method for crude oil, refined products, and blendstock inventories. Materials and supplies are stated at average cost. Cost for convenience store merchandise inventories is determined under the retail inventory method and cost for convenience store fuel inventories is determined under the first-in, first-out (FIFO) method.

8

ALON USA ENERGY, INC. AND SUBSIDIARIES

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

     Carrying value of inventories consisted of the following:

	December 31,		June 30,
	2004		2005
Crude oil, refined products, and blendstocks	$	58,412	$	62,921
Materials and supplies		5,570		5,577
Store merchandise		12,860		13,570
Store fuel		2,487		3,276
Total inventories	$	79,329	$	85,344

     Market values exceeded LIFO costs by $25,766 and $49,392 at December 31, 2004 and June 30, 2005, respectively.

(7) Investment in HEP

     On February 28, 2005, the Company completed the contribution of three pipeline and three product terminals to HEP. In exchange for this contribution, which is referred to as the HEP transaction, the Company received $120,000 in cash, prior to closing costs of approximately $2,000, and 937,500 Units. The Units are accounted for under the equity method of accounting for investment in limited partnerships and the Units were recorded at an initial fair value of $32 per unit, or $30,000. The investment in the Units is recorded net of $6,715 of the related deferred pro rata gain in the consolidated balance sheet as of June 30, 2005. The Company recognized $412 in equity earnings in investee and recorded the receipt of a $516 cash distribution from investee during the first six months of 2005. See note 2 for a discussion of the HEP transaction.

(8) Property, Plant, and Equipment

     Property, plant, and equipment consisted of the following:

	December 31,			June 30,
	2004			2005
Refining facilities	$	149,016		$	162,410
Pipelines and terminals		69,289			26,227
Retail		59,543			61,695
Other		9,323			10,125
Property, plant, and equipment, gross		287,171			260,457
Less accumulated depreciation		(50,943	)		(53,188	)
Property, plant, and equipment, net	$	236,228		$	207,269

     On February 28, 2005, the Company completed the contribution of three pipelines and three product terminals to HEP. See note 2.

(9) Employee and Postretirement Benefits

     The Company has two defined benefit pension plans covering substantially all of its refining and market segment employees. The Company policy is to make contributions annually of not less than the minimum funding requirements under the Employee Retirement Income Security Act of 1974. The Company’s anticipated contributions to its pension plans during 2005 have not changed significantly from amounts previously disclosed in the Company’s consolidated financial statements for the year ended December 31, 2004. For the six months ended June 30, 2004 and 2005, the Company contributed $399 and $1,148, respectively, to its qualified pension plan.

9

ALON USA ENERGY, INC. AND SUBSIDIARIES

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

     The components of net periodic benefit cost related to the Company’s benefit plans were as follows for the three and six months ended June 30, 2004 and 2005.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2004			2005			2004			2005
Components of net periodic benefit cost:
Service cost	$	332		$	347		$	663		$	693
Interest cost		457			478			913			957
Expected return on plan assets		(347	)		(414	)		(694	)		(827	)
Amortization of net loss		140			166			282			332
Net periodic benefit cost	$	582		$	577		$	1,164		$	1,155

(10) Long-Term Debt

Revolving Credit Facility

     As of June 30, 2005, the Company had a revolving credit facility which provides for commitments of $141,600 for a three-year term. In addition, the Company has a separate credit facility for the issuance of letters of credit for up to $20,000. Subject to commitment amounts and terms, the revolving credit facility provides for the issuance of letters of credit and for up to $82,000 of revolving credit loans. The revolving credit facility is primarily used for issuance of letters of credit (principally for crude oil purchases). The Company is charged various fees and expenses in connection with this facility, including facility fees and various letter of credit fees. Amounts outstanding under this revolving credit facility accrue interest at the Eurodollar plus 2.5% per year. This facility includes certain restrictions and covenants, including, among other things, limitations on capital expenditures, dividend restrictions and minimum net worth and coverage ratios.

     No borrowings were outstanding under the revolving credit facility at June 30, 2005. As of June 30, 2004 and 2005, the Company had $106,854 and $141,135, respectively, of outstanding letters of credit under the revolving credit facility.

Debt Repayment

     On February 28, 2005, the Company made a $25,000 subordinated debt payment to Alon Israel (see note 5).

Guarantees and Restrictions

     Alon Israel, the majority stockholder of Alon, and other related parties guarantee the payment of the Company’s obligations under its revolving credit facility if the Company defaults on such payments and there is a shortfall in the proceeds realized from collateral, which supports the revolving credit facility. These guarantees terminated upon the completion of the Company’s initial public offering in August 2005.

(11) Stock Based Compensation

     The Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Accordingly, compensation cost for stock options is measured as the excess of the estimated fair value of the common stock over the exercise price and is generally recognized over the scheduled accelerated vesting period. Current period stock compensation expense is presented as selling, general and administrative expenses in the accompanying statements of operations.

     The Company’s subsidiaries use the minimum value method for calculating the fair value impact of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). Accordingly, there is no significant pro

10

ALON USA ENERGY, INC. AND SUBSIDIARIES

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

forma impact on net income and earnings per share from adoption of SFAS No. 123. The Company recognizes stock compensation expense using the accelerated vesting method prescribed by FASB Interpretation No. 28.

(12) 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 all years presented to reflect this stock split.

     (b) Special Dividends

     Upon the completion of the Company’s initial public offering on August 2, 2005 (note 15), the boards of directors of each of the Company and Alon USA Operating, Inc. paid special dividends to pre-offering stockholders of record. The applicable stockholders of record of the Company were paid aggregate dividends of $68,479 and the minority interest stockholders of record of Alon USA Operating, Inc. were paid aggregate dividends of $4,652.

(13) Earnings Per Share

     Basic earnings per share is computed by dividing net income by the weighted average of the common shares outstanding. As of June 30, 2005, there were no dilutive potential common shares outstanding.

(14) 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 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

11

ALON USA ENERGY, INC. AND SUBSIDIARIES

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

expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Substantially all amounts accrued are expected to be paid out over the next five to ten years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

     The Company had accrued environmental remediation obligations of $7,058 ($3,000 current payable and $4,058 non-current liability) at December 31, 2004 and $5,744 ($3,000 current payable and $2,744 non-current liability) at June 30, 2005.

(15) Subsequent Event – Initial Public Offering of Alon

     On August 2, 2005, the Company completed an initial public offering of 11,730,000 shares of its common stock at a price of $16.00 per share for an aggregate offering price of $187,680. The Company received approximately $172,542 in net proceeds from the initial public offering after payment of expenses, underwriting discounts and commissions of approximately $15,138, or $1.29 per share.

     The initial public offering by the Company, the receipt of proceeds and the use of proceeds received by the Company, including the distributions of the dividends to pre-offering stockholders of record (note 12(b)), the prepayment of $20,709 of debt to Alon Israel and the repayment of $3,631 of debt to Atofina Petrochemicals, Inc. are not reflected in the Company’s financial statements as of June 30, 2005 included in this report because the offering was completed after the end of the second quarter 2005.

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Item 1. (b) Schedules to the Financial Statements (Parent Only) — Schedule I

ALON USA ENERGY, INC. (PARENT COMPANY ONLY)

CONDENSED BALANCE SHEETS
(dollars in thousands)

	December 31,			June 30,
	2004			2005
				(Unaudited)
ASSETS
Current assets	$	2,126		$	4,929
Investment in subsidiary		111,558			137,068
Total assets	$	113,684		$	141,997
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	511		$	—
Long-term debt		41,701			20,607
Total liabilities		42,212			20,607
Shareholders’ equity:
Shareholders’ investment		8,729			8,729
Accumulated other comprehensive loss		(2,261	)		(2,261	)
Retained earnings		65,004			114,922
Total stockholders’ equity		71,472			121,390
Total liabilities and stockholders’ equity	$	113,684		$	141,997

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ALON USA ENERGY, INC. (PARENT COMPANY ONLY)

CONDENSED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands)

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2004			2005			2004			2005
General and administrative expenses	$	1		$	—		$	3		$	—
Interest expense		700			354			1,379			979
Loss before income tax benefit and equity earnings in subsidiary		(701	)		(354	)		(1,382	)		(979	)
Income tax benefit		(269	)		(140	)		(537	)		(387	)
Loss before equity earnings in subsidiary		(432	)		(214	)		(845	)		(592	)
Equity earnings in subsidiary		15,720			27,696			17,630			50,510
Net income	$	15,288		$	27,482		$	16,785		$	49,918

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ALON USA ENERGY, INC. (PARENT COMPANY ONLY)

CONDENSED STATEMENTS OF CASH FLOWS
(unaudited, dollars in thousands)

	For the Six Months
	Ended June 30,
	2004			2005
Cash flows from operating activities:
Net income	$	16,785		$	49,918
Adjustments:
Accrued interest on subordinated notes to stockholders		1,379			979
Equity earnings in subsidiary		(17,630	)		(50,510	)
Changes in operating assets and liabilities:
Accounts payable and accrued liabilities		(2,196	)		(2,393	)
Net cash used in operating activities		(1,662	)		(2,006	)
Cashflows from investing activities:
Dividends received from subsidiary		—			25,000
Net cash provided by investing activities		—			25,000
Cash flows from financing activities:
Stock issuance and payments from stockholders		140			—
Additions to long-term debt		2,727			2,927
Payments on long-term debt		—			(25,000	)
Net cash provided by (used in) financing activities		2,867			(22,073	)
Net increase in cash and cash equivalents		1,205			921
Cash and cash equivalents, beginning of period		264			44
Cash and cash equivalents, end of period	$	1,469		$	965

15

ALON USA ENERGY, INC. (PARENT COMPANY ONLY)

NOTES TO CONDENSED FINANCIAL STATEMENTS
(unaudited, dollars in thousands)

(1) Basis of Presentation

     Under the agreements governing indebtedness of certain direct and indirect subsidiaries of Alon, such subsidiaries are restricted from making dividend payments, loans or advances to the Company. These restrictions result in restricted net assets (as defined in Rule 4-08 (e)(3) of Regulation S-X) of the Company’s direct and indirect subsidiaries exceeding 25% of the consolidated net assets of the Company and its subsidiaries.

     The accompanying condensed financial statements summarize the Company’s financial position as of December 31, 2004 and June 30, 2005 (unaudited) and the results of operations and cash flows for the three months and six months ended June 30, 2004 (unaudited) and 2005 (unaudited).

     The Alon USA Energy, Inc. (Parent Company Only) condensed financial statements should be read in conjunction with the consolidated financial statements of the Company and Subsidiaries included elsewhere herein.

(2) Long-Term Debt

     As of December 31, 2004, the Company had unsecured subordinated notes payable to its parent company, Alon Israel, of $36,300. The Company retired $25,000 of the subordinated debt in February 2005, with the cash received in the form of a dividend from its wholly-owned subsidiary, Alon USA, Inc. As of June 30, 2005, the unpaid principal balance of the subordinated notes totaled $11,300. The remaining principal and related accrued interest totaling $20,709 was paid in full on August 4, 2005 with proceeds received in the Company’s initial public offering of common stock (see notes 5 and 15 of the consolidated financial statements (unaudited)).

(3) Dividends Received

     In February 2005, the Company received $25,000 in the form of a cash dividend from its wholly-owned subsidiary, Alon USA, Inc. The dividend represented a portion of the proceeds Alon USA, Inc., through its subsidiaries, received as a result of the HEP transaction (see note 5 of the consolidated financial statements (unaudited)).

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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 Management���s Discussion and Analysis of Financial Condition and the consolidated financial statements and notes thereto for the year ended December 31, 2004 included in our registration statement onForm S-1 (Registration No. 333-124797) declared effective by the U.S. Securities Exchange Commission (“SEC”) on July 27, 2005. The terms “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 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 registration statement on Form S-1 (Registration No. 333-124797) under the caption “Risk Factors.”

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     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 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 are able to supply our branded and unbranded distributors in this region with refined products produced at our Big Spring refinery and distributed through our product pipeline and terminal network. 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 June 30, 2005, we operated 167 convenience stores in West Texas and New Mexico. Our convenience stores typically offer merchandise, food products and motor fuels under the 7-Eleven and FINA brand names.

Summary of Recent Developments

     On August 2, 2005, we completed an initial public offering of 11,730,000 shares of our common stock at a price of $16.00 per share for an aggregate offering price of approximately $187.7 million. We received approximately $172.5 million in net proceeds from the initial public offering after payment of expenses, underwriting discounts and commissions of approximately $15.1 million or $1.29 per share. The initial public offering represented the sale by us of a 25.1% interest in our Company. See “— Liquidity and Capital Resources — Initial Public Offering of Alon USA Energy, Inc.” below for additional information.

     The second quarter of 2005 continued to reflect the positive refinery fundamentals experienced in the first quarter of 2005. These positive fundamentals, combined with enhanced operations as a result of the major turnaround and crude oil throughput capacity expansion in February 2005, resulted in significantly enhanced results of operations reported for the six month period ended June 30, 2005 compared to the six month period ended June 30, 2004. Results of our operations are further described below and under “— Results of Operations” and “— Capital Liquidity and Resources”:

• Net sales increased $205.4 million to $998.3 million and operating income increased $51.2 million to $93.8 million for the first six months of 2005, compared to the first six months of 2004.

• Our average refinery operating margin increased $2.74 per barrel to $11.33 per barrel for the first six months of 2005, compared to the first six months of 2004.

• Our capital expenditures and turnaround spending totaled approximately $27.2 million, of which $12.6 million was spent on a major turnaround and the completion of crude throughput expansion from 62,000 bpd to 70,000 bpd in February 2005.

     In February 2005, we completed the contribution of certain of our pipeline and terminal assets to Holly Energy Partners, L.P. (“HEP”). In exchange for this contribution we received $120 million in cash and 937,500 subordinated Class B limited partnership units in HEP. Simultaneously with this transaction, we entered into a

18

Pipelines and Terminal Agreement with HEP with an initial term of 15 years and three subsequent five year renewal terms exercisable at our sole discretion. Pursuant to the Pipelines and Terminal Agreement, we have agreed to transport and store minimum volumes of refined products in these pipelines and terminals and to pay specified tariffs and fees for such transportation and storage during the term of the agreement.

Major Influences on Results of Operations

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

     In order to measure our operating performance, we compare our per barrel refinery operating margin to certain industry benchmarks, specifically the Gulf Coast and Group III, or mid-continent, 3/2/1 crack spreads. A 3/2/1 crack spread in a given region is calculated assuming that three barrels of a benchmark crude oil are converted, or cracked, into two barrels of gasoline and one barrel of diesel. We calculate our refinery operating margin by dividing the margin between net sales and cost of sales attributable to our refining and marketing segment, exclusive of net sales and cost of sales relating to our non-integrated system, by our Big Spring refinery’s throughput volumes.

     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 value of WTI crude oil less the value of WTS crude oil. We refer to this differential as the sweet/sour spread. A widening of the sweet/sour spread can favorably influence our refinery operating margin.

     The results of operations from our refining and marketing segment are also significantly affected by our Big Spring refinery’s operating costs, particularly the cost of natural gas used for fuel and the cost of electricity. Natural gas prices have historically been volatile. For example, natural gas prices ranged between $4.57 and $8.75 per MMBTU in 2004. Over the first six months of 2005, natural gas prices ranged between $5.79 and $7.75 per MMBTU. Typically, electricity prices fluctuate with natural gas prices.

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

     Safety, reliability and the environmental performance of our refinery operations are critical to our financial performance. The financial impact of planned downtime, such as a turnaround or major maintenance project, is mitigated through a diligent planning process that considers product availability, margin environment and the availability of resources to perform the required maintenance.

     The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Because crude oil and refined products are essentially commodities, we have no control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market value under the LIFO inventory valuation methodology, price fluctuations generally have little effect on our financial results.

     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

19

convenience, branding and competitive pricing. Motor fuel margin is sales less the delivered cost of fuel and motor fuel taxes, measured on a cents per gallon, or cpg, basis. Our motor fuel margins are driven by local supply, demand and competitor pricing. Our 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.

Outlook

     Since the beginning of 2005, refinery fundamentals, including the continued high demand for refined products and a strengthening economy have resulted in increases in refinery operating margins and favorable sweet/sour spreads. Average crack spreads have remained strong in the second quarter of 2005 as year-on-year demand increases continue at above historical levels in the United States, China and India and refining capacity remains limited. During the first six months of 2005, average Gulf Coast and Group III crack spreads were $8.44 and $9.80 per barrel, respectively, compared to the first six months of 2004 average Gulf Coast and Group III crack spreads of $7.91 and $9.18 per barrel, respectively.

     The average sweet/sour spread was $4.41 per barrel in the first six months of 2005, compared to $3.20 per barrel for the first six months of 2004. The higher sweet/sour spread in the first six months of 2005 is a result of the continued increased demand for sweet crude oils due to low-sulfur gasoline regulations and higher incremental sour crude oil production. According to the Energy Information Administration, or EIA, the growth of sour crude oil production over the next several years is expected to exceed the growth of sweet crude oil production as new discoveries of sour crude oil reserves come to the market from areas such as the deepwater Gulf of Mexico, while sweet crude oil production declines in some major regions such as the North Sea. The need for compliance with low-sulfur fuels standards is also expected to keep demand for sweet crude oils strong relative to sour crude oils.

     Operationally, we expect to benefit during the remainder of 2005 from the 8,000 bpd crude oil throughput capacity expansion and the major turnaround completed in the first quarter of 2005.

Factors Affecting Comparability

     Our financial condition and operating results over the six-month period ended June 30, 2005 have been influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.

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

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

     The HEP transaction was recorded as a partial sale for accounting purposes. We recognized pre-tax gain of $29.2 million in the six month period ending June 30, 2005 in connection with the transaction. We expect the remaining $73.6 million of deferred gain to be recognized between now and 2017. In addition, $6.7 million of pro-rata gain was deferred and is subtracted from the carrying value of our investment in HEP in our consolidated balance sheet. See Note 2 of the consolidated financial statements for the six months ended June 30, 2005 included elsewhere in this Form 10-Q.

     In the first quarter of 2005, we successfully completed a major turnaround at our Big Spring refinery. In connection with this turnaround, we expanded our crude oil throughput capacity from 62,000 bpd to 70,000 bpd at a cost of $6.4 million. The expansion and turnaround were completed as scheduled and the refinery resumed full

20

production capabilities on March 6, 2005. Our expanded crude oil processing capability should enable us to spread our fixed costs over a higher production base and, consequently, should lower our per barrel direct operating expense. In addition, the increased throughput capacity should result in increased production and higher sales volumes, which will affect the comparability of our future operating results to periods prior to the expansion. Our average refinery production increased from 47,060 bpd for the first quarter 2005, to 71,602 bpd for the second quarter 2005. Refinery production was 62,394 bpd for the second quarter 2004.

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 include cost of sales for motor fuels and for merchandise. Motor fuel cost of sales represents the net cost of purchased fuel, including transportation costs and associated motor fuel taxes. Merchandise cost of sales includes the delivered cost of merchandise purchases, net of merchandise rebates and commissions.

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

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

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

ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2004			2005			2004			2005
STATEMENT OF OPERATIONS DATA:
Net sales	$	440,179		$	590,366		$	792,902		$	998,340
Operating costs and expenses:
Cost of sales		365,046			498,047			668,026			849,601
Direct operating expenses		17,781			20,373			36,693			38,709
Selling, general and administrative expenses (a)		19,208			18,983			36,526			35,648
Depreciation and amortization (b)		4,504			5,018			9,266			9,852
Total operating costs and expenses		406,539			542,421			750,511			933,810
Gain on disposition of assets (c)		175			1,530			175			29,223
Operating income		33,815			49,475			42,566			93,753
Interest expense		5,676			4,745			11,691			9,752
Equity earnings in investee		—			(277	)		—			(412	)
Other income, net		(51	)		(830	)		(144	)		(1,080	)
Income tax expense		11,415			16,354			12,534			32,009
Minority interest in income of subsidiaries		1,487			2,001			1,700			3,566
Net income	$	15,288		$	27,482		$	16,785		$	49,918
Earnings per share (d)	$	.44		$	.79		$	.48		$	1.43
Weighted average shares outstanding (d)		35,001,120			35,001,120			35,001,210			35,001,120
OTHER DATA:
Adjusted EBITDA (e)	$	38,195		$	54,070		$	51,801		$	75,874
Capital expenditures, net of disposition proceeds		21,880			5,361			23,022			(101,541	)
Capital expenditures for turnarounds and catalysts		410			399			1,500			10,781
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	35,126		$	65,413		$	23,926		$	48,976
Investing activities		(22,290	)		(5,244	)		(24,522	)		91,276
Financing activities		3,271			(612	)		32,683			(35,063	)
BALANCE SHEET DATA (end of period):
Cash and cash equivalents							$	39,343		$	168,546
Working capital								63,152			147,806
Total assets								460,583			612,882
Total debt								196,924			157,901
Stockholders equity								63,848			121,390

(a)	Includes corporate headquarters selling, general and administrative expenses of $127, and $128 for the three months ended June 30, 2004 and 2005, respectively, and $254 and $256 for the six months ended June 30, 2004 and 2005, respectively, which are not allocated to our two operating segments.
(b)	Includes corporate depreciation and amortization of $433, and $478 for the three months ended June 30, 2004 and 2005, respectively, and $850 and $949 for the six months ended June 30, 2004 and 2005, respectively, which are not allocated to our two operating segments.
(c)	Gain on disposition of assets reported in the six months ended June 30, 2005, reflects the initial pre-tax gain recognized in connection with assets contributed in the HEP transaction and the monthly recognition of the deferred gain recorded in connection with the HEP transaction.

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(d)	Weighted average common shares outstanding and earnings per common share amounts for the three and six months ended June 30, 2004 and 2005, have been restated to reflect the effect of a 33,600-for-one split of Alon’s common stock which was effected on July 6, 2005.
(e)	See “— Reconciliation of Amounts Reported Under Generally Accepted Accounting Principles” for information regarding our definition of Adjusted EBITDA, its limitations as an analytical tool and a reconciliation of net income to Adjusted EBITDA for the periods presented.

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REFINING AND MARKETING SEGMENT

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2004			2005			2004			2005
	(unaudited, dollars in thousands, except for
	per barrel and pricing statistics)
STATEMENT OF OPERATIONS DATA:
Net sales (a)	$	392,086		$	542,774		$	701,778		$	909,708
Operating Costs and Expenses:
Cost of sales		331,398			464,656			603,995			788,170
Direct operating expenses		17,781			20,373			36,693			38,709
Selling, general and administrative expenses		6,509			6,407			11,588			11,085
Depreciation and amortization		3,063			3,489			6,350			6,800
Total operating costs and expenses		358,751			494,925			658,626			844,764
Gain on disposition of assets (b)		—			1,530			—			29,223
Operating income	$	33,335		$	49,379		$	43,152		$	94,167
KEY OPERATING STATISTICS:
Total sales volume (bpd)		89,479			95,217			85,816			83,799
Non-integrated marketing sales volume (bpd)		19,629			20,543			19,682			20,304
Non-integrated marketing margin (per barrel sales volume) (c)	$	0.25		$	.26		$	.14		$	(.32	)
Per barrel of throughput:
Refinery operating margin (d)	$	10.58		$	11.83		$	8.59		$	11.33
Direct operating expenses		3.12			3.10			3.24			3.57
PRICING STATISTICS:
WTI crude oil (per barrel)	$	38.31		$	53.00		$	36.77		$	51.39
WTS crude oil (per barrel)		35.44			49.26			33.57			46.98
Crack spreads (3/2/1) (per barrel):
Gulf Coast	$	9.09		$	10.18		$	7.91		$	8.44
Group III		11.51			11.62			9.18			9.80
Crude differentials (per barrel):
WTI less WTS	$	2.87		$	3.74		$	3.20		$	4.41
Product price (per gallon):
Gulf Coast unleaded		120.0	¢		147.8	¢		111.6	¢		140.2	¢
Gulf Coast low-sulfur diesel		98.7			155.8			96.0			147.0
Group III unleaded		124.9			151.3			114.3			143.7
Group III low-sulfur diesel		106.0			158.9			99.7			149.8
Natural gas (per MMBTU)	$	6.16		$	6.95		$	5.94		$	6.73

THROUGHPUT AND YIELD DATA:

	For the Three Months Ended								For the Six Months Ended
	June 30,								June 30,
	2004				2005				2004				2005
	Bpd		%		Bpd		%		Bpd		%		Bpd		%
Refinery crude throughput:
Sour crude		54,291		91.2		61,572		89.7		54,035		91.8		51,391		91.2
Sweet crude		4,924		8.8		7,033		10.3		4,851		8.2		4,943		8.8
Total crude throughput		59,215		100.0		68,605		100.0		58,886		100.0		56,334		100.0
Blendstocks		3,363				3,502				3,456				3,511
Total refinery throughput (e)		62,578				72,107				62,342				59,845
Refinery product yields (f):
Gasoline		29,045		46.6		31,340		43.8		29,228		47.4		26,478		44.6
Diesel/jet		20,100		32.2		25,867		36.1		19,937		31.9		20,579		34.6
Asphalt		6,325		10.1		6,374		8.9		5,714		8.2		5,341		9.0
Petrochemicals		4,970		8.0		5,145		7.2		4,753		7.3		4,386		7.4
Other		1,954		3.1		2,876		4.0		2,605		5.2		2,615		4.4
Total refined products manufactured		62,394		100.0		71,602		100.0		62,237		100.0		59,399		100.0

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(a)	Net sales include intersegment sales to our retail segment at prices which approximate market price. These intersegment sales are eliminated through consolidation of our financial statements.
(b)	Gain on disposition of assets in the first six months of 2005 reflects the initial pre-tax gain and the monthly recognition of deferred gain recorded in connection with the HEP transaction.
(c)	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.
(d)	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.
(e)	Total refinery throughput represents the total of crude oil and blendstock inputs in the refinery production process.
(f)	Total refinery yield 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.

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RETAIL SEGMENT

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2004			2005			2004			2005
	(unaudited, dollars in thousands, except for per gallon data)
STATEMENT OF OPERATIONS DATA:
Net sales	$	78,919		$	87,184		$	147,019		$	161,080
Operating Costs and Expenses:
Cost of sales (a)		64,474			72,983			119,926			133,879
Selling, general and administrative expenses		12,572			12,448			24,684			24,307
Depreciation and amortization		1,008			1,051			2,066			2,103
Total operating costs and expenses		78,054			86,482			146,676			160,289
Gain on disposition of assets		175			—			175			—
Operating income	$	1,040		$	702		$	518		$	791
KEY OPERATING STATISTICS:
Number of stores (end of period)		167			167			167			167
Fuel sales (thousands of gallons)		24,712			24,678			48,713			48,066
Fuel sales (thousands of gallons per site per month)		49			49			49			48
Fuel margin (cents per gallon) (b)		12.5	¢		10.3	¢		11.7	¢		11.5	¢
Fuel sales price (cents per gallon)		156.0			212.0			188.0			200.0
Merchandise sales	$	34,292		$	34,860		$	64,946		$	64,855
Merchandise sales (per site per month)		68			70			65			65
Merchandise margin (c)		33.1	%		33.5	%		32.9	%		33.4	%

(a)	Cost of sales include intersegment purchases of motor fuels from our refining and marketing segment at prices which approximate market prices. These intersegment sales are eliminated through consolidation of our financial statements.
(b)	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.
(c)	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 June 30, 2005 Compared to the Three Months Ended June 30, 2004

Net Sales

     Consolidated.Net sales for the three months ended June 30, 2005 were $590.4 million, compared to $440.2 million for the three months ended June 30, 2004, an increase of $150.2 million or 34.1%. This increase is primarily due to higher than average refined product prices over the comparable period in 2004. In addition, refined product sales volume increased over the comparable period in 2004 as a result of the completion of our 8,000 bpd throughput capacity expansion in the first quarter of 2005.

     Refining and Marketing Segment.Net sales for our refining and marketing segment were $542.8 million for the three months ended June 30, 2005, compared to $392.1 million for the three months ended June 30, 2004, an increase of $150.7 million or 38.4%. This increase was primarily due to significantly higher refined product prices. The increase in refined product prices that we experienced were similar to the price increases experienced in the Gulf Coast markets. The average price of Gulf Coast gasoline for the second quarter of 2005 increased 27.8 cents per gallon (“cpg”) to 147.8 cpg, compared to 120.0 cpg in the second quarter of 2004, an increase of 23.2%. The average Gulf Coast diesel price increased by approximately 57.1 cpg to 155.8 cpg in the second quarter of 2005, as compared to 98.7 cpg in the second quarter of 2004, an increase of 57.9%. Also, contributing to the sales revenue increase was an increase in sales volume. Our sales volume increase by 21.9 million gallons, or 6.4%, to 363.9 million gallons for the three months ended June 30, 2005 compared to 342.0 million gallons for the three months

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ended June 30, 2004. This increase in sales volume resulted primarily from the completion of our 8,000 bpd throughput capacity expansion in the first quarter of 2005.

     Retail Segment.Net sales for our retail segment were $87.2 million for the three months ended June 30, 2005 compared to $78.9 million for the three months ended June 30, 2004, an increase of $8.3 million or 10.5%. This increase was primarily attributable to higher average retail fuel prices. Average retail fuel prices were $2.12 per gallon for the second quarter of 2005, compared to average retail fuel prices of $1.56 per gallon for the second quarter of 2004. Our retail merchandise sales increased slightly in the second quarter of 2005 over the first quarter of 2004.

Cost of Sales

     Consolidated.Cost of sales was $498.0 million for the three months ended June 30, 2005, compared to $365.0 million for the three months ended June 30, 2004, an increase of $133.0 million or 36.4%. This increase resulted primarily from higher crude oil prices.

     Refining and Marketing Segment.Cost of sales for our refining and marketing segment was $464.7 million for the three months ended June 30, 2005, compared to $331.4 million for the three months ended June 30, 2004, an increase of $133.3 million or 40.2%. This increase was primarily due to significantly higher crude oil prices. The average price per barrel of WTS for the second quarter of 2005 increased $13.82 per barrel to $49.26 per barrel, compared to $35.44 per barrel for the second quarter of 2004, an increase of 39.0%.

     Retail Segment.Cost of sales for our retail segment was $73.0 million for the three months ended June 30, 2005, compared to $64.5 million for the three months ended June 30, 2004, an increase of $8.5 million or 13.2%. This increase was primarily attributable to higher motor fuel costs.

Direct Operating Expenses

     Direct operating expenses were $20.4 million for the three months ended June 30, 2005, compared to $17.8 million for the three months ended June 30, 2004, an increase of $2.6 million or 14.6%. This increase was primarily attributable to an increase in natural gas prices in the second quarter 2005 compared to the second quarter 2004. The average price of natural gas was $6.95 per MMBTU in the second quarter of 2005, compared to $6.16 per MMBTU for the second quarter of 2004. In addition, overall energy usage increased as a result of the 8,000 bpd crude oil throughput capacity expansion at our Big Spring refinery in the first quarter of 2005.

Selling, General and Administrative Expenses

     Consolidated.SG&A expenses for the three months ended June 30, 2005 were $19.0 million, compared to $19.2 million for the three months ended June 30, 2004, a decrease of $0.2 million or 1.0%. This decrease resulted primarily from lower credit card related fees.

     Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the three months ended June 30, 2005 were $6.4 million, compared to $6.5 million for the three month period ended June 30, 2004, a decrease of $0.1 million or 1.5%. This decrease resulted from lower credit card related fees.

     Retail Segment.SG&A expenses for our retail segment for the three months ended June 30, 2005 were $12.4 million, compared to $12.6 million for the three months ended June 30, 2004, a decrease of $0.2 million or 1.6%. This decrease was primarily attributable to reduced healthcare and workers compensation costs, which were partially offset by higher utility and credit card brokerage fees.

Depreciation and Amortization

     Depreciation and amortization for the three months ended June 30, 2005 was $5.0 million, compared to $4.5 million for the three months ended June 30, 2004. This increase was primarily attributable to the completion of the various capital projects in late 2004 and the first six months of 2005. Partially offsetting this increase was the reduction in depreciation due to the disposition of assets in the HEP transaction.

27

Operating Income

     Consolidated. Operating income for the three months ended June 30, 2005 was $49.5 million, compared to $33.8 million for the three months ended June 30, 2004, an increase of $15.7 million or 46.4%. 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 June 30, 2005 was $49.4 million, compared to operating income for the three months ended June 30, 2004 of $33.3 million, an increase of $16.1 million or 48.3%. This increase was 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 at our Big Spring refinery in the first quarter of 2005. Our refinery operating margin for the second quarter of 2005 increased $1.25 per barrel to $11.83 per barrel, compared to $10.58 per barrel in the second quarter of 2004. This increase was attributable, in part, to higher differentials between refined product prices and crude oil prices. The Gulf Coast 3/2/1 crack spread increased by 12.0% from an average of $9.09 per barrel in the second quarter of 2004 to an average of $10.18 per barrel in the second quarter of 2005. Also contributing to this increase was a widening of the sweet/sour spread. The average sweet/ sour spread increased $.87 per barrel to $3.74 per barrel for the first quarter of 2005 compared to the average sweet/sour spread of $2.87 per barrel for the first quarter of 2004, an increase of 30.3%.

     Retail Segment. Operating income for our retail segment was $0.7 million for the three months ended June 30, 2005, compared to $1.0 million (including a $0.2 million gain on disposition of assets for three months ended June 30, 2004) a decrease of $0.3 million. This decrease was primarily attributable to the $0.2 million gain on disposition of assets realized in the second quarter 2004 and the lower motor fuel margin realized on fuel sales as the significant increase in crude and refined product prices exerted downward pressure on retail motor fuel margins. This decrease was partially offset by the increase in our merchandise margin which increased to 33.5% in the second quarter of 2005, compared to 33.1% in the second quarter of 2004.

Interest Expense

     Interest expense was $4.7 million for the three months ended June 30, 2005, compared to $5.7 million for the three months ended June 30, 2004, a decrease of $1.0 million or 17.5%. This decrease was primarily attributable to the repayment of $25.0 million of debt to Alon Israel in the first quarter of 2005.

Income Tax Expense

     Income tax expense was $16.4 million for the three months ended June 30, 2005, compared to $11.4 million for the three months ended June 30, 2004, an increase of $5.0 million. This increase resulted from our higher taxable income in the second quarter of 2005. Our effective tax rate was 35.7% for the second quarter of 2005 and 40.5% for the second quarter of 2004. We revised our 2005 effective income tax rate from 39.5% to 37.5% in the second quarter of 2005 resulting in a $1.2 million reduction in tax expense.

Minority Interest

     Minority interest represents the proportional share of net income related to the non-voting common stock of two of our subsidiaries, Alon Assets and Alon Operating, not owned by us. Minority interest was $2.0 million for the three months ended June 30, 2005, compared to $1.5 million for the three months ended June 30, 2004, an increase of $0.5 million. This increase was primarily attributable to the increase in net income as a result of the factors discussed above. The increase also reflects the increase in minority interest ownership to 6.4% in the second quarter of 2005 compared to 5.6% in the first quarter of 2005 as a result of the exercise of stock options by the minority interest owners.

Net Income

     Net income was $27.5 million for the three months ended June 30, 2005, compared to $15.3 million for the three months ended June 30, 2004, an increase of $12.2 million or 79.7%. This increase was attributable to the factors discussed above.

28

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

Net Sales

     Consolidated. Net sales for the six months ended June 30, 2005 were $998.3 million, compared to $792.9 million for the six months ended June 30, 2004, an increase of $205.4 million or 25.9%. This increase is primarily due to higher average refined product prices over the comparable period in 2004. This increase was partially offset by reduced refined product sales volume in the first quarter of 2005, compared to the first quarter of 2004, due to reduced production at our Big Spring refinery as a result of our February 2005 major turnaround.

     Refining and Marketing Segment. Net sales for our refining and marketing segment were $909.7 million for the six months ended June 30, 2005, compared to $701.8 million for the six months ended June 30, 2004, an increase of $207.9 million or 29.6%. This increase was primarily due to significantly higher refined product prices. The increase in refined product prices that we experienced were similar to the price increases experienced in the Gulf Coast markets. The average price of Gulf Coast gasoline for the first six months of 2005 increased 28.6 cpg to 140.2 cpg, compared to 111.6 cpg for the first six months of 2004, an increase of 25.6%. The average Gulf Coast diesel price increased by approximately 51.0 cpg to 147.0 cpg for the first six months of 2005, as compared to 96.0 cpg for the first six months of 2004, an increase of 53.1%. This increase was partially offset by reduced refined product sales volume in the first quarter of 2005, due to reduced production at our Big Spring refinery as a result of our February 2005 major turnaround. Our sales volume decreased by 19.0 million gallons, or 2.9%, to 637.0 million gallons for the six months ended June 30, 2005 compared to 656.0 million gallons for the six months ended June 30, 2004. This first quarter decrease in sales volume was partially offset by our 8,000 bpd throughput capacity expansion and resumption of full refinery operations following the successful completion of the major turnaround in the first quarter of 2005.

     Retail Segment.Net sales for our retail segment were $161.1 million for the six months ended June 30, 2005 compared to $147.0 million for the six months ended June 30, 2004, an increase of $14.1 million or 9.6%. This increase was primarily attributable to higher average retail fuel prices. Average retail fuel prices were $2.00 per gallon for the first six months of 2005, compared to average retail fuel prices of $1.88 per gallon for the first six months of 2004. Our retail merchandise margin increased in the first six months of 2005 compared to the first six months of 2004.

Cost of Sales

     Consolidated. Cost of sales was $849.6 million for the six months ended June 30, 2005, compared to $668.0 million for the six months ended June 30, 2004, an increase of $181.6 million or 27.2%. This increase resulted primarily from higher crude oil prices.

     Refining and Marketing Segment. Cost of sales for our refining and marketing segment was $788.2 million for the six months ended June 30, 2005, compared to $604.0 million for the six months ended June 30, 2004, an increase of $184.2 million or 30.5%. This increase was primarily due to significantly higher crude oil prices. The average price per barrel of WTS for the first six months of 2005 increased $13.41 per barrel to $46.98 per barrel, compared to $33.57 per barrel for the first six months of 2004, an increase of 39.9%.

     Retail Segment. Cost of sales for our retail segment was $133.9 million for the six months ended June 30, 2005, compared to $119.9 million for the six months ended June 30, 2004, an increase of $14.0 million or 11.7%. This increase was primarily attributable to higher motor fuel costs.

Direct Operating Expenses

     Direct operating expenses, were $38.7 million for the six months ended June 30, 2005, compared to $36.7 million for the six months ended June 30, 2004, an increase of $2.0 million or 5.4%. This increase was primarily attributable to an increase in natural gas prices in the first six months of 2005 compared to the first six months of 2004. The average price of natural gas was $6.73 per MMBTU for the first six months of 2005, compared to $5.94 per MMBTU for the first six months of 2004. In addition, overall energy usage increased as a result of the 8,000 bpd increase in throughput capacity at the Big Spring refinery as a result of the first quarter throughput expansion.

29

Selling, General and Administrative Expenses

     Consolidated. SG&A expenses for the six months ended June 30, 2005 were $35.6 million, compared to $36.5 million for the six months ended June 30, 2004, a decrease of $0.9 million or 2.5%. This decrease resulted primarily from lower credit card related fees.

     Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the six months ended June 30, 2005 were $11.1 million, compared to $11.6 million for the six month period ended June 30, 2004, a decrease of $0.5 million or 4.3%. This decrease resulted from lower credit card related fees.

     Retail Segment. SG&A expenses for our retail segment for the six months ended June 30, 2005 were $24.3 million, compared to $24.7 million for the six months ended June 30, 2004, a decrease of $0.4 million or 1.6%. This decrease was primarily attributable to reduced healthcare and workers compensation costs, which were partially offset by higher utility and credit card brokerage fees.

Depreciation and Amortization

     Depreciation and amortization for the six months ended June 30, 2005 was $9.9 million, compared to $9.3 million for the six months ended June 30, 2004. This increase was primarily attributable to the completion of the various capital projects in late 2004 and the first six months of 2005. Partially offsetting this increase was the reduction in depreciation due to the disposition of assets in the HEP transaction.

Operating Income

     Consolidated. Operating income (excluding $29.2 million of gain on disposition of assets resulting from the HEP transaction) for the six months ended June 30, 2005 was $64.5 million, compared to $42.4 million (excluding $0.2 million gain on disposition of assets) for the six months ended June 30, 2004, an increase of $22.1 million or 52.1%. This increase was primarily attributable to higher operating income in our refining and marketing segment.

     Refining and Marketing Segment. Operating income for our refining and marketing segment for the six months ended June 30, 2005 was $94.1 million. Excluding $29.2 million of gain on disposition of assets resulting from the HEP transaction, which management believes enhances period-to-period comparability, operating income for our refining and marketing segment for the six months ended June 30, 2005 was $64.9 million, compared to operating income for the six months ended June 30, 2004 of $43.2 million, an increase of $21.7 million or 50.2%. This increase was attributable to the increase in our refinery operating margins and increased sales volumes as a result of the first quarter of 2005 throughput capacity expansion at our Big Spring refinery. Our refinery operating margin for the first six months of 2005 increased $2.74 per barrel to $11.33 per barrel, compared to $8.59 per barrel for the first six months of 2004. This increase was attributable, in part, to higher differentials between refined product prices and crude oil prices. The Gulf Coast 3/2/1 crack spread increased by 6.7% from an average of $7.91 per barrel in the first six months of 2004 to an average of $8.44 per barrel for the first six months of 2005. Also contributing to this increase was a widening of the sweet/sour spread. The average sweet/ sour spread increased $1.21 per barrel to $4.41 per barrel for the first six months of 2005 compared to the average sweet/sour spread of $3.20 per barrel for the first six months of 2004.

     Retail Segment.Operating income for our retail segment was $0.8 million for the six months ended June 30, 2005, compared to $0.5 million for six months ended June 30, 2004, an increase of $0.3 million. This increase was primarily attributable to the increase in our merchandise margin which increased to 33.4% in the first six months of 2005, compared to 32.9% for the first six months of 2004. Partially offsetting this increase was the lower motor fuel margin realized on fuel sales as the significant increase in crude and refined product prices continued to exert downward pressure on retail motor fuel margins.

Interest Expense

     Interest expense was $9.8 million for the six months ended June 30, 2005, compared to $11.7 million for the six months ended June 30, 2004, a decrease of $1.9 million or 16.2%. This decrease was primarily attributable to the repayment of $25.0 million of debt to Alon Israel, in the first quarter of 2005. In addition, 2004 interest expense

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included $0.7 million of non-cash debt issuance costs incurred as a result of entering into our secured term loan facility and repaying our existing term debt in the first quarter of 2004.

Income Tax Expense

     Income tax expense was $32.0 million for the six months ended June 30, 2005, compared to $12.5 million for the six months ended June 30, 2004, an increase of $19.5 million. This increase resulted from our higher taxable income in the six months ended June 30, 2005, which included the recognition of $29.2 million of pre-tax gain on disposition of assets in connection with the HEP transaction. Our effective tax rate was 37.4% for the six months ended June 30, 2005 and 40.4% for the six months ended June 30, 2004.

Minority Interest

     Minority interest represents the proportional share of net income related to the non-voting common stock of two of our subsidiaries, Alon Assets and Alon Operating, not owned by us. Minority interest was $3.6 million for the six months ended June 30, 2005, compared to $1.7 million for the six months ended June 30, 2004, an increase of $1.9 million. This increase was primarily attributable to the increase in net income as a result of the factors discussed above. This increase was partially offset by the overall reduction in minority interest ownership to 6.4% in 2005 compared to 7.6% in 2004 as a result of the repurchase of outstanding shares from one of the minority interest holders.

Net Income

     Net income was $49.9 million for the six months ended June 30, 2005, compared to $16.8 million for the six months ended June 30, 2004, an increase of $33.1 million or 197.0%. 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. We believe that our cash on hand, cash flows from operations, borrowings under our revolving credit facility, proceeds from our initial public offering and other capital resources will be sufficient to satisfy the anticipated cash requirements associated with our existing operations during the next 12 months. Our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive and other factors beyond our control. In addition, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors, including any expansion of our business that we complete.

Cash Flow

     The following table sets forth our consolidated cash flows for the three months ended June 30, 2004 and 2005, and the six months ended June 30, 2004 and 2005:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2004			2005			2004			2005
Non cash provided by (used in):
Operating activities	$	35,126		$	65,413		$	23,926		$	48,976
Investing activities		(22,290	)		(5,244	)		(24,522	)		91,276
Financing activities		3,271			(612	)		32,683			(35,063	)
Net increase in cash and cash equivalents	$	16,107		$	59,557		$	32,087		$	105,189

Cash Flows Provided By Operating Activities

     Net cash provided by operating activities for the six months ended June 30, 2005 was $49.0 million compared to net cash provided by operating activities of $23.9 million for the six months ended June 30, 2004. The $25.1 million net increase in cash provided by operating activities was primarily due to increased operating income of $22.1 million (excluding gain on distribution of assets) in the first six months of 2005 as a result of higher refinery

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operating margins. Additionally, increases in accounts payable as a result of rising crude oil prices and deferred income taxes payable positively impacted cash provided by operating activities in the six months ended June 30, 2005. The most significant use of cash from operating activities in the first six months of 2005 was related to the increase in accounts receivable as a result of higher refined product prices and summer season asphalt sales. The most significant uses of cash in operating activities in the first six months of 2004 were increases in accounts receivable and prepaid purchases for crude oil which were temporary and related to timing of customer drafts and crude purchases.

Cash Flows Provided By (Used In) Investing Activities

     Net cash provided by investing activities for the six months ended June 30, 2005 was $91.3 million compared to net cash used in investing activities of $24.5 million for the six months ended June 30, 2004. This difference was primarily due to the receipt of $118.0 of net cash proceeds in connection with the HEP transaction, which was partially offset by capital expenditures of $27.2 million in the first six months of 2005. Capital expenditures in the six months ended June 30, 2005 included approximately $10.8 million for turnaround and catalyst replacement costs, $1.8 million for the completion of our crude unit expansion, $1.1 million for retail store automation and $7.2 million for the completion of our MACTII regulatory compliance projects.

Cash Flows Provided By (Used In) Financing Activities

     Net cash used in financing activities was $35.1 million during the six months ended June 30, 2005 compared to net cash provided by financing activities of $32.7 million during the six months ended June 30, 2004. Cash used in financing activities in the first six months of 2005 included the payment of $1.5 million of dividends to our minority stockholders and $33.8 million of debt repayments. Cash provided by financing activities in the first six months of 2004 included the net proceeds received in connection with our $100.0 million senior secured term loan.

Initial Public Offering of Alon USA Energy, Inc.

     On August 2, 2005, we completed an initial public offering of 11,730,000 shares of our common stock at a price of $16.00 per share for an aggregate offering price of approximately $187.7 million. We received approximately $172.5 million in net proceeds from the initial public offering after payment of expenses, underwriting discounts and commissions of approximately $15.1 million or $1.29 per share.

     On August 2, 2005, we paid pre-closing stockholders of Alon USA Energy, Inc. aggregate dividends of approximately $68.5 million, and the minority interest stockholders of Alon USA Operating, Inc. were paid aggregate dividends of approximately $4.7 million. During August 2005, we repaid the remaining $20.7 million of outstanding debt owed to our parent company, Alon Israel, and $3.6 million payable to Atofina Petrochemicals, Inc. The remaining proceeds from the initial public offering are currently invested in various highly liquid, low risk debt instruments with maturities of three months or less.

     Our initial public offering, the receipt of proceeds and the use of the proceeds we received, including the distribution of dividends to pre-offering stockholders of record, are not reflected in our financial statements included in this report because the offering was completed after the end of the second quarter.

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.

     As of June 30, 2005, our total cash and cash equivalents were $168.5 million, and we had total indebtedness of approximately $157.9 million. We had $141.1 million face value of letters of credit outstanding and no cash borrowings outstanding under our revolving credit facility.

     Borrowing availability under the revolving credit facility is limited at any time to an amount equal to the lower of $141.6 million and the amount of the borrowing base (as defined in the revolving credit agreement). In addition,

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we have a separate credit facility for the issuance of letters of credit of up to $20.0 million. As of June 30, 2005, the borrowing base under the revolving credit facility exceeded the $141.6 million maximum borrowing capacity by $140.0 million. The entire revolving credit facility is available in the form of letters of credit, and $82.0 million of the revolving credit facility is available in the form of revolving loans. The borrowings under the revolving credit facility bear interest at the Eurodollar rate plus 2.50% per annum. The borrowings under the revolving credit facility are jointly and severally guaranteed by substantially all of our subsidiaries, and such borrowings are secured by a pledge of substantially all of our and our subsidiaries’ assets, including cash, accounts receivable and inventory.

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 2005 is $35.2 million, of which $16.4 million, primarily related to the crude unit expansion and regulatory compliance and $10.8 million related to turnaround and chemical catalysts, had been spent as of June 30, 2005.

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

     As of June 30, 2005, we had completed substantially all of the expenditures required to meet regulatory requirements under the Voluntary Emission Reduction Permit program, or VERP, sponsored by the Texas Commission on Environmental Quality, or TCEQ, and for Maximum Achievable Control Technologies for petroleum refineries, or MACT II, which required additional air emission controls for certain processing units at our Big Spring refinery.

     Turnaround and Chemical Catalyst Costs.We completed a major turnaround on substantially all of our major processing units, including the crude unit and the fluid catalytic cracking unit, in the first week of March 2005, at a cost of approximately $7.7 million. Chemical catalyst replacement costs associated with the turnaround were approximately $3.1 million.

Contractual Obligations and Commercial Commitments

     Information regarding our known contractual obligations of the types described below as of June 30, 2005 is set forth in the following table. As of June 30, 2005, we did not have any capital lease obligations or any agreements to purchase goods or services that were binding on us and that specified all significant terms.

	Payments Due by Period
	Less Than							More Than
Contractual Obligations	1 Year		1-3 Years		3-5 Years			5 Years		Total
	(dollars in thousands)
Long-term debt obligations (a)	$	4,904	$	13,873	$	97,122	(b)	$	42,002	$	157,901
Operating lease obligations		5,807		28,070		14,182			7,540		55,599
Pipelines and Terminals Agreement (c)		9,811		58,863		39,242			179,859		287,775
Other commitments (d)		3,747		12,483		5,654			34,636		56,520
Total obligations	$	24,269	$	113,289	$	156,200		$	264,037	$	557,795

(a)	We repaid approximately $24.3 million of outstanding debt with a portion of the proceeds received from our initial public offering, of which $3.6 million was due within one year and $20.7 million was due within five years.
(b)	Includes $92.5 million of indebtedness owed under our term loan. We have the right to prepay our term loan commencing in January 2006. We intend to repay all amounts outstanding under the term loan in the first quarter of 2006.
(c)	Balances represent the minimum committed volume multiplied by the tariff and terminal rates pursuant to the terms of the Pipelines and Terminals Agreement with HEP. See “Business — Pipelines and Product Terminals — HEP transaction.”

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(d) Other commitments include refinery maintenance services costs and management fees to our parent. These management fees were terminated in connection with our initial public offering for an aggregate payment of $6.0 million, of which $2.0 million is payable in August 2005 and the remaining $4.0 million is due in the first quarter of 2006.

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” in our registration statement on Form S-1 (Registration No. 333-124797) declared effective by the SEC on July 27, 2005 for the period ended March 31, 2005 and the year ended December 31, 2004. 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. No significant changes to these accounting policies have occurred subsequent to December 31, 2004.

Reconciliation of Amounts Reported Under Generally Accepted Accounting Principles

     Reconciliation of earnings before minority interest, income tax expense, interest expense, depreciation, amortization and gain on disposition of assets (“EBITDA”) to amounts reported under generally accepted accounting principles in financial statements.

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

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

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

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

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

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

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

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

     The following table reconciles net income to Adjusted EBITDA for the three months and six months ended June 30, 2004 and 2005, respectively:

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2004			2005			2004			2005
				(dollars in thousands)
Net income	$	15,288		$	27,482		$	16,785		$	49,918
Minority interest		1,487			2,001			1,700			3,566
Income Tax Expense		11,415			16,354			12,534			32,009
Interest Expense		5,676			4,745			11,691			9,752
Depreciation and amortization		4,504			5,018			9,266			9,852
Gain on disposition of assets		(175	)		(1,530	)		(175	)		(29,223	)
Adjusted EBITDA	$	38,195		$	54,070		$	51,801		$	75,874

New Accounting Standards and Disclosures

     In December 2004, the FASB issued Statement of Accounting Standards No. 123R, “Share-Based Payment” (SFAS No. 123R), which requires expensing stock options and other share-based compensation payments to employees and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing pro forma disclosure only. This standard is effective for us as of January 1, 2006 and will apply to all awards granted, modified, cancelled or repurchased after that date as well as the unvested portion of prior awards. Because we use the minimum value method of measuring equity share options for pro forma disclosure purposes under SFAS No. 123, we will apply SFAS 123R prospectively to new awards and to awards modified, repurchased or cancelled after January 1, 2006. The adoption of SFAS No. 123R is not expected to materially affect our financial position or results of operations.

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

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

     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” which requires a company that qualified for the deduction for domestic production activities under the 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. We are currently reviewing the effects of this FSP, but do not anticipate any tax contingencies or significant changes to the effective tax rate as a result of the application of this pronouncement.

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

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

     In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Errors Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3.” This statement changes the requirements for accounting for and reporting a change in accounting principles and applies to all voluntary changes in accounting principles. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. This statement requires retrospective application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of change. This statement becomes effective for fiscal years beginning after December 15, 2005.

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.

     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 June 30, 2005, we held approximately 1.9 million barrels of crude and product inventories valued under the LIFO valuation method with an average cost of $31.84 per barrel. Market value exceeded carrying value of LIFO costs by $49.4 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 to $47.5 million.

     In accordance with SFAS No. 133, all commodity futures contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section of our consolidated financial statements. As of June 30, 2005, our open future positions were immaterial.

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Interest Rate Risk.

     As of June 30, 2005, $100.0 million of our outstanding debt was at floating interest rates. Outstanding borrowings under our term loan bear interest at a rate per annum equal to an alternate base rate, not to be less than 4.50%, plus 5.50%, or LIBOR, not to be less than 3.50%, plus 6.50%. Consequently, we are exposed with respect to this loan to interest rate risk during periods in which the alternate base rate and LIBOR are higher than 4.50% and 3.50%, respectively. An increase of 1.0% in the alternate base rate above 4.5% or in LIBOR above 3.5% would result in an increase in our interest expense of approximately $1.0 million per year.

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 Alon’s 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 2. Unregistered Sale of Equity Securities and Use of Proceeds

Use of Proceeds

     On July 27, 2005, the SEC declared effective our registration statements on Form S-1 (Registration Nos. 333-124797 and 333-126952) related to our sale of up to 11,730,000 shares or our common stock at a maximum aggregate offering price of approximately $187.7 million. On August 2, 2005, we completed an initial public offering of all 11,730,000 registered shares at a price of $16.00 per share for an aggregate offering price of approximately $187.7 million. Of the aggregate gross proceeds, approximately $2.0 million was used to pay offering expenses related to the initial public offering, and $13.1 million was used to pay underwriting discounts and commissions. None of the expenses incurred and paid by us in this offering were direct or indirect payment (i) to our directors, officers, general partners or their associates, (ii) to persons owning 10% or more of any class of our equity securities, or (iii) to our affiliates. Net proceeds of the offering after payment of expenses and underwriting discounts and commission were approximately $172.5 million.

     The offering was made through an underwriting syndicate led by Credit Suisse First Boston, Deutsch Bank Securities and Lehman Brothers as joint book-running managers.

     As of August 15, 2005, we used the net proceeds from the offering as follows:

• payment of a dividend in the amount of approximately $65.7 million to Alon Israel Oil Company, Ltd., a stockholder of the Company;

• payment of a dividend in the amount of approximately $2.7 million to Tabris Investments Inc., a stockholder of the Company;

• payment of a dividend in the amount of approximately $4.7 million to the minority stockholders of Alon USA Operating, Inc., a subsidiary of the Company; and

• approximately $20.7 million was used to repay debt due to our parent company, Alon Israel, and $3.6 million was used to repay debt due to Atofina Petrochemicals, Inc.

Item 4. Submission of Matters to a Vote Security Holders

     On July 6, 2005, our stockholders, at a special meeting of stockholders, unanimously approved an amendment and restatement to our Certificate of Incorporation in connection with our initial public offering of common stock. On July 7, 2005, our stockholders, at a special meeting of stockholders, unanimously approved (i) an amendment and restatement to our Bylaws, (ii) forms of Indemnification Agreement for our officers and directors and (iii) adoption of our 2005 Incentive Compensation Plan and authorized us to obtain insurance for our directors and officers.

Item 6. Exhibits

Exhibit
Number	Description of Exhibit
3.1	Amended Restated Certificate of Incorporation of Alon USA Energy, Inc. (previously filed as 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. (previously filed as 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 (previously filed as Exhibit 4.1 to Form S-1, filed by the Company on June 17, 2005, SEC File No. 333-124797).

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Exhibit
Number	Description of Exhibit
10.1	Second Amendment, dated as of May 6, 2005, to the Amended and Restated Credit Agreement, dated as of January 14, 2004, among Alon USA Energy, Inc., the lenders listed therein and Credit Suisse First Boston (previously filed as Exhibit 10.18 to Form S-1, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.2	Second Amendment, dated as of June 16, 2005, to the Amended Revolving Credit Agreement, dated as of January 14, 2005, among Alon USA, LP, the guarantor companies and financial institutions identified therein and Israel Discount Bank of New York (previously filed as Exhibit 10.20.1 to Form S-1, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.3	Amendment, dated as of June 17, 2005, to the Management and Consulting Agreement, dated as of August 1, 2003, among Alon USA, Inc., Alon Israel Oil Company, Ltd. and Alon USA Energy, Inc. (previously filed as Exhibit 10.21.1 to Form S-1, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.4	Registration Rights Agreement, dated as of July 6, 2005, between Alon USA Energy, Inc. and Alon Israel Oil Company, Ltd. (previously filed as Exhibit 10.22 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).
10.5	Executive Employment Agreement, dated as of July 31, 2000, between Jeff D. Morris and Alon USA GP, Inc., as amended on May 4, 2005 (previously filed as Exhibit 10.23 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.6	Executive Employment Agreement, dated as of July 31, 2000, between Claire A. Hart and Alon USA GP, Inc., as amended on May 4, 2005 (previously filed as Exhibit 10.24 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.7	Executive Employment Agreement, dated as of February 5, 2001, between Joseph A. Concienne, III and Alon USA GP, Inc., as amended on May 4, 2005 (previously filed as Exhibit 10.25 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.8	Management Employment Agreement, dated as of October 1, 2002, between Harlin R. Dean and Alon USA GP, LLC, as amended on May 4, 2005 (previously filed as Exhibit 10.26 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.9	Description of Director Compensation (previously filed as Exhibit 10.30 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.10	Form of Director Indemnification Agreement (previously filed as Exhibit 10.31 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.11	Form of Officer Indemnification Agreement (previously filed as Exhibit 10.32 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.12	Form of Director and Officer Indemnification Agreement (previously filed as Exhibit 10.33 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.13	Agreement of Principles of Employment, dated as of July 6, 2005, between David Wiessman and Alon USA Energy, Inc. (previously filed as Exhibit 10.50 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).
10.14	Alon USA Energy, Inc. 2005 Incentive Compensation Plan. (previously filed as Exhibit 10.51 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).
10.15	Agreement, dated as of July 6, 2005, by and among Alon USA Energy, Inc., Alon USA, Inc., Alon USA Capital, Inc., Alon USA Operating, Inc., Alon Assets, Inc., Jeff D. Morris, Claire A. Hart and Joseph A. Concienne, III (previously filed as Exhibit 10.52 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).
31.1	Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.

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Exhibit
Number	Description of Exhibit
31.2	Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification 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.

	ALON USA ENERGY, INC.
Date: August 22, 2005	By:	/s/ David Wiessman
		David Wiessman
		Executive Chairman

Date: August 22, 2005	By:	/s/ Jeff D. Morris
		Jeff D. Morris
		Chief Executive Officer

Date: August 22, 2005	By:	/s/ Shai Even
		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. (previously filed as 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. (previously filed as 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 (previously filed as Exhibit 4.1 to Form S-1, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.1	Second Amendment, dated as of May 6, 2005, to the Amended and Restated Credit Agreement, dated as of January 14, 2004, among Alon USA Energy, Inc., the lenders listed therein and Credit Suisse First Boston (previously filed as Exhibit 10.18 to Form S-1, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.2	Second Amendment, dated as of June 16, 2005, to the Amended Revolving Credit Agreement, dated as of January 14, 2005, among Alon USA, LP, the guarantor companies and financial institutions identified therein and Israel Discount Bank of New York (previously filed as Exhibit 10.20.1 to Form S-1, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.3	Amendment, dated as of June 17, 2005, to the Management and Consulting Agreement, dated as of August 1, 2003, among Alon USA, Inc., Alon Israel Oil Company, Ltd. and Alon USA Energy, Inc. (previously filed as Exhibit 10.21.1 to Form S-1, filed by the Company on June 17, 2005, SEC File No. 333-124797).
10.4	Registration Rights Agreement, dated as of July 6, 2005, between Alon USA Energy, Inc. and Alon Israel Oil Company, Ltd. (previously filed as Exhibit 10.22 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).
10.5	Executive Employment Agreement, dated as of July 31, 2000, between Jeff D. Morris and Alon USA GP, Inc., as amended on May 4, 2005 (previously filed as Exhibit 10.23 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.6	Executive Employment Agreement, dated as of July 31, 2000, between Claire A. Hart and Alon USA GP, Inc., as amended on May 4, 2005 (previously filed as Exhibit 10.24 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.7	Executive Employment Agreement, dated as of February 5, 2001, between Joseph A. Concienne, III and Alon USA GP, Inc., as amended on May 4, 2005 (previously filed as Exhibit 10.25 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.8	Management Employment Agreement, dated as of October 1, 2002, between Harlin R. Dean and Alon USA GP, LLC, as amended on May 4, 2005 (previously filed as Exhibit 10.26 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.9	Description of Director Compensation (previously filed as Exhibit 10.30 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.10	Form of Director Indemnification Agreement (previously filed as Exhibit 10.31 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.11	Form of Officer Indemnification Agreement (previously filed as Exhibit 10.32 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).
10.12	Form of Director and Officer Indemnification Agreement (previously filed as Exhibit 10.33 to Form S-1, filed by the Company on May 11, 2005, SEC File No. 333-124797).

42

Exhibit
Number	Description of Exhibit
10.13	Agreement of Principles of Employment, dated as of July 6, 2005, between David Wiessman and Alon USA Energy, Inc. (previously filed as Exhibit 10.50 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).
10.14	Alon USA Energy, Inc. 2005 Incentive Compensation Plan. (previously filed as Exhibit 10.51 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).
10.15	Agreement, dated as of July 6, 2005, by and among Alon USA Energy, Inc., Alon USA, Inc., Alon USA Capital, Inc., Alon USA Operating, Inc., Alon Assets, Inc., Jeff D. Morris, Claire A. Hart and Joseph A. Concienne, III (previously filed as Exhibit 10.52 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).
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*	Certification 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.

43