Alon USA Energy 10Q 2010 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, 2010


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

FOR THE TRANSITION PERIOD FROM TO

Commission file number: 001-32567

Alon USA Energy, Inc.

(Exact name of Registrant as specified in its charter)


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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yeso Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filero	Accelerated filerþ	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

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 1, 2010, was 54,181,329.


PART I. FINANCIAL INFORMATION			1
ITEM 1. FINANCIAL STATEMENTS			1
CONSOLIDATED BALANCE SHEETS			1
CONSOLIDATED STATEMENTS OF OPERATIONS			2
CONSOLIDATED STATEMENTS OF CASH FLOWS			3
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS			4
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			24
FORWARD-LOOKING STATEMENTS			24
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			51
ITEM 4. CONTROLS AND PROCEDURES			52
PART II. OTHER INFORMATION			53
ITEM 6. EXHIBITS			53

SIGNATURES			54
EXHIBITS			55
EX-4.3 FORM OF CERTIFICATE OF DESIGNATION OF THE 8.50% SERIES A CONVERTIBLE PREFERRED STOCK
EX-4.4 SPECIMEN 8.50% SERIES A CONVERTIBLE PREFERRED STOCK CERTIFICATE
EX-31.1 CERTIFICATION OF CEO PURSUANT TO SECTION 302
EX-31.2 CERTIFICATION OF CFO PURSUANT TO SECTION 302
EX-32.1 CERTIFICATION OF CEO AND CFO PURSUANT TO SECTION 906

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALON USA ENERGY, INC. AND SUBSIDIARIES

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


	September 30,				December 31,
	2010				2009
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	39,635			$	40,437
Accounts and other receivables, net		125,095				103,094
Income tax receivable		18,128				65,418
Inventories		197,699				214,999
Deferred income tax asset		71,296				7,700
Prepaid expenses and other current assets		14,262				4,188

Total current assets		466,115				435,836

Equity method investments		22,520				43,052
Property, plant, and equipment, net		1,484,004				1,477,426
Goodwill		105,943				105,943
Other assets		96,982				70,532

Total assets	$	2,175,564			$	2,132,789
				��

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	332,748			$	248,253
Accrued liabilities		86,828				92,380
Short-term debt and current portion of long-term debt		40,946				10,946

Total current liabilities		460,522				351,579

Other non-current liabilities		138,375				95,076
Long-term debt		912,577				926,078
Deferred income tax liability		332,626				328,138

Total liabilities		1,844,100				1,700,871

Commitments and contingencies (Note 17)
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; 54,181,329 and 54,170,913 shares issued and outstanding at September 30, 2010, and December 31, 2009, respectively		542				542
Additional paid-in capital		290,447				289,853
Accumulated other comprehensive loss, net of income tax		(25,285	)			(32,871	)
Retained earnings		60,962				165,248

Total stockholders’ equity		326,666				422,772

Non-controlling interest in subsidiaries		4,798				9,146

Total equity		331,464				431,918

Total liabilities and equity	$	2,175,564			$	2,132,789

The accompanying notes are an integral part of these consolidated financial statements.

ALON USA ENERGY, INC. AND SUBSIDIARIES

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


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Net sales (1)	$	1,248,569		$	1,253,113		$	2,668,243		$	3,081,691
Operating costs and expenses:
Cost of sales		1,153,743			1,165,295			2,443,533			2,693,343
Direct operating expenses		68,448			64,091			192,816			204,300
Selling, general and administrative expenses		35,012			32,276			96,001			95,772
Depreciation and amortization		26,781			25,247			78,471			70,898

Total operating costs and expenses		1,283,984			1,286,909			2,810,821			3,064,313

Gain (loss) on disposition of assets		—			(547	)		474			(2,147	)

Operating income (loss)		(35,415	)		(34,343	)		(142,104	)		15,231
Interest expense		(24,091	)		(21,460	)		(72,411	)		(70,739	)
Equity earnings of investees		3,864			12,811			4,970			21,184
Gain on bargain purchase		17,480			—			17,480			—
Other income (loss), net		(494	)		(180	)		13,345			268

Loss before income tax benefit, non-controlling interest in loss of subsidiaries and accumulated dividends on preferred stock of subsidiary		(38,656	)		(43,172	)		(178,720	)		(34,056	)
Income tax benefit		(21,905	)		(16,452	)		(73,711	)		(13,006	)

Loss before non-controlling interest in loss of subsidiaries and accumulated dividends on preferred stock of subsidiary		(16,751	)		(26,720	)		(105,009	)		(21,050	)
Non-controlling interest in loss of subsidiaries		(1,167	)		(2,312	)		(7,224	)		(2,953	)
Accumulated dividends on preferred stock of subsidiary		—			2,150			—			6,450

Net loss available to common stockholders	$	(15,584	)	$	(26,558	)	$	(97,785	)	$	(24,547	)


Loss per share, basic	$	(0.29	)	$	(0.57	)	$	(1.80	)	$	(0.52	)

Weighted average shares outstanding, basic (in thousands)		54,181			46,810			54,177			46,808


Loss per share, diluted	$	(0.29	)	$	(0.57	)	$	(1.80	)	$	(0.52	)

Weighted average shares outstanding, diluted (in thousands)		54,181			46,810			54,177			46,808


Cash dividends per share	$	0.04		$	0.04		$	0.12		$	0.12


(1)		Includes excise taxes on sales by the retail segment of $14,204 and $12,073 for the three months and $40,521 and $34,887 for the nine months ended September 30, 2010, and 2009, respectively.

The accompanying notes are an integral part of these consolidated financial statements.

ALON USA ENERGY, INC. AND SUBSIDIARIES

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


	For the Nine Months Ended
	September 30,
	2010			2009
Cash flows from operating activities:
Net loss available to common stockholders	$	(97,785	)	$	(24,547	)
Adjustments to reconcile net loss available to common stockholders to cash provided by (used in) operating activities:
Depreciation and amortization		78,471			70,898
Stock compensation		446			533
Deferred income tax expense		(73,715	)		(14,575	)
Non-controlling interest in loss of subsidiaries		(7,224	)		(2,953	)
Equity earnings of investees (net of dividends)		(2,614	)		(13,788	)
Accumulated dividends on preferred stock of subsidiary		—			6,450
Amortization of debt issuance costs		4,475			5,689
Amortization of original issuance discount		1,235			—
Write-off of unamortized debt issuance costs		6,659			—
Bargain purchase gain		(17,480	)		—
(Gain) loss on disposition of assets		(474	)		2,147
Changes in operating assets and liabilities, net of acquisition effects:
Accounts and other receivables, net		(22,001	)		(8,399	)
Income tax receivable		47,290			103,032
Inventories		34,644			(48,072	)
Heating oil crack spread hedge		—			117,485
Prepaid expenses and other current assets		(3,943	)		192
Other assets		(30,461	)		5,506
Accounts payable		36,480			161,370
Accrued liabilities		12,989			(27,604	)
Other non-current liabilities		(4,267	)		(8,232	)

Net cash provided by (used in) operating activities		(37,275	)		325,132


Cash flows from investing activities:
Capital expenditures		(20,526	)		(52,132	)
Capital expenditures to rebuild the Big Spring refinery		—			(45,072	)
Capital expenditures for turnarounds and catalysts		(12,668	)		(13,005	)
Proceeds from insurance to rebuild Big Spring refinery		—			34,125
Proceeds from sale of securities		36,852			—
Proceeds from sale of assets		20,095			—
Acquisition of Bakersfield refinery		(32,409	)		—
Earnout payment related to Krotz Springs refinery acquisition		(6,562	)		(17,521	)

Net cash used in investing activities		(15,218	)		(93,605	)


Cash flows from financing activities:
Dividends paid to stockholders		(6,501	)		(5,617	)
Dividends paid to non-controlling interest		(429	)		(576	)
Inventory supply agreement		45,807			—
Deferred debt issuance costs		(2,450	)		(7,238	)
Revolving credit facilities, net		(6,527	)		(123,029	)
Payments on long-term debt		(8,209	)		(95,443	)
Additions to short-term debt		76,500			—
Payments on short-term debt		(46,500	)		—

Net cash provided by (used in) financing activities		51,691			(231,903	)


Net decrease in cash and cash equivalents		(802	)		(376	)
Cash and cash equivalents, beginning of period		40,437			18,454

Cash and cash equivalents, end of period	$	39,635		$	18,078


Supplemental cash flow information:
Cash paid for interest	$	53,717		$	67,968

Cash paid (refunds received) for income tax	$	(46,748	)	$	(106,281	)


Non-cash activities:
Financing activity — payments on long-term debt from deposit held to secure heating oil crack spread hedge	$	—		$	(50,000	)

The accompanying notes are an integral part of these consolidated financial statements.

ALON USA ENERGY, INC. AND SUBSIDIARIES

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

(1) Basis of Presentation and Certain Significant Accounting Policies

(a) Basis of Presentation

The consolidated financial statements include the accounts of Alon USA Energy, Inc. and its subsidiaries (collectively, “Alon”). All significant intercompany balances and transactions have been eliminated. These consolidated financial statements of Alon are unaudited and have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements. In the opinion of Alon’s management, the information included in these consolidated financial statements reflects all adjustments, consisting of normal and recurring adjustments, which are necessary for a fair presentation of Alon’s consolidated financial position and results of operations for the interim periods presented. The results of operations for the interim periods are not necessarily indicative of the operating results that may be obtained for the year ending December 31, 2010.

The consolidated balance sheet as of December 31, 2009, has been derived from the audited financial statements as of that date. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in Alon’s Annual Report on Form 10-K for the year ended December 31, 2009.

(b) Revenue Recognition

Revenues from sales of refined products are earned and realized upon transfer of title to the customer based on the contractual terms of delivery (including payment terms and prices). Title primarily transfers at the refinery or terminal when the refined product is loaded into common carrier pipelines, trucks or railcars (free on board origin). In some situations, title transfers at the customer’s destination (free on board destination).

In the ordinary course of business, logistical and refinery production schedules necessitate the occasional sale of crude oil to third parties. All purchases and sales of crude oil are recorded net, in cost of sales in the consolidated statements of operations.

(c) New Accounting Standards

In February 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-09,Subsequent Event (Topic 855)which amends FASB Accounting Standards Codification (“ASC”) Topic 855,Subsequent Eventsso that SEC filers, as defined in the ASU, no longer are required to disclose the date through which subsequent events have been evaluated in originally issued and revised financial statements. ASU 2010-09 is effective immediately. ASU 2010-09 only affects disclosure requirements and will not have any effect on Alon’s consolidated financial statements.

In January 2010, the FASB issued ASU 2010-06,Improving Disclosures about Fair Valuewhich amends FASB ASC Topic 820,Fair Value Measurements and Disclosure, to require entities to make new disclosure about recurring and non-recurring fair-value measurements. The update requires new disclosures regarding significant transfers in and out of Level 1 and Level 2 fair-value measurements and information about purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair-value adjustments. The update provides additional guidance on other fair value disclosures. This update is effective for interim and annual reporting periods beginning after December 15, 2009. ASU 2010-06 only affects disclosure requirements and will not have any effect on Alon’s consolidated financial statements.

(d) Reclassifications

Certain reclassifications have been made to the prior period balances to conform to the current presentation.

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

(2) Bakersfield Refinery Acquisition

On June 1, 2010, Alon completed the acquisition of the Bakersfield, California refinery (“Bakersfield refinery”) from Big West of California, LLC, a subsidiary of Flying J, Inc. The aggregate purchase price was $58,409 in cash, which included the purchase price of hydrocarbon inventories. In connection with the acquisition, an affiliate of Alon purchased certain refinery assets not installed at the Bakersfield refinery location for $26,000. The remaining assets were purchased by Alon. Alon incurred $309 of acquisition-related costs that were recognized in selling, general and administrative expenses in the consolidated statement of operations for the nine months ended September 30, 2010.

The Bakersfield refinery is located in California’s Central Valley and has the capacity to refine up to 70,000 barrels of crude oil per day. The refinery has traditionally been supplied by local California crude oils produced in the San Joaquin Valley and the Los Angeles Basin. Historically, this refinery has been a major provider of quality motor fuels in central California and is also a large supplier of gas oil products to other refiners.

Alon plans to integrate the operations of the Bakersfield refinery with its other California refineries by processing vacuum gas oil produced by the California refineries in the hydrocracker unit located at the Bakersfield refinery.

An acquirer is required to recognize and measure the goodwill acquired in a business combination or a gain from a bargain purchase. FASB ASC 805 defines a bargain purchase as a business combination in which the total acquisition-date fair value of the identifiable net assets acquired exceeds the fair value of the consideration transferred plus any non-controlling interest in the acquiree, and it requires the acquirer to recognize that excess in earnings as a gain attributable to the acquirer.

An independent appraisal of the net assets acquired in the Bakersfield refinery acquisition has been completed. The fair value of the assets acquired and liabilities assumed are as follows:


Current assets	$	17,033
Other assets		17,122
Property, plant and equipment		69,403
Other non-current liabilities		(53,669	)

Net assets acquired		49,889
Less: Gain on bargain purchase		(17,480	)

Total consideration	$	32,409

In connection with the acquisition of the Bakersfield refinery, Alon recorded a discounted accrued environmental remediation obligation of $42,122. This amount is included as a non-current liability in the consolidated balance sheet at September 30, 2010.

Also in connection with the acquisition of the Bakersfield refinery, Alon entered into an indemnification agreement with a prior owner for remediation expenses of conditions that existed at the refinery on the acquisition date. Alon is required to make indemnification claims to the prior owner by March 15, 2015. The discounted indemnification amount is $17,122 and is shown as a non-current receivable in the consolidated balance sheet at September 30, 2010.

(3) Segment Data

Alon’s revenues are derived from three operating segments: (i) refining and unbranded marketing, (ii) asphalt and (iii) retail and branded marketing. The reportable operating segments are strategic business units that offer different products and services. The segments are managed separately as each segment requires unique technology, marketing strategies and distinct operational emphasis. Each operating segment’s performance is evaluated primarily based on operating income.

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

(a) Refining and Unbranded Marketing Segment

Alon’s refining and unbranded marketing segment includes sour and heavy crude oil refineries located in Big Spring, Texas, and Paramount, Bakersfield and Long Beach, California (the “California refineries”) and a light sweet crude oil refinery located in Krotz Springs, Louisiana. At these refineries, Alon refines crude oil into products including gasoline, diesel, jet fuel, petrochemicals, feedstocks, asphalts and other petroleum products, which are marketed primarily in the South Central, Southwestern and Western regions of the United States. Finished products and blendstocks are also marketed through sales and exchanges with other major oil companies, state and federal governmental entities, unbranded wholesale distributors and various other third parties. Alon also acquires finished products through exchange agreements and third-party suppliers.

(b) Asphalt Segment

Alon’s asphalt segment includes the Willbridge, Oregon refinery and 12 refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Oregon (Willbridge), Washington (Richmond Beach), Arizona (Phoenix, Flagstaff and Fredonia), and Nevada (Fernley) (50% interest) as well as a 50% interest in Wright Asphalt Products Company, LLC (“Wright”) which specializes in marketing patented tire rubber modified asphalt products. Alon produces both paving and roofing grades of asphalt and, depending on the terminal, can manufacture performance-graded asphalts, emulsions and cutbacks. The operations in which Alon has a 50% interest (Fernley and Wright), are recorded under the equity method of accounting, and the investments are included as part of total assets in the asphalt segment data.

(c) Retail and Branded Marketing Segment

Alon’s retail and branded marketing segment operates 306 convenience stores located primarily in Central and West Texas and New Mexico. These convenience stores typically offer various grades of gasoline, diesel fuel, general merchandise and food and beverage products to the general public primarily under the 7-Eleven and FINA brand names. Alon’s branded marketing business markets gasoline and diesel under the FINA brand name, primarily in the Southwestern and South Central United States through a network of approximately 640 locations, including Alon’s convenience stores. Historically, substantially all of the motor fuel sold through Alon’s convenience stores and the majority of the motor fuels marketed in Alon’s branded business have been supplied by Alon’s Big Spring refinery.

(d) Corporate

Operations that are not included in any of the three segments are included in the corporate category. These operations consist primarily of corporate headquarters operating and depreciation expenses.

Segment data as of and for the three and nine-month periods ended September 30, 2010 and 2009, are presented below:


	Refining and						Retail and Branded						Consolidated
	Unbranded Marketing			Asphalt			Marketing			Corporate			Total
Three Months ended September 30, 2010
Net sales to external customers	$	830,478		$	144,610		$	273,481		$	—		$	1,248,569
Intersegment sales/purchases		226,000			(55,052	)		(170,948	)		—			—
Depreciation and amortization		21,315			1,716			3,353			397			26,781
Operating income (loss)		(52,601	)		8,962			8,809			(585	)		(35,415	)
Total assets		1,818,774			153,104			184,694			18,992			2,175,564
Turnaround, chemical catalyst, capital expenditures and capital expenditures to rebuild the Big Spring refinery		5,844			465			1,322			1,344			8,975

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


	Refining and						Retail and Branded						Consolidated
	Unbranded Marketing			Asphalt			Marketing			Corporate			Total
Three Months ended September 30, 2009
Net sales to external customers	$	860,692		$	175,189		$	217,232		$	—		$	1,253,113
Intersegment sales/purchases		197,825			(73,800	)		(124,025	)		—			—
Depreciation and amortization		19,943			1,700			3,399			205			25,247
Operating income (loss)		(57,780	)		19,666			4,165			(394	)		(34,343	)
Total assets		1,742,871			251,382			193,850			17,163			2,205,266
Turnaround, chemical catalyst, capital expenditures and capital expenditures to rebuild the Big Spring refinery		28,341			523			751			1,755			31,370

	Refining and						Retail and Branded						Consolidated
	Unbranded Marketing			Asphalt			Marketing			Corporate			Total
Nine Months ended September 30, 2010
Net sales to external customers	$	1,598,064		$	316,715		$	753,464		$	—		$	2,668,243
Intersegment sales/purchases		632,785			(158,754	)		(474,031	)		—			—
Depreciation and amortization		62,150			5,148			10,209			964			78,471
Operating income (loss)		(146,506	)		(8,754	)		14,684			(1,528	)		(142,104	)
Total assets		1,818,774			153,104			184,694			18,992			2,175,564
Turnaround, chemical catalyst and capital expenditures		27,902			991			2,149			2,152			33,194

	Refining and						Retail and Branded						Consolidated
	Unbranded Marketing			Asphalt			Marketing			Corporate			Total
Nine Months ended September 30, 2009
Net sales to external customers	$	2,139,099		$	351,429		$	591,163		$	—		$	3,081,691
Intersegment sales/purchases		513,818			(188,676	)		(325,142	)		—			—
Depreciation and amortization		55,120			5,099			10,179			500			70,898
Operating income (loss)		6,386			1,973			7,941			(1,069	)		15,231
Total assets		1,742,871			251,382			193,850			17,163			2,205,266
Turnaround, chemical catalyst, capital expenditures and capital expenditures to rebuild the Big Spring refinery		104,259			1,099			1,864			2,987			110,209

Operating income (loss) for each segment consists of net sales less cost of sales, direct operating expenses, selling, general and administrative expenses, depreciation and amortization, and gain (loss) on disposition of assets. Intersegment sales are intended to approximate wholesale market prices. Consolidated totals presented are after intersegment eliminations.

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

(4) Cash and Cash Equivalents

Alon considers 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.

(5) Fair Value

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

Alon must determine fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As required, Alon utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of

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

unobservable inputs (level 3) within the fair value hierarchy. Alon generally applies the “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the consolidated balance sheets at September 30, 2010, and December 31, 2009, respectively:


	Quoted Prices in
	Active Markets		Significant
	For Identical		Other		Significant
	Assets or		Observable		Unobservable
	Liabilities		Inputs		Inputs		Consolidated
	(Level 1)		(Level 2)		(Level 3)		Total
Nine Months ended September 30, 2010
Assets:
Commodity contracts (futures and forwards)	$	531	$	—	$	—	$	531
Liabilities:
Commodity contracts (swaps)		873		633		—		1,506
Commodity contracts (call options)		—		6,646		—		6,646
Interest rate swaps		—		10,821		—		10,821

Year ended December 31, 2009
Assets:
Commodity contracts (futures and forwards)	$	322	$	—	$	—	$	322
Commodity contracts (swaps)		—		89		—		89
Liabilities:
Commodity contracts (swaps)		—		9,983		—		9,983
Interest rate swaps		—		16,933		—		16,933

(6) Derivative Financial Instruments

Commodity Derivatives — Mark to Market

Alon selectively utilizes commodity derivatives to manage its exposure to commodity price fluctuations and uses crude oil, refined product and precious metal (catalyst) commodity derivative contracts to reduce risk associated with potential price changes on committed obligations. Alon does not speculate using derivative instruments. There is not a significant credit risk on Alon’s derivative instruments which are transacted through counterparties meeting established collateral and credit criteria.

Alon has elected not to designate the following commodity derivatives as cash flow hedges for financial accounting purposes. Therefore, changes in the fair value of the commodity derivatives are included in income in the period of the change.

At September 30, 2010, Alon held net forward contracts for the purchase of 92,966 barrels of refined products at an average price of $86.11 per barrel. At September 30, 2009, Alon held net forward contracts for sales of 200,015 barrels of refined products at an average price of $70.31 per barrel. The contracts are recorded at their fair market values and an unrealized gain of $531 and an unrealized loss of $688 have been included in cost of sales in the consolidated statement of operations for the nine months ended September 30, 2010 and 2009, respectively.

At September 30, 2009, Alon held net futures contracts for purchases of 91,000 barrels of refined products at an average price of $75.32 per barrel. The contract was recorded at its fair market value and an unrealized gain of $150 has been included in cost of sales in the consolidated statement of operations for the nine months ended September 30, 2009.

At September 30, 2009, Alon held futures contracts for 434,000 barrels of crude swaps at an average price of $74.80 per barrel. The contracts are recorded at their fair market values.

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

At September 30, 2010, Alon held futures contracts for sales of 255,600 barrels of heating oil crack spread swaps at an average of $11.38 per barrel. The contracts are recorded at their fair market values and an unrealized loss of $633 has been included in cost of sales in the consolidated statement of operations for the nine months ended September 30, 2010.

At September 30, 2010, Alon had written call contracts outstanding for the net purchase of 3,514,500 barrels of crude and sale of 3,514,500 barrels of heating oil at an average strike price of $11.35 per barrel for a period of 21 months commencing October 2010. The value of the obligation equals the premium received resulting in no unrealized gain or loss to be included in cost of sales in the consolidated statement of operations for the nine months ended September 30, 2010.

At September 30, 2010, Alon also held futures contracts for 2,846 ounces of platinum swaps and 2,534 ounces of palladium swaps at an average price of $1,664.50 and $573.35 per ounce, respectively. The contracts are recorded at their fair market values and an unrealized loss of $873 has been included in other income (loss) in the consolidated statement of operations for the nine months ended September 30, 2010.

Cash Flow Hedges

To designate a derivative as a cash flow hedge, Alon documents at the inception of the hedge the assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. If, during the term of the derivative, the hedge is determined to be no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings when the underlying transaction occurs.

Interest Rate Derivatives.Alon selectively utilizes interest rate related derivative instruments to manage its exposure to floating-rate debt instruments. Alon periodically uses interest rate swap agreements to manage its floating to fixed rate position by converting certain floating-rate debt to fixed-rate debt. As of September 30, 2010, Alon had interest rate swap agreements with a notional amount of $300,000 with remaining periods ranging from less than three months to approximately two years and fixed interest rates ranging from 4.25% to 4.45%. All of these swaps were accounted for as cash flow hedges.

For cash flow hedges, gains and losses reported in accumulated other comprehensive income in stockholders’ equity are reclassified into interest expense when the forecasted transactions affect income. During the nine months ended September 30, 2010 and 2009, Alon recognized in accumulated other comprehensive income unrealized after-tax gains of $3,973 and $4,069, respectively, for the fair value measurement of the interest rate swap agreements. There were no amounts reclassified from accumulated other comprehensive income into interest expense as a result of the discontinuance of cash flow hedge accounting.

For the three and nine months ended September 30, 2010 and 2009, there was no hedge ineffectiveness recognized in income. No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.

Commodity Derivatives.In May 2008, as part of financing the acquisition of the Krotz Springs refinery, Alon entered into futures contracts for the forward purchase of crude oil and the forward sale of heating oil of 14,849,750 barrels. These futures contracts were designated as cash flow hedges for accounting purposes. Gains and losses for the futures contracts designated as cash flow hedges reported in accumulated other comprehensive income in the balance sheet are reclassified into cost of sales when the forecasted transactions affect income. In the fourth quarter of 2008, Alon determined during its retrospective assessment of hedge effectiveness that the hedge was no longer highly effective. Cash flow hedge accounting was discontinued in the fourth quarter of 2008 and all changes in value subsequent to the discontinuance were recognized into earnings. In April 2009, Alon completed an unwind of these futures contracts for $139,290.

Losses of $2,825 and $6,354 for the three and nine months ended September 30, 2010, and gains of $433 and $4,447 for the three and nine months ended September 30, 2009, have been reclassified from accumulated other comprehensive income to earnings since the discontinuance of cash flow hedge accounting, respectively. All remaining adjustments from accumulated comprehensive income to cost of sales will be recorded in October 2010.

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

No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.

The following table presents the effect of derivative instruments on the consolidated statements of financial position.


	As of September 30, 2010
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (swaps)		$	—	Accounts Payable	$	(633	)
Commodity contracts (futures, forwards, swaps and call options)			—	Accrued liabilities		(3,826	)
Commodity contracts (call options)			—	Other non-current liabilities		(3,162	)

Total derivatives not designated as hedging instruments		$	—		$	(7,621	)


Derivatives designated as hedging instruments:
Interest rate swaps		$	—	Other non-current liabilities	$	(10,821	)

Total derivatives designated as hedging instruments			—			(10,821	)

Total derivatives		$	—		$	(18,442	)


	As of December 31, 2009
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures, forwards and SPR swaps)	Accounts receivable	$	411	Accrued liabilities	$	(9,983	)

Total derivatives not designated as hedging instruments under ASC 815		$	411		$	(9,983	)


Derivatives designated as hedging instruments:
Interest rate swaps		$	—	Other non-current liabilities	$	(16,933	)

Total derivatives designated as hedging instruments under ASC 815			—			(16,933	)

Total derivatives		$	411		$	(26,916	)

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

The following tables present the effect of derivative instruments on Alon’s consolidated statements of operations and accumulated other comprehensive income (“OCI”).


							Gain (Loss) Reclassified
							from Accumulated OCI into
							Income (Ineffective
			Gain (Loss) Reclassified from				Portion and Amount
	Gain (Loss) Recognized		Accumulated OCI into Income (Effective				Excluded from
Cash Flow Hedging Relationships	in OCI		Portion)				Effectiveness Testing)
			Location	Amount			Location	Amount
For the Three Months Ended September 30, 2010
Commodity contracts (heating oil swaps)	$	—	Cost of sales	$	(2,825	)		$	—
Interest rate swaps		2,494	Interest expense		(3,693	)			—

Total derivatives	$	2,494		$	(6,518	)		$	—


For the Nine Months Ended September 30, 2010
Commodity contracts (heating oil swaps)	$	—	Cost of sales	$	(6,354	)		$	—
Interest rate swaps		6,112	Interest expense		(10,917	)			—

Total derivatives	$	6,112		$	(17,271	)		$	—


							Gain (Loss) Reclassified
							from Accumulated OCI into
							Income (Ineffective
			Gain (Loss) Reclassified from				Portion and Amount
	Gain (Loss) Recognized		Accumulated OCI into Income				Excluded from
Cash Flow Hedging Relationships	in OCI		(Effective Portion)				Effectiveness Testing)
			Location	Amount			Location	Amount
For the Three Months Ended September 30, 2009
Commodity contracts (heating oil swaps)	$	—	Cost of sales	$	433			$	—
Interest rate swaps		622	Interest expense		(3,713	)			—

Total derivatives	$	622		$	(3,280	)		$	—


For the Nine Months Ended September 30, 2009
Commodity contracts (heating oil swaps)	$	—	Cost of sales	$	4,447			$	—
Interest rate swaps		6,261	Interest expense		(10,716	)			—

Total derivatives	$	6,261		$	(6,269	)		$	—

Derivatives not designated as hedging instruments:


	Gain (Loss) Recognized in Income
	Location	Amount
For the Three Months Ended September 30, 2010
Commodity contracts (futures & forwards)	Cost of sales	$	1,796
Commodity contracts (heating oil swaps)	Cost of sales		(186	)
Commodity contracts (call options)	Cost of sales		60
Commodity contracts (commodity swaps)	Other income (loss), net		(671	)

Total derivatives		$	999


For the Nine Months Ended September 30, 2010
Commodity contracts (futures & forwards)	Cost of sales	$	3,536
Commodity contracts (heating oil swaps)	Cost of sales		(501	)
Commodity contracts (commodity swaps)	Other income (loss), net		(873	)

Total derivatives		$	2,162

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


	Gain (Loss) Recognized in Income
	Location	Amount
For the Three Months Ended September 30, 2009
Commodity contracts (futures & forwards)	Cost of sales	$	564

Total derivatives		$	564


For the Nine Months Ended September 30, 2009
Commodity contracts (futures & forwards)	Cost of sales	$	(13,927	)
Commodity contracts (heating oil swaps)	Cost of sales		41,182
Commodity contracts (SPR swaps)	Cost of sales		174

Total derivatives		$	27,429

(7) Inventories

Alon’s inventories 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, asphalt, 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,
	2010		2009
Crude oil, refined products, asphalt and blendstocks	$	73,689	$	150,370
Inventory consigned to others		82,158		22,558
Materials and supplies		18,743		18,069
Store merchandise		18,250		18,856
Store fuel		4,859		5,146

Total inventories	$	197,699	$	214,999

Crude oil, refined products, asphalt and blendstock inventories totaled 2,281 barrels and 3,301 barrels as of September 30, 2010 and December 31, 2009, respectively.

Market values of crude oil, refined products, asphalt and blendstock inventories exceeded LIFO costs by $104,450 and $100,496 at September 30, 2010 and December 31, 2009, respectively.

(8) Property, Plant and Equipment, Net

Property, plant and equipment, net consisted of the following:


	September 30,			December 31,
	2010			2009
Refining facilities	$	1,607,192		$	1,535,841
Pipelines and terminals		39,213			39,213
Retail		136,279			137,150
Other		16,999			16,747

Property, plant and equipment, gross		1,799,683			1,728,951
Less accumulated depreciation		(315,679	)		(251,525	)

Property, plant and equipment, net	$	1,484,004		$	1,477,426

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

(9) Additional Financial Information

The tables that follow provide additional financial information related to the consolidated financial statements.

(a) Other Assets


	September 30,		December 31,
	2010		2009
Deferred turnaround and chemical catalyst cost	$	25,236	$	24,387
Environmental receivables		20,589		3,448
Deferred debt issuance costs		17,138		25,822
Intangible assets		8,005		8,516
Other		26,014		8,359

Total other assets	$	96,982	$	70,532

Unamortized debt issuance costs of $6,659 related to the prepayment of the Alon Refining Krotz Springs, Inc. revolving credit facility were written off in the first quarter of 2010.

In connection with the acquisition of the Bakersfield refinery on June 1, 2010, Alon entered into an indemnification agreement with a prior owner for remediation expenses of conditions that existed at the refinery on the acquisition date. Alon is required to make indemnification claims to the prior owner by March 15, 2015. The discounted indemnification amount is $17,122 and is shown in environmental receivables. Alon has also recorded a corresponding environmental liability (Note 17).

(b) Accrued Liabilities and Other Non-Current Liabilities


	September 30,		December 31,
	2010		2009
Accrued Liabilities:
Taxes other than income taxes, primarily excise taxes	$	19,930	$	20,205
Employee costs		8,153		6,716
Commodity swaps		3,826		9,983
Valero earnout liability		8,750		8,750
Other		46,169		46,726

Total accrued liabilities	$	86,828	$	92,380


Other Non-Current Liabilities:
Pension and other postemployment benefit liabilities, net	$	34,235	$	34,902
Environmental accrual (Note 17)		67,161		27,350
Asset retirement obligations		10,097		8,789
Interest rate swap valuations		10,821		16,933
Valero earnout liability		—		6,562
Commodity swaps		3,162		—
Other		12,899		540

Total other non-current liabilities	$	138,375	$	95,076

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

(c) Comprehensive Loss

The following table displays the computation of total comprehensive loss:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Loss before non-controlling interest in loss of subsidiaries and accumulated dividends on preferred stock of subsidiary	$	(16,751	)	$	(26,720	)	$	(105,009	)	$	(21,050	)

Other comprehensive gain, net of tax:
Unrealized gain on cash flow hedges, net of tax		3,401			131			7,976			1,267

Total other comprehensive income, net of tax		3,401			131			7,976			1,267

Comprehensive loss		(13,350	)		(26,589	)		(97,033	)		(19,783	)

Comprehensive loss attributable to non-controlling interest (including accumulated dividends on preferred shares of subsidiary)		(956	)		(153	)		(6,834	)		3,587

Comprehensive loss attributable to common stockholders	$	(12,394	)	$	(26,436	)	$	(90,199	)	$	(23,370	)

The following table displays the components of accumulated other comprehensive loss, net of tax.


	September 30,			December 31,
	2010			2009
Unrealized losses on cash flow hedges, net of tax	$	(8,309	)	$	(15,895	)
Pension and post-employment benefits, net of tax		(16,976	)		(16,976	)

Accumulated other comprehensive loss, net of tax	$	(25,285	)	$	(32,871	)

(10) Postretirement Benefits

Alon has three defined benefit pension plans covering substantially all of its refining and unbranded marketing segment employees, excluding West Coast employees and employees of SCS. The benefits are based on years of service and the employee’s final average monthly compensation. Alon’s funding policy is to contribute annually not less than the minimum required nor more than the maximum amount that can be deducted for federal income tax purposes. Contributions are intended to provide not only for benefits attributed to service to date but also for those benefits expected to be earned in the future. Alon’s estimated contributions during 2010 to its pension plans has not changed significantly from amounts previously disclosed in Alon’s consolidated financial statements for the year ended December 31, 2009. For the nine months ended September 30, 2010 and 2009, Alon contributed $5,000 and $3,430, respectively, to its qualified pension plans.

The components of net periodic benefit cost related to Alon’s benefit plans were as follows for the three and nine months ended September 30, 2010 and 2009:


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Components of net periodic benefit cost:
Service cost	$	1,018		$	837		$	3,055		$	2,510
Interest cost		946			841			2,837			2,522
Expected return on plan assets		(904	)		(840	)		(2,715	)		(2,519	)
Amortization of net loss		385			262			1,157			788

Net periodic benefit cost	$	1,445		$	1,100		$	4,334		$	3,301

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

(11) Indebtedness

Debt consisted of the following:


	September 30,			December 31,
	2010			2009
Term loan credit facility	$	430,875		$	434,250
Revolving credit facilities		210,050			216,577
Senior secured notes		206,928			205,693
Short-term debt		30,000			—
Retail credit facilities		75,670			80,504

Total debt		953,523			937,024
Less short-term debt and current portion of long-term debt		(40,946	)		(10,946	)

Total long-term debt	$	912,577		$	926,078
	��

(a) Alon USA Energy, Inc. Credit Facilities

Term Loan Credit Facility. Alon has a term loan (the “Alon Energy Term Loan”) that will mature on August 2, 2013. Principal payments of $4,500 per annum are paid in quarterly installments, subject to reduction from mandatory repayments associated with certain events.

Borrowings under the Alon Energy Term Loan bear interest at a rate based on a margin over the Eurodollar rate from between 1.75% to 2.50% per annum based upon the ratings of the loans by Standard & Poor’s Rating Service and Moody’s Investors Service, Inc. Currently, the margin is 2.25% over the Eurodollar rate.

The Alon Energy Term Loan is jointly and severally guaranteed by all of Alon’s subsidiaries except for Alon’s retail subsidiaries, those subsidiaries established in conjunction with the Krotz Springs refinery acquisition and certain subsidiaries established in conjunction with the Bakersfield refinery acquisition. The Alon Energy Term Loan is secured by a second lien on cash, accounts receivable and inventory and a first lien on most of the remaining assets of Alon excluding those of Alon’s retail subsidiaries, those subsidiaries established in conjunction with the Krotz Springs refinery acquisition and certain subsidiaries established in conjunction with the Bakersfield refinery acquisition.

The Alon Energy Term Loan contains customary restrictive covenants, such as restrictions on liens, mergers, consolidations, sales of assets, additional indebtedness, different businesses, certain lease obligations, and certain restricted payments. The Alon Energy Term Loan does not contain any maintenance financial covenants.

At September 30, 2010 and December 31, 2009, the Alon Energy Term Loan had an outstanding balance of $430,875 and $434,250, respectively.

Letter of Credit Facility.On March 9, 2010, Alon entered into an unsecured credit facility with Israel Discount Bank of New York (the “Alon Energy Letter of Credit Facility”) for the issuance of letters of credit in an amount not to exceed $60,000 and with a sub-limit for borrowings not to exceed $30,000. This facility will terminate on January 31, 2013. On September 30, 2010, Alon had $60,000 of outstanding letters of credit under this facility. Borrowings under this facility bear interest at the Eurodollar rate plus 3.00% per annum subject to an overall minimum interest rate of 4.00%.

This facility contains certain customary restrictive covenants including financial covenants.

(b) Alon USA LP Credit Facility

Revolving Credit Facility.Alon has a $240,000 revolving credit facility (the “Alon USA LP Credit Facility”) that will mature on January 1, 2013. The Alon USA LP Credit Facility can be used both for borrowings and the issuance of letters of credit, subject to a limit of the lesser of the facility or the amount of the borrowing base under the facility.

Borrowings under the Alon USA LP Credit Facility bear interest at the Eurodollar rate plus 3.00% per annum subject to an overall minimum interest rate of 4.00%.

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

The Alon USA LP Credit Facility is secured by (i) a first lien on Alon’s cash, accounts receivables, inventories and related assets and (ii) a second lien on Alon’s fixed assets and other specified property, in each case, excluding those of Alon Paramount Holdings, Inc. (“Alon Holdings”), and its subsidiaries other than Alon Pipeline Logistics, LLC (“Alon Logistics”), the subsidiaries established in conjunction with the Krotz Springs refinery acquisition, the subsidiaries established in conjunction with the Bakersfield refinery acquisition and Alon’s retail subsidiaries.

The Alon USA LP Credit Facility contains certain restrictive covenants including maintenance financial covenants. As currently amended, the maintenance financial covenants for the leverage ratio and the interest coverage ratio will not apply until the fiscal quarter ending December 31, 2010. The maintenance financial covenant for the current ratio will continue to be measured for all fiscal quarters of 2010. If we will not be able to maintain the level required by these covenants, then borrowings under the Alon USA LP Credit Facility that are currently in long-term debt will be classified under short-term and current portion of long-term debt.

Borrowings of $144,000 and $88,000 were outstanding under the Alon USA LP Credit Facility at September 30, 2010 and December 31, 2009, respectively. At September 30, 2010 and December 31, 2009, outstanding letters of credit under the Alon USA LP Credit Facility were $92,945 and $128,963, respectively.

(c) Paramount Petroleum Corporation Credit Facility

Revolving Credit Facility.Paramount Petroleum Corporation has a $300,000 revolving credit facility (the “Paramount Credit Facility”) that will mature on February 28, 2012. The Paramount Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility or the amount of the borrowing base under the facility.

Borrowings under the Paramount Credit Facility bear interest at the Eurodollar rate plus a margin based on excess availability. The average excess availability during September 2010 was $69,223 and the margin was 1.75%.

The Paramount Credit Facility is primarily secured by (i) a first lien on accounts receivables, inventories and related assets and (ii) a second lien on Alon Holdings’ (excluding Alon Logistics) fixed assets and other specified property.

The Paramount Credit Facility contains certain restrictive covenants related to working capital, operations and other matters.

Borrowings of $66,050 and $45,290 were outstanding under the Paramount Credit Facility at September 30, 2010 and December 31, 2009, respectively. At September 30, 2010 and December 31, 2009, outstanding letters of credit under the Paramount Credit Facility were $57,842 and $17,999, respectively.

(d) Alon Refining Krotz Springs, Inc. Credit Facilities

Senior Secured Notes.In October 2009, Alon Refining Krotz Springs, Inc. (“ARKS”) issued 13.50% senior secured notes (the “Senior Secured Notes”) in aggregate principal amount of $216,500 in a private offering. The Senior Secured Notes were issued at an offering price of 94.857%.

ARKS received gross proceeds of $205,365 from the sale of the Senior Secured Notes (before fees and expenses related to the offering). In connection with the closing, ARKS prepaid in full all outstanding obligations under its term loan. The remaining proceeds from the offering were used for general corporate purposes.

The terms of the Senior Secured Notes are governed by an indenture (the “Indenture”) and the obligations under the Indenture are secured by a first priority lien on ARKS’ property, plant and equipment and a second priority lien on ARKS’ cash, accounts receivable and inventory.

The Indenture also contains restrictive covenants such as restrictions on loans, mergers, sales of assets, additional indebtedness and restricted payments. The Indenture does not contain any maintenance financial covenants.

On February 17, 2010, ARKS exchanged $216,480 of Senior Secured Notes for an equivalent amount of Senior Secured Notes (“Exchange Notes”) registered under the Securities Act of 1933. The Exchange Notes will mature on October 15, 2014 and the entire principal amount is due at maturity. Interest is payable semi-annually in

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

arrears on April 15 and October 15. The Exchange Notes are substantially identical to the Senior Secured Notes, except that the Exchange Notes have been registered with the Securities and Exchange Commission and are not subject to transfer restrictions.

At September 30, 2010 and December 31, 2009, the Senior Secured Notes had an outstanding balance (net of unamortized discount) of $206,928 and $205,693, respectively. Alon is utilizing the effective interest method to amortize the original issue discount over the life of the Senior Secured Notes.

Short-Term Credit Facility.On March 15, 2010, ARKS entered into a $65,000 short-term credit facility with Bank Hapoalim B.M. (the “ARKS Term Facility”). The ARKS Term Facility as currently amended and restated matures on November 15, 2010. ARKS originally borrowed $65,000 and has repaid $35,000 as of September 30, 2010.

Borrowings under the ARKS Term Facility bear interest at LIBOR plus 3.00% and $30,000 was outstanding under the ARKS Term Facility at September 30, 2010. The ARKS Term Facility is secured by a second lien on all assets other than cash, accounts receivable, and inventory of ARKS. The ARKS Term Facility contains customary restrictive covenants, such as restrictions on liens, mergers, consolidation, sales of assets, capital expenditures, additional indebtedness, investments, hedging transactions, and certain restricted payments.

The ARKS Term Facility was prepaid in full on October 28, 2010.

Revolving Credit Facility.On March 15, 2010, ARKS terminated its revolving credit facility agreement (the “ARKS Facility”) and repaid all outstanding amounts thereunder. As a result of the prepayment of the ARKS Facility, Alon recorded a write-off of unamortized debt issuance costs of $6,659 as interest expense in the first quarter of 2010.

Borrowings of $83,287 and outstanding letters of credit of $2,765 were outstanding under the ARKS Facility at December 31, 2009.

(e) Retail Credit Facilities

Term Credit Agreement.Southwest Convenience Stores, LLC (“SCS”) is a party to a credit agreement (the “SCS Credit Agreement”) that matures on July 1, 2017. Monthly principal payments are based on a 15-year amortization term.

Borrowings under the SCS Credit Agreement bear interest at a Eurodollar rate plus 1.50% per annum.

Obligations under the SCS Credit Agreement are jointly and severally guaranteed by Alon, Alon Brands, Inc., Skinny’s, LLC and all of the subsidiaries of SCS. The obligations under the SCS Credit Agreement are secured by a pledge of substantially all of the assets of SCS and Skinny’s, LLC and each of their subsidiaries, including cash, accounts receivable and inventory.

The SCS Credit Agreement contains customary restrictive covenants on its activities, such as restrictions on liens, mergers, consolidations, sales of assets, additional indebtedness, investments, certain lease obligations and certain restricted payments. The SCS Credit Agreement also includes one annual financial covenant.

At September 30, 2010 and December 31, 2009, the SCS Credit Agreement had an outstanding balance of $74,944 and $79,694, respectively, and there were no further amounts available for borrowing.

Other Retail Related Credit Facilities.In 2003, Alon obtained $1,545 in mortgage loans to finance the acquisition of new retail locations. The interest rates on these loans ranged between 5.5% and 9.7%, with 5 to 15-year payment terms. At September 30, 2010 and December 31, 2009, the outstanding balances were $726 and $810, respectively.

(12) Stock-Based Compensation

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

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

(a) Amended and Restated 2005 Incentive Compensation Plan (share value in dollars)

Alon’s original incentive compensation plan, the Alon USA Energy, Inc. 2005 Incentive Compensation Plan, was approved by its stockholders in 2006. In May 2010, Alon’s stockholders approved an amended and restated incentive compensation plan, the Alon USA Energy, Inc. Amended and Restated 2005 Incentive Compensation Plan, which is a component of Alon’s overall executive incentive compensation program. The Amended and Restated 2005 Incentive Compensation Plan permits the granting of awards in the form of options to purchase common stock, Stock Appreciation Rights (“SARs”), restricted shares of common stock, restricted common stock units, performance shares, performance units and senior executive plan bonuses to Alon’s directors, officers and key employees. Other than the restricted share grants and SARs discussed below, there have been no stock-based awards granted under the Amended and Restated 2005 Incentive Compensation Plan.

Restricted Stock. Non-employee directors are awarded an annual grant of shares of restricted stock valued at $25. The restricted shares granted to the non-employee directors vest over a period of three years, assuming continued service at vesting.

Compensation expense for the restricted stock grants amounted to $22 and $22 for the three months ended September 30, 2010 and 2009, respectively, and $53 and $53 for the nine months ended September 30, 2010 and 2009, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations. There is no material difference between intrinsic value and fair value under FASB ASC Topic 718-10 for pro forma disclosure purposes.

The following table summarizes the restricted share activity from January 1, 2009:


				Weighted
				Average
				Grant Date
				Fair Values
Nonvested Shares	Shares			(per share)
Nonvested at January 1, 2009		7,662		$	19.58
Granted		5,841			12.84
Vested		(3,277	)		22.89
Forfeited		—			—

Nonvested at December 31, 2009		10,226		$	14.67

Granted		10,416			7.20
Vested		(4,473	)		16.77
Forfeited		—			—

Nonvested at September 30, 2010		16,169		$	9.28

As of September 30, 2010, there was $85 of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the Amended and Restated 2005 Incentive Compensation Plan. That cost is expected to be recognized over a weighted-average period of 2.1 years. The fair value of shares vested in 2010 was $31.

Stock Appreciation Rights.In March 2007, Alon granted awards of 361,665 SARs to certain officers and key employees at a grant price equal to $28.46. The March 2007 SARs vest as follows: 50% on March 7, 2009, 25% on March 7, 2010, and 25% on March 7, 2011, and, pursuant to an amendment to the grant agreements on January 25, 2010, are exercisable during the three-year period following the date of vesting.

In July 2008, Alon granted awards of 12,000 SARs to certain employees at the close of the Krotz Springs refinery acquisition at a grant price equal to $14.23. The July 2008 SARs vest as follows: 50% on July 1, 2010, 25% on July 1, 2011, and 25% on July 1, 2012, and are exercisable during the 365-day period following the date of vesting.

In December 2008, Alon granted an award of 10,000 SARs at a grant price equal to $14.23. The December 2008 SARs vest as follows: 25% on December 1, 2010, 25% on December 1, 2011, 25% on December 1, 2012 and 25% on December 1, 2013 and are exercisable during the 365-day period following the date of vesting.

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

In January 2010, Alon granted awards of 177,250 SARs to certain officers and key employees at a grant price equal to $16.00. The January 2010 SARs vest as follows: 50% on December 10, 2011, 25% on December 10, 2012 and 25% on December 10, 2013 and are exercisable during the 365-day period following the date of vesting.

In March 2010, Alon granted awards of 10,000 SARs at a grant price equal to $16.00 and 10,000 SARs at a grant price equal to $10.00 to an executive officer. The March 2010 SARs vest as follows: 50% on March 1, 2012, 25% on March 1, 2013, and 25% on March 1, 2014, and are exercisable during the 365-day period following the date of vesting.

When exercised, all SARs are convertible into shares of Alon common stock, the number of which will be determined at the time of exercise by calculating the difference between the closing price of Alon common stock on the exercise date and the grant price of the SARs (the “Spread”), multiplying the Spread by the number of SARs being exercised and then dividing the product by the closing price of Alon common stock on the exercise date.

Compensation expense for the SARs grants amounted to $97 and $119 for the three months ended September 30, 2010 and 2009, respectively, and $403 and $359 for the nine months ended September 30, 2010 and 2009, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.

(b) 2000 Incentive Stock Compensation Plan

On August 1, 2000, Alon Assets, Inc. (“Alon Assets”) and Alon USA Operating, Inc. (“Alon Operating”), majority owned, fully consolidated subsidiaries of Alon, adopted the 2000 Incentive Stock Compensation Plan pursuant to which Alon’s board of directors may grant stock options to certain officers and members of executive management. The 2000 Incentive Stock Compensation Plan authorized grants of options to purchase up to 16,154 shares of common stock of Alon Assets and 6,066 shares of common stock of Alon Operating. All authorized options were granted in 2000 and there have been no additional options granted under this plan. All stock options have ten-year terms. The options are subject to accelerated vesting and become fully exercisable if Alon achieves certain financial performance and debt service criteria. Upon exercise, Alon will reimburse the option holder for the exercise price of the shares and under certain circumstances the related federal and state taxes payable as a result of such exercises (gross-up liability). This plan was closed to new participants subsequent to August 1, 2000, the initial grant date. Total compensation expense recognized under this plan was ($24) and $12 for the three months ended September 30, 2010 and 2009, respectively, and ($11) and $121 for the nine months ended September 30, 2010 and 2009, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.

The following table summarizes the stock option activity for Alon Assets and Alon Operating for the nine months ended September 30, 2010, and for the year ended December 31, 2009:


	Alon Assets					Alon Operating
				Weighted					Weighted
	Number of			Average		Number of			Average
	Options			Exercise		Options			Exercise
	Outstanding			Price		Outstanding			Price
Outstanding at January 1, 2009		2,793		$	100		1,049		$	100
Granted		—			—		—			—
Exercised		—			—		—			—
Forfeited and expired		—			—		—			—

Outstanding at December 31, 2009		2,793		$	100		1,049		$	100

Granted		—			—		—			—
Exercised		(2,187	)		100		(822	)		100
Forfeited and expired		—			—		—			—

Outstanding at September 30, 2010		606		$	100		227		$	100

The intrinsic value of total options exercised in 2010 was $1,508.

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

(13) Stockholders’ Equity (per share in dollars)

Common Stock Dividends

On September 15, 2010, Alon paid a regular quarterly cash dividend of $0.04 per share on Alon’s common stock to stockholders of record at the close of business on August 28, 2010.

(14) Loss Per Share (loss per share in dollars)

Basic loss per share is calculated as net loss available to common stockholders divided by the average number of shares of common stock outstanding. Diluted earnings per share include the dilutive effect of restricted shares and SARs using the treasury stock method and the dilutive effect of convertible preferred shares using the if-converted method.

The calculation of loss per share, basic and diluted, for the three and nine months ended September 30, 2010 and 2009, is as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Net loss available to common stockholders	$	(15,584	)	$	(26,558	)	$	(97,785	)	$	(24,547	)
Average number of shares of common stock outstanding		54,181			46,810			54,177			46,808
Dilutive SARs		—			—			—			—

Average number of shares of common stock outstanding assuming dilution		54,181			46,810			54,177			46,808

Loss per share – basic	$	(0.29	)	$	(0.57	)	$	(1.80	)	$	(0.52	)

Loss per share – diluted *	$	(0.29	)	$	(0.57	)	$	(1.80	)	$	(0.52	)


*		For the purpose of adjusting net loss in the calculation of diluted loss per share issued by Alon’s subsidiaries, the effect for the three and nine months ended September 30, 2010 and 2009, is anti-dilutive and therefore excluded from the calculation.

(15) Big Spring Refinery Fire

On February 18, 2008, a fire at the Big Spring refinery destroyed the propylene recovery unit and damaged equipment in the alkylation and gas concentration units for which insurance policies at the time of the fire provided a combined single limit of $385,000 for property damage, with a $2,000 deductible, and business interruption coverage with a 45-day waiting period. Alon also had third party liability insurance which provided coverage with a limit of $150,000 and a $5,000 deductible. Alon received insurance proceeds of $330,000 for work performed through December 31, 2008 and $55,000 for business interruption recovery as a result of the fire with $350,875 of proceeds received in 2008 and $34,125 of proceeds received in January 2009.

(16) Related-Party Transactions

Sale of Preferred Shares (per share amounts in dollars)

In connection with the acquisition of the Krotz Springs refinery, pursuant to a stock purchase agreement (the “Stock Purchase Agreement”) Alon Israel Oil Company, Ltd. (“Alon Israel”) provided letters of credit in the amount of $55,000 (the “Original L/Cs”) to support the borrowing base of ARKS and purchased 80,000 shares of Series A Preferred Stock, par value $1,000.00 per share. Alon Israel issued an additional $25,000 of letters of credit in the first quarter of 2009 for the benefit of ARKS. In connection with the termination of the ARKS Facility, Alon returned to Alon Israel $65,000 of letters of credit, leaving $15,000 of letters of credit outstanding at September 30, 2010. Alon Israel provided assurances of $30,000 to support Alon in connection with the Alon Energy Letter of Credit Facility. In December 2009, Alon Israel’s shares of Series A Preferred Stock were exchanged for 7,351,051 shares of Alon common stock.

Pursuant to a stockholders agreement (as amended, the “Stockholders Agreement”) entered into in connection with the Stock Purchase Agreement, Alon Israel was granted an option (the “L/C Option”), exercisable at

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

any time the letters of credit are outstanding, to withdraw all or part of the letters of credit and acquire shares of Series A Preferred Stock of Alon Refining Louisiana, Inc. (“ARL”) at their par value of $1,000.00 per share, in an amount equal to such withdrawn letters of credit (the “L/C Preferred Shares”).

Under the terms of the Stockholders Agreement, with respect to the L/C Preferred Shares, during the period beginning on the date of issuance of any L/C Preferred Shares in connection with the exercise of the L/C Option and ending on December 31, 2010, each of Alon Louisiana Holdings, Inc. (“Alon Louisiana Holdings”) and Alon have the option to purchase from Alon Israel all or a portion of the then-outstanding L/C Preferred Shares at a price per share equal to the par value plus accrued but unpaid dividends (the “Call Option”), subject to the prior release of all of the letters of credit and conditioned upon approval of the purchase by Alon’s Audit Committee.

If the Call Option is not exercised by Alon Louisiana Holdings or Alon, the L/C Preferred Shares are exchangeable for shares of Alon common stock in accordance with the terms of the Stockholders Agreement. Specifically, (i) the L/C Preferred Shares may be exchanged at the election of either Alon or Alon Israel, for shares of Alon common stock upon a change of control of either ARL or Alon; (ii) in the event that the Call Option is not exercised, Alon Israel will have the option to exchange L/C Preferred Shares it then holds for Alon common stock during a 5-business day period beginning on the first day on which Alon’s securities trading window is open after each of January 3, 2010, July 1, 2010, and January 1, 2011; and (iii) if not so exchanged, all of the L/C Preferred Shares will be mandatorily exchanged for shares of Alon common stock on July 3, 2011.

Pursuant to the Stockholders Agreement, in the event that any letter of credit is drawn upon by beneficiaries of a letter of credit, a promissory note will be issued by Alon Louisiana Holdings in favor of Alon Israel for the amount of any such drawn letters of credit. This promissory note will provide that Alon may exchange the promissory note for shares of Alon common stock.

Sale of HEP Units

In January 2010, Alon sold 150,200 Holly Energy Partners (“HEP”) limited partnership units to each of Dor-Alon Energy in Israel (1988) Ltd. and Blue Square —Israel, Ltd., both affiliates of Alon Israel, and Alon also exchanged 287,258 HEP units for auction rate securities held by Alon Israel (which were sold in March 2010 and no gain or loss was recognized). The HEP units sold and exchanged were based on a price per unit based on the average closing price of HEP’s publically traded Class A limited partnership units for the 30 trading days preceding the closing of such transaction for a total of $22,760.

Richmond Beach Property Sale

On April 22, 2010, Alon entered into a Purchase and Sale Agreement with BSRE Point Wells, LP (“BSRE”), a subsidiary of Blue Square-Israel, Ltd., an affiliated entity, to sell a parcel of land at Richmond Beach, Washington for $19,500. The sale of the land was completed on June 1, 2010 and Alon deferred recognition of the gain on the sale of land of $5,539 as the land was sold to an affiliated entity. The deferred gain will be recognized at such time as the property is sold to a third party.

In conjunction with the sale, Alon entered into a development agreement with BSRE. The agreement provides that Alon and BSRE, in order to enhance the value of the land with a view towards maximizing the proceeds from its sale, intend to cooperate in the development and construction of a mixed-use residential and planned community real estate project on the land. As part of this agreement, Alon agreed to pay a quarterly development fee of $439, commencing in the third quarter of 2010, in exchange for the right to participate in the potential profits realized by BSRE from the development of the land.

(17) Commitments and Contingencies

(a) Commitments

In the normal course of business, Alon has long-term commitments to purchase utilities such as natural gas, electricity and water for use by its refineries, terminals, pipelines and retail locations. Alon 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.

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

Offtake Agreement with Valero

In connection with the Krotz Springs refinery acquisition in July 2008, Alon and Valero Energy Corporation (“Valero”) entered into an offtake agreement for five years that provides for Valero to purchase, at market prices, light cycle oil and straight run diesel.

Earnout Agreement with Valero

In connection with the Krotz Springs refinery acquisition Alon and Valero entered into an earnout agreement, which was amended in August 2009, to fix the remaining amounts to be paid thereunder. Pursuant to the earnout agreement, Alon has paid Valero approximately $19,688 in 2009 and $6,562 in the first nine months of 2010. Additionally, Alon has agreed to pay Valero an additional sum of $8,750 in four installments of approximately $2,188 per quarter through the third quarter of 2011 which will result in aggregate earnout payments of $35,000. The $8,750 that remains to be paid is included in accrued liabilities on the consolidated balance sheet at September 30, 2010.

Supply and Offtake Agreement with J. Aron & Company

On April 21, 2010, ARKS entered into a Supply and Offtake Agreement, which was amended on May 26, 2010 (the “Supply and Offtake Agreement”), with J. Aron & Company (“J. Aron”), the proceeds of which allowed ARKS to retire part of its obligations under the ARKS Term Facility and support the operation of the refinery at a minimum of 72,000 barrels per day. Pursuant to the Supply and Offtake Agreement, (i) J. Aron agreed to sell to ARKS, and ARKS agreed to buy from J. Aron, at market price, crude oil for processing at the Krotz Springs refinery and (ii) ARKS agreed to sell, and J. Aron agreed to buy, at market price, certain refined products produced at the Krotz Springs refinery.

In connection with the execution of the Supply and Offtake Agreement, ARKS also entered into agreements that provided for the sale, at market price, of ARKS’ crude oil and certain refined product inventories to J. Aron, the lease to J. Aron of crude oil and refined product storage tanks located at the Krotz Springs refinery, and an agreement to identify prospective purchasers of refined products on J. Aron’s behalf. The Supply and Offtake Agreement has an initial term that expires on May 31, 2012 and automatically renews for up to two additional 12-month terms unless either party provides notice of termination at least six months prior to the end of the then-current term. Following expiration or termination of the Supply and Offtake Agreement, ARKS is obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the Krotz Springs refinery.

Standby LC Facility

On May 28, 2010, ARKS entered into a secured Credit Agreement (the “Standby LC Facility”) by and between ARKS, as Borrower, and Goldman Sachs Bank USA, as Issuing Bank. The Standby LC Facility provides for up to $200,000 of letters of credit to be issued to J. Aron. Obligations under the Standby LC Facility are secured by a first priority lien on the existing and future accounts receivable and inventory of ARKS. At this time there is no further availability under the Standby LC Facility.

The Standby LC Facility includes customary events of default and restrictions on the activities of ARKS and its subsidiaries. The Standby LC Facility contains no maintenance financial covenants.

(b) Contingencies

Alon is involved in various other claims and legal actions arising in the ordinary course of business. Alon believes the ultimate disposition of these matters will not have a material effect on Alon’s financial position, results of operations or liquidity.

(c) Environmental

Alon is subject to federal, state, and local environmental laws and regulations. These rules regulate the discharge of materials into the environment and may require Alon to incur future obligations to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites; to remediate or restore these sites; to compensate others for damage to property and natural resources and for remediation and

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

restoration costs. These possible obligations relate to sites owned by Alon and associated with past or present operations. Alon is currently participating in environmental investigations, assessments and cleanups under these regulations at refineries, service stations, pipelines and terminals. Alon may in the future be involved in additional environmental investigations, assessments and cleanups. The magnitude of future costs will depend on factors such as the unknown nature and contamination at many sites, the timing, extent and method of the remedial actions which may be required, and the determination of Alon’s liability in proportion to other responsible parties.

Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Substantially all amounts accrued are expected to be paid out over the next 15 years. The level of future expenditures for environmental remediation obligations cannot be determined with any degree of reliability.

Alon has accrued environmental remediation obligations of $69,645 ($2,485 current payable and $67,160 non-current liability) at September 30, 2010, and $29,454 ($2,104 current payable and $27,350 non-current liability) at December 31, 2009.

In connection with the acquisition of the Bakersfield refinery on June 1, 2010, Alon recorded a discounted accrued environmental remediation obligation of $42,122 which is included as part of the non-current liability at September 30, 2010.

Also in connection with the acquisition of the Bakersfield refinery on June 1, 2010, a subsidiary of Alon entered into an indemnification agreement with a prior owner for remediation expenses of conditions that existed at the refinery on the acquisition date. Alon is required to make indemnification claims to the prior owner by March 15, 2015. The discounted indemnification amount is $17,122 and has been recorded as a non-current receivable at September 30, 2010.

Paramount Petroleum Corporation has indemnification agreements with a prior owner for part of the remediation expenses at its refineries and offsite tank farm and, as a result, has recorded a current receivable of $1,200 and non-current receivable of $3,467 at September 30, 2010.

(18) Subsequent Event

Dividend Declared

On November 3, 2010, Alon declared its regular quarterly cash dividend of $0.04 per share on Alon’s common stock, payable on December 15, 2010, to stockholders of record at the close of business on November 30, 2010.

Preferred Stock Offering

On October 28, 2010, Alon completed a registered direct offering of Alon’s 8.5% Series A Convertible Preferred Stock (the “Preferred Stock”) for an aggregate offering price of $39,400 after deducting $600 of offering expenses. The holders of the Preferred Stock can convert, at the holder’s option, the Preferred Stock into Alon’s common stock based on an initial conversion price of $6.74 per share of Alon’s common stock, in each case subject to adjustments. If all of the Preferred Stock will be converted into Alon’s common stock based on the initial conversion price, then 5,934,800 shares of Alon’s common stock will be issued.

Alon used $30,000 of the Preferred Stock proceeds to prepay in full the ARKS Term Facility on October 28, 2010.


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

The following discussion of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2009. In this document, the words “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;

	•		changes in the light/heavy 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;

	•		the global financial crisis’ impact on our business, financial condition and our ability to refinance existing credit facilities or extend their terms; and

	•		the other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2009 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 South Central, Southwestern and Western regions of the United States. Our crude oil refineries are located in Texas, California, Oregon and Louisiana and have a combined throughput capacity of approximately 250,000 barrels per day (“bpd”). Our refineries produce petroleum products including various grades of gasoline, diesel fuel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt, and other petroleum-based products.

Refining and Unbranded Marketing Segment. Our refining and unbranded marketing segment includes sour and heavy crude oil refineries located in Big Spring, Texas; and Paramount, Bakersfield and Long Beach, California; and a light sweet crude oil refinery located in Krotz Springs, Louisiana. We refer to the Long Beach, Bakersfield and Paramount refineries together as our “California refineries.” The refineries in our refining and unbranded marketing segment have a combined throughput capacity of approximately 240,000 bpd. At these refineries we refine crude oil into petroleum products, including gasoline, diesel fuel, jet fuel, petrochemicals, feedstocks and asphalts, which are marketed primarily in the South Central, Southwestern, and Western United States.

We market transportation fuels produced at our Big Spring refinery in West and Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in these regions as our “physically integrated system” because we supply our retail and branded marketing segment convenience stores and unbranded distributors in this region with motor fuels produced at our Big Spring refinery and distributed through a network of pipelines and terminals which we either own or have access to through leases or long-term throughput agreements.

We market refined products produced at our Paramount refinery to wholesale distributors, other refiners and third parties primarily on the West Coast. Our Long Beach refinery produces asphalt products. Unfinished fuel products and intermediates produced at our Long Beach refinery are transferred to our Paramount refinery via pipeline and truck for further processing or sold to third parties. Refined products produced at our Bakersfield refinery have historically been marketed in central California. Currently, the Bakersfield refinery is shut down as we plan to integrate its operations with that of our other California refineries by processing vacuum gas oil produced at the Paramount refinery in the Bakersfield refinery’s hydrocracker unit.

Krotz Springs’ liquid product yield is approximately 101.5% of total feedstock input, meaning that for each 100 barrels of crude oil and feedstocks input into the refinery, it produces 101.5 barrels of refined products. Of the 101.5%, on average 99.0% is light finished products such as gasoline and distillates, including diesel and jet fuel, petrochemical feedstocks and liquefied petroleum gas, and the remaining 2.5% is primarily heavy oils. We market refined products from Krotz Springs to wholesale distributors, other refiners, and third parties. The refinery’s location provides access to upriver markets on the Mississippi and Ohio Rivers and its docking facilities along the Atchafalaya River allow barge access. The refinery also uses its direct access to the Colonial Pipeline to transport products to markets in the Southern and Eastern United States.

Asphalt Segment. Our asphalt segment markets asphalt produced at our Texas and California refineries included in the refining and marketing segment and at our Willbridge, Oregon refinery. Asphalt produced by the refineries in our refining and marketing segment is transferred to the asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices. Our asphalt segment markets asphalt through 12 refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Oregon (Willbridge), Washington (Richmond Beach), Arizona (Phoenix, Flagstaff and Fredonia) and Nevada (Fernley) (50% interest) as well as a 50% interest in Wright Asphalt Products Company, LLC (“Wright”). We produce both paving and roofing grades of asphalt, including performance-graded asphalts, emulsions and cutbacks.

Retail and Branded Marketing Segment. Our retail and branded marketing segment operates 306 convenience stores located primarily in Central and West Texas and New Mexico. These convenience stores typically

offer various grades of gasoline, diesel fuel, general merchandise and food and beverage products to the general public, primarily under the 7-Eleven and FINA brand names. Substantially all of the motor fuel sold through our retail operations and the majority of the motor fuel marketed in our branded business is supplied by our Big Spring refinery. In 2010, approximately 91% of the motor fuel requirements of our branded marketing operations, including retail operations, were supplied by our Big Spring refinery. Branded distributors that are not part of our integrated supply system, primarily in Central Texas, are supplied with motor fuels we obtain from third-party suppliers.

We market gasoline and diesel under the FINA brand name through a network of approximately 640 locations, including our convenience stores. Approximately 65% of the gasoline and 22% of the diesel motor fuel produced at our Big Spring refinery was transferred to our retail and branded marketing segment at prices substantially determined by reference to commodity pricing information published by Platts. Additionally, our retail and branded marketing segment licenses the use of the FINA brand name and provides credit card processing services to approximately 270 licensed locations that are not under fuel supply agreements with us.

Third Quarter Operational and Financial Highlights

Operating loss for the third quarter of 2010 was $35.4 million, compared to $34.3 million in the same period last year. Operating loss increased principally due to lower refinery throughput and lower asphalt sales volumes and margins, partially offset by higher refinery margins, higher retail fuel margins and increased motor fuel sales volumes. Other operational and financial highlights for the third quarter of 2010 include the following:

	•		Combined refinery throughput for the three months ended September 30, 2010, averaged 138,253 bpd, consisting of: 53,060 bpd at the Big Spring refinery, 21,035 bpd at the California refineries and 64,158 bpd at the Krotz Springs refinery, compared to a combined average throughput of 157,660 bpd for the three months ended September 30, 2009, consisting of: 62,500 bpd at the Big Spring refinery, 35,470 bpd at the California refineries and 59,690 bpd at the Krotz Springs refinery.

	•		Operating margin at the Big Spring refinery was $5.04 per barrel for the third quarter of 2010, compared to $1.34 per barrel for the same period in 2009. The operating margin in 2009 was negatively impacted by the absence of the alkylation unit and additional feedstock costs related to preparations for start up of the ultra-low sulfur gasoline unit in the fourth quarter of 2009.

	•		Operating margin at the California refineries was $0.17 per barrel for the third quarter of 2010, compared to ($0.55) per barrel for the same period in 2009. This increase primarily resulted from higher West Coast 3/2/1 crack spreads and greater light/heavy spreads.

	•		Operating margin at the Krotz Springs refinery was $1.00 per barrel for the third quarter of 2010, compared to $2.45 per barrel for the same period in 2009. The decrease primarily resulted from efforts to return to normal operating conditions after restart in June 2010 from an extended turnaround and also higher crude oil costs relative to WTI.

	•		Asphalt margins in the third quarter of 2010 were $77.59 per ton compared to $82.99 per ton in the third quarter of 2009. The average blended asphalt sales price increased 7.3% from $446.26 per ton in the third quarter of 2009 to $478.65 per ton in the third quarter of 2010 and the average non-blended asphalt sales price increased 83.4% from $190.23 per ton in the third quarter of 2009 to $348.89 per ton in the third quarter of 2010. Asphalt sales volumes in the third quarter of 2010 were 307 thousand tons compared to 427 thousand tons in the third quarter of 2009.

	•		Retail and branded marketing segment retail fuel sales gallons increased by 19.1% from 30.9 million gallons in the third quarter of 2009 to 36.8 million gallons in the third quarter of 2010. Our branded fuel sales increased by 24.1% from 68.3 million gallons in the third quarter of 2009 to 84.7 million gallons in the third quarter of 2010. Operating income for our retail and branded marketing segment was $8.8 million for the third quarter of 2010 compared to $4.2 million for the same period in 2009.

	•		On September 15, 2010, Alon paid a regular quarterly cash dividend of $0.04 per share on Alon’s common stock to stockholders of record at the close of business on August 31, 2010.

Major Influences on Results of Operations

Refining and Unbranded Marketing. Earnings and cash flow from our refining and unbranded 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 crude oil and other 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 affect our earnings.

In order to measure our operating performance, we compare our per barrel refinery operating margins to certain industry benchmarks. We compare our Big Spring refinery’s per barrel operating margin to the Gulf Coast and Group III, or mid-continent, 3/2/1 crack spreads. A 3/2/1 crack spread in a given region is calculated assuming that three barrels of a benchmark crude oil are converted, or cracked, into two barrels of gasoline and one barrel of diesel. We calculate the Gulf Coast 3/2/1 crack spread using the market values of Gulf Coast conventional gasoline and ultra-low sulfur diesel and the market value of West Texas Intermediate, or WTI, a light, sweet crude oil. We calculate the Group III 3/2/1 crack spread using the market values of Group III conventional gasoline and ultra-low sulfur diesel and the market value of WTI crude oil. We calculate the per barrel operating margin for our Big Spring refinery by dividing the Big Spring refinery’s gross margin by its throughput volumes. Gross margin is the difference between net sales and cost of sales (exclusive of substantial unrealized hedge positions and inventories adjustments related to acquisitions).

We compare our California refineries’ per barrel operating margin to the West Coast 6/1/2/3 crack spread. A 6/1/2/3 crack spread is calculated assuming that six barrels of a benchmark crude oil are converted into one barrel of gasoline, two barrels of diesel and three barrels of fuel oil. We calculate the West Coast 6/1/2/3 crack spread using the market values of West Coast LA CARBOB pipeline gasoline, LA ultra-low sulfur pipeline diesel, LA 380 pipeline CST (fuel oil) and the market value of WTI crude oil. The per barrel operating margin of the California refineries is calculated by dividing the California refinery’s gross margin by their throughput volumes. Another comparison to other West Coast refineries that we use is the West Coast 3/2/1 crack spread. This is calculated using the market values of West Coast LA CARBOB pipeline gasoline, LA ultra-low sulfur pipeline diesel and the market value of WTI crude oil.

Our Krotz Springs refinery’s per barrel margin is compared to the Gulf Coast 2/1/1 crack spread. The 2/1/1 crack spread is calculated assuming that two barrels of a benchmark crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate the Gulf Coast 2/1/1 crack spread using the market values of Gulf Coast conventional gasoline and Gulf Coast high sulfur diesel and the market value of WTI crude oil.

Our Big Spring refinery and California refineries are capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate and sweet crude oils. We measure the cost advantage of refining sour crude oil by calculating the difference between the value of WTI crude oil less the value of West Texas Sour, or WTS, a medium, sour crude oil. We refer to this differential as the sweet/sour spread. A widening of the sweet/sour spread can favorably influence the operating margin for our Big Spring and California refineries. In addition, our California refineries are capable of processing significant volumes of heavy crude oils which historically have cost less than light crude oils. We measure the cost advantage of refining heavy crude oils by calculating the difference between the value of WTI crude oil less the value of MAYA crude, which we refer to as the light/heavy spread. A widening of the light/heavy spread can favorably influence the refinery operating margins for our California refineries.

The Krotz Springs refinery has the capability to process substantial volumes of low-sulfur, or sweet, crude oils to produce a high percentage of light, high-value refined products. Sweet crude oil typically comprises 100% of the Krotz Springs refinery’s crude oil input, comprised of equal amounts of Heavy Louisiana Sweet, or HLS crude oil, and Light Louisiana Sweet, or LLS crude oil. We measure the cost of refining these lighter sweet crude oils by calculating the difference between the average value of HLS and LLS crude oils to the value of WTI crude oil. A narrowing of this spread can favorably influence the refinery operating margins of our Krotz Springs refinery.

The results of operations from our refining and unbranded marketing segment are also significantly affected by our refineries’ 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 from $13.58 per million British

thermal units, or MMBTU, in July of 2008 to $2.51 MMBTU in September of 2009. Typically, electricity prices fluctuate with natural gas prices.

Demand for gasoline products is generally higher during summer months than during winter months due to seasonal increases in highway traffic. As a result, the operating results for our refining and unbranded 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 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 refineries 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 expectations for 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. Crude oil and refined products are essentially commodities, and 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.

Asphalt. Earnings from our asphalt segment depend primarily upon the margin between the price at which we sell our asphalt and the transfer prices for asphalt produced at our refineries in the refining and unbranded marketing segment. Asphalt is transferred to our asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices. The asphalt segment also conducts operations at and markets asphalt produced by our refinery located in Willbridge, Oregon. In addition to producing asphalt at our refineries, at times when refining margins are unfavorable we opportunistically purchase asphalt from other producers for resale. A portion of our asphalt sales are made using fixed price contracts for delivery at future dates. Because these contracts are priced at the market prices for asphalt at the time of the contract, a change in the cost of crude oil between the time we enter into the contract and the time we produce the asphalt can positively or negatively influence the earnings of our asphalt segment. Demand for paving asphalt products is higher during warmer months than during colder months due to seasonal increases in road construction work. As a result, revenues from our asphalt segment for the first and fourth calendar quarters are expected to be lower than those for the second and third calendar quarters.

Retail and Branded Marketing. Earnings and cash flows from our retail and branded marketing segment are primarily affected by merchandise and motor fuel sales volumes and margins at our convenience stores and the motor fuel sales volumes and margins from sales to our FINA-branded distributors, together with licensing and credit card related fees generated from our FINA-branded distributors and licensees. Retail merchandise gross margin is equal to retail merchandise sales less the delivered cost of the retail merchandise, net of vendor discounts and rebates, measured as a percentage of total retail merchandise sales. Retail merchandise sales are driven by convenience, branding and competitive pricing. Motor fuel margin is equal to motor fuel sales less the delivered cost of fuel and motor fuel taxes, measured on a cents per gallon (“cpg”) basis. Our motor fuel margins are driven by local supply, demand and competitor pricing. Our convenience store 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.

Factors Affecting Comparability

Our financial condition and operating results over the three and nine months ended September 30, 2010 and 2009, have been influenced by the following factors which are fundamental to understanding comparisons of our period-to-period financial performance.

The Krotz Springs refinery was shut down during November 2009 for a scheduled turnaround and remained down until its restart in June 2010. Throughput at the Big Spring refinery was lower over the three and nine months ended September 30, 2010, as we implemented new operating procedures. The California refineries’ throughput was lower over the three and nine months ended September 30, 2010, due to continued efforts to optimize asphalt production with demand.

On June 1, 2010, we purchased the Bakersfield, California refinery from Big West of California, LLC, a subsidiary of Flying J, Inc. The refinery is non-operational at this time and will require major turnaround work and additional capital expenditures before it can be returned to operations and integrated with the other California

refineries. In connection with the Bakersfield refinery acquisition, the acquisition date fair value of the identifiable net assets acquired exceeded the fair value of the consideration transferred, resulting in a $17.5 million bargain purchase gain.

Results of Operations

Net Sales. Net sales consist primarily of sales of refined petroleum products through our refining and unbranded marketing segment and asphalt segment and sales of merchandise, including food products, and motor fuels, through our retail and branded marketing segment.

For the refining and unbranded marketing segment, net sales consist of gross sales, net of customer rebates, discounts and excise taxes and includes inter-segment sales to our asphalt and retail and branded marketing segments, which are eliminated through consolidation of our financial statements. Asphalt sales consist of gross sales, net of any discounts and applicable taxes. Retail net sales consist of gross merchandise sales, less rebates, commissions and discounts, and gross fuel sales, including motor fuel taxes. For our petroleum and asphalt products, net sales are mainly affected by crude oil and refined product prices and volume changes caused by operations. Our retail merchandise sales are affected primarily by competition and seasonal influences.

Cost of Sales. Refining and unbranded marketing cost of sales includes crude oil and other raw materials, inclusive of transportation costs. Asphalt cost of sales includes costs of purchased asphalt, blending materials and 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. Cost of sales excludes depreciation and amortization expense.

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

Selling, General and Administrative Expenses. Selling, general and administrative, or SG&A, expenses consist primarily of costs relating to the operations of our convenience stores, including labor, utilities, maintenance and retail corporate overhead costs. Refining and marketing and asphalt 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 Alon and our three operating segments for the three and nine months ended September 30, 2010 and 2009. The summary financial data for our three operating segments does not include certain SG&A expenses and depreciation and amortization related to our corporate headquarters. The following data should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this Form 10-Q. All information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” except for Balance Sheet data as of December 31, 2009 is unaudited.


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(dollars in thousands, except per						(dollars in thousands, except per
	share data)						share data)
STATEMENT OF OPERATIONS DATA:
Net sales (1)	$	1,248,569		$	1,253,113		$	2,668,243		$	3,081,691
Operating costs and expenses:
Cost of sales		1,153,743			1,165,295			2,443,533			2,693,343
Direct operating expenses		68,448			64,091			192,816			204,300
Selling, general and administrative expenses (2)		35,012			32,276			96,001			95,772
Depreciation and amortization (3)		26,781			25,247			78,471			70,898

Total operating costs and expenses		1,283,984			1,286,909			2,810,821			3,064,313

Gain (loss) on disposition of assets		—			(547	)		474			(2,147	)

Operating income (loss)		(35,415	)		(34,343	)		(142,104	)		15,231
Interest expense (4)		(24,091	)		(21,460	)		(72,411	)		(70,739	)
Equity earnings of investees		3,864			12,811			4,970			21,184
Gain from bargain purchase (5)		17,480			—			17,480			—
Other income (loss), net (6)		(494	)		(180	)		13,345			268

Loss before income tax benefit, non-controlling interest in loss of subsidiaries and accumulated dividends on preferred stock of subsidiary		(38,656	)		(43,172	)		(178,720	)		(34,056	)
Income tax benefit		(21,905	)		(16,452	)		(73,711	)		(13,006	)

Loss before non-controlling interest in loss of subsidiaries and accumulated dividends on preferred stock of subsidiary		(16,751	)		(26,720	)		(105,009	)		(21,050	)
Non-controlling interest in loss of subsidiaries		(1,167	)		(2,312	)		(7,224	)		(2,953	)
Accumulated dividends on preferred stock of subsidiary		—			2,150			—			6,450

Net loss available to common stockholders	$	(15,584	)	$	(26,558	)	$	(97,785	)	$	(24,547	)

Loss per share, basic	$	(0.29	)	$	(0.57	)	$	(1.80	)	$	(0.52	)

Weighted average shares outstanding, basic (in thousands)		54,181			46,810			54,177			46,808

Loss per share, diluted	$	(0.29	)	$	(0.57	)	$	(1.80	)	$	(0.52	)

Weighted average shares outstanding, diluted (in thousands)		54,181			46,810			54,177			46,808


Cash dividends per share	$	0.04		$	0.04		$	0.12		$	0.12


CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	24,285		$	28,168		$	(37,275	)	$	325,132
Investing activities		(11,162	)		(48,891	)		(15,218	)		(93,605	)
Financing activities		18,799			(4,676	)		51,691			(231,903	)


	For the Three Months Ended					For the Nine Months Ended
	September 30,					September 30,
	2010			2009		2010			2009
	(dollars in thousands, except per					(dollars in thousands, except per
	share data)					share data)
OTHER DATA:
Adjusted EBITDA (7)	$	(5,264	)	$	4,082	$	(45,792	)	$	109,728
Capital expenditures (8)		7,838			22,888		20,526			52,132
Capital expenditures to rebuild the Big Spring refinery		—			5,791		—			45,072
Capital expenditures for turnaround and chemical catalyst		1,137			2,691		12,668			13,005


	September 30,		December 31,
	2010		2009
BALANCE SHEET DATA (end of period):
Cash and cash equivalents	$	39,635	$	40,437
Working capital		5,593		84,257
Total assets		2,175,564		2,132,789
Total debt		953,523		937,024
Total equity		331,464		431,918


(1)		Includes excise taxes on sales by the retail and branded marketing segment of $14,204 and $12,073 for the three months ended September 30, 2010 and 2009, respectively, and $40,521 and $34,887 for the nine months ended September 30, 2010 and 2009, respectively.

(2)		Includes corporate headquarters selling, general and administrative expenses of $188 and $189 for the three months ended September 30, 2010 and 2009, respectively, and $564 and $569 for the nine months ended September 30, 2010 and 2009, respectively, which are not allocated to our three operating segments.

(3)		Includes corporate depreciation and amortization of $397 and $205 for the three months ended September 30, 2010 and 2009, respectively, and $964 and $500 for the nine months ended September 30, 2010 and 2009, respectively, which are not allocated to our three operating segments.

(4)		Interest expense of $72,411 for the nine months ended September 30, 2010, includes a charge of $6,659 for the write-off of debt issuance costs associated with our prepayment of the Alon Refining Krotz Springs, Inc. revolving credit facility. Interest expense of $70,739 for the nine months ended September 30, 2009, includes $5,715 related to the unwind of a heating oil crack spread hedge.

(5)		In connection with the Bakersfield refinery acquisition, the acquisition date fair value of the identifiable net assets acquired exceeded the fair value of the consideration transferred, resulting in a $17,480 bargain purchase gain.

(6)		Other income (loss), net for the nine months ended September 30, 2010, substantially represents the gain from the sale of our investment in Holly Energy Partners.

(7)		Adjusted EBITDA represents earnings before non-controlling interest in income of subsidiaries, income tax expense, interest expense, depreciation and amortization, gain on bargain purchase and gain on disposition of assets. Adjusted EBITDA is not a recognized measurement under GAAP; however, the amounts included in Adjusted EBITDA are derived from amounts included in our consolidated financial statements. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors, and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of non-controlling interest in income of subsidiaries, income tax expense, interest expense, gain on disposition of assets, gain on bargain purchase and the accounting effects of capital expenditures and acquisitions, items that may vary for different companies for reasons unrelated to overall operating performance.

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 non-controlling interest have on the income generated by non-wholly-owned subsidiaries;

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

	•		Our calculation of Adjusted EBITDA may differ from 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 loss available to common stockholders to Adjusted EBITDA for the three and nine months ended September 30, 2010 and 2009, respectively:


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(dollars in thousands)
Net loss available to common stockholders	$	(15,584	)	$	(26,558	)	$	(97,785	)	$	(24,547	)
Non-controlling interest in loss of subsidiaries (including accumulated dividends on preferred stock of subsidiary)		(1,167	)		(162	)		(7,224	)		3,497
Income tax benefit		(21,905	)		(16,452	)		(73,711	)		(13,006	)
Interest expense		24,091			21,460			72,411			70,739
Depreciation and amortization		26,781			25,247			78,471			70,898
Gain on bargain purchase		(17,480	)		—			(17,480	)		—
(Gain) loss on disposition of assets		—			547			(474	)		2,147

Adjusted EBITDA	$	(5,264	)	$	4,082		$	(45,792	)	$	109,728


(8)		Includes corporate capital expenditures of $1,344 and $1,755 for the three months ended September 30, 2010 and 2009, respectively, and $2,152 and $2,987 for the nine months ended September 30, 2010 and 2009, respectively, which are not allocated to our three operating segments.

REFINING AND UNBRANDED MARKETING SEGMENT


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(dollars in thousands, except per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	1,056,478		$	1,058,517		$	2,230,849		$	2,652,917
Operating costs and expenses:
Cost of sales		1,022,950			1,038,134			2,138,284			2,397,016
Direct operating expenses		57,711			51,286			159,556			171,295
Selling, general and administrative expenses		7,103			6,934			17,365			21,500
Depreciation and amortization		21,315			19,943			62,150			55,120

Total operating costs and expenses		1,109,079			1,116,297			2,377,355			2,644,931

Loss on disposition of assets		—			—			—			(1,600	)

Operating income (loss)	$	(52,601	)	$	(57,780	)	$	(146,506	)	$	6,386


KEY OPERATING STATISTICS:
Total sales volume (bpd)		129,194			127,580			78,639			127,460
Per barrel of throughput:
Refinery operating margin – Big Spring (2)	$	5.04		$	1.34		$	6.39		$	6.32
Refinery operating margin – CA Refineries (2)		0.17			(0.55	)		0.92			2.41
Refinery operating margin – Krotz Springs (2)		1.00			2.45			0.44			6.64
Refinery direct operating expense – Big Spring (3)		4.66			4.11			5.58			4.13
Refinery direct operating expense – CA Refineries (3)		6.86			3.85			7.66			4.37
Refinery direct operating expense – Krotz Springs (3)		3.39			2.75			5.82			3.77
Capital expenditures		4,707			19,859			15,234			46,182
Capital expenditures to rebuild the Big Spring refinery		—			5,791			—			45,072
Capital expenditures for turnaround and chemical catalyst		1,137			2,691			12,668			13,005

PRICING STATISTICS:
WTI crude oil (per barrel)	$	76.05		$	68.17		$	77.50		$	57.03
WTS crude oil (per barrel)		73.89			66.49			75.55			55.69
MAYA crude oil (per barrel)		67.50			63.20			68.45			51.98
HLS crude oil (per barrel)		78.18			69.76			79.41			58.71
LLS crude oil (per barrel)		79.63			70.43			80.58			59.87
Crack spreads (3/2/1) (per barrel):
Gulf Coast	$	7.76		$	6.52		$	8.20		$	8.14
Group III		10.53			8.01			9.60			9.02
West Coast		15.30			14.85			13.65			15.74
Crack spreads (6/1/2/3) (per barrel):
West Coast	$	4.68		$	5.39		$	3.66		$	4.73
Crack spreads (2/1/1) (per barrel):
Gulf Coast high sulfur diesel	$	7.02		$	5.36		$	7.40		$	7.14
Crude oil differentials (per barrel):
WTI less WTS	$	2.16		$	1.68		$	1.95		$	1.34
WTI less MAYA		8.55			4.97			9.05			5.05
HLS/LLS less WTI		2.86			1.93			2.50			2.26
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	1.950		$	1.773		$	2.014		$	1.545
Gulf Coast ultra-low sulfur diesel		2.086			1.789			2.094			1.565
Gulf Coast high sulfur diesel		2.006			1.728			2.029			1.510
Group III unleaded gasoline		2.031			1.814			2.056			1.575
Group III ultra-low sulfur diesel		2.123			1.814			2.110			1.567
West Coast LA CARBOB (unleaded gasoline)		2.183			2.042			2.183			1.798
West Coast LA ultra-low sulfur diesel		2.160			1.847			2.144			1.602
Natural gas (per MMBTU)		4.23			3.44			4.52			3.90

THROUGHPUT AND YIELD DATA:
BIG SPRING


	For the Three Months Ended										For the Nine Months Ended
	September 30,										September 30,
	2010					2009					2010					2009
	bpd		%			bpd		%			bpd		%			bpd		%
Refinery throughput:
Sour crude		42,680		80.4			44,924		71.9			36,836		79.7			50,345		80.0
Sweet crude		7,938		15.0			15,521		24.8			7,021		15.1			10,411		16.5
Blendstocks		2,442		4.6			2,055		3.3			2,387		5.2			2,177		3.5

Total refinery throughput (4)		53,060		100.0			62,500		100.0			46,244		100.0			62,933		100.0

Refinery production:
Gasoline		25,937		49.2			27,366		44.1			23,096		50.5			27,424		43.8
Diesel/jet		17,772		33.7			19,690		31.8			14,738		32.2			20,477		32.7
Asphalt		3,193		6.1			5,830		9.4			2,636		5.8			5,879		9.4
Petrochemicals		3,382		6.4			3,340		5.4			2,664		5.8			3,286		5.3
Other		2,419		4.6			5,790		9.3			2,620		5.7			5,524		8.8

Total refinery production (5)		52,703		100.0			62,016		100.0			45,754		100.0			62,590		100.0

Refinery utilization (6)				72.3	%				86.3	%				64.6	%				86.8	%

THROUGHPUT AND YIELD DATA:
CALIFORNIA REFINERIES


	For the Three Months Ended										For the Nine Months Ended
	September 30,										September 30,
	2010					2009					2010					2009
	bpd		%			bpd		%			bpd		%			bpd		%
Refinery throughput:
Medium sour crude		4,635		22.0			16,073		45.3			4,065		20.7			16,164		46.6
Heavy crude		15,886		75.6			18,937		53.4			15,082		77.0			18,259		52.6
Blendstocks		514		2.4			460		1.3			443		2.3			288		0.8

Total refinery throughput (4)		21,035		100.0			35,470		100.0			19,590		100.0			34,711		100.0

Refinery production:
Gasoline		3,401		16.6			5,456		15.8			2,888		15.2			5,189		15.3
Diesel/jet		4,758		23.3			8,434		24.5			4,067		21.4			8,037		23.7
Asphalt		6,974		34.1			10,441		30.3			6,554		34.3			10,215		30.2
Light unfinished		—		—			—		—			—		—			467		1.4
Heavy unfinished		4,831		23.6			9,546		27.7			5,099		26.8			9,409		27.8
Other		498		2.4			585		1.7			439		2.3			551		1.6

Total refinery production (5)		20,462		100.0			34,462		100.0			19,047		100.0			33,868		100.0

Refinery utilization (6)				28.3	%				48.3	%				26.4	%				53.1	%

THROUGHPUT AND YIELD DATA:
KROTZ SPRINGS (A)


	For the Three Months Ended										For the Nine Months Ended
	September 30,										September 30,
	2010					2009					2010					2009
	bpd		%			bpd		%			bpd		%			bpd		%
Refinery throughput:
Light sweet crude		38,597		60.1			30,741		51.5			16,460		56.9			28,755		50.2
Heavy sweet crude		23,854		37.2			27,547		46.2			11,603		40.1			24,691		43.1
Blendstocks		1,707		2.7			1,402		2.3			878		3.0			3,862		6.7

Total refinery throughput (4)		64,158		100.0			59,690		100.0			28,941		100.0			57,308		100.0

Refinery production:
Gasoline		26,442		40.9			27,441		45.4			11,720		40.3			26,628		45.8
Diesel/jet		31,383		48.5			26,855		44.5			13,609		46.9			25,288		43.4
Heavy Oils		1,487		2.3			1,205		2.0			1,437		4.9			1,151		2.0
Other		5,368		8.3			4,865		8.1			2,304		7.9			5,090		8.8

Total refinery production (5)		64,680		100.0			60,366		100.0			29,070		100.0			58,157		100.0

Refinery utilization (6)				75.2	%				70.1	%				33.8	%				64.3	%


(A)		The throughput data for the nine months ended September 30, 2010, reflects substantially four months of operations beginning June 2010 due to the restart of the Krotz Springs refinery after major turnaround activity.

(1)		Net sales include intersegment sales to our asphalt and retail and branded marketing segments at prices which approximate wholesale market price. These intersegment sales are eliminated through consolidation of our financial statements.

(2)		Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales (exclusive of substantial unrealized hedge positions and inventory adjustments related to acquisitions) attributable to each refinery by the 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 margins to these crack spreads to assess our operating performance relative to other participants in our industry.

		The refinery operating margin for the three and nine months ended September 30, 2010, excludes a benefit of $2,990 and $4,515 to cost of sales for inventory adjustments related to the Bakersfield refinery acquisition. There were unrealized hedging gains of $1,019 for the Big Spring refinery for the three months ended September 30, 2009. There were unrealized hedging losses of $108 and $322 for the California refineries for the three and nine months ended September 30, 2010, respectively. There were unrealized hedging losses of $169 and $722 for the Krotz Springs refinery for the three and nine months ended September 30, 2010, respectively. Also, there was an unrealized gain of $20,369 for the Krotz Springs refinery for the nine months ended September 30, 2009. Additionally, the Krotz Springs refinery margin for the nine months ended September 30, 2009 excludes realized gains related to the unwind of the heating oil crack spread hedge of $139,290.

(3)		Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses at our Big Spring, California, and Krotz Springs refineries, exclusive of depreciation and amortization, by the applicable refinery’s total throughput volumes. Direct operating expenses related to the Bakersfield refinery of $1,712 and $2,122 have been excluded from the per barrel measurement calculation for the three and nine months ended September 30, 2010, respectively.

(4)		Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.

(5)		Total refinery production represents the barrels per day of various products produced from processing crude and other refinery feedstocks through the crude units and other conversion units at the refineries.

(6)		Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.

ASPHALT SEGMENT


	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2010		2009		2010			2009
			(dollars in thousands, except per ton data)
STATEMENTS OF OPERATIONS DATA:
Net sales	$	144,610	$	175,189	$	316,715		$	351,429
Operating costs and expenses:
Cost of sales (1)		120,791		139,751		282,500			307,881
Direct operating expenses		10,737		12,805		33,260			33,005
Selling, general and administrative expenses		2,404		1,267		4,561			3,471
Depreciation and amortization		1,716		1,700		5,148			5,099

Total operating costs and expenses		135,648		155,523		325,469			349,456

Operating income (loss)	$	8,962	$	19,666	$	(8,754	)	$	1,973


KEY OPERATING STATISTICS:
Blended asphalt sales volume (tons in thousands) (2)		289		367		625			813
Non-blended asphalt sales volume (tons in thousands) (3)		18		60		52			143
Blended asphalt sales price per ton (2)	$	478.65	$	446.26	$	477.68		$	404.39
Non-blended asphalt sales price per ton (3)		348.89		190.23		349.29			158.49
Asphalt margin per ton (4)		77.59		82.99		50.54			45.55
Capital expenditures	$	465	$	523	$	991		$	1,099


(1)		Cost of sales includes intersegment purchases of asphalt blends from our refining and unbranded marketing segment at prices which approximate wholesale market prices. These intersegment purchases are eliminated through consolidation of our financial statements.

(2)		Blended asphalt represents base asphalt that has been blended with other materials necessary to sell the asphalt as a finished product.

(3)		Non-blended asphalt represents base material asphalt and other components that require additional blending before being sold as a finished product.

(4)		Asphalt margin is a per ton measurement calculated by dividing the margin between net sales and cost of sales by the total sales volume. Asphalt margins are used in the asphalt industry to measure operating results related to asphalt sales.

RETAIL AND BRANDED MARKETING SEGMENT


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
				(dollars in thousands, except per gallon data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	273,481		$	217,232		$	753,464		$	591,163
Operating costs and expenses:
Cost of sales (2)		236,002			185,235			655,534			502,264
Selling, general and administrative expenses		25,317			23,886			73,511			70,232
Depreciation and amortization		3,353			3,399			10,209			10,179

Total operating costs and expenses		264,672			212,520			739,254			582,675

Gain (loss) on disposition of assets		—			(547	)		474			(547	)

Operating income	$	8,809		$	4,165		$	14,684		$	7,941


KEY OPERATING STATISTICS:
Branded fuel sales (thousands of gallons) (3)		84,711			68,280			230,031			204,929
Branded fuel margin (cents per gallon) (3)		8.9	¢		9.6	¢		6.7	¢		5.6	¢

Number of stores (end of period)		306			305			306			305
Retail fuel sales (thousands of gallons)		36,759			30,915			104,881			89,296
Retail fuel sales (thousands of gallons per site per month)		40			34			38			33
Retail fuel margin (cents per gallon) (4)		13.4	¢		9.7	¢		12.3	¢		15.0	¢
Retail fuel sales price (dollars per gallon) (5)	$	2.67		$	2.48		$	2.68		$	2.22
Merchandise sales	$	74,932		$	69,413		$	211,660		$	202,675
Merchandise sales (per site per month)	$	82		$	76		$	77		$	74
Merchandise margin (6)		32.2	%		31.4	%		31.7	%		30.9	%
Capital expenditures	$	1,322		$	751		$	2,149		$	1,864


(1)		Includes excise taxes on sales by the retail and branded marketing segment of $14,204 and $12,073 for the three months ended September 30, 2010 and 2009, respectively, and $40,521 and $34,887 for the nine months ended September 30, 2010 and 2009. Includes net royalty and related net credit card fees of $873 and $744 for the three months ended September 30, 2010 and 2009, respectively, and $2,692 and $1,661 for the nine months ended September 30, 2010 and 2009.

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

(3)		Marketing sales volume represents branded fuel sales to our wholesale marketing customers that are primarily supplied by the Big Spring refinery. The branded fuels that are not supplied by the Big Spring refinery are obtained from third-party suppliers. The marketing margin represents the margin between the net sales and cost of sales attributable to our branded fuel sales volume, expressed on a cents-per-gallon basis.

(4)		Retail fuel margin represents the difference between motor fuel sales revenue 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.

(5)		Retail fuel sales price per gallon represents the average sales price for motor fuels sold through our retail convenience stores.

(6)		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 convenience store industry to measure in-store, or non-fuel, operating results.

Three Months Ended September 30, 2010 Compared to the Three Months Ended September 30, 2009

Net Sales

Consolidated. Net sales for the three months ended September 30, 2010, were $1,248.6 million, compared to $1,253.1 million for the three months ended September 30, 2009, a decrease of $4.5 million or 0.4%.

Refining and Unbranded Marketing Segment. Net sales for our refining and unbranded marketing segment were $1,056.5 million for the three months ended September 30, 2010, compared to $1,058.5 million for the three months ended September 30, 2009, a decrease of $2.0 million or 0.2%. The increase in refined product prices in the three months ended September 30, 2010, was offset by lower throughput volumes, as compared to the same period last year.

Combined refinery throughput for the three months ended September 30, 2010, averaged 138,253 bpd, consisting of: 53,060 bpd at the Big Spring refinery, 21,035 bpd at the California refineries and 64,158 bpd at the Krotz Springs refinery, compared to a combined average throughput of 157,660 bpd for the three months ended September 30, 2009, consisting of: 62,500 bpd at the Big Spring refinery, 35,470 bpd at the California refineries and 59,690 bpd at the Krotz Springs refinery. The Big Spring refinery throughput was lower as a result of efforts to implement new operating procedures and the California refineries’ throughput was lower due to our continued efforts to optimize asphalt production with demand.

The increase in refined product prices that our refineries experienced resembled the price increases experienced in each refinery’s respective markets. The average price of Gulf Coast gasoline for the three months ended September 30, 2010, increased 17.7 cpg, or 10.0%, to 195.0 cpg, compared to 177.3 cpg for the three months ended September 30, 2009. The average Gulf Coast ultra-low sulfur diesel price for the three months ended September 30, 2010, increased 29.7 cpg, or 16.6%, to 208.6 cpg, compared to 178.9 cpg for the three months ended September 30, 2009. The average price of West Coast LA CARBOB gasoline for the three months ended September 30, 2010, increased 14.1 cpg, or 6.9%, to 218.3 cpg, compared to 204.2 cpg for the three months ended September 30, 2009. The average West Coast LA ultra-low sulfur diesel price for the three months ended September 30, 2010, increased 31.3 cpg, or 17.0%, to 216.0 cpg, compared to 184.7 cpg for the three months ended September 30, 2009.

Asphalt Segment. Net sales for our asphalt segment were $144.6 million for the three months ended September 30, 2010, compared to $175.2 million for the three months ended September 30, 2009, a decrease of $30.6 million or 17.5%. The decrease was due primarily to a decrease in asphalt sales volumes and partially offset by higher asphalt sales price for the three months ended September 30, 2010. For the three months ended September 30, 2010, the asphalt sales volume decreased 28.1% from 427 thousand tons for the three months ended September 30, 2009, to 307 thousand tons for the three months ended September 30, 2010. For the three months ended September 30, 2010, the average blended asphalt sales price increased 7.3% from $446.26 per ton for the three months ended September 30, 2009, to $478.65 per ton for the three months ended September 30, 2010, and the average non-blended asphalt sales price increased 83.4% from $190.23 per ton for the three months ended September 30, 2009, to $348.89 per ton for the three months ended September 30, 2010.

Retail and Branded Marketing Segment. Net sales for our retail and branded marketing segment were $273.5 million for the three months ended September 30, 2010, compared to $217.2 million for the three months ended September 30, 2009, an increase of $56.3 million or 25.9%. This increase was primarily attributable to increases in motor fuel prices, motor fuel volume and merchandise sales.

Cost of Sales

Consolidated. Cost of sales were $1,153.7 million for the three months ended September 30, 2010, compared to $1,165.3 million for the three months ended September 30, 2009, a decrease of $11.6 million or 1.0%.

This decrease was primarily due to lower refinery throughput volumes at our refining and unbranded marketing segment and lower sales volumes at our asphalt segment, partially offset by higher crude oil prices.

Refining and Unbranded Marketing Segment.Cost of sales for our refining and unbranded marketing segment were $1,023.0 million for the three months ended September 30, 2010, compared to $1,038.1 million for the three months ended September 30, 2009, a decrease of $15.1 million or 1.5%. This decrease was primarily due to lower refinery throughput, partially offset by an increase in the cost of crude oil. The average price per barrel of WTI for the three months ended September 30, 2010, increased $7.88 per barrel to an average of $76.05 per barrel, compared to an average of $68.17 per barrel for the three months ended September 30, 2009, an increase of 11.6%.

Asphalt Segment. Cost of sales for our asphalt segment were $120.8 million for the three months ended September 30, 2010, compared to $139.8 million for the three months ended September 30, 2009, a decrease of $19.0 million or 13.6%. The decrease was due primarily to lower asphalt sales volumes and partially offset by higher crude oil costs for the three months ended September 30, 2010.

Retail and Branded Marketing Segment.Cost of sales for our retail and branded marketing segment was $236.0 million for the three months ended September 30, 2010, compared to $185.2 million for the three months ended September 30, 2009, an increase of $50.8 million or 27.4%. This increase was primarily attributable to increases in motor fuel prices, motor fuel volume and merchandise costs.

Direct Operating Expenses

Consolidated. Direct operating expenses were $68.4 million for the three months ended September 30, 2010, compared to $64.1 million for the three months ended September 30, 2009, an increase of $4.3 million or 6.7%. This increase was primarily due to the acquisition of the Bakersfield refinery in June 2010 and the increased cost of natural gas.

Refining and Unbranded Marketing Segment.Direct operating expenses for our refining and unbranded marketing segment for the three months ended September 30, 2010, were $57.7 million, compared to $51.3 million for the three months ended September 30, 2009, an increase of $6.4 million or 12.5%. This increase was primarily due to the acquisition of the Bakersfield refinery in June 2010 and the increased cost of natural gas.

Asphalt Segment.Direct operating expenses for our asphalt segment for the three months ended September 30, 2010, were $10.7 million, compared to $12.8 million for the three months ended September 30, 2009, a decrease of $2.1 million or 16.4%. The decrease was due to lower sales volumes for the three months ended September 30, 2010.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for the three months ended September 30, 2010, were $35.0 million, compared to $32.3 million for the three months ended September 30, 2009, an increase of $2.7 million or 8.4% primarily due to employee related costs.

Refining and Unbranded Marketing Segment. SG&A expenses for our refining and unbranded marketing segment for the three months ended September 30, 2010, were $7.1 million, compared to $6.9 million for the three months ended September 30, 2009, an increase of $0.2 million or 2.9%.

Asphalt Segment. SG&A expenses for our asphalt segment for the three months ended September 30, 2010, were $2.4 million, compared to $1.3 million for the three months ended September 30, 2009. This increase is due to employee related costs for the three months ended September 30, 2010.

Retail and Branded Marketing Segment. SG&A expenses for our retail and branded marketing segment for the three months ended September 30, 2010 were $25.3 million, compared to $23.9 million for the three months ended September 30, 2009, an increase of $1.4 million or 5.9%. The increase was primarily attributable to increased payroll and related costs.

Depreciation and Amortization

Depreciation and amortization for the three months ended September 30, 2010, was $26.8 million, compared to $25.2 million for the three months ended September 30, 2009, an increase of $1.6 million or 6.3%. This increase was primarily attributable to depreciation on assets from the Bakersfield refinery acquisition in June 2010 and also new equipment placed in service in the fourth quarter of 2009 and the first half of 2010.

Operating Income (Loss)

Consolidated. Operating loss for the three months ended September 30, 2010, was $35.4 million, compared to $34.3 million for the three months ended September 30, 2009, an increase in loss of $1.1 million. This increase was primarily due to lower asphalt sales volumes and margins and lower throughput at our refineries, partially offset by higher refinery margins, higher retail fuel sales margins and increased motor fuel sales volumes.

Refining and Unbranded Marketing Segment. Operating loss for our refining and unbranded marketing segment was $52.6 million for the three months ended September 30, 2010, compared to $57.8 million for the three months ended September 30, 2009, a decrease in loss of $5.2 million. This decrease was primarily due to improved margins.

Refinery operating margin at the Big Spring refinery was $5.04 per barrel for the three months ended September 30, 2010, compared to $1.34 per barrel for the three months ended September 30, 2009. Light product yields increased in 2010 due to the operation of substantially all refinery units that were damaged in the 2008 fire. Light product yields were approximately 88.8% for the third quarter of 2010 and 80.6% for the third quarter of 2009. The average Gulf Coast 3/2/1 crack spread increased 19.0% to $7.76 per barrel for the three months ended September 30, 2010, compared to $6.52 per barrel for the three months ended September 30, 2009. Refinery operating margin at the California refineries was $0.17 per barrel for the three months ended September 30, 2010, compared to ($0.55) per barrel for the three months ended September 30, 2009. The West Coast 3/2/1 average crack spreads increased 3.0% to $15.30 per barrel for the three months ended September 30, 2010, compared to $14.85 per barrel for the three months ended September 30, 2009. The Krotz Springs refinery operating margin for the three months ended September 30, 2010, was $1.00 per barrel, compared to $2.45 per barrel for the three months ended September 30, 2009. The decrease is primarily due to higher HLS/LLS crude oil costs relative to WTI.

The increases in refining margins at our Big Spring and California refineries were in part due to improvements in the sweet/sour and light/heavy differentials. The sweet/sour differential increased 28.6% to $2.16 per barrel for the three months ended September 30, 2010, compared to $1.68 per barrel for the three months ended September 30, 2009. The light/heavy differential increased 72.0% to $8.55 per barrel for the three months ended September 30, 2010, compared to $4.97 per barrel for the three months ended September 30, 2009.

Asphalt Segment.Operating income for our asphalt segment was $9.0 million for the three months ended September 30, 2010, compared to $19.7 million for the three months ended September 30, 2009, a decrease of $10.7 million. The decrease was primarily due to lower sales volumes and margins for the three months ended September 30, 2010, and partially offset by higher asphalt sales prices for the three months ended September 30, 2010.

Retail and Branded Marketing Segment.Operating income for our retail and branded marketing segment was $8.8 million for the three months ended September 30, 2010, compared to $4.2 million for the three months ended September 30, 2009, an increase of $4.6 million. This increase was primarily due to higher retail fuel sales margins, increased motor fuel sales volumes and higher merchandise sales combined with a higher profit margin.

Interest Expense

Interest expense was $24.1 million for the three months ended September 30, 2010, compared to $21.5 million for the three months ended September 30, 2009, an increase of $2.6 million, or 12.1%. The increase was primarily due to increased expense associated with the senior secured notes issued in the October 2009.

Gain from Bargain Purchase

In connection with the Bakersfield refinery acquisition, the acquisition date fair value of the identifiable net assets acquired exceeded the fair value of the consideration transferred, resulting in a $17.5 million bargain purchase gain.

Income Tax Benefit

Income tax benefit was $21.9 million for the three months ended September 30, 2010, compared to $16.5 million for the three months ended September 30, 2009. The increase resulted from our higher pre-tax loss in the third quarter of 2010, excluding the $17.5 million non-taxable bargain purchase gain recorded in the third quarter of 2010, compared to the third quarter of 2009, and an increase in the effective tax rate. Our effective tax rate was 39.0% for the third quarter of 2010, excluding the $17.5 million non-taxable bargain purchase gain, compared to an effective tax rate of 38.1% for the third quarter of 2009.

Non-Controlling Interest In Loss Of Subsidiaries

Non-controlling interest in loss of subsidiaries represents the proportional share of net loss related to non-voting common stock owned by non-controlling interests in two of our subsidiaries, Alon Assets, Inc. and Alon USA Operating, Inc. Non-controlling interest in loss of subsidiaries was $1.2 million for the three months ended September 30, 2010, compared to $2.3 million for the three months ended September 30, 2009, a decrease of $1.1 million or 47.8%. This decrease resulted from lower net loss for the third quarter of 2010 compared to the third quarter of 2009.

Net Loss Available to Common Stockholders

Net loss available to common stockholders was $15.6 million for the three months ended September 30, 2010, compared to $26.6 million for the three months ended September 30, 2009, a decrease of $11.0 million or 41.4%. This decrease was attributable to the factors discussed above.

Nine Months Ended September 30, 2010 Compared to the Nine Months Ended September 30, 2009

Net Sales

Consolidated. Net sales for the nine months ended September 30, 2010, were $2,668.2 million, compared to $3,081.7 million for the nine months ended September 30, 2009, a decrease of $413.5 million or 13.4%. This decrease was primarily due to lower throughput at our refineries and lower asphalt sales volumes, partially offset by higher refined product prices and higher revenues from increased motor fuel sales volumes.

Refining and Unbranded Marketing Segment. Net sales for our refining and unbranded marketing segment were $2,230.8 million for the nine months ended September 30, 2010, compared to $2,652.9 million for the nine months ended September 30, 2009, a decrease of $422.1 million or 15.9%. This decrease was primarily due to lower refinery throughput, partially offset by higher refined product prices.

Combined refinery throughput for the nine months ended September 30, 2010, averaged 94,775 bpd, consisting of: 46,244 bpd at the Big Spring refinery, 19,590 bpd at the California refineries and 28,941 bpd at the Krotz Springs refinery, compared to a combined average of 154,952 bpd for the nine months ended September 30, 2009, consisting of: 62,933 bpd at the Big Spring refinery, 34,711 bpd at the California refineries and 57,308 bpd at

the Krotz Springs refinery. The Big Spring refinery throughput was lower as a result of efforts to implement new operating procedures and the California refineries’ throughput was lower due to our continued efforts to optimize asphalt production with demand. The Krotz Springs refinery throughput was lower due to its shut down for turnaround activities until its restart in June 2010.

The increase in refined product prices that our refineries experienced resembled the price increases experienced in each refinery’s respective markets. The average price of Gulf Coast gasoline for the nine months ended September 30, 2010, increased 46.9 cpg, or 30.4%, to 201.4 cpg, compared to 154.5 cpg for the nine months ended September 30, 2009. The average Gulf Coast ultra-low sulfur diesel price for the nine months ended September 30, 2010, increased 52.9 cpg, or 33.8%, to 209.4 cpg, compared to 156.5 cpg for the nine months ended September 30, 2009. The average price of West Coast LA CARBOB gasoline for the nine months ended September 30, 2010, increased 38.5 cpg, or 21.4%, to 218.3 cpg, compared to 179.8 cpg for the nine months ended September 30, 2009. The average West Coast LA ultra-low sulfur diesel price for the nine months ended September 30, 2010, increased 54.2 cpg, or 33.8%, to 214.4 cpg, compared to 160.2 cpg for the nine months ended September 30, 2009.

Asphalt Segment. Net sales for our asphalt segment were $316.7 million for the nine months ended September 30, 2010, compared to $351.4 million for the nine months ended September 30, 2009, a decrease of $34.7 million or 9.9%. The decrease was due primarily to a decrease in asphalt sales volumes and partially offset by higher asphalt sales price for the nine months ended September 30, 2010. For the nine months ended September 30, 2010, the asphalt volume decreased 29.2% from 956 thousand tons for the nine months ended September 30, 2009, to 677 thousand tons for the nine months ended September 30, 2010. For the nine months ended September 30, 2010, the average blended asphalt sales price increased 18.1% from $404.39 per ton for the nine months ended September 30, 2009, to $477.68 per ton for the nine months ended September 30, 2010, and the average non-blended asphalt sales price increased 120.4% from $158.49 per ton for the nine months ended September 30, 2009, to $349.29 per ton for the nine months ended September 30, 2010.

Retail and Branded Marketing Segment. Net sales for our retail and branded marketing segment were $753.5 million for the nine months ended September 30, 2010, compared to $591.2 million for the nine months ended September 30, 2009, an increase of $162.3 million or 27.5%. This increase was primarily attributable to increases in motor fuel prices, motor fuel volume and merchandise sales.

Cost of Sales

Consolidated. Cost of sales was $2,443.5 million for the nine months ended September 30, 2010, compared to $2,693.3 million for the nine months ended September 30, 2009, a decrease of $249.8 million or 9.3%. This decrease was primarily due to lower throughput at our refineries and lower asphalt sales volumes, partially offset by higher crude oil prices and increased motor fuel sales volumes.

Refining and Unbranded Marketing Segment.Cost of sales for our refining and unbranded marketing segment was $2,138.3 million for the nine months ended September 30, 2010, compared to $2,397.0 million for the nine months ended September 30, 2009, a decrease of $258.7 million or 10.8%. This decrease was primarily due to lower refinery throughput, partially offset by higher crude oil prices. The average price per barrel of WTI for the nine months ended September 30, 2010, increased $20.47 per barrel to an average of $77.50 per barrel, compared to an average of $57.03 per barrel for the nine months ended September 30, 2009, an increase of 35.9%.

Asphalt Segment. Cost of sales for our asphalt segment were $282.5 million for the nine months ended September 30, 2010, compared to $307.9 million for the nine months ended September 30, 2009, a decrease of $25.4 million or 8.2%. The decrease was due primarily to lower asphalt sales volumes and partially offset by higher crude oil costs for the nine months ended September 30, 2010.

Retail and Branded Marketing Segment.Cost of sales for our retail and branded marketing segment was $655.5 million for the nine months ended September 30, 2010, compared to $502.3 million for the nine months ended September 30, 2009, an increase of $153.2 million or 30.5%. This increase was primarily attributable to increases in motor fuel prices, motor fuel volume and merchandise costs.

Direct Operating Expenses

Consolidated. Direct operating expenses were $192.8 million for the nine months ended September 30, 2010, compared to $204.3 million for the nine months ended September 30, 2009, a decrease of $11.5 million or 5.6%. This decrease was primarily due to lower throughput at our refineries for the nine months ended September 30, 2010, compared to the same period in 2009, partially offset by the acquisition of the Bakersfield refinery in June 2010 and the higher cost of natural gas.

Refining and Unbranded Marketing Segment.Direct operating expenses for our refining and unbranded marketing segment for the nine months ended September 30, 2010, were $159.6 million, compared to $171.3 million for the nine months ended September 30, 2009, a decrease of $11.7 million or 6.8%. This decrease was primarily due to lower throughput at our refineries for the nine months ended September 30, 2010, compared to the nine months ended September 30, 2009. This decrease was partially offset by the acquisition of the Bakersfield refinery in June 2010 and the higher cost of natural gas.

Asphalt Segment.Direct operating expenses for our asphalt segment for the nine months ended September 30, 2010, were $33.3 million, compared to $33.0 million for the nine months ended September 30, 2009, an increase of $0.3 million or 0.9%. The increase is primarily due to the higher cost of natural gas.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for the nine months ended September 30, 2010, were $96.0 million, compared to $95.8 million for the nine months ended September 30, 2009, an increase of $0.2 million or 0.2% .

Refining and Unbranded Marketing Segment. SG&A expenses for our refining and unbranded marketing segment for the nine months ended September 30, 2010, were $17.4 million, compared to $21.5 million for the nine months ended September 30, 2009, a decrease of $4.1 million or 19.1%. The decrease is primarily due to net bad debt recoveries of $1.5 million recorded in the nine months ended September 30, 2010, and higher payroll and related costs in the nine months ended September 30, 2009.

Asphalt Segment. SG&A expenses for our asphalt segment for the nine months ended September 30, 2010, were $4.6 million, compared to $3.5 million for the nine months ended September 30, 2009, an increase of $1.1 million, or 31.4%. This increase is due to employee related costs in the nine months ended September 30, 2010.

Retail and Branded Marketing Segment. SG&A expenses for our retail and branded marketing segment for the nine months ended September 30, 2010, were $73.5 million, compared to $70.2 million for the nine months ended September 30, 2009, an increase of $3.3 million or 4.7%. The increase was primarily attributable to increased payroll and related costs in the nine months ended September 30, 2010.

Depreciation and Amortization

Depreciation and amortization for the nine months ended September 30, 2010, was $78.5 million, compared to $70.9 million for the nine months ended September 30, 2009, an increase of $7.6 million or 10.7%. This increase was due to depreciation on the increase in assets for the Krotz Springs refinery resulting from the settlement of the earnout agreement with Valero in August of 2009, the depreciation of assets from the Bakersfield refinery acquisition in June 2010 and depreciation of new equipment placed in service in the fourth quarter of 2009 and the first half of 2010.

Operating Income (Loss)

Consolidated. Operating income (loss) for the nine months ended September 30, 2010, was ($142.1) million, compared to $15.2 million for the nine months ended September 30, 2009, a decrease of $157.3 million. This decrease was primarily due to lower refinery throughput and margins and lower asphalt sales volumes, partially offset by higher branded fuel margins and motor fuel sales volumes.

Refining and Unbranded Marketing Segment. Operating income (loss) for our refining and unbranded marketing segment was ($146.5) million for the nine months ended September 30, 2010, compared to $6.4 million for the nine months ended September 30, 2009, a decrease of $152.9 million. This decrease was primarily due to lower refining margins and lower refinery throughput.

Refinery operating margin at the Big Spring refinery was $6.39 per barrel for the nine months ended September 30, 2010, compared to $6.32 per barrel for the nine months ended September 30, 2009. Light product yields increased in 2010 due to the operation of substantially all refinery units that were damaged in the 2008 fire. Light product yields were approximately 87.6% for the first nine months of 2010 and 81.3% for the first nine months of 2009. The Gulf Coast 3/2/1 crack spread increased 0.7% to $8.20 per barrel for the nine months ended September 30, 2010, compared to $8.14 per barrel for the nine months ended September 30, 2009. Refinery operating margin at the California refineries was $0.92 per barrel for the nine months ended September 30, 2010, compared to $2.41 per barrel for the nine months ended September 30, 2009. The decrease was partially due to decreased West Coast 3/2/1 crack spreads. The West Coast 3/2/1 average crack spreads decreased 13.3% to $13.65 per barrel for the nine months ended September 30, 2010, compared to $15.74 per barrel for the nine months ended September 30, 2009. The Krotz Springs refinery operating margin for the nine months ended September 30, 2010,was $0.44 per barrel, compared to $6.64 per barrel for the nine months ended September 30, 2009. The decrease is primarily due the fact that the Krotz Springs refinery had been down due to major turnaround and maintenance activities until its restart in June 2010.

The decreases in refining margins at our California refineries were in part offset by improvements in the light/heavy differentials. The light/heavy differential increased 79.2% to $9.05 per barrel for the nine months ended September 30, 2010, compared to $5.05 per barrel for the nine months ended September 30, 2009.

Asphalt Segment.Operating income (loss) for our asphalt segment was ($8.8) million for the nine months ended September 30, 2010, compared to $2.0 million for the nine months ended September 30, 2009, a decrease of ($10.8) million. The decrease was primarily due to lower sales volumes for the nine months ended September 30, 2010.

Retail and Branded Marketing Segment.Operating income for our retail and branded marketing segment was $14.7 million for the nine months ended September 30, 2010, compared to $7.9 million for the nine months ended September 30, 2009, an increase of $6.8 million. This increase was primarily due to higher branded fuel margins, increased motor fuel sales volumes and higher merchandise sales combined with a higher profit margin.

Interest Expense

Interest expense was $72.4 million for the nine months ended September 30, 2010, compared to $70.7 million for the nine months ended September 30, 2009, an increase of $1.7 million, or 2.4%. Included in interest expense for the nine months ended September 30, 2010, is a charge of $6.7 million for the write-off of debt issuance costs associated with our prepayment of the Alon Refining Krotz Springs, Inc. revolving credit facility, and for the nine months ended September 30, 2009, is a charge of $5.7 million related to liquidation of our heating oil hedge.

Gain from Bargain Purchase

Income Tax Benefit

Income tax benefit was $73.7 million for the nine months ended September 30, 2010, compared to $13.0 million for the nine months ended September 30, 2009. This increase resulted from a higher pre-tax loss in the nine months ended September 30, 2010. The pre-tax loss for the nine months ended September 30, 2010 includes the

$17.5 million non-taxable bargain purchase gain. Our effective tax rate was 37.6% for the first nine months of 2010, excluding the $17.5 million non-taxable bargain purchase gain, compared to an effective tax rate of 38.2% for the first nine months of 2009.

Non-Controlling Interest In Loss Of Subsidiaries

Non-controlling interest in loss of subsidiaries was $7.2 million for the nine months ended September 30, 2010, compared to $3.0 million for the nine months ended September 30, 2009, an increase of $4.2 million.

Net Loss Available to Common Stockholders

Net loss available to common stockholders was $97.8 million for the nine months ended September 30, 2010, compared to $24.5 million for the nine months ended September 30, 2009, an increase in loss of $73.3 million. 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, borrowings under our revolving credit facilities and other credit lines and advances from affiliates. We believe that the aforementioned sources of funds and other sources of capital available to us will be sufficient to satisfy the anticipated cash requirements associated with our business during the next 12 months.

On October 28, 2010, we completed a registered direct offering of our 8.5% Series A Convertible Preferred Stock for an aggregate offering price of $39.4 million after deducting $0.6 million of offering expenses. We used $30.0 million of the proceeds from the offering to prepay in full the ARKS Term Facility on October 28, 2010. Also in October 2010, we obtained $23.0 million of letters of credit outside our existing credit facilities.

On April 21, 2010, ARKS entered into a Supply and Offtake Agreement, which was amended on May 26, 2010,(the “Supply and Offtake Agreement”), with J. Aron & Company (“J. Aron”), the proceeds of which allowed ARKS to retire part of its obligations under the ARKS Term Facility and support the operation of the refinery at a minimum of 72,000 barrels per day. Pursuant to the Supply and Offtake Agreement, (i) J. Aron agreed to sell to ARKS, and ARKS agreed to buy from J. Aron, at market price, crude oil for processing at the Krotz Springs refinery and (ii) ARKS agreed to sell, and J. Aron agreed to buy, at market price, certain refined products produced at the Krotz Springs refinery.

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 the costs of such future capital expenditures related to the expansion of our business. Certain of our credit facilities contain financial covenants for which we must maintain compliance; the most restrictive of these covenants is contained in the Alon USA LP Credit Facility agreement which requires a subsidiary of ours, Alon USA, Inc., to maintain a net debt to EBITDA ratio, as defined, of no more than 4 to 1. However, this covenant is not effective until December 31, 2010. If we will not be able to maintain the level required by these covenants, then borrowings under the Alon USA LP Credit Facility that are currently in long-term debt will be classified under short-term debt and current portion of long-term debt.

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

Cash Flows

The following table sets forth our consolidated cash flows for the nine months ended September 30, 2010, and 2009:


	For the Nine Months Ended
	September 30,
	2010			2009
	(dollars in thousands)
Cash provided by (used in):
Operating activities	$	(37,275	)	$	325,132
Investing activities		(15,218	)		(93,605	)
Financing activities		51,691			(231,903	)

Net decrease in cash and cash equivalents	$	(802	)	$	(376	)

Cash Flows Provided By (Used In) Operating Activities

Net cash provided by (used in) operating activities during the nine months ended September 30, 2010, was ($37.3) million, compared to $325.1 million during the nine months ended September 30, 2009. The change in cash used in operating activities of $362.4 million is primarily attributable to the difference of approximately $137.9 million in net income, adjusted for non-cash adjustments, the difference in working capital from income tax refunds received of approximately $47.3 million in 2010 compared to approximately $103.0 million in 2009. In addition, we received proceeds of $133.6 million from the liquidation of our heating oil crack spread hedge in 2009.

Cash Flows Used In Investing Activities

Net cash used in investing activities was $15.2 million during the nine months ended September 30, 2010, compared to $93.6 million during the nine months ended September 30, 2009. The change in net cash used in investing activities of $78.4 million was primarily attributable to lower 2010 capital expenditures of $77.0 million compared to 2009, proceeds received from the sale of securities and disposal of assets of $56.9 million in 2010, offset by $32.4 million for the Bakersfield refinery acquisition in 2010. Earnout payments related to the Krotz Springs refinery acquisition were $10.9 million less during the nine months ended September 30, 2010, compared to the nine months ended September 30, 2009. Cash used in investing activities during the nine months ended September 30, 2009, included insurance proceeds of $34.1 million to rebuild the Big Spring refinery.

Cash Flows Provided by (Used In) Financing Activities

Net cash provided by (used in) financing activities was $51.7 million during the nine months ended September 30, 2010, compared to ($231.9) million during the nine months ended September 30, 2009. The net change in cash provided by (used in) financing activities of $283.6 million is primarily attributable to additions to short-term financing of $30.0 million through the Term Loan Credit Facility, proceeds received of $45.8 million from the Supply and Offtake Agreement and lower payments of $14.7 million on our long-term debt and revolving credit facilities in 2010 compared to repayments of $218.5 million in 2009.

Indebtedness

Alon USA Energy, Inc. Credit Facilities

Term Loan Credit Facility. We have a term loan (the “Alon Energy Term Loan”) that will mature on August 2, 2013. Principal payments of $4.5 million per annum are paid in quarterly installments, subject to reduction from mandatory repayments associated with certain events.

The Alon Energy Term Loan is jointly and severally guaranteed by all of our subsidiaries except for our retail subsidiaries, those subsidiaries established in conjunction with the Krotz Springs refinery acquisition and certain subsidiaries established in conjunction with the Bakersfield refinery acquisition. The Alon Energy Term Loan is secured by a second lien on cash, accounts receivable and inventory and a first lien on most of our remaining assets excluding those of our retail subsidiaries, those subsidiaries established in conjunction with the Krotz Springs refinery acquisition and certain subsidiaries established in conjunction with the Bakersfield refinery acquisition.

At September 30, 2010 and December 31, 2009, the Alon Energy Term Loan had an outstanding balance of $430.9 million and $434.3 million, respectively.

Letter of Credit Facility.On March 9, 2010, we entered into an unsecured credit facility with Israel Discount Bank of New York (the “Alon Energy Letter of Credit Facility”) for the issuance of letters of credit in an amount not to exceed $60.0 million and with a sub-limit for borrowings not to exceed $30.0 million. This facility will terminate on January 31, 2013. On September 30, 2010, we had $60.0 million of outstanding letters of credit under this facility. Borrowings under this facility bear interest at the Eurodollar rate plus 3.00% per annum subject to an overall minimum interest rate of 4.00%.

This facility contains certain customary restrictive covenants including financial covenants. Certain of these covenants become applicable at September 30, 2010, while others first apply at December 31, 2010.

Alon USA LP Credit Facility

Revolving Credit Facility.We have a $240.0 million revolving credit facility (the “Alon USA LP Credit Facility”) that will mature on January 1, 2013. The Alon USA LP Credit Facility can be used both for borrowings and the issuance of letters of credit, subject to a limit of the lesser of the facility or the amount of the borrowing base under the facility.

Borrowings under the Alon USA LP Credit Facility bear interest at the Eurodollar rate plus 3.00% per annum subject to an overall minimum interest rate of 4.00%.

The Alon USA LP Credit Facility is secured by (i) a first lien on our cash, accounts receivables, inventories and related assets and (ii) a second lien on our fixed assets and other specified property, in each case, excluding those of Alon Paramount Holdings, Inc. (“Alon Holdings”), and its subsidiaries other than Alon Pipeline Logistics, LLC (“Alon Logistics”), the subsidiaries established in conjunction with the Krotz Springs refinery acquisition, the subsidiaries established in conjunction with the Bakersfield refinery acquisition and our retail subsidiaries.

Borrowings of $144.0 million and $88.0 million were outstanding under the Alon USA LP Credit Facility at September 30, 2010, and December 31, 2009, respectively. At September 30, 2010 and December 31, 2009, outstanding letters of credit under the Alon USA LP Credit Facility were $92.9 million and $129.0 million, respectively.

Paramount Petroleum Corporation Credit Facility

Revolving Credit Facility.We have a $300.0 million revolving credit facility (the “Paramount Credit Facility”) that will mature on February 28, 2012. The Paramount Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility or the amount of the borrowing base under the facility.

The Paramount Credit Facility contains certain restrictive covenants related to working capital, operations and other matters.

Borrowings of $66.1 million and $45.3 million were outstanding under the Paramount Credit Facility at September 30, 2010 and December 31, 2009, respectively. At September 30, 2010 and December 31, 2009, outstanding letters of credit under the Paramount Credit Facility were $57.8 million and $18.0 million, respectively.

Alon Refining Krotz Springs, Inc. Credit Facilities

Senior Secured Notes.In October 2009, Alon Refining Krotz Springs, Inc. (“ARKS”) issued 13.50% senior secured notes (the “Senior Secured Notes”) in aggregate principal amount of $216.5 million in a private offering. The Senior Secured Notes were issued at an offering price of 94.857%.

ARKS received gross proceeds of $205.4 million from the sale of the Senior Secured Notes (before fees and expenses related to the offering). In connection with the closing, ARKS prepaid in full all outstanding obligations under its term loan. The remaining proceeds from the offering were used for general corporate purposes.

On February 17, 2010, ARKS exchanged $216.5 million of Senior Secured Notes for an equivalent amount of Senior Secured Notes (“Exchange Notes”) registered under the Securities Act of 1933. The Exchange Notes will mature on October 15, 2014 and the entire principal amount is due at maturity. Interest is payable semi-annually in arrears on April 15 and October 15. The Exchange Notes are substantially identical to the Senior Secured Notes, except that the Exchange Notes have been registered with the Securities and Exchange Commission and are not subject to transfer restrictions.

At September 30, 2010 and December 31, 2009, the Senior Secured Notes had an outstanding balance (net of unamortized discount) of $206.9 million and $205.7 million, respectively. Alon is utilizing the effective interest method to amortize the original issue discount over the life of the Senior Secured Notes.

Short-Term Credit Facility.On March 15, 2010, ARKS entered into a $65.0 million short-term credit facility with Bank Hapoalim B.M. (the “ARKS Term Facility”). The ARKS Term Facility as currently amended and restated matures on November 15, 2010. ARKS originally borrowed $65.0 million and has repaid $35.0 million as of September 30, 2010.

Borrowings under the ARKS Term Facility bear interest at LIBOR plus 3.00% and $30.0 million was outstanding under the ARKS Term Facility at September 30, 2010. The ARKS Term Facility is secured by a second lien on all assets other than cash, accounts receivable, and inventory of ARKS. The ARKS Term Facility contains customary restrictive covenants, such as restrictions on liens, mergers, consolidation, sales of assets, capital expenditures, additional indebtedness, investments, hedging transactions, and certain restricted payments.

The ARKS Term Facility was prepaid on full in October 28, 2010.

Revolving Credit Facility.On March 15, 2010, ARKS terminated its revolving credit facility agreement (the “ARKS Facility”) and repaid all outstanding amounts thereunder. As a result of the prepayment of the ARKS Facility, we recorded a write-off of unamortized debt issuance costs of $6.7 million as interest expense in the first quarter of 2010.

Borrowings of $83.3 million and outstanding letters of credit of $2.8 million were outstanding under the ARKS Facility at December 31, 2009.

Retail Credit Facilities

Term Credit Agreement.Southwest Convenience Stores, LLC (��SCS”) is a party to a credit agreement (the “SCS Credit Agreement”) that matures on July 1, 2017. Monthly principal payments are based on a 15-year amortization term.

Borrowings under the SCS Credit Agreement bear interest at a Eurodollar rate plus 1.50% per annum.

At September 30, 2010 and December 31, 2009, the SCS Credit Agreement had an outstanding balance of $74.9 million and $79.7 million, respectively, and there were no further amounts available for borrowing.

Other Retail Related Credit Facilities.In 2003, Alon obtained $1.5 million in mortgage loans to finance the acquisition of new retail locations. The interest rates on these loans ranged between 5.5% and 9.7%, with 5 to 15-year payment terms. At September 30, 2010 and December 31, 2009, the outstanding balances were $0.7 million and $0.8 million, respectively.

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 updated total capital expenditure and turnaround/chemical catalyst budget for 2010 is $45.3 million, of which $20.1 million is related to regulatory and compliance projects, $22.7 million is related to turnaround and chemical catalyst, and $2.5 million is related to various improvement and sustaining projects. Approximately $33.2 million has been spent as of September 30, 2010.

Turnaround and Chemical Catalyst Costs. We expect to spend approximately $22.7 million during 2010 relating to turnaround and chemical catalyst. Approximately $12.7 million has been spent as of September 30, 2010, compared to $13.0 million for the same period in 2009.

Contractual Obligations and Commercial Commitments

There have been no material changes outside the ordinary course of business from our contractual obligations and commercial commitments detailed in our Annual Report on Form 10-K for the year ended December 31, 2009.

Off-Balance Sheet Arrangements

We have no material 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 are described under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2009. Certain critical accounting policies that materially affect the amounts recorded in our consolidated financial statements are the use of the LIFO method for valuing certain inventories and the deferral and subsequent amortization of costs associated with major turnarounds and chemical catalysts replacements. No significant changes to these accounting policies have occurred subsequent to December 31, 2009.

New Accounting Standards and Disclosures

New accounting standards are disclosed in Note 1(c) Basis of Presentation and Certain Significant Accounting Policies—New Accounting Standards included in the consolidated financial statements included in Item 1 of this report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES 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, refined products, asphalt and blendstocks, 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, 2010, we held approximately 2.3 million barrels of crude oil, refined product and asphalt inventories valued under the LIFO valuation method with an average cost of $31.62 per barrel. Market value exceeded carrying value of LIFO costs by $104.4 million. We refer to this excess as our LIFO reserve. If the market value of these inventories had been $1.00 per barrel lower, our LIFO reserve would have been reduced by $2.3 million.

In accordance with fair value provisions of ASC 825-10, 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 which have not been closed or settled at the end of the reporting period. A “long” represents 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, 2010:


Description				Wtd Avg Purchase		Wtd Avg Sales					Market			Gain
of Activity	Contract Volume			Price/BBL		Price/BBL		Contract Value			Value			(Loss)
								(in thousands)
Forwards-long (Diesel)		92,966		$	86.11	$	—	$	8,005		$	8,536		$	531


Description				Wtd Avg Contract		Wtd Avg Market					Market			Gain
of Activity	Contract Volume			Price/Oz		Price/Oz		Contract Value			Value			(Loss)
								(in thousands)
Futures-short (Platinum)		(2,846	)	$	1,480.00	$	1,664.50	$	(4,212	)	$	(4,737	)	$	(525	)
Futures-short (Palladium)		(2,534	)		436.00		573.35		(1,105	)		(1,453	)		(348	)


Description				Wtd Avg Contract		Wtd Avg Market					Market			Gain
of Activity	Contract Volume			Spread		Spread		Contract Value			Value			(Loss)
								(in thousands)
Futures-crack spread (Heating oil)		255,600		$	11.38	$	8.90	$	2,908		$	2,275		$	(633	)
Futures-call options (Heating oil)		(3,514,500	)	$	13.24	$	13.24	$	(46,535	)	$	(46,535	)	$	—

Interest Rate Risk

As of September 30, 2010, $613.3 million of our outstanding debt was at floating interest rates out of which approximately $144.0 million was at the Eurodollar rate plus 3.00%, subject to a minimum interest rate of 4.00%. As of September 30, 2010, we had interest rate swap agreements with a notional amount of $300.0 million with remaining periods ranging from less than three months to approximately two years and fixed interest rates ranging from 4.25% to 4.45%. An increase of 1% in the Eurodollar rate on indebtedness, net of the weighted average notional amount of the interest rate swap agreements outstanding in 2010 and the instrument subject to the minimum interest rate, would result in an increase in our interest expense of approximately $5.0 million per year.

ITEM 4. CONTROLS AND PROCEDURES

(1) 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 amended (the “Exchange Act”)) 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 including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosures.

(2) Changes in internal control over financial reporting.

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

PART II. OTHER INFORMATION

ITEM 6. EXHIBITS


Exhibit
Number		Description of Exhibit
3.1		Amended and 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).

4.2		Indenture, dated as of October 22, 2009, by and among Alon Refining Krotz Springs, Inc. and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K, filed by the Company on October 23, 2009, SEC File No. 001-32567).

4.3		Form of Certificate of Designation of the 8.50% Series A Convertible Preferred Stock.

4.4		Specimen 8.50% Series A Convertible Preferred Stock Certificate.

10.1		Amendment No. 3 to Credit Agreement, dated August 11, 2010 (as amended, supplemented or otherwise modified from time to time), among Alon Refining Krotz Springs, Inc., each other party joined as a borrower thereunder from time to time, the Lenders party thereto, and Bank Hapoalim B.M., as Administrative Agent (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on August 13, 2010, 2010, SEC File No. 001-32567).

10.2		Form of Series A Convertible Preferred Stock Purchase Agreement (incorporated by reference to Exhibit 10.105 to Form S-1/A, filed by the Company on October 21, 2010, Registration No. 333-169583).

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

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

32.1		Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

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


	Alon USA Energy, Inc.
Date: November 8, 2010	By:	/s/ David Wiessman
		David Wiessman
		Executive Chairman


Date: November 8, 2010	By:	/s/ Jeff D. Morris
		Jeff D. Morris
		Chief Executive Officer



Date: November 8, 2010	By:	/s/ Shai Even
		Shai Even
		Chief Financial Officer

EXHIBITS


Exhibit
Number		Description of Exhibit
3.1		Amended and 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).

4.2		Indenture, dated as of October 22, 2009, by and among Alon Refining Krotz Springs, Inc. and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K, filed by the Company on October 23, 2009, SEC File No. 001-32567).

4.3		Form of Certificate of Designation of the 8.50% Series A Convertible Preferred Stock.

4.4		Specimen 8.50% Series A Convertible Preferred Stock Certificate.

10.1		Amendment No. 3 to Credit Agreement, dated August 11, 2010 (as amended, supplemented or otherwise modified from time to time), among Alon Refining Krotz Springs, Inc., each other party joined as a borrower thereunder from time to time, the Lenders party thereto, and Bank Hapoalim B.M., as Administrative Agent (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on August 13, 2010, 2010, SEC File No. 001-32567).

10.2		Form of Series A Convertible Preferred Stock Purchase Agreement (incorporated by reference to Exhibit 10.105 to Form S-1/A, filed by the Company on October 21, 2010, Registration No. 333-169583).

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

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

32.1		Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.

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Alon USA Energy (ALJ) Inactive 10-Q2010 Q3 Quarterly report

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