Alon USA Energy 10Q 2005 Q3 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 SEPTEMBER 30, 2005


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

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

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

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

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

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

The number of shares of the Registrant’s common stock, par value $0.01 per share, outstanding as of November 9, 2005 was 46,797,357.

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		5
CONDENSED BALANCE SHEETS		16

ITEM 1.(b) SCHEDULES TO THE FINANCIAL STATEMENTS (PARENT ONLY) – SCHEDULE I		16

CONDENSED STATEMENTS OF OPERATIONS		17
CONDENSED STATEMENTS OF CASH FLOWS		18
NOTES TO CONDENSED FINANCIAL STATEMENTS		19

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		20
Forward-Looking Statements		20

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK		39

ITEM 4. CONTROLS AND PROCEDURES		41

PART II. OTHER INFORMATION		42

ITEM 2. UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS		42

ITEM 6. EXHIBITS		43

SIGNATURES		44
EXHIBITS		45
CERTIFICATION OF CEO PURSUANT TO SECTION 302
CERTIFICATION OF CFO PURSUANT TO SECTION 302
CERTIFICATION OF CEO AND CFO PURSUANT TO SECTION 906
Certifications of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO and CFO Pursuant to Section 906

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)


	September 30,			December 31,
	2005			2004
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	193,294		$	63,357
Short-term investments		29,675			—
Accounts and other receivables, net		112,683			69,328
Inventories		97,743			79,329
Prepaid expenses and other current assets		10,032			2,441

Total current assets		443,427			214,455

Investment in HEP		22,963			—
Property, plant and equipment, net		210,266			236,228
Other assets		27,127			21,833

Total assets	$	703,783		$	472,516


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	183,012		$	153,897
Current portion of deferred gain on disposition of assets		5,741			—
Current portion of long-term debt		4,461			16,115

Total current liabilities		193,214			170,012

Other non-current liabilities		16,739			19,436
Deferred gain on disposition of assets		59,798			—
Long-term debt		128,416			171,591
Deferred income tax liability		51,064			31,829

Total liabilities		449,231			392,868

Commitments and contingencies (note 16)
Minority interest in subsidiaries		4,803			8,176

Stockholders’ equity:
Preferred stock, par value $0.01, 10,000,000 shares authorized; no shares issued and outstanding		—			—
Common stock, par value $0.01, 100,000,000 shares authorized; 46,797,357 and 35,001,120 shares issued and outstanding at September 30, 2005 and December 31, 2004, respectively		468			350
Additional paid-in capital		180,711			8,379
Accumulated other comprehensive loss		(2,261	)		(2,261	)
Retained earnings		70,831			65,004

Total stockholders’ equity		249,749			71,472

Total liabilities and stockholders’ equity	$	703,783		$	472,516

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

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 Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Net sales	$	648,135		$	445,386		$	1,646,475		$	1,238,288
Operating costs and expenses:
Cost of sales		565,820			389,976			1,415,421			1,058,002
Direct operating expenses		24,550			18,121			63,259			54,814
Selling, general and administrative expenses		16,083			15,364			51,731			51,890
Depreciation and amortization		5,470			4,893			15,322			14,159

Total operating costs and expenses		611,923			428,354			1,545,733			1,178,865

Gain on disposition of assets		8,020			—			37,243			175

Operating income		44,232			17,032			137,985			59,598
Interest expense		4,827			5,888			14,579			17,579
Equity earnings in HEP		(321	)		—			(733	)		—
Other income, net		(1,269	)		(63	)		(2,349	)		(207	)

Income before income tax expense and minority interest in income of subsidiaries		40,995			11,207			126,488			42,226
Income tax expense		16,225			4,488			48,234			17,022

Income before minority interest in income of subsidiaries		24,770			6,719			78,254			25,204
Minority interest in income of subsidiaries		382			619			3,948			2,319

Net income	$	24,388		$	6,100		$	74,306		$	22,885

Earnings per share	$	.57		$	.17		$	1.98		$	.65

Weighted average shares outstanding		42,821,120			35,001,120			37,607,787			35,001,120

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

ALON USA ENERGY, INC., AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW

(unaudited, dollars in thousands)


	For the Nine Months Ended
	September 30,
	2005			2004
Cash flows from operating activities:
Net income	$	74,306		$	22,885
Adjustments:
Depreciation and amortization		15,322			14,159
Stock compensation		1,693			399
Deferred income tax expense		14,599			—
Minority interest in income of subsidiaries		3,948			2,319
Accrued interest on subordinated notes to stockholders		—			2,773
Gain on disposition of assets		(37,243	)		(175	)
Changes in operating assets and liabilities:
Accounts and other receivables, net		(43,355	)		(19,177	)
Inventories		(18,414	)		(9,668	)
Prepaid expenses and other current assets		(5,069	)		181
Other assets		2,331			3,375
Accounts payable and accrued liabilities		27,815			15,021
Other non-current liabilities		(3,451	)		(2,564	)

Net cash provided by operating activities		32,482			29,528


Cash flows from investing activities:
Capital expenditures		(17,568	)		(18,125	)
Turnaround and chemical catalyst expenditures		(11,371	)		(1,698	)
Proceeds from disposition of assets, net		118,000			328
Net purchases of short-term investments		(29,675	)		—
Deferred payment on acquisition of minority interest in subsidiary		—			(10,000	)
Acquisition of asphalt business		—			(580	)
Dividends from investment in HEP (net of equity earnings)		322			—
Minority interest shares purchased		(5,098	)		—

Net cash provided by (used in) investing activities		54,610			(30,075	)


Cash flows from financing activities:
Payments received for shares issued, net		172,287			140
Dividends paid to minority interest shareholders		(6,134	)		—
Dividends paid to shareholders		(68,479	)		—
Net payments on revolving credit facilities		—			(19,600	)
Deferred debt issuance costs		—			(1,885	)
Additions to long-term debt		2,936			99,831
Payments on long-term debt		(57,765	)		(51,491	)

Net cash provided by financing activities		42,845			26,995


Net increase in cash and cash equivalents		129,937			26,448
Cash and cash equivalents, beginning of period		63,357			7,256

Cash and cash equivalents, end of period	$	193,294		$	33,704


Supplemental cash flow information:
Cash paid for interest	$	13,283		$	11,103

Cash paid for income tax	$	21,467		$	12,084

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

ALON USA ENERGY, INC., AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW

(unaudited, dollars in thousands)


	For the Nine Months Ended
	September 30,
	2005		2004
Non-cash activities:
Financing activity — receipt of Class B HEP subordinated units as proceeds from disposition of assets	$	30,000	$	—


Asphalt Business Acquisition:
Property, plant and equipment acquired	$	—	$	(3,917	)
Net working capital acquired (accounts and other receivables, net inventories, accounts payable		—		817
Net debt assumed		—		2,520

Cash used in acquisition of asphalt business	$	—	$	(580	)

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

ALON USA ENERGY, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands, except share and per share data)

(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 (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements. In the opinion of 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 that may be obtained 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).

On July 6, 2005, the Company (i) increased its authorized common shares to 100,000,000 and (ii) effected a 33,600-for-1 stock split of its common shares, resulting in 35,001,120 common shares outstanding. The earnings per share information and all common share information have been retroactively restated for the 2005 and 2004 periods presented to reflect this stock split.

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 September 30, 2005 and 2004, the Company recorded revenues related to linked refined product sales of $5,758 and $11,566, respectively. For the three months ended September 30, 2005 and 2004, the Company recorded costs related to linked refined product sales of $5,830 and $11,595, respectively.

For the nine months ended September 30, 2005 and 2004, the Company recorded revenues related to linked refined product sales of $25,570 and $52,845, respectively. For the nine months ended September 30, 2005 and 2004, the Company recorded costs related to linked refined product sales of $25,943 and $53,094, respectively.

(2)

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 $172,158 in net proceeds from the initial public offering after payment of expenses, underwriting discounts and commissions of approximately $15,522, or $1.32 per share. The initial public offering represented the sale of a 25.1% interest in the Company.

The Company’s use of proceeds from the initial public offering included the distribution of dividends to pre-offering stockholders of record (note 14(b)), and the prepayment of debt (note 12).

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands, except per share data)

(3)

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 units of 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 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 initial 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 September 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 remaining deferred gain will be recognized over a period of approximately 12 years or less depending on circumstances described in the indemnification agreement. The Company exercised its rights under the indemnification agreement to reduce the indemnity amount by $10,000, resulting in an additional gain of $6,499, and a corresponding decrease in the deferred gain balance. The deferred gain is recorded $5,741 as a current liability and $59,798 as a long-term liability in the September 30, 2005 consolidated balance sheet.

(4)

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.

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands)

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 September 15, 2005. The adoption of Statement No. 153 had no impact on the Company’s financial position or results of operations.

In December 2004 the FASB issued FASB Staff Position (“FSP”) FAS 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, for the Tax Deduction Provided to U.S. Based Manufacturers by the American Jobs Creation Act of 2004” (“Jobs Creation Act”) which requires a company that qualifies for the deduction for domestic production activities under the Jobs Creation Act to account for it as a special deduction under FASB Statement No. 109, Accounting for Income Taxes, as opposed to an adjustment of recorded deferred tax assets and liabilities. The Company has included the effects of this FSP in its calculation of the September 30, 2005 deferred income tax provision.

In September 2005, the Emerging Issues Task Force, (EITF) reached a consensus concerning the accounting for linked purchase and sale arrangements in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The EITF concluded that non-monetary exchanges of finished goods inventory within the same line of business be recognized at the carrying value of the inventory transferred. The consensus is to be applied to new buy/sell arrangements entered in reporting periods beginning after March 15, 2006. The Company does not expect the impact of this EITF Issue No. 04-13 consensus to have a material effect on the Company’s financial position or results of operations.

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.

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands)

(5)

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 the Company’s complex sour crude oil refinery, its owned crude oil pipeline systems 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.

(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.

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

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


	For the Three Months Ended September 30, 2005
	Refining and						Corporate
	Marketing			Retail			and other			Eliminations			Consolidated
Net sales:
Unaffiliated customers	$	558,671		$	89,464		$	—		$	—		$	648,135
Intersegment		41,816			—			—			(41,816	)		—

Total net sales	$	600,487		$	89,464		$	—		$	(41,816	)	$	648,135

Operating income (loss)	$	42,645		$	2,191		$	(604	)	$	—		$	44,232
Interest expense		(3,916	)		(911	)		—			—			(4,827	)
Other income, net		314			—			1,276			—			1,590

Income before income tax expense and minority interest	$	39,043		$	1,280		$	672		$	—		$	40,995

Total assets	$	619,458		$	72,188		$	12,137		$	—		$	703,783
Depreciation and amortization		3,906			1,087			477			—			5,470
Turnaround, chemical catalyst and capital expenditures		784			873			42			—			1,699


	For the Three Months Ended September 30, 2004
	Refining and						Corporate
	Marketing			Retail			and other			Eliminations			Consolidated
Net sales:
Unaffiliated customers	$	366,549		$	78,837		$	—		$	—		$	445,386
Intersegment		30,917			—			—			(30,917	)		—

Total net sales	$	397,466		$	78,837		$	—		$	(30,917	)	$	445,386

Operating income (loss)	$	16,461		$	1,156		$	(585	)	$	—		$	17,032
Interest expense		(4,865	)		(1,023	)		—			—			(5,888	)
Other income (expense), net		64			(69	)		68			—			63

Income (loss) before income tax expense and minority interest	$	11,660		$	64		$	(517	)	$	—		$	11,207

Total assets	$	369,984		$	70,769		$	13,428		$	—		$	454,181
Depreciation and amortization		3,446			1,002			445			—			4,893
Turnaround, chemical catalyst and capital expenditures		3,429			1,394			150			—			4,973

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


	For the Nine Months Ended September 30, 2005
	Refining and						Corporate
	Marketing			Retail			and other			Eliminations			Consolidated
Net sales:
Unaffiliated customers	$	1,395,931		$	250,544		$	—		$	—		$	1,646,475
Intersegment		114,264		—			—			(114,264	)		—

Total net sales	$	1,510,195		$	250,544		$	—		$	(114,264	)	$	1,646,475

Operating income (loss)	$	136,812		$	2,982		$	(1,809	)	$	—		$	137,985
Interest expense		(11,928	)		(2,651	)		—			—			(14,579	)
Other income, net		701			—			2,381			—			3,082

Income before income tax expense and minority interest		125,585		$	331		$	572		$	—		$	126,488

Total assets	$	619,458		$	72,188		$	12,137		$	—		$	703,783
Depreciation and amortization		10,706			3,190			1,426			—			15,322
Turnaround, chemical catalyst and capital expenditures		25,834			2,903			202			—			28,939


	For the Nine Months Ended September 30, 2004
	Refining and						Corporate
	Marketing			Retail			and other			Eliminations			Consolidated
Net sales:
Unaffiliated customers	$	1,012,432		$	225,856		$	—		$	—		$	1,238,288
Intersegment		86,812			—			—			(86,812	)		—

Total net sales	$	1,099,244		$	225,856		$	—		$	(86,812	)	$	1,238,288

Operating income (loss)	$	59,613		$	1,674		$	(1,689	)	$	—		$	59,598
Interest expense		(14,922	)		(2,657	)		—			—			(17,579	)
Other income (expense), net		128			(74	)		153			—			207

Income (loss) before income tax expense and minority interest	$	44,819		$	(1,057	)	$	(1,536	)	$	—		$	42,226

Total assets	$	369,984		$	70,769		$	13,428		$	—		$	454,181
Depreciation and amortization		9,796			3,068			1,295			—			14,159
Turnaround, chemical catalyst and capital expenditures		16,651			2,610			562			—			19,823

(6)

Cash, Cash Equivalents and Short-Term Investments

The Company’s investment portfolio consists of cash and cash equivalents, including demand deposits and money market accounts. All highly-liquid instruments with a maturity of three months or less at the time of purchase are considered 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 ratings.

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

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

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 owed to the Company’s parent, Alon Israel Oil Company, Ltd. (“Alon Israel”), and paid a dividend of $1,482 to current minority interest owners (see note 3). On August 2, 2005, the Company completed its initial public offering. Net cash proceeds from the initial public offering after fees and commission, closing costs, prepayment of debt and distribution of dividends were $72,306 (see note 2).

(7)

Derivative Financial Instruments

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

At September 30, 2005, the Company held net forward contracts for purchases of 85 thousand barrels of refined products at an average price of $126.29 per barrel. As of September 30, 2005, these forward contracts had a fair value of $9,031. At September 30, 2004, the Company held net forward contracts for purchases of 30 thousand barrels of refined products at an average price of $51.88 per barrel. At September 30, 2004, these forward contracts had a fair value of $1,631. At September 30, 2004, the Company held net futures contracts for sale of 25 thousand barrels of crude oil at an average price of $44.50 per barrel. At September 30, 2004, these futures contracts had a fair value of $1,241. None of these contracts were designated as hedges for accounting purposes. Accordingly, net unrealized losses of $1,704 and $54 were recorded as a reduction of net sales in the September 30, 2005 and 2004 consolidated statement of operations, respectively.

(8)

Inventories

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

Carrying value of inventories consisted of the following:


	September 30,		December 31,
	2005		2004
Crude oil, refined products, and blendstocks	$	74,432	$	58,412
Materials and supplies		5,743		5,570
Store merchandise		13,051		12,860
Store fuel		4,517		2,487

Total inventories	$	97,743	$	79,329

Market values exceeded LIFO costs by $87,377 and $25,756 at September 30, 2005 and December 31, 2004, respectively.

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands, except for share and per share data)

(9)

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 pro rata gain in the consolidated balance sheet as of September 30, 2005 as a basis adjustment. The Company recognized $733 in equity earnings in investee and recorded the receipt of a $1,055 cash distribution from HEP during the first nine months of 2005 (note 3).

(10)

Property, Plant, and Equipment

Property, plant, and equipment consisted of the following:


	September 30,			December 31,
	2005			2004
Refining facilities	$	167,782		$	149,016
Pipelines and terminals		26,598			69,289
Retail		62,709			59,543
Other		10,266			9,323

Property, plant, and equipment, gross		267,355			287,171
Less accumulated depreciation		(57,089	)		(50,943	)

Property, plant, and equipment, net	$	210,266		$	236,228

On February 28, 2005, the Company completed the contribution of three pipelines and three product terminals to HEP (note 3).

(11)

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 nine months ended September 30, 2005 and 2004, the Company contributed $3,249 and $2,131, respectively, to its qualified pension plan.

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


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Components of net periodic benefit cost:
Service cost	$	382		$	332		$	1,075		$	995
Interest cost		535			457			1,492			1,370
Expected return on plan assets		(414	)		(347	)		(1,241	)		(1,041	)
Amortization of net loss		181			140			513			422

Net periodic benefit cost	$	684		$	582		$	1,839		$	1,746

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands, except for share and per share data)

(12)

Long-Term Debt

(a)

Revolving Credit Facility

In January 2004, the Company amended its existing revolving credit facility, extending the term for an additional three years and increasing the available aggregate commitments under the facility to $141,600. 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 rate 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 September 30, 2005. As of September 30, 2005 and 2004, the Company had $130,244 and $113,651, respectively, of outstanding letters of credit under the revolving credit facility and the other credit facility.

(b)

Debt Repayment

On February 28, 2005, the Company made a $25,000 debt payment to Alon Israel (see note 6). In August 2005, the Company prepaid the remaining principal and interest of $20,709 on the debt owed to Alon Israel and the remaining $3,631 of the deferred purchase price debt owed to Atofina Petrochemicals (note 2).

(13)

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 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.

The Company issued 66,237 restricted shares of its common stock to certain employees and directors subsequent to the August 2, 2005 initial public offering. These shares vest ratably on an annual basis, over a three year period.

(14)

Stockholders Equity

(a)

Stock Split

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands, except for share and per share data)

(b)

Special Dividends

Upon the completion of the Company’s initial public offering on August 2, 2005 (note 2), the board 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.

(c)

Initial Public Offering

On August 2, 2005 the Company completed an initial public offering of 11,730,000 shares of its common stock at an aggregate offering price of $187,680. The Company received approximately $172,158 in net proceeds from the initial public offering (see note 2).

(15)

Earnings Per Share

Basic and diluted earnings per share are computed by dividing net income by the weighted average of the common shares outstanding. Weighted average common share and earnings per common share amount for the three and nine months ended September 30, 2005 and 2004 have been restated to reflect the effect of a 33,600-for-one split of the Company’s common stock which was effected on July 6, 2005. On August 2, 2005, the Company completed an initial public offering of 11,730,000 shares of its common stock, which are included in the calculation of weighted average number of shares outstanding. As of September 30, 2005, there were 10,317 potentially dilutive common shares outstanding.

(16)

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

ALON USA ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands, except for share and per share data)

have no future economic benefit are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Substantially all amounts accrued are expected to be paid out over the next five to ten years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

The Company had accrued environmental remediation obligations of $5,150 ($3,000 current payable and $2,150 non-current liability) at September 30, 2005 and $7,058 ($3,000 current payable and $4,058 non-current liability) at December 31, 2004.

ALON USA ENERGY, INC. (PARENT COMPANY ONLY)

CONDENSED BALANCE SHEETS

(dollars in thousands)

ITEM 1.(b) SCHEDULES TO THE FINANCIAL STATEMENTS (PARENT ONLY) — SCHEDULE I


	September 30,			December 31,
	2005			2004
	(Unaudited)
ASSETS
Current assets	$	88,493		$	2,126
Investment in subsidiary		161,314			111,558

Total assets	$	249,807		$	113,684


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	—		$	511
Long-term debt		—			41,701
Long-term liabilities		58			—

Total liabilities		58			42,212

Shareholders’ equity:
Shareholders’ investment		181,179			8,729
Accumulated other comprehensive loss		(2,261	)		(2,261	)
Retained earnings		70,831			65,004

Total stockholders’ equity		249,749			71,472

Total liabilities and stockholders’ equity	$	249,807		$	113,684

ALON USA ENERGY, INC. (PARENT COMPANY ONLY)

CONDENSED STATEMENTS OF OPERATIONS

(unaudited, dollars in thousands)


	For the Three Months Ended					For the Nine Months Ended
	September 30,					September 30,
	2005		2004			2005			2004
Interest income	$	424	$	—		$	424		$	—

General and administrative expenses		87		—			87			3
Interest expense		102		688			1,081			2,067

Income (loss) before income tax expense (benefit) and equity earnings in subsidiary		235		(688	)		(744	)		(2,070	)
Income tax expense (benefit)		93		(281	)		(294	)		(818	)

Income (loss) before equity earnings in subsidiary		142		(407	)		(450	)		(1,252	)
Equity earnings in subsidiary		24,246		6,507			74,756			24,137

Net income	$	24,388	$	6,100		$	74,306		$	22,885

ALON USA ENERGY, INC. (PARENT COMPANY ONLY)

CONDENSED STATEMENTS OF CASH FLOWS

(unaudited, dollars in thousands)


	For the Nine Months
	Ended September 30,
	2005			2004
Cash flows from operating activities:
Net income	$	74,306		$	22,885
Stock compensation		163			—
Adjustments:
Accrued interest on subordinated notes to stockholders		—			2,067
Equity earnings in subsidiary		(74,756	)		(24,137	)
Changes in operating assets and liabilities:
Accounts payable and accrued liabilities		(16,744	)		(2,486	)

Net cash used in operating activities		(17,031	)		(1,671	)


Cash flows 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		172,287			140
Dividends paid		(68,479	)		—
Additions to long-term debt		2,826			2,727
Payments on long-term debt		(44,526	)		—

Net cash provided by financing activities		62,108			2,867


Net increase in cash and cash equivalents		70,077			1,196
Cash and cash equivalents, beginning of period		44			264

Cash and cash equivalents, end of period	$	70,121		$	1,460

ALON USA ENERGY, INC. (PARENT COMPANY ONLY)

NOTES TO CONDENSED FINANCIAL STATEMENTS

(unaudited, dollars in thousands, except share and per share data)

(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 September 30, 2005 (unaudited) and December 31, 2004 and the results of operations and cash flows for the three months and nine months ended September 30, 2005 (unaudited) and 2004 (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)

Initial Public Offering of Alon

(3)

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. 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 (note 2 of the consolidated financial statements (unaudited)).

(4)

Dividends Paid

In August 2005, the Company paid $68,479 in the form of a cash dividend to its pre-offering stockholders of record. The dividend represented a portion of the proceeds from the initial public offering (notes 2 and 14 of the consolidated financial statements (unaudited)).

(5)

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 (note 3 of the consolidated financial statements (unaudited)).

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 and 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;

	•		the effects of transactions involving forward contracts and derivative instruments;

	•		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.”

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 September 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 $172.2 million in net proceeds from the initial public offering after payment of expenses, underwriting discounts and commissions of approximately $15.5 million or $1.32 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 third quarter of 2005 continued to reflect the positive refinery fundamentals experienced in the first half of 2005. These positive fundamentals, including strong refining margins and favorable differentials between WTI and WTS crude oil, resulted in significantly enhanced results of operations reported for the nine month period ended September 30, 2005 compared to the nine month period ended September 30, 2004. The effects of the favorable refining margins and WTI/WTS crude oil differentials were partially offset by decreased production in the third quarter 2005 as a result of the acceleration of a reformer catalyst regeneration that was previously scheduled for January 2006. See “— Factors Affecting Comparability” for additional information. Results of our operations are further described below and under “— Results of Operations” and “— Liquidity and Capital Resources”:

•

Net sales increased $408.2 million to $1,646.5 million and operating income increased $78.4 million to $138.0 million for the first nine months of 2005, compared to the first nine months of 2004.

•		Our average refinery operating margin increased $3.38 per barrel to $11.70 per barrel for the first nine months of 2005, compared to the first nine months of 2004.

•		Our capital expenditures and turnaround spending for the nine months ended September 30, 2005 totaled approximately $28.9 million, of which $13.1 million was spent on a major turnaround, catalyst and the crude throughput expansion from 62,000 bpd to 70,000 bpd in February 2005, $9.7 million was spent on regulatory and compliance projects and $6.1 million was spent on various sustaining and capital improvement projects.

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

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 $5.79 and $14.20 per MMBTU in the first nine months of 2005. Over the first nine months of 2004, natural gas prices ranged between $4.57 and $7.29 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 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 remained strong in the third quarter of 2005 as a result of production and supply interruptions in the Gulf Coast region associated with hurricanes Katrina and Rita, tight finished product inventories, concern over adequate refining capacity to meet demand and continued year-on-year demand increases at above historical levels in the United States, China and India. During the first nine months of 2005, average Gulf Coast and Group III crack spreads were $11.37 and $12.12 per barrel, respectively, compared to average Gulf Coast and Group III crack spreads of $7.51 and $8.82 per barrel, respectively, in the first nine months of 2004.

The average sweet/sour spread was $4.30 per barrel in the first nine months of 2005, compared to $3.42 per barrel for the first nine months of 2004. The higher sweet/sour spread in the first nine 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 and the first quarter of 2006 as a result of a reformer catalyst regeneration that was accelerated from January 2006 to September 2005 and from the 8,000 bpd crude oil throughput capacity expansion completed in the first quarter of 2005.

Factors Affecting Comparability

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

In September 2005 we completed a reformer catalyst regeneration that had been previously planned for January 2006. As a result of the downtime associated with the regeneration, refinery throughput for the third quarter 2005 decreased by approximately 5,400 barrels per day as compared to the second quarter 2005. Full refinery throughput capacity was restored upon the completion of the regeneration in the first week of September 2005.

The contribution of assets in connection with the HEP transaction on February 28, 2005 reduced property, plant and equipment, net, by approximately $37.8 million, which decreased our depreciation expense.

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 are no longer incurred by us, resulting in an offsetting decrease in cost of sales. However, we anticipate that the additional tariff and terminalling fees will be greater than the operating expenses that we will no longer incur, resulting in a net increase to cost of sales. This net increase to cost of sales has the effect of reducing our refinery operating margin.

The HEP transaction was recorded as a partial sale for accounting purposes. We recognized pre-tax gain of $37.2 million in the nine-month period ending September 30, 2005 in connection with the transaction. This pre-tax gain includes an additional $6.5 million, which was recognized in September 2005, as a result of events which permitted us to accelerate recognition of a portion of the deferred gain. We expect the remaining $65.5 million of deferred gain to be recognized between now and 2017. In addition, $6.7 million of pro-rata gain was subtracted from the carrying value of our investment in HEP in our consolidated balance sheet as a basis adjustment. See Note 3 of the consolidated financial statements 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. 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 was 66,747 bpd for the third quarter 2005, reflecting effects of reduced production resulting from the accelerated reformer catalyst regeneration performed in September 2005. Average refinery production was 58,803 bpd for the third 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 includes cost of sales for motor fuels and for merchandise. Motor fuel cost of sales represents the net cost of purchased fuel, including transportation costs and associated motor fuel taxes. Merchandise cost of sales includes the delivered cost of merchandise purchases, net of merchandise rebates and commissions.

Direct Operating Expenses. Direct operating expenses, all of which relate to our refining and marketing segment, include costs associated with the actual operations of our refinery, such as energy and utility costs, routine maintenance, 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.

ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED

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.


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(unaudited, dollars in thousands except share and per share data)
STATEMENT OF OPERATIONS DATA:
Net sales	$	648,135		$	445,386		$	1,646,475		$	1,238,288
Operating costs and expenses:
Cost of sales		565,820			389,976			1,415,421			1,058,002
Direct operating expenses		24,550			18,121			63,259			54,814
Selling, general and administrative expenses (a)		16,083			15,364			51,731			51,890
Depreciation and amortization (b)		5,470			4,893			15,322			14,159

Total operating costs and expenses		611,923			428,354			1,545,733			1,178,865

Gain on disposition of assets (c)		8,020			—			37,243			175

Operating income		44,232			17,032			137,985			59,598
Interest expense		4,827			5,888			14,579			17,579
Equity earnings in investee		(321	)		—			(733	)		—
Other income, net		(1,269	)		(63	)		(2,349	)		(207	)
Income tax expense		16,225			4,488			48,234			17,022
Minority interest in income of subsidiaries		382			619			3,948			2,319

Net income	$	24,388		$	6,100		$	74,306		$	22,885


Earnings per share (d)	$	.57		$	.17		$	1.98		$	.65

Weighted average shares outstanding (d)		42,821,120			35,001,120			37,607,787			35,001,120


OTHER DATA:
Adjusted EBITDA (e)	$	43,272		$	21,988		$	119,146		$	73,789
Capital expenditures, net of disposition proceeds		1,109			4,775			(100,432	)		17,797
Capital expenditures for turnarounds and catalysts		590			198			11,371			1,698

CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	(16,494	)	$	5,602		$	32,482		$	29,528
Investing activities		(36,666	)		(5,553	)		54,610			(30,075	)
Financing activities		77,908			(5,688	)		42,845			26,995

BALANCE SHEET DATA (end of period):
Cash, cash equivalents and short-term investments							$	222,969		$	33,704
Working capital								250,213			47,909
Total assets								703,783			454,181
Total debt								132,877			194,678
Stockholders’ equity								249,749			69,948


(a)		Includes corporate headquarters selling, general and administrative expenses of $127 and $140 for the three months ended September 30, 2005 and 2004, respectively, and $383 and $394 for the nine months ended September 30, 2005 and 2004, respectively, which are not allocated to our two operating segments.

(b)		Includes corporate depreciation and amortization of $477 and $445 for the three months ended September 30, 2005 and 2004, respectively, and $1,426 and $1,295 for the nine months ended September 30, 2005 and 2004, respectively, which are not allocated to our two operating segments.

(c)		Gain on disposition of assets reported in the three months ended September 30, 2005, reflects the $6.5 million accelerated pre-tax gain ($4.2 million after-tax gain) and the monthly recognition of deferred gain recorded in connection with the HEP transaction. Gain on disposition of assets reported in the nine months ended September 30, 2005, reflects the $26.7 million initial pre-tax gain, the monthly recognition of deferred gain and the $6.5 million accelerated pre-tax gain recorded in connection with the HEP transaction.


(d)		Weighted average common shares outstanding and earnings per common share amounts for the three and nine months ended September 30, 2005 and 2004, 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. On August 2, 2005, Alon completed an initial public offering of 11,730,000 shares of its common stock. Those shares are included in the calculation of weighted average number of shares outstanding.

(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.

REFINING AND MARKETING SEGMENT


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(unaudited, dollars in thousands, except for
				per barrel and pricing statistics)
STATEMENT OF OPERATIONS DATA:
Net sales (a)	$	600,487		$	397,466		$	1,510,195		$	1,099,244
Operating costs and expenses:
Cost of sales		534,353			356,089			1,322,523			960,084
Direct operating expenses		24,550			18,121			63,259			54,814
Selling, general and administrative expenses		3,090			3,349			14,175			14,937
Depreciation and amortization		3,906			3,446			10,706			9,796

Total operating costs and expenses		565,899			381,005			1,410,663			1,039,631

Gain on disposition of assets (b)		8,057			—			37,280			—

Operating income	$	42,645		$	16,461		$	136,812		$	59,613


KEY OPERATING STATISTICS:
Total sales volume (bpd)		87,313			85,963			84,983			85,865
Non-integrated marketing sales volume (bpd)		21,154			20,404			20,590			19,924
Non-integrated marketing margin (per barrel sales volume) (c)	$	(4.98	)	$	(.33	)	$	(1.94	)	$	(.02	)
Per barrel of throughput:
Refinery operating margin (d)	$	12.35		$	7.74		$	11.70		$	8.32
Direct operating expenses		4.00			3.34			3.73			3.27

PRICING STATISTICS:
WTI crude oil (per barrel)	$	63.03		$	43.86		$	55.31		$	39.13
WTS crude oil (per barrel)		58.94			39.99			51.01			35.71
Crack spreads (3/2/1) (per barrel):
Gulf Coast	$	17.13		$	6.71		$	11.37		$	7.51
Group III		16.66			8.08			12.12			8.82
Crude differentials (per barrel):
WTI less WTS	$	4.09		$	3.87		$	4.30		$	3.42
Product price (per gallon):
Gulf Coast unleaded gasoline		192.8	¢		121.0	¢		157.9	¢		114.7	¢
Gulf Coast low-sulfur diesel		187.0			119.2			160.5			103.7
Group III unleaded gasoline		190.7			124.0			159.5			117.5
Group III low-sulfur diesel		187.8			123.1			162.6			107.5
Natural gas (per MMBTU)	$	9.73		$	5.58		$	7.75		$	5.82

THROUGHPUT AND YIELD DATA:


	For the Three Months Ended								For the Nine Months Ended
	September 30,								September 30,
	2005				2004				2005				2004
	Bpd		%		Bpd		%		Bpd		%		Bpd		%
Refinery crude throughput:
Sour crude		55,757		88.4		51,504		92.6		52,862		90.2		53,100		92.0
Sweet crude		7,286		11.6		4,114		7.4		5,732		9.8		4,603		8.0

Total crude throughput		63,043		100.0		55,618		100.0		58,594		100.0		57,703		100.0

Blendstocks		3,669				3,356				3,565				3,423

Total refinery throughput (e)		66,712				58,974				62,159				61,126

Refinery production (f):
Gasoline		29,934		44.8		26,212		44.6		27,643		44.7		28,215		46.2
Diesel/jet		22,974		34.4		19,200		32.6		21,386		34.5		19,690		32.2
Asphalt		6,976		10.5		6,402		10.9		5,892		9.5		5,945		9.7
Petrochemicals		3,975		6.0		4,234		7.2		4,247		6.9		4,579		7.5
Other		2,888		4.3		2,755		4.7		2,707		4.4		2,655		4.4

Total refinery production		66,747		100.0		58,803		100.0		61,875		100.0		61,084		100.0


(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 reported in the three months ended September 30, 2005, reflects the $6.5 million accelerated pre-tax gain ($4.2 million after-tax gain) and the monthly recognition of deferred gain recorded in connection with the HEP transaction. Gain on disposition of assets reported in the nine months ended September 30, 2005, reflects the $26.7 million initial pre-tax gain, the monthly recognition of deferred gain and the $6.5 million accelerated pre-tax 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 production represents the barrels per day of various finished products produced from processing crude and other refinery feedstocks through the crude units and other conversion units at the refinery.

RETAIL SEGMENT


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(unaudited, dollars in thousands, except for per gallon data)
STATEMENT OF OPERATIONS DATA:
Net sales	$	89,464		$	78,837		$	250,544		$	225,856
Operating Costs and Expenses:
Cost of sales (a)		73,283			64,804			207,162			184,730
Selling, general and administrative expenses		12,866			11,875			37,173			36,559
Depreciation and amortization		1,087			1,002			3,190			3,068

Total operating costs and expenses		87,236			77,681			247,525			224,357

Gain (loss) on disposition of assets		(37	)		—			(37	)		175

Operating income	$	2,191		$	1,156		$	2,982		$	1,674


KEY OPERATING STATISTICS:
Number of stores (end of period)		167			167			167			167
Fuel sales (thousands of gallons)		21,706			24,780			69,772			73,493
Fuel sales (thousands of gallons per site per month)		44			50			47			50
Fuel margin (cents per gallon) (b)		20.4	¢		11.2	¢		14.3	¢		11.5	¢
Fuel sales price (cents per gallon)		249.0			181.0			215.0			173.0
Merchandise sales	$	35,391		$	34,046		$	100,246		$	98,992
Merchandise sales (per site per month)		71			68			67			66
Merchandise margin (c)		33.2	%		33.1	%		33.3	%		33.0	%


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

(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 September 30, 2005 Compared to the Three Months Ended September 30, 2004

Net Sales

Consolidated. Net sales for the three months ended September 30, 2005 were $648.1 million, compared to $445.4 million for the three months ended September 30, 2004, an increase of $202.7 million or 45.5%. This increase was 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 $600.5 million for the three months ended September 30, 2005, compared to $397.5 million for the three months ended September 30, 2004, an increase of $203.0 million or 51.1%. This increase was primarily due to significantly higher refined product prices. The increase in refined product prices that we experienced was similar to the price increases experienced in the Gulf Coast markets. The average price of Gulf Coast gasoline for the third quarter of 2005 increased 71.8 cents per gallon (“cpg”) to 192.8 cpg, compared to 121.0 cpg in the third quarter of 2004, an increase of 59.3%. The average Gulf Coast diesel price increased by approximately 67.8 cpg to 187.0 cpg in the third quarter of 2005 as compared to 119.2 cpg in the third quarter of 2004, an increase of 56.9%. Also, contributing to the increase in sales was an increase in sales volume. Our sales volume increased by 5.2 million gallons, or 1.6%, to 337.4 million gallons for the three months ended September 30, 2005 compared to 332.2 million gallons

for the three months ended September 30, 2004. This increase in sales volume resulted primarily from the 8,000 bpd throughput capacity expansion completed in the first quarter of 2005, which resulted in average refinery production of 66,747 bpd for the third quarter of 2005 compared to 58,803 bpd for the third quarter 2004, despite the effects of a reformer catalyst regeneration in September 2005 which decreased production for the third quarter 2005 by approximately 4,900 bpd compared to second quarter 2005 production of 71,602 bpd.

Retail Segment. Net sales for our retail segment were $89.5 million for the three months ended September 30, 2005 compared to $78.8 million for the three months ended September 30, 2004, an increase of $10.7 million or 13.6%. This increase was primarily attributable to higher average retail fuel prices. Average retail fuel prices were $2.49 per gallon for the third quarter of 2005, compared to average retail fuel prices of $1.81 per gallon for the third quarter of 2004.

Cost of Sales

Consolidated. Cost of sales was $565.8 million for the three months ended September 30, 2005, compared to $390.0 million for the three months ended September 30, 2004, an increase of $175.8 million or 45.1%. This increase resulted primarily from higher crude oil prices.

Refining and Marketing Segment. Cost of sales for our refining and marketing segment was $534.4 million for the three months ended September 30, 2005, compared to $356.1 million for the three months ended September 30, 2004, an increase of $178.3 million or 50.0%. This increase was primarily due to the increase in refinery production in the third quarter 2005 compared to third quarter 2004 and to significantly higher crude oil prices. The average price per barrel of WTS for the third quarter of 2005 increased $18.95 per barrel to $58.94 per barrel, compared to $39.99 per barrel for the third quarter of 2004, an increase of 47.4%.

Retail Segment. Cost of sales for our retail segment was $73.3 million for the three months ended September 30, 2005, compared to $64.8 million for the three months ended September 30, 2004, an increase of $8.5 million or 13.1%. This increase was primarily attributable to higher motor fuel costs.

Direct Operating Expenses

Direct operating expenses were $24.6 million for the three months ended September 30, 2005, compared to $18.1 million for the three months ended September 30, 2004, an increase of $6.5 million or 35.9%. This increase was primarily attributable to an increase in natural gas prices in the third quarter 2005 compared to the third quarter 2004. The average price of natural gas was $9.73 per MMBTU in the third quarter of 2005, compared to $5.58 per MMBTU for the third 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. Efficiencies gained as a result of the first quarter 2005 turnaround partially offset the effects of increased prices and energy usage.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for the three months ended September 30, 2005 were $16.1 million, compared to $15.4 million for the three months ended September 30, 2004, an increase of $0.7 million or 4.5%. This increase resulted primarily from an increase in credit card brokerage fees and was partially offset by lower advertising expense and professional fees.

Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the three months ended September 30, 2005 were $3.1 million, compared to $3.3 million for the three-month period ended September 30, 2004, a decrease of $0.2 million or 6.1%. This decrease resulted from lower advertising expense and professional fees.

Retail Segment. SG&A expenses for our retail segment for the three months ended September 30, 2005 were $12.9 million, compared to $11.9 million for the three months ended September 30, 2004, an increase of $1.0 million or 8.4%. This increase was primarily attributable to higher credit card brokerage fees as a result of the increase in fuel prices, which were partially offset by decreased healthcare and workers compensation costs.

Depreciation and Amortization

Depreciation and amortization for the three months ended September 30, 2005 was $5.5 million, compared to $4.9 million for the three months ended September 30, 2004. This increase was primarily attributable to the completion of the various capital projects in late 2004 and the first nine 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 for the three months ended September 30, 2005 was $44.2 million. Excluding $8.0 million of net gain on disposition of assets resulting from the HEP transaction, which management believes enhances period-to-period comparability, operating income for the three months ended September 30, 2005 was $36.2 million, compared to $17.0 million for the three months ended September 30, 2004, an increase of $19.2 million or 112.9%. 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 September 30, 2005 was $42.6 million. Excluding $8.1 million of gain on disposition of assets resulting from the HEP transaction, which management believes enhances period-to-period comparability, operating income for the three months ended September 30, 2005 was $34.5 million, compared to operating income for the three months ended September 30, 2004 of $16.5 million, an increase of $18.0 million or 109.1%. This increase was primarily attributable to the increase in our refinery operating margins and increased sales volumes as a result of the 8,000 bpd crude oil throughput capacity expansion at our Big Spring refinery in the first quarter of 2005. Our refinery operating margin for the third quarter of 2005 increased $4.61 per barrel to $12.35 per barrel, compared to $7.74 per barrel in the third quarter of 2004. This increase was attributable, in part, to higher differentials between refined product prices and crude oil prices as a result of production and supply interruptions in the Gulf Coast region associated with hurricanes Katrina and Rita. The Gulf Coast 3/2/1 crack spread increased by 155.3% to an average of $17.13 per barrel in the third quarter of 2005 compared to an average of $6.71 per barrel in the third quarter of 2004. Also contributing to this increase was a widening of the sweet/sour spread. The average sweet/sour spread increased $.22 per barrel to $4.09 per barrel for the third quarter of 2005 compared to the average sweet/sour spread of $3.87 per barrel for the third quarter of 2004, an increase of 5.7%.

Retail Segment. Operating income for our retail segment was $2.2 million for the three months ended September 30, 2005, compared to $1.2 million, an increase of $1.0 million. This increase was primarily attributable to the higher motor fuel margins. Average motor fuel margins increased 9.2 cpg to 20.4 cpg in the third quarter 2005 compared to 11.2 cpg in the third quarter 2004.

Interest Expense

Interest expense was $4.8 million for the three months ended September 30, 2005, compared to $5.9 million for the three months ended September 30, 2004, a decrease of $1.1 million or 18.6%. This decrease was primarily attributable to the net repayment of $54.8 million of debt during the first nine months of 2005.

Income Tax Expense

Income tax expense was $16.2 million for the three months ended September 30, 2005, compared to $4.5 million for the three months ended September 30, 2004, an increase of $11.7 million. This increase resulted from our higher taxable income in the third quarter of 2005. Our effective tax rate was 39.6% and reflects the benefit of the Jobs Creation Act tax credit for the third quarter of 2005. Our effective tax rate was 40.0% for the third quarter of 2004.

Minority Interest

Minority interest represents the proportional share of net income related to non-voting common stock owned by minority shareholders in two of our subsidiaries, Alon Assets and Alon Operating. Minority interest was $0.4 million for the three months ended September 30, 2005, compared to $0.6 million for the three months ended September 30, 2004, a decrease of $0.2 million. This decrease resulted from a reduction

in the minority interest ownership percentage to 4.9% in the third quarter 2005 compared to 8.4% in the third quarter 2004 as a result of the issuance of additional voting common stock by Alon Assets and Alon Operating in the third quarter 2005 and the repurchase of shares of non-voting common stock by Alon Assets and Alon Operating in the first quarter 2005. This decrease was partially offset by the increase in net income as a result of the factors discussed above.

Net Income

Net income was $24.4 million for the three months ended September 30, 2005, compared to $6.1 million for the three months ended September 30, 2004, an increase of $18.3 million or 300.0%. This increase was attributable to the factors discussed above.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Net Sales

Consolidated. Net sales for the nine months ended September 30, 2005 were $1,646.5 million, compared to $1,238.3 million for the nine months ended September 30, 2004, an increase of $408.2 million or 33.0%. This increase is primarily due to higher average refined product prices over the comparable period in 2004.

Refining and Marketing Segment. Net sales for our refining and marketing segment were $1,510.2 million for the nine months ended September 30, 2005, compared to $1,099.2 million for the nine months ended September 30, 2004, an increase of $411.0 million or 37.4%. This increase was primarily due to significantly higher refined product prices. The increase in refined product prices that we experienced was similar to the price increases experienced in the Gulf Coast markets. The average price of Gulf Coast gasoline for the first nine months of 2005 increased 43.2 cpg to 157.9 cpg, compared to 114.7 cpg for the first nine months of 2004, an increase of 37.7%. The average Gulf Coast diesel price increased by approximately 56.8 cpg to 160.5 cpg for the first nine months of 2005, as compared to 103.7 cpg for the first nine months of 2004, an increase of 54.8%. Refined product sales volume and production for the nine months ended September 30, 2005 did not differ materially from the comparable period in 2004 as the effects of the first quarter 2005 turnaround and third quarter 2005 reformer catalyst regeneration were offset by the 8,000 bpd throughput capacity expansion in the first quarter 2005.

Retail Segment. Net sales for our retail segment were $250.5 million for the nine months ended September 30, 2005 compared to $225.9 million for the nine months ended September 30, 2004, an increase of $24.6 million or 10.9%. This increase was primarily attributable to higher average retail fuel prices. Average retail fuel prices were $2.15 per gallon for the first nine months of 2005, compared to average retail fuel prices of $1.73 per gallon for the first nine months of 2004. Our retail merchandise margin increased in the first nine months of 2005 compared to the first nine months of 2004.

Cost of Sales

Consolidated. Cost of sales was $1,415.4 million for the nine months ended September 30, 2005, compared to $1,058.0 million for the nine months ended September 30, 2004, an increase of $357.4 million or 33.8%. This increase resulted primarily from higher crude oil prices.

Refining and Marketing Segment. Cost of sales for our refining and marketing segment was $1,322.5 million for the nine months ended September 30, 2005, compared to $960.1 million for the nine months ended September 30, 2004, an increase of $362.4 million or 37.7%. This increase was primarily due to significantly higher crude oil prices. The average price per barrel of WTS for the first nine months of 2005 increased $15.30 per barrel to $51.01 per barrel, compared to $35.71 per barrel for the first nine months of 2004, an increase of 42.8%.

Retail Segment. Cost of sales for our retail segment was $207.2 million for the nine months ended September 30, 2005, compared to $184.7 million for the nine months ended September 30, 2004, an increase of $22.5 million or 12.2%. This increase was primarily attributable to higher motor fuel costs.

Direct Operating Expenses

Direct operating expenses, were $63.3 million for the nine months ended September 30, 2005, compared to $54.8 million for the nine months ended September 30, 2004, an increase of $8.5 million or 15.5%. This increase was primarily attributable to an increase in natural gas prices in the first nine months of 2005 compared to the first nine months of 2004. The average price of natural gas was $7.75 per MMBTU for the first nine months of 2005, compared to $5.82 per MMBTU for the first nine 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 in the first quarter 2005. Efficiencies gained as a result of the first quarter 2005 turnaround partially offset the effects of increased prices and energy usage.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for the nine months ended September 30, 2005 were $51.7 million, compared to $51.9 million for the nine months ended September 30, 2004, a decrease of $0.2 million or 0.4%.

Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the nine months ended September 30, 2005 were $14.2 million, compared to $14.9 million for the nine month period ended September 30, 2004, a decrease of $0.7 million or 4.7%. This decrease is primarily related to lower advertising expenses and professional fees.

Retail Segment. SG&A expenses for our retail segment for the nine months ended September 30, 2005 were $37.2 million, compared to $36.6 million for the nine months ended September 30, 2004, an increase of $0.6 million or 1.6%. This increase was primarily attributable to increased credit card brokerage fees, which were partially offset by reduced healthcare and workers compensation costs.

Depreciation and Amortization

Depreciation and amortization for the nine months ended September 30, 2005 were $15.3 million, compared to $14.2 million for the nine months ended September 30, 2004. This increase was primarily attributable to the completion of the various capital projects in late 2004 and the first nine 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 for the three months ended September 30, 2005 was $138.0 million. Excluding $37.2 million of the net gain on disposition of assets resulting from the HEP transaction, which management believes enhances period-to-period comparability, operating income for the nine months ended September 30, 2005 was $100.8 million, compared to $59.4 million (excluding $0.2 million gain on disposition of assets) for the nine months ended September 30, 2004, an increase of $41.4 million or 69.7%. 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 nine months ended September 30, 2005 was $136.8 million. Excluding $37.3 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 nine months ended September 30, 2005 was $99.5 million, compared to operating income for the nine months ended September 30, 2004 of $59.6 million, an increase of $39.9 million or 66.9%. This increase was primarily attributable to the increase in our refinery operating margins. Our refinery operating margin for the first nine months of 2005 increased $3.38 per barrel to $11.70 per barrel, compared to $8.32 per barrel for the first nine 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 51.4% from to average of $11.37 per barrel in the first nine months of 2005 from an average of $7.51 per barrel for the first nine months of 2004. Also contributing to this increase was a widening of the sweet/sour spread. The average sweet/ sour spread increased $0.88 per barrel to $4.30 per barrel for the first nine months of 2005 compared to the average sweet/sour spread of $3.42 per barrel for the first nine months of 2004.

Retail Segment. Operating income for our retail segment was $3.0 million for the nine months ended September 30, 2005, compared to $1.7 million for nine months ended September 30, 2004, an increase of $1.3 million. Average motor fuel margins increased 2.8 cpg to 14.3 cpg in the nine months ended September 30, 2005 compared to 11.5 cpg in the nine months ended September 30, 2004. In addition our merchandise margin increased to 33.3% for the nine months ended September 30, 2005 compared to 33.0% for the nine months ended September 30, 2004.

Interest Expense

Interest expense was $14.6 million for the nine months ended September 30, 2005, compared to $17.6 million for the nine months ended September 30, 2004, a decrease of $3.0 million or 17.0%. This decrease was primarily attributable to the repayment of debt in the first nine months of 2005. In addition, 2004 interest expense 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 $48.2 million for the nine months ended September 30, 2005, compared to $17.0 million for the nine months ended September 30, 2004, an increase of $31.2 million. This increase resulted from our higher taxable income in the nine months ended September 30, 2005, which included the recognition of $37.2 million of pre-tax gain on disposition of assets in connection with the HEP transaction. Our effective tax rate was 38.1% and reflects the benefit of the Jobs Creation Act tax credit for the nine months ended September 30, 2005. Our effective tax rate was 40.3% for the nine months ended September 30, 2004.

Minority Interest

Minority interest was $3.9 million for the nine months ended September 30, 2005, compared to $2.3 million for the nine months ended September 30, 2004, an increase of $1.6 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 percentage to 4.9% in 2005 compared to 8.4% in 2004 as a result of the issuance of additional voting common stock by Alon Assets and Alon Operating in the third quarter 2005 and the repurchase of non-voting common stock by Alon Assets and Alon Operating in the first quarter 2005.

Net Income

Net income was $74.3 million for the nine months ended September 30, 2005, compared to $22.9 million for the nine months ended September 30, 2004, an increase of $51.4 million or 224.5%. This increase was attributable to the factors discussed above.

Liquidity and Capital Resources

Our primary sources of liquidity are cash on hand, cash generated from our operating activities and borrowings under our revolving credit facility. In addition, our liquidity was enhanced during the third quarter 2005 by the receipt of $72.3 million net cash proceeds received from our initial public offering (see note 2). 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 nine months ended September 30, 2005 and 2004:


	For the Nine Months Ended
	September 30,
	2005		2004
Non cash provided by (used in):
Operating activities	$	32,482	$	29,528
Investing activities		54,610		(30,075	)
Financing activities		42,845		26,995

Net increase in cash and cash equivalents	$	129,937	$	26,448

Cash Flows Provided By Operating Activities

Net cash provided by operating activities for the nine months ended September 30, 2005 was $32.5 million compared to net cash provided by operating activities of $29.5 million for the nine months ended September 30, 2004. The $3.0 million net increase in cash provided by operating activities was primarily due to increased net income (excluding after-tax gains on dispositions of assets) as a result of higher refinery operating margins. Additionally, increases in accounts payable as a result of rising crude oil prices positively impacted cash provided by operating activities in the nine months ended September 30, 2005. The most significant use of cash from operating activities in the nine months ended September 30, 2005 was related to the increase in accounts receivable as a result of higher refined product prices. In addition, increased unfinished gasoline and diesel inventories built as a result of the reformer catalyst regeneration completed in September 2005, resulted in a temporary use of cash from operating activities. The most significant uses of cash in operating activities in the first nine 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 nine months ended September 30, 2005 was $54.6 million compared to net cash used in investing activities of $30.1 million for the nine months ended September 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 short-term investments of $29.7 million and capital expenditures of $28.9 million in the nine months ended September 30, 2005. Capital expenditures in the nine months ended September 30, 2005 included $9.7 million for regulatory and compliance projects, $1.7 million for the completion of our crude unit expansion, $1.1 million for retail store automation and $5.0 million for various sustaining and capital improvement projects. In addition, $11.4 million was spent for turnaround and catalyst replacement cost.

Cash Flows Provided By (Used In) Financing Activities

Net cash provided by financing activities was $42.8 million during the nine months ended September 30, 2005 compared to net cash provided by financing activities of $27.0 million during the nine months ended September 30, 2004. Cash provided by financing activities in the first nine months of 2005 included the net proceeds from the initial public offering on August 2, 2005 of $74.7 million after payment of commissions and expenses, debt prepayment, and dividends to pre-offering stockholders and minority interest stockholders. In addition, cash used in financing activities during the nine months ended September 30, 2005 included debt repayment of $30.6 million. Cash provided by financing activities in the first nine 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 paid pre-closing stockholders of Alon USA Energy, Inc. aggregate dividends of approximately $68.4 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.

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 September 30, 2005, our total cash and cash equivalents were $223.0 million, and we had total debt of approximately $132.9 million. We intend to prepay $100.0 million of term loan in the first quarter 2006. As of September 30, 2005, we also intend to use cash for general corporate purposes and discretionary and non-discretionary capital expenditures. As of September 30, 2005, we had $130.2 million face value of letters of credit outstanding and no 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 or the amount of the borrowing base (as defined in the revolving credit agreement). In addition, we have a separate credit facility for the issuance of letters of credit of up to $20.0 million. As of September 30, 2005, the borrowing base under the revolving credit facility exceeded the $141.6 million maximum borrowing capacity by $214.8 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 $17.6 million, primarily related to the crude unit expansion, regulatory and compliance projects and $11.4 million related to turnaround and chemical catalysts, had been spent as of September 30, 2005.

Clean Air Capital Expenditures. We expect to spend approximately $29.4 million over the next nine 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 2006.

As of September 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. An additional $0.6 million was spent in the third quarter 2005 in connection with a reformer catalyst regeneration which had originally been scheduled for January 2006.

Contractual Obligations and Commercial Commitments

Information regarding our known contractual obligations of the types described below as of September 30, 2005 is set forth in the following table. As of September 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)	$	487	$	13,872	$	97,122	(b)	$	21,396	$	132,877
Operating lease obligations		2,903		28,070		14,182			7,540		52,695
Pipelines and Terminals Agreement (c)		4,905		58,863		39,242			179,859		282,869
Other commitments (d)		707		12,483		5,654			34,636		53,480

Total obligations	$	9,002	$	113,288	$	156,200		$	243,431	$	521,921


(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.

(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 was paid 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.

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 nine months ended September 30, 2005 and 2004, respectively:


	For the Three Months Ended					For the Nine Months Ended
	September 30,					September 30,
	2005			2004		2005			2004
	(dollars in thousands)
Net income	$	24,388		$	6,100	$	74,306		$	22,885
Minority interest		382			619		3,948			2,319
Income tax expense		16,225			4,488		48,234			17,022
Interest expense		4,827			5,888		14,579			17,579
Depreciation and amortization		5,470			4,893		15,322			14,159
Gain on disposition of assets		(8,020	)		—		(37,243	)		(175	)

Adjusted EBITDA	$	43,272		$	21,988	$	119,146		$	73,789

New Accounting Standards and Disclosures

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 September 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 interim periods beginning after September 15, 2005. The adoption of Statement No. 153 had no impact on the Company’s financial position or results of operations.

In December 2004 the FASB issued FASB Staff Position (“FSP”) FAS 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, for the Tax Deduction Provided to U.S. Based Manufacturers by the American Jobs Creation Act of 2004” (“Jobs Creation Act”) which requires a company that qualifies for the deduction for domestic production activities under the 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 has included the effects of this FSP in its calculation of the September 30, 2005 deferred income tax provision.

In September 2005, the Emerging Issues Task Force, (EITF) reached a consensus concerning the accounting for linked purchase and sale arrangements in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The EITF concluded that generally requires non-monetary exchanges of finished goods inventory within the same line of business be recognized at the carrying value of the inventory transferred. The consensus is to be applied to new buy/sell arrangements entered in reporting periods beginning after March 15, 2006. The Company does not expect the impact of this EITF Issue No. 04-13 consensus to have a material effect on the Company’s financial position or results of operations.

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 September 30, 2005, we held approximately 2.0 million barrels of crude and product inventories valued under the LIFO valuation method with an average cost of $35.96 per barrel. Market value exceeded carrying value of LIFO costs by $87.4 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 $85.4 million.

In accordance with SFAS No. 133, all commodity futures contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section of our consolidated financial statements. “Forwards” represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period. “Futures” represent trades which have been executed on the New York Mercantile Exchange (“NYMEX’) which have not been closed or settled at the end of the reporting period. A “long” represent an obligation to purchase product and a “short” represents an obligation to sell product.

The following table provides information about our derivative commodity instruments as of September 30, 2005:


			Wtd Avg		Wtd Avg
Description	Contract		Purchase		Sales		Contract		Fair		Gain
of Activity	Volume		Price		Price		Value		Value		(Loss)
	(bbls)		(price per gallon)				(dollars in thousands)
Futures-long		—	$	—	$	—	$	—	$	—	$	—
Futures-short		—		—		—		—		—		—
Forwards-long (refined products)		110,000		2.98		—		13,784		11,653		(2,131	)
Forwards-short (refined products)		25,000		—		2.90		3,049		2,622		427

Interest Rate Risk.

As of September 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.

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 $2.4 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 $172.2 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 September 30, 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.

•		approximately $2.5 million was used for general corporate purposes.

ITEM 6. EXHIBITS


Exhibit Number		Description of Exhibit

3.1		Amended Restated Certificate of Incorporation of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.1 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).

3.2		Amended and Restated Bylaws of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.2 to Form S-1, filed by the Company on July 14, 2005, SEC File No. 333-124797).

4.1		Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Form S-1, filed by the Company on June 17, 2005, SEC File No. 333-124797).

10.1		Registration Rights Agreement, dated as of July 6, 2005, between Alon USA Energy, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.22 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).

10.2		Agreement of Principles of Employment, dated as of July 6, 2005, between David Wiessman and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.50 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).

10.3		Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.51 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).

10.4		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 (incorporated by reference to Exhibit 10.52 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).

10.5		Form of Restricted Stock Award Agreement relating to Director Grants pursuant to Section 12 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on August 5, 2005, SEC File No. 001-32567).

10.6		Form of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on August 5, 2005, SEC File No. 001-32567).

31.1		Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.

31.2		Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.

32.1*		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

SIGNATURES

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



	By:	/s/ David Wiessman
Date: November 10, 2005		David Wiessman
		Executive Chairman



	By:	/s/ Jeff D. Morris
Date: November 10, 2005		Jeff D. Morris
		Chief Executive Officer



	By:	/s/ Shai Even
Date: November 10, 2005		Shai Even
		Chief Financial Officer

EXHIBITS


Exhibit Number		Description of Exhibit

3.1		Amended Restated Certificate of Incorporation of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.1 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).

3.2		Amended and Restated Bylaws of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.2 to Form S-1, filed by the Company on July 14, 2005, SEC File No. 333-124797).

4.1		Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Form S-1, filed by the Company on June 17, 2005, SEC File No. 333-124797).

10.1		Registration Rights Agreement, dated as of July 6, 2005, between Alon USA Energy, Inc. and Alon Israel Oil Company, Ltd. (incorporated by reference to Exhibit 10.22 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).

10.2		Agreement of Principles of Employment, dated as of July 6, 2005, between David Wiessman and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.50 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).

10.3		Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.51 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).

10.4		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 (incorporated by reference to Exhibit 10.52 to Form S-1, filed by the Company on July 7, 2005, SEC File No. 333-124797).

10.5		Form of Restricted Stock Award Agreement relating to Director Grants pursuant to Section 12 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on August 5, 2005, SEC File No. 001-32567).

10.6		Form of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K filed by the Company on August 5, 2005, SEC File No. 001-32567).

31.1		Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.

31.2		Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.

32.1*		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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Alon USA Energy (ALJ) Inactive 10-Q2005 Q3 Quarterly report

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