Alon USA Energy (ALJ) 10-Q 2011 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, 2011

OR

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE TRANSITION PERIOD FROM __________TO __________

Commission file number: 001-32567

Alon USA Energy, Inc.

(Exact name of Registrant as specified in its charter)

___________________________________________________

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

7616 LBJ Freeway, Suite 300, Dallas, Texas 75251

(Address of principal executive offices) (Zip Code)

(972) 367-3600

(Registrant’s telephone number, including area code)

___________________________________________________

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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).

Yes  þ No o

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:

Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o
	(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). Yes o No þ

The number of shares of the Registrant’s common stock, par value $0.01 per share, outstanding as of November 1, 2011, was 56,017,382.

TABLE OF CONTENTS

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	19
FORWARD-LOOKING STATEMENTS	19
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	41
ITEM 4. CONTROLS AND PROCEDURES	43
PART II. OTHER INFORMATION	44
ITEM 6. EXHIBITS	44
SIGNATURES	45
EXHIBITS	46
EX-10.1 SUPPLEMENTAL AGREEMENT TO SUPPLY AND OFFTAKE AGREEMENT BETWEEN ALON REFINING KROTZ SPRINGS, INC. AND J. ARON & COMPANY
EX-10.2 SUPPLEMENTAL AGREEMENT TO SUPPLY AND OFFTAKE AGREEMENT BETWEEN ALON USA, LP AND J. ARON & COMPANY
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, 2011			December 31, 2010
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	175,601		$	71,687
Accounts and other receivables, net	210,850			115,541
Income tax receivable	8,642			8,642
Inventories	254,164			141,050
Deferred income tax asset	36,699			49,052
Prepaid expenses and other current assets	8,555			7,875
Total current assets	694,511			393,847
Equity method investments	20,189			18,664
Property, plant, and equipment, net	1,510,063			1,488,532
Goodwill	105,943			105,943
Other assets, net	89,191			81,535
Total assets	$	2,419,897		$	2,088,521
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	330,965		$	292,991
Accrued liabilities	139,281			88,354
Current portion of long-term debt	124,707			11,512
Total current liabilities	594,953			392,857
Other non-current liabilities	179,714			160,976
Long-term debt	929,301			904,793
Deferred income tax liability	298,013			288,128
Total liabilities	2,001,981			1,746,754
Commitments and contingencies (Note 14)
Stockholders’ equity:
Preferred stock, par value $0.01, 10,000,000 shares authorized; 4,000,000 issued and outstanding at September 30, 2011 and December 31, 2010, respectively	40,000			40,000
Common stock, par value $0.01, 100,000,000 shares authorized; 55,933,446 and 54,281,636 shares issued and outstanding at September 30, 2011 and December 31, 2010, respectively	558			543
Additional paid-in capital	316,953			290,809
Accumulated other comprehensive loss, net of income tax	(20,433		)	(21,917		)
Retained earnings	79,270			33,052
Total stockholders’ equity	416,348			342,487
Non-controlling interest in subsidiaries	1,568			(720		)
Total equity	417,916			341,767
Total liabilities and equity	$	2,419,897		$	2,088,521

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

1

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, dollars in thousands except per share data)

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Net sales (1)	$	2,056,653		$	1,248,569		$	5,303,388		$	2,668,243
Operating costs and expenses:
Cost of sales	1,827,098			1,153,743			4,717,673			2,443,533
Direct operating expenses	83,338			68,448			202,476			192,816
Selling, general and administrative expenses	34,680			35,012			107,595			96,001
Depreciation and amortization	29,812			26,781			80,046			78,471
Total operating costs and expenses	1,974,928			1,283,984			5,107,790			2,810,821
Gain on disposition of assets	229			—			161			474
Operating income (loss)	81,954			(35,415		)	195,759			(142,104		)
Interest expense	(22,582		)	(24,091		)	(63,780		)	(72,411		)
Equity earnings of investees	2,005			3,864			3,775			4,970
Gain on bargain purchase	—			17,480			—			17,480
Other income (loss), net	(14,272		)	(494		)	(51,065		)	13,345
Income (loss) before income tax expense (benefit) and non-controlling interest in income (loss) of subsidiaries	47,105			(38,656		)	84,689			(178,720		)
Income tax expense (benefit)	17,004			(21,905		)	26,952			(73,711		)
Income (loss) before non-controlling interest in income (loss) of subsidiaries	30,101			(16,751		)	57,737			(105,009		)
Non-controlling interest in income (loss) of subsidiaries	1,480			(1,167		)	2,317			(7,224		)
Net income (loss) available to common stockholders	$	28,621		$	(15,584	)	$	55,420		$	(97,785	)
Income (loss) per share, basic	$	0.51		$	(0.29	)	$	1.00		$	(1.80	)
Weighted average shares outstanding, basic (in thousands)	55,755			54,181			55,290			54,177
Income (loss) per share, diluted	$	0.46		$	(0.29	)	$	0.91		$	(1.80	)
Weighted average shares outstanding, diluted (in thousands)	61,690			54,181			61,231			54,177
Cash dividends per share	$	0.04		$	0.04		$	0.12		$	0.12

___________________________________

(1) Includes excise taxes on sales by the retail segment of $15,476 and $14,204 for the three months and $44,887 and $40,521 for the nine months ended September 30, 2011, and 2010, respectively.

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

2

ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited, dollars in thousands)
	For the Nine Months Ended
	September 30,
	2011			2010
Cash flows from operating activities:
Net income (loss) available to common stockholders	$	55,420		$	(97,785	)
Adjustments to reconcile net income (loss) available to common stockholders to cash provided by (used in) operating activities:
Depreciation and amortization	80,046			78,471
Stock compensation	2,135			446
Deferred income tax expense	21,438			(73,715		)
Non-controlling interest in income (loss) of subsidiaries	2,317			(7,224		)
Equity earnings of investees (net of dividends)	(1,525		)	(2,614		)
Amortization of debt issuance costs	4,370			4,475
Amortization of original issuance discount	2,146			1,235
Write-off of unamortized debt issuance costs	—			6,659
Gain on bargain purchase	—			(17,480		)
Gain on disposition of assets	(161		)	(474		)
Changes in operating assets and liabilities, net of acquisition effects:
Accounts and other receivables, net	(95,309		)	(22,001		)
Income tax receivable	—			47,290
Inventories	(114,279		)	34,644
Prepaid expenses and other current assets	(680		)	(3,943		)
Other assets, net	(13,705		)	(30,461		)
Accounts payable	37,974			36,480
Accrued liabilities	57,153			12,989
Other non-current liabilities	21,022			(4,267		)
Net cash provided by (used in) operating activities	58,362			(37,275		)
Cash flows from investing activities:
Capital expenditures	(91,120		)	(20,526		)
Capital expenditures for turnarounds and catalysts	(6,995		)	(12,668		)
Proceeds from disposition of assets	547			20,095
Proceeds from sale of securities	—			36,852
Acquisition of Bakersfield refinery	—			(32,409		)
Earnout payment related to Krotz Springs refinery acquisition	(6,562		)	(6,562		)
Net cash used in investing activities	(104,130		)	(15,218		)
Cash flows from financing activities:
Dividends paid to stockholders	(6,652		)	(6,501		)
Dividends paid to non-controlling interest	(570		)	(429		)
Proceeds from issuance of common stock	11,900			—
Stock issuance costs	(537		)	—
Inventory supply agreement	1,165			45,807
Deferred debt issuance costs	(2,169		)	(2,450		)
Revolving credit facilities, net	125,053			(6,527		)
Additions to long-term debt	30,136			—
Payments on long-term debt	(8,644		)	(8,209		)
Additions to short-term debt	—			76,500
Payments on short-term debt	—			(46,500		)
Net cash provided by financing activities	149,682			51,691
Net increase (decrease) in cash and cash equivalents	103,914			(802		)
Cash and cash equivalents, beginning of period	71,687			40,437
Cash and cash equivalents, end of period	$	175,601		$	39,635
Supplemental cash flow information:
Cash paid for interest	$	49,784		$	53,717
Cash paid (received) for income tax, net of refunds	$	3,203		$	(46,748	)

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

3

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited, dollars in thousands except as noted)

(1) Basis of Presentation

(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, 2011.

The consolidated balance sheet as of December 31, 2010, 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, 2010.

(b) New Accounting Standards

In September 2011, the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 350, Intangibles - Goodwill and Other, were amended to permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If the existence of events or circumstances leads an entity to believe that the fair value of the entity is not below its carrying amount, then performing the two-step impairment test is unnecessary. The adoption of this guidance will not affect Alon's financial position or results of operations.

In June 2011, the provisions of FASB ASC 220, Comprehensive Income, were amended to allow an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. Under either option, the entity is required to present reclassification adjustments on the face of the financial statements for items that are reclassified from other comprehensive income to net income in the statement where those components are presented. These provisions are effective for the first interim or annual period beginning after December 15, 2011, and are to be applied retrospectively, with early adoption permitted. The adoption of this guidance will not affect Alon's financial position or results of operations because these requirements only affect disclosures.

(2) 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.

(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. In Bakersfield, Alon is converting intermediate products into finished products and is not refining crude oil. 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

4

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

(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 303 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, 2011 and 2010, are presented below:

	Refining and Unbranded Marketing		Asphalt			Retail and Branded Marketing			Corporate			Consolidated Total
Three Months Ended September 30, 2011
Net sales to external customers	$	1,471,936	$	201,081		$	383,636		$	—		$	2,056,653
Intersegment sales/purchases	390,245		(114,492		)	(275,753		)	—			—
Depreciation and amortization	25,179		1,522			2,707			404			29,812
Operating income (loss)	77,380		(4,114		)	9,280			(592		)	81,954
Total assets	2,047,354		145,788			212,253			14,502			2,419,897
Turnaround, chemical catalyst and capital expenditures	17,664		125			7,777			329			25,895

	Refining and Unbranded Marketing			Asphalt			Retail and Branded Marketing			Corporate			Consolidated 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 and capital expenditures	5,844			465			1,322			1,344			8,975

5

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

	Refining and Unbranded Marketing		Asphalt			Retail and Branded Marketing			Corporate			Consolidated Total
Nine Months Ended September 30, 2011
Net sales to external customers	$	3,784,798	$	435,135		$	1,083,455		$	—		$	5,303,388
Intersegment sales/purchases	1,012,327		(232,971		)	(779,356		)	—			—
Depreciation and amortization	64,799		4,999			9,037			1,211			80,046
Operating income (loss)	200,523		(27,439		)	24,450			(1,775		)	195,759
Total assets	2,047,354		145,788			212,253			14,502			2,419,897
Turnaround, chemical catalyst and capital expenditures	83,114		1,458			12,271			1,272			98,115

	Refining and Unbranded Marketing			Asphalt			Retail and Branded Marketing			Corporate			Consolidated 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

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 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.

(3) 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 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 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.

6

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

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, 2011, and December 31, 2010, respectively:

	Quoted Prices in Active Markets For Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Consolidated Total
As of September 30, 2011
Assets:
Commodity contracts (futures and forwards)	$	3,618	$	—	$	—	$	3,618
Liabilities:
Commodity contracts (swaps)	—		2,540		—		2,540
Commodity contracts (call options)	—		33,429		—		33,429
Interest rate swap	—		5,217		—		5,217
As of December 31, 2010
Assets:
Commodity contracts (futures and forwards)	$	1,214	$	—	$	—	$	1,214
Liabilities:
Commodity contracts (swaps)	—		681		—		681
Commodity contracts (call options)	—		8,876		—		8,876
Interest rate swap	—		7,501		—		7,501

(4) 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. Credit risk on Alon’s derivative instruments is mitigated by transacting with counterparties meeting established collateral and credit criteria.

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, 2011, Alon had an interest rate swap agreement with a notional amount of $100,000, a remaining period of 15 months and a fixed interest rate of 4.25%. This swap was accounted for as a cash flow hedge.

For cash flow hedges, gains and losses reported in equity are reclassified into interest expense when the forecasted transaction affects income. During the nine months ended September 30, 2011 and 2010, Alon recognized in equity unrealized after-tax gains of $1,484 and $3,973, respectively, for the fair value measurement of the interest rate swap agreements. There were no amounts reclassified from equity into interest expense as a result of the discontinuance of cash flow hedge accounting.

For the nine months ended September 30, 2011 and 2010, 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. 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

7

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

accounting was discontinued in the fourth quarter of 2008 and all changes in value subsequent to the discontinuance were recognized into earnings. An after-tax loss of $4,003 for the nine months ended September 30, 2010 was reclassified from equity to earnings due to the discontinuance of cash flow hedge accounting. 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, 2011
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (swaps)		$	—	Accrued liabilities	$	(2,540	)
Commodity contracts (call options)		—		Accrued liabilities	(33,429		)
Commodity contracts (futures and forwards)	Accounts receivable	7,090		Accrued liabilities	(3,472		)
Total derivatives not designated as hedging instruments		$	7,090		$	(39,441	)
Derivatives designated as hedging instruments:
Interest rate swap		$	—	Other non-current liabilities	$	(5,217	)
Total derivatives designated as hedging instruments		—			(5,217		)
Total derivatives		$	7,090		$	(44,658	)

	As of December 31, 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	$	(681	)
Commodity contracts (call options)		—		Accrued liabilities	(5,748		)
Commodity contracts (futures and forwards)	Accounts receivable	1,364		Accrued liabilities	(150		)
Commodity contracts (call options)		—		Other non-current liabilities	(3,128		)
Total derivatives not designated as hedging instruments		$	1,364		$	(9,707	)
Derivatives designated as hedging instruments:
Interest rate swap		$	—	Other non-current liabilities	$	(7,501	)
Total derivatives designated as hedging instruments		—			(7,501		)
Total derivatives		$	1,364		$	(17,208	)

8

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”).

Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI		Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				Gain (Loss) Reclassified from Accumulated OCI into Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
			Location	Amount			Location	Amount
For the Three Months Ended September 30, 2011
Interest rate swap	$	918	Interest expense	$	(1,058	)		$	—
Total derivatives	$	918		$	(1,058	)		$	—
For the Three Months Ended September 30, 2010
Commodity contracts (swaps)	$	—	Cost of sales	$	(2,825	)		$	—
Interest rate swaps	2,494		Interest expense	(3,693		)		—
Total derivatives	$	2,494		$	(6,518	)		$	—

Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI		Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				Gain (Loss) Reclassified from Accumulated OCI into Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
			Location	Amount			Location	Amount
For the Nine Months Ended September 30, 2011
Interest rate swap	$	2,284	Interest expense	$	(3,053	)		$	—
Total derivatives	$	2,284		$	(3,053	)		$	—
For the Nine Months Ended September 30, 2010
Commodity contracts (swaps)	$	—	Cost of sales	$	(6,354	)		$	—
Interest rate swaps	6,112		Interest expense	(10,917		)		—
Total derivatives	$	6,112		$	(17,271	)		$	—

Derivatives not designated as hedging instruments:

	Gain (Loss) Recognized in Income
	Location	Amount
For the Three Months Ended September 30, 2011
Commodity contracts (futures & forwards)	Cost of sales	$	(469	)
Commodity contracts (swaps)	Cost of sales	(1,038		)
Commodity contracts (call options)	Other income (loss), net	(14,269		)
Total derivatives		$	(15,776	)
For the Three Months Ended September 30, 2010
Commodity contracts (futures & forwards)	Cost of sales	$	1,796
Commodity contracts (swaps)	Cost of sales	$	(126	)
Commodity contracts (swaps)	Other income (loss), net	(671		)
Total derivatives		$	999

9

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 Nine Months Ended September 30, 2011
Commodity contracts (futures & forwards)	Cost of sales	$	10,290
Commodity contracts (swaps)	Cost of sales	(3,716		)
Commodity contracts (call options)	Other income (loss), net	(51,093		)
Total derivatives		$	(44,519	)
For the Nine Months Ended September 30, 2010
Commodity contracts (futures & forwards)	Cost of sales	$	3,536
Commodity contracts (swaps)	Cost of sales	$	(501	)
Commodity contracts (swaps)	Other income (loss), net	(873		)
Total derivatives		$	2,162

(5) 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, 2011		December 31, 2010
Crude oil, refined products, asphalt and blendstocks	$	146,377	$	60,588
Crude oil inventory consigned to others	59,301		38,445
Materials and supplies	21,675		19,059
Store merchandise	19,451		17,237
Store fuel	7,360		5,721
Total inventories	$	254,164	$	141,050

Crude oil, refined products, asphalt and blendstock inventories totaled 2,733 thousand barrels and 2,441 thousand barrels as of September 30, 2011 and December 31, 2010, respectively. A reduction of inventory volumes resulted in a liquidation of LIFO inventory layers associated with refined products and asphalt carried at lower costs which prevailed in previous years. The liquidation decreased cost of sales by approximately $44,570 for the nine months ended September 30, 2011. An increase in LIFO inventory associated with crude oil resulted in an increase to cost of sales of $21,074 for the nine months ended September 30, 2011.

Market values of crude oil, refined products, asphalt and blendstock inventories exceeded LIFO costs by $100,522 and $115,072 at September 30, 2011 and December 31, 2010, respectively.

Crude oil inventory consigned to others represents inventory that was sold to third parties with an obligation by Alon to repurchase the inventory at the end of the respective agreements. As a result of this requirement to repurchase inventory, no revenue was recorded on these transactions and the inventory volumes remain valued under the LIFO method.

Alon had 929 thousand barrels and 674 thousand barrels of crude oil consigned to others at September 30, 2011 and December 31, 2010, respectively. Alon recorded liabilities associated with this consigned inventory of $26,916 in accounts payable and $56,994 in other non-current liabilities and $27,034 in accounts payable and $32,433 in other non-current liabilities at September 30, 2011 and December 31, 2010, respectively.

Additionally, Alon recorded accrued liabilities of $3,131 and accounts receivable of $1,073 at September 30, 2011 and December 31, 2010, respectively, for forward commitments related to month-end consignment inventory target levels differing

10

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

from projected levels and the associated pricing with these inventory level differences.

Normal Purchase Normal Sale

Effective January 1, 2011, Alon elected to account for all inventory financing agreements it has under the "Normal Purchase Normal Sales" exemption of FASB ASC 815, Derivatives and Hedging. This exemption applies to situations where commodities are physically delivered. In previous periods Alon recorded changes in the fair value of the estimated settlement liability of these contracts through the statement of operations. Beginning January 1, 2011 and forward, changes in fair value of the estimated settlement liability will no longer be recorded due to the Normal Purchase Normal Sale exemption. If the contracts were settled September 30, 2011, the payment would be in excess of the liabilities recorded by $8,946.

(6) Property, Plant and Equipment, Net

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

	September 30, 2011			December 31, 2010
Refining facilities	$	1,704,182		$	1,628,039
Pipelines and terminals	41,708			40,686
Retail	144,326			137,771
Other	18,418			16,773
Property, plant and equipment, gross	1,908,634			1,823,269
Less accumulated depreciation	(398,571		)	(334,737		)
Property, plant and equipment, net	$	1,510,063		$	1,488,532

The increase in refining facilities at September 30, 2011 is mainly due to the investment in the integration of the hydrocracker unit in Bakersfield, California.

(7) Additional Financial Information

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

(a) Other Assets, Net

	September 30, 2011		December 31, 2010
Deferred turnaround and chemical catalyst cost	$	24,202	$	23,047
Environmental receivables	16,338		17,426
Deferred debt issuance costs	14,083		16,284
Intangible assets, net	7,539		7,901
Receivable from supply agreements	12,095		5,805
Other, net	14,934		11,072
Total other assets	$	89,191	$	81,535

11

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

(b) Accrued Liabilities and Other Non-Current Liabilities

	September 30, 2011		December 31, 2010
Accrued Liabilities:
Taxes other than income taxes, primarily excise taxes	$	32,943	$	23,584
Employee costs	10,804		11,571
Commodity contracts	39,441		5,898
Accrued finance charges	19,023		12,246
Environmental accrual	7,349		7,349
Valero earnout liability	—		6,562
Other	29,721		21,144
Total accrued liabilities	$	139,281	$	88,354
Other Non-Current Liabilities:
Pension and other postemployment benefit liabilities, net	$	33,481	$	33,157
Environmental accrual (Note 14)	59,387		61,657
Asset retirement obligations	11,314		10,932
Interest rate swap valuations	5,217		7,501
Consignment inventory	56,994		32,433
Commodity contracts	—		3,128
Other	13,321		12,168
Total other non-current liabilities	$	179,714	$	160,976

(c) Comprehensive Income (Loss)

The following table displays the computation of total comprehensive income (loss):

	For the Three Months Ended					For the Nine Months Ended
	September 30,					September 30,
	2011		2010			2011		2010
Income (loss) before non-controlling interest in income (loss) of subsidiaries	$	30,101	$	(16,751	)	$	57,737	$	(105,009	)
Other comprehensive gain, net of tax:
Unrealized gain on cash flow hedges, net of tax	597		3,401			1,484		7,976
Total other comprehensive income, net of tax	597		3,401			1,484		7,976
Comprehensive gain (loss)	30,698		(13,350		)	59,221		(97,033		)
Comprehensive income (loss) attributable to non-controlling interest	1,463		(956		)	2,300		(6,834		)
Comprehensive income (loss) attributable to common stockholders	$	29,235	$	(12,394	)	$	56,921	$	(90,199	)

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

	September 30, 2011			December 31, 2010
Unrealized losses on cash flow hedges, net of tax	$	(3,857	)	$	(5,341	)
Pension and post-employment benefits, net of tax	(16,576		)	(16,576		)
Accumulated other comprehensive loss, net of tax	$	(20,433	)	$	(21,917	)

(8) Postretirement Benefits

Alon has three defined benefit pension plans covering substantially all of its refining and unbranded marketing segment employees. 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 2011 to its pension plans has not

12

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

changed significantly from amounts previously disclosed in Alon’s consolidated financial statements for the year ended December 31, 2010. For the nine months ended September 30, 2011 and 2010, Alon contributed $4,410 and $5,000, 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, 2011 and 2010:

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	914		$	1,018		$	2,743		$	3,055
Interest cost	1,035			946			3,105			2,837
Expected return on plan assets	(932		)	(904		)	(2,798		)	(2,715		)
Amortization of net loss	447			385			1,343			1,157
Net periodic benefit cost	$	1,464		$	1,445		$	4,393		$	4,334

(9) Indebtedness

Debt consisted of the following:

	September 30, 2011			December 31, 2010
Term loan credit facility	$	426,375		$	429,750
Revolving credit facilities	310,172			185,120
Senior secured notes	208,804			207,378
Retail credit facilities	108,657			94,057
Total debt	1,054,008			916,305
Less current portion	(124,707		)	(11,512		)
Total long-term debt	$	929,301		$	904,793

Alon Brands Term Loans. In March 2011, Alon Brands issued $30,000 five-year unsecured notes (the "Alon Brands Term Loans") to a group of investors including certain shareholders of Alon Israel and their affiliates. The notes will mature in March 2016. The group of investors have the right to request that principal payments of the loan will be paid in four equal, consecutive annual payments, starting in March 2013. Otherwise, the principal amount will be paid at the maturity date in March 2016. During the third quarter of 2011, certain shareholders of Alon Israel assigned $6,000 of the Alon Brands Term Loans to Alon Israel.

Borrowings under the Alon Brands Term Loans bear interest at a rate of 7% per annum, payable on a semi-annual basis, provided that the interest rate will increase to 9% per annum solely with respect to the portion of the loan equal to the unexercised portion of the warrants described below.

The Alon Brands Term Loans contain certain restrictive covenants, including maintenance financial covenants.

In conjunction with the issuance of the Alon Brands Term Loans, Alon issued 3,092,783 warrants to purchase shares of Alon USA Energy, Inc. common stock at an initial exercise price per share of $9.70. The warrants are exercisable in whole or in part until March 2016, five years from the date of issuance. The allocated fair value of the warrants was $10,988 and was recorded as additional paid-in capital at the time of issuance.

At September 30, 2011, the Alon Brands Term Loans had an outstanding balance of $19,731 (net of unamortized discount of $10,269). Alon is utilizing the effective interest method to amortize the discount over the five-year life of the Alon Brands Term Loans and has amortized $362 and $719 to interest expense for the three and nine months ended September 30, 2011, respectively.

Paramount Petroleum 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.

13

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

Borrowings under the Paramount Credit Facility bear interest at the Eurodollar rate plus a margin based on excess availability. Based on the excess availability at September 30, 2011, the margin was 1.75%.

Borrowings of $113,172, which are included in current portion of long-term debt, and $63,120, which are included in long-term debt, were outstanding under the Paramount Credit Facility at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011 and December 31, 2010, outstanding letters of credit under the Paramount Credit Facility were $130,272 and $1,250, respectively.

Financial Covenants. Alon has certain credit facilities that contain restrictive covenants, including maintenance financial covenants. At September 30, 2011, Alon was in compliance with these covenants.

(10) 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.

(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.

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.

In May 2011, Alon granted awards of 180,000 restricted shares to certain executive officers at a grant date price of $13.53. These May 2011 restricted shares will vest as follows: 50% on May 10, 2012 and 50% on May 10, 2016, assuming continued service at vesting.

Compensation expense for the restricted stock grants amounted to $389 and $22 for the three months ended September 30, 2011 and 2010, respectively, and $665 and $53 for the nine months ended September 30, 2011 and 2010, 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, 2010:

			Weighted Average Grant Date Fair Values
Nonvested Shares	Shares		(per share)
Nonvested at January 1, 2010	10,226		$	14.67
Granted	10,416		7.20
Vested	(4,473	)	16.77
Forfeited	—		—
Nonvested at December 31, 2010	16,169		$	9.28
Granted	186,015		13.50
Vested	(7,278	)	10.31
Forfeited	—		—
Nonvested at September 30, 2011	194,906		$	13.26

As of September 30, 2011, there was $1,908 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 2.5 years. The fair value of shares vested in 2011 was $88.

Restricted Stock Units. In May 2011, Alon granted 500,000 restricted stock units to the CEO and President of Alon at a

14

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

grant date fair value of $11.47. Each restricted unit represents the right to receive one share of Alon common stock upon the vesting of the restricted stock unit. All 500,000 restricted stock units vest on March 1, 2015, assuming continued service at vesting. Compensation expense for the restricted stock units amounted to $374 and $623 for the three and nine months ended September 30, 2011, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.

Stock Appreciation Rights. Through December 31, 2010, Alon has granted awards of 580,915 SARs to certain officers and key employees of Alon of which 62% of these SARs have a grant price of $28.46 and the remaining SARs have grant prices ranging from $10.00 to $16.00.

In January 2011, Alon granted awards of 18,250 SARs to certain officers and key employees at a grant price equal to $16.00. The January 2011 SARs vest as follows: 50% on January 5, 2013, 25% on January 5, 2014, and 25% on January 5, 2015, 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 $31 and $97 for the three months ended September 30, 2011 and 2010, respectively, and $305 and $403 for the nine months ended September 30, 2011 and 2010, 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, 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. This plan was closed to new participants subsequent to August 1, 2000, the initial grant date. All remaining stock options outstanding were exercised during the three months ended March 31, 2011. Total compensation expense recognized under this plan was $(11) for the nine months ended September 30, 2010 and is included in selling, general and administrative expenses in the consolidated statements of operations.

During the three months ended September 30, 2011, an agreement was reached with one of the participants whereby the participant would exchange 2,019 shares of common stock of Alon Assets and 758 shares of Alon Operating for 377,710 shares of common stock of Alon USA Energy, Inc. One-third of the shares were exchanged in October 2011 and the remaining two-thirds will be exchanged equally in October 2012 and October 2013. Compensation expense of $542 associated with the difference in value between the participants ownership of Alon Assets and Alon Operating stock compared to Alon USA Energy, Inc. stock was recognized for the three and nine months ended September 30, 2011 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, 2011, and for the year ended December 31, 2010:

	Alon Assets				Alon Operating
	Number of Options Outstanding		Weighted Average Exercise Price		Number of Options Outstanding		Weighted Average Exercise Price
Outstanding at January 1, 2010	2,793		$	100.00	1,049		$	100.00
Granted	—		—		—		—
Exercised	(2,187	)	100.00		(822	)	100.00
Forfeited and expired	—		—		—		—
Outstanding at December 31, 2010	606		$	100.00	227		$	100.00
Granted	—		—		—		—
Exercised	(606	)	100.00		(227	)	100.00
Forfeited and expired	—		—		—		—
Outstanding at September 30, 2011	—		$	—	—		$	—

The intrinsic value of total options exercised in 2011 was $471.

15

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

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

Common Stock Dividends. On September 15, 2011, 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 September 1, 2011.

Preferred Stock Dividends. On September 30, 2011, shares of Alon common stock were issued for payment of the quarterly 8.5% preferred stock dividend to preferred stockholders of record at the close of business on September 20, 2011.

Warrants. In conjunction with the issuance of the Alon Brands Term Loans, Alon issued 3,092,783 warrants to purchase shares of Alon USA Energy, Inc. common stock at an initial exercise price per share of $9.70. The warrants are exercisable in whole or in part until March 2016, five years from the date of issuance.

Standby Equity Distribution Agreement. In January 2011, Alon entered into a Standby Equity Distribution Agreement (the "SEDA”) with YA Global Master SPV Ltd. ("YA Global”) to purchase up to $25,000 of Alon USA Energy, Inc. common stock ("Common Stock"). At any time during the effective period of the agreement, Alon may require YA Global to purchase shares of Common Stock by delivering an advance notice (as provided for in the SEDA) to YA Global. The purchase price of the Common Stock is 98.5% of the market price during the five consecutive trading days after the receipt of the advance notice is provided to YA Global. In no event shall the number of shares of Common Stock owned by YA Global and its affiliates exceed 4.99% of the outstanding Common Stock at that time. The SEDA automatically terminates in January 2013. During the first nine months of 2011, Alon sold Common Stock with total proceeds of $11,900.

(12) Earnings (Loss) Per Share

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

The calculation of earnings (loss) per share, basic and diluted, for the three and nine months ended September 30, 2011 and 2010, is as follows:

	For the Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2011		2010			2011		2010
Net income (loss) available to common stockholders	$	28,621	$	(15,584	)	$	55,420	$	(97,785	)
Average number of shares of common stock outstanding	55,755		54,181			55,290		54,177
Dilutive SARs, RSUs, convertible preferred stock and warrants	5,935		—			5,941		—
Average number of shares of common stock outstanding assuming dilution	61,690		54,181			61,231		54,177
Income (loss) per share – basic	$	0.51	$	(0.29	)	$	1.00	$	(1.80	)
Income (loss) per share – diluted	$	0.46	$	(0.29	)	$	0.91	$	(1.80	)

(13) Related-Party Transactions

Alon Brands Term Loans    

In March 2011, Alon Brands issued $12,000 five-year unsecured notes to certain shareholders of Alon Israel and their affiliates as part of the Alon Brands Term Loans. The Alon Brands Term Loans will mature in March 2016. The shareholders have the right to request that principal payments of the loan will be paid in four equal, consecutive annual payments, starting in March 2013. Otherwise, the principal amount will be paid at the maturity date in March 2016. During the third quarter of 2011, these shareholders assigned the Alon Brands Term Loans to Alon Israel.

Borrowings under the Alon Brands Term Loans bear interest at a rate of 7% per annum, payable on a semi-annual basis, provided that the interest rate will increase to 9% per annum solely with respect to the portion of the loan equal to the unexercised portion of the warrants described below.

In conjunction with the issuance of the Alon Brands Term Loans, Alon issued to certain shareholders of Alon Israel 1,237,113 warrants to purchase shares of Alon USA Energy, Inc. common stock at an initial exercise price per share of $9.70.

16

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

The warrants are exercisable in whole or in part until March 2016, five years from the date of issuance.

(14) 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 typically short-term in nature or provide terms for cancellation.

Supply and Offtake Agreement with J. Aron & Company

In February 2011, Alon entered into a Supply and Offtake Agreement (the “Supply and Offtake Agreement”), with J. Aron & Company (“J. Aron”). Pursuant to the Supply and Offtake Agreement (i) J. Aron agreed to sell to Alon, and Alon agreed to buy from J. Aron, at market prices, crude oil for processing at the Big Spring refinery and (ii) Alon agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced at the Big Spring refinery.

In connection with the execution of the Supply and Offtake Agreement, Alon also entered into agreements that provided for the sale, at market prices, of Alon's 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 Big Spring 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 in May 2016. J. Aron may elect to terminate the agreement prior to the initial term beginning in May 2013, provided Alon receives notice of termination at least six months prior to that date. Following expiration or termination of the Supply and Offtake Agreement, Alon is obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the Big Spring refinery.

(b) Contingencies

Alon is involved in various other claims and legal actions arising in the ordinary course of business. In August 2011, Alon received from the Federal Trade Commission a civil investigative demand to provide documents as part of an industry-wide investigation related to petroleum industry practices and pricing. Alon believes the ultimate disposition of this and all other 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 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 $66,736 ($7,349 current payable and $59,387 non-current liability) at September 30, 2011, and $69,006 ($7,349 current payable and $61,657 non-current liability) at December 31, 2010.

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. Alon has recorded a current receivable of $2,675 and a non-current receivable of $13,840, and a current receivable of $2,675 and a non-current receivable of $14,386 at September 30, 2011 and December 31, 2010, respectively.

Paramount Petroleum Corporation has indemnification agreements with a prior owner for part of the remediation

17

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

expenses at its refineries and offsite tank farm and, as a result, has recorded a current receivable of $1,323 and a non-current receivable of $2,498, and a current receivable of $1,323 and a non-current receivable of $3,039 at September 30, 2011 and December 31, 2010, respectively.

(15) Subsequent Event

Dividend Declared

On November 2, 2011, Alon declared its regular quarterly cash dividend of $0.04 per share on Alon’s common stock, payable on December 15, 2011, to stockholders of record at the close of business on December 1, 2011.

Crude Oil Supply Arrangements

In October 2011, Alon entered into arrangements that will allow the Krotz Springs refinery to process on average 20,000 to 25,000 barrels per day of West Texas Intermediate priced crude oil during 2012.

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

The following discussion of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2010. 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 spread between West Texas Intermediate ("WTI") crude oil and Light Louisiana Sweet and Heavy Louisiana Sweet crude oils, as well as the spread between California crudes such as Buena Vista and WTI;

• 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 such as flooding, casualty losses and other matters beyond our control;

• the global financial crisis’ impact on our business and financial condition; and

• the other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2010 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.

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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. In Bakersfield, we are converting intermediate products into finished products and are not refining crude oil.

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 convenience stores, branded 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 from our California refineries to wholesale distributors, other refiners and third parties primarily on the West Coast. We started up the hydrocracker unit in Bakersfield in late June 2011 and began processing vacuum gas oil produced at our other California refineries.

The Krotz Springs refinery's processing units are structured to yield 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 Big Spring 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 303 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 2011, approximately 90% 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 58% of the gasoline and 21% 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 240 licensed locations that are not under fuel supply agreements with us.

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Third Quarter Operational and Financial Highlights

Operating income for the third quarter of 2011 was $82.0 million, compared to an operating loss of $(35.4) in the same period last year. Our operational and financial highlights for the third quarter of 2011 include the following:

• Combined refinery throughput for the third quarter of 2011 averaged 162,214 bpd, consisting of 56,828 bpd at the Big Spring refinery, 39,056 bpd at the California refineries and 66,330 bpd at the Krotz Springs refinery, compared to a combined average throughput of 138,253 bpd for third quarter of 2010, 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.

• Operating margin at the Big Spring refinery was $23.05 per barrel for the third quarter of 2011, compared to $5.04 per barrel for the same period in 2010. This increase is due to higher Gulf Coast 3/2/1 crack spreads and improved operating efficiencies at higher throughputs.

• Operating margin at the California refineries was $3.64 per barrel for the third quarter of 2011, compared to $0.12 per barrel for the same period in 2010. This increase reflects higher margin received on greater yield of light products due to the integration of the Bakersfield hydrocracker and a slight increase in the West Coast 3/1/1/1 crack spread.

• Operating margin at the Krotz Springs refinery was $7.77 per barrel for the third quarter of 2011, compared to $0.97 per barrel for the same period in 2010. This increase is due to higher Gulf Coast 2/1/1 crack spreads.

• The average sweet/sour spread for the third quarter of 2011 was $0.82 per barrel compared to $2.16 per barrel for the same period in 2010. The average LLS to WTI spread for the third quarter of 2011 was $18.87 per barrel compared to $3.11 per barrel for the same period in 2010. The average WTI to Buena Vista spread for the third quarter of 2011 was $(17.52) per barrel compared to $0.87 per barrel for the same period in 2010.

• The average Gulf Coast 3/2/1 crack spread was $31.28 per barrel for the third quarter of 2011 compared to $7.76 per barrel for the third quarter of 2010. The average West Coast 3/1/1/1 crack spread for the third quarter of 2011 was $11.22 per barrel compared to $9.09 per barrel for the third quarter of 2010. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the third quarter of 2011 was $12.44 per barrel compared to $3.91 per barrel for the third quarter of 2010.

• Asphalt margins in the third quarter of 2011 were $25.68 per ton compared to $77.59 per ton in the third quarter of 2010. This decrease was due primarily to higher crude oil costs without having the ability to increase asphalt sales prices accordingly. The average blended asphalt sales price increased 12.8% from $478.65 per ton in the third quarter of 2010 to $540.07 per ton in the third quarter of 2011 and the average non-blended asphalt sales price increased 10.0% from $348.89 per ton in the third quarter of 2010 to $383.87 per ton in the third quarter of 2011. The average price of Buena Vista crude increased 42.7% from $75.18 per barrel in the third quarter of 2010 to $107.27 per barrel in the third quarter of 2011.

• Retail fuel sales volume increased by 10.9% from 36.8 million gallons in the third quarter of 2010 to 40.8 million gallons in the third quarter of 2011. Our branded fuel sales volume increased by 12.4% from 84.7 million gallons in the third quarter of 2010 to 95.2 million gallons in the third quarter of 2011.

• On September 15, 2011, we paid a regular quarterly cash dividend of $0.04 per share on our common stock to stockholders of record at the close of business on September 1, 2011.

• On September 30, 2011, shares of our common stock were issued for payment of the quarterly 8.5% preferred stock dividend to preferred stockholders of record at the close of business on September 20, 2011.

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 3/2/1 crack spreads. A 3/2/1

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crack spread 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 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 3/1/1/1 crack spread. A 3/1/1/1 crack spread is calculated assuming that three barrels of a benchmark crude oil are converted into one barrel of gasoline, one barrel of diesel and one barrel of fuel oil. This is calculated 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 Buena Vista crude oil.

We compare our Krotz Springs refinery’s per barrel margin 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 Light Louisiana Sweet, or LLS, 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 Buena Vista crude oil. A widening of this 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. This input was primarily comprised of Heavy Louisiana Sweet, or HLS crude oil, and LLS crude oil. We measure the cost of refining these lighter sweet crude oils by calculating the difference between the average value of LLS crude oil (which also approximates the value of HLS crude oil) to the average 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. 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,

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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 nine months ended September 30, 2011 and 2010, have been influenced by the following factors which are fundamental to understanding comparisons of our period-to-period financial performance.

Throughput at the Big Spring refinery was higher over the nine months ended September 30, 2011, after we implemented new operating procedures. The California refineries were shut down for most of the first quarter of 2011 to redeploy resources for the integration of the Bakersfield hydrocracker unit acquired in June 2010. Crude throughput was reduced at the Krotz Springs refinery during the second quarter of 2011 due to the flooding in Louisiana and its impact on crude oil supply to the refinery. Additionally, the Krotz Springs refinery was shut down during November 2009 for a scheduled turnaround and remained down until its restart in June 2010.

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.

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ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED

Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for Alon and our three operating segments for the three and nine months ended September 30, 2011 and 2010. 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, 2010 is unaudited.

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
Net sales (1)	$	2,056,653		$	1,248,569		$	5,303,388		$	2,668,243
Operating costs and expenses:
Cost of sales	1,827,098			1,153,743			4,717,673			2,443,533
Direct operating expenses	83,338			68,448			202,476			192,816
Selling, general and administrative expenses (2)	34,680			35,012			107,595			96,001
Depreciation and amortization (3)	29,812			26,781			80,046			78,471
Total operating costs and expenses	1,974,928			1,283,984			5,107,790			2,810,821
Gain on disposition of assets	229			—			161			474
Operating income (loss)	81,954			(35,415		)	195,759			(142,104		)
Interest expense (4)	(22,582		)	(24,091		)	(63,780		)	(72,411		)
Equity earnings of investees	2,005			3,864			3,775			4,970
Gain on bargain purchase (5)	—			17,480			—			17,480
Other income (loss), net (6)	(14,272		)	(494		)	(51,065		)	13,345
Income (loss) before income tax expense (benefit) and non-controlling interest in income (loss) of subsidiaries	47,105			(38,656		)	84,689			(178,720		)
Income tax expense (benefit)	17,004			(21,905		)	26,952			(73,711		)
Income (loss) before non-controlling interest in income (loss) of subsidiaries	30,101			(16,751		)	57,737			(105,009		)
Non-controlling interest in income (loss) of subsidiaries	1,480			(1,167		)	2,317			(7,224		)
Net income (loss) available to common stockholders	$	28,621		$	(15,584	)	$	55,420		$	(97,785	)
Income (loss) per share, basic	$	0.51		$	(0.29	)	$	1.00		$	(1.80	)
Weighted average shares outstanding, basic (in thousands)	55,755			54,181			55,290			54,177
Income (loss) per share, diluted	$	0.46		$	(0.29	)	$	0.91		$	(1.80	)
Weighted average shares outstanding, diluted (in thousands)	61,690			54,181			61,231			54,177
Cash dividends per share	$	0.04		$	0.04		$	0.12		$	0.12
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	109,478		$	24,285		$	58,362		$	(37,275	)
Investing activities	(28,055		)	(11,162		)	(104,130		)	(15,218		)
Financing activities	(22,964		)	18,799			149,682			51,691
OTHER DATA:
Adjusted EBITDA (7)	99,270			(5,264		)	228,354			(45,792		)
Capital expenditures (8)	23,162			7,838			91,120			20,526
Capital expenditures for turnaround and chemical catalyst	2,733			1,137			6,995			12,668

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	September 30, 2011	December 31, 2010
BALANCE SHEET DATA (end of period):
Cash and cash equivalents	175,601	71,687
Working capital	99,558	990
Total assets	2,419,897	2,088,521
Total debt	1,054,008	916,305
Total equity	417,916	341,767

(1) Includes excise taxes on sales by the retail and branded marketing segment of $15,476 and $14,204 for the three months ended September 30, 2011 and 2010, respectively, and $44,887 and $40,521 for the nine months ended September 30, 2011 and 2010, respectively.

(2) Includes corporate headquarters selling, general and administrative expenses of $188 and $188 for the three months ended September 30, 2011 and 2010, respectively, and $564 and $564 for the nine months ended September 30, 2011 and 2010, respectively, which are not allocated to our three operating segments.

(3) Includes corporate depreciation and amortization of $404 and $397 for the three months ended September 30, 2011 and 2010, respectively, and $1,211 and $964 for the nine months ended September 30, 2011 and 2010, 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.

(5) In connection with the Bakersfield refinery acquisition in 2010, 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 three and nine months ended September 30, 2011 is substantially the loss on heating oil crack spread contracts. 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 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.

25

The following table reconciles net income (loss) available to common stockholders to Adjusted EBITDA for the three and nine months ended September 30, 2011 and 2010, respectively:

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(dollars in thousands)
Net income (loss) available to common stockholders	$	28,621		$	(15,584	)	$	55,420		$	(97,785	)
Non-controlling interest in income (loss) of subsidiaries	1,480			(1,167		)	2,317			(7,224		)
Income tax expense (benefit)	17,004			(21,905		)	26,952			(73,711		)
Interest expense	22,582			24,091			63,780			72,411
Depreciation and amortization	29,812			26,781			80,046			78,471
Gain on bargain purchase	—			(17,480		)	—			(17,480		)
Gain on disposition of assets	(229		)	—			(161		)	(474		)
Adjusted EBITDA	$	99,270		$	(5,264	)	$	228,354		$	(45,792	)

Adjusted EBITDA does not exclude loss on heating oil crack spread contracts of $14,269 and $51,093 for the three and nine months ended September 30, 2011, respectively.

(8) Includes corporate capital expenditures of $329 and $1,344 for the three months ended September 30, 2011 and 2010, respectively, and $1,272 and $2,152 for the nine months ended September 30, 2011 and 2010, respectively, which are not allocated to our three operating segments.

26

REFINING AND UNBRANDED MARKETING SEGMENT
	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(dollars in thousands, except per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	1,862,181		$	1,056,478		$	4,797,125		$	2,230,849
Operating costs and expenses:
Cost of sales	1,681,163			1,022,950			4,336,655			2,138,284
Direct operating expenses	72,271			57,711			170,214			159,556
Selling, general and administrative expenses	6,189			7,103			24,946			17,365
Depreciation and amortization	25,179			21,315			64,799			62,150
Total operating costs and expenses	1,784,802			1,109,079			4,596,614			2,377,355
Gain on disposition of assets	1			—			12			—
Operating income (loss)	$	77,380		$	(52,601	)	$	200,523		$	(146,506	)
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin – Big Spring (2)	$	23.05		$	5.04		$	20.67		$	6.39
Refinery operating margin – CA Refineries (2)	3.64			0.12			(0.16		)	0.86
Refinery operating margin – Krotz Springs (2)	7.77			0.97			5.61			0.35
Refinery direct operating expense – Big Spring (3)	4.68			4.66			4.40			5.58
Refinery direct operating expense – CA Refineries (3)	7.20			6.86			6.13			7.66
Refinery direct operating expense – Krotz Springs (3)	3.61			3.39			3.42			5.82
Capital expenditures	14,931			4,707			76,119			15,234
Capital expenditures for turnaround and chemical catalyst	2,733			1,137			6,995			12,668
PRICING STATISTICS:
WTI crude oil (per barrel)	$	89.75		$	76.05		$	95.42		$	77.50
WTS crude oil (per barrel)	88.93			73.89			92.95			75.55
Buena Vista crude oil (per barrel)	107.27			75.18			106.62			75.89
LLS crude oil (per barrel)	112.94			79.18			110.50			80.37
Crack spreads (3/2/1) (per barrel):
Gulf Coast	$	31.28		$	7.76		$	24.53		$	8.20
Crack spreads (3/1/1/1) (per barrel):
West Coast	11.22			9.09			11.09			8.60
Crack spreads (2/1/1) (per barrel):
Gulf Coast high sulfur diesel	$	12.44		$	3.91		$	9.87		$	4.59
Crude oil differentials (per barrel):
WTI less WTS	$	0.82		$	2.16		$	2.47		$	1.95
LLS less WTI	18.87			3.11			14.55			2.81
WTI less Buena Vista	(17.52		)	0.87			(11.20		)	1.61
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	2.82		$	1.95		$	2.80		$	2.01
Gulf Coast ultra-low sulfur diesel	3.01			2.09			2.97			2.09
Gulf Coast high sulfur diesel	2.95			2.01			2.91			2.03
West Coast LA CARBOB (unleaded gasoline)	2.89			2.18			2.92			2.18
West Coast LA ultra-low sulfur diesel	3.03			2.16			3.05			2.14
Natural gas (per MMBTU)	4.05			4.23			4.21			4.52

27

THROUGHPUT AND PRODUCTION DATA: BIG SPRING REFINERY	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
Sour crude	42,769	75.2		42,680	80.4		48,882	80.2		36,836	79.7
Sweet crude	10,904	19.2		7,938	15.0		9,845	16.2		7,021	15.1
Blendstocks	3,155	5.6		2,442	4.6		2,162	3.6		2,387	5.2
Total refinery throughput (4)	56,828	100.0		53,060	100.0		60,889	100.0		46,244	100.0
Refinery production:
Gasoline	26,846	47.3		25,937	49.2		28,969	47.8		23,096	50.5
Diesel/jet	18,570	32.6		17,772	33.7		19,704	32.5		14,738	32.2
Asphalt	4,619	8.1		3,193	6.1		4,505	7.4		2,636	5.8
Petrochemicals	3,422	6.0		3,382	6.4		3,664	6.0		2,664	5.8
Other	3,423	6.0		2,419	4.6		3,837	6.3		2,620	5.7
Total refinery production (5)	56,880	100.0		52,703	100.0		60,679	100.0		45,754	100.0
Refinery utilization (6)		89.9	%		72.3	%		88.3	%		64.6	%

THROUGHPUT AND PRODUCTION DATA: CALIFORNIA REFINERIES	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
Medium sour crude	9,363	24.0		4,635	22.0		4,632	21.7		4,065	20.7
Heavy crude	23,928	61.2		15,886	75.6		14,707	68.9		15,082	77.0
Blendstocks	5,765	14.8		514	2.4		2,018	9.4		443	2.3
Total refinery throughput (4)	39,056	100.0		21,035	100.0		21,357	100.0		19,590	100.0
Refinery production:
Gasoline	10,178	26.1		3,401	16.6		4,433	20.9		2,888	15.2
Diesel/jet	14,863	38.3		4,758	23.3		6,933	32.9		4,067	21.4
Asphalt	10,918	28.0		6,974	34.1		6,456	30.5		6,554	34.3
Light unfinished	525	1.3		—	—		177	0.8		—	—
Heavy unfinished	960	2.5		4,831	23.6		2,462	11.6		5,099	26.8
Other	1,498	3.8		498	2.4		708	3.3		439	2.3
Total refinery production (5)	38,942	100.0		20,462	100.0		21,169	100.0		19,047	100.0
Refinery utilization (6)		45.9	%		28.3	%		26.7	%		26.4	%

THROUGHPUT AND PRODUCTION DATA: KROTZ SPRINGS REFINERY	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
Light sweet crude	64,420	97.1		38,597	60.1		48,895	78.5		16,460	56.9
Heavy sweet crude	1,845	2.8		23,854	37.2		12,528	20.1		11,603	40.1
Blendstocks	65	0.1		1,707	2.7		846	1.4		878	3.0
Total refinery throughput (4)	66,330	100.0		64,158	100.0		62,269	100.0		28,941	100.0
Refinery production:
Gasoline	27,396	41.1		26,442	40.9		25,905	41.5		11,720	40.3
Diesel/jet	30,491	45.7		31,383	48.5		28,757	46.0		13,609	46.9
Heavy Oils	2,828	4.2		1,487	2.3		2,577	4.1		1,437	4.9
Other	6,017	9.0		5,368	8.3		5,245	8.4		2,304	7.9
Total refinery production (5)	66,732	100.0		64,680	100.0		62,484	100.0		29,070	100.0
Refinery utilization (6)		79.7	%		75.2	%		80.2	%		33.8	%

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(1) Net sales include intersegment sales to our asphalt and retail and branded marketing segments at prices which approximate wholesale market prices. 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 nine months ended September 30, 2011, excludes a benefit from inventory reductions of $22,460. The refinery operating margin for the three and nine months ended September 30, 2010, excludes a benefit of $2,990 and $4,515, respectively, to cost of sales for inventory adjustments related to the Bakersfield refinery acquisition.

(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 $3,356 for the nine months ended September 30, 2011 and $2,122 for the three and nine months ended September 30, 2010, respectively, have been excluded from the per barrel measurement calculation.

(4) Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process. The throughput data of the California refineries for the nine months ended September 30, 2011, reflects substantially six months of operations beginning in late March 2011 due to the integration of the Bakersfield hydrocracker unit. The throughput data of the Krotz Springs refinery for the nine months ended September 30, 2011, reflects approximately a one month shutdown due to flooding in Louisiana and the impact on crude supply to the refinery. The throughput data of the Krotz Springs refinery for the nine months ended September 30, 2010, reflects substantially four months of operations beginning in June 2010 due to the restart after major turnaround activity.

(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.

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ASPHALT SEGMENT
	For the Three Months Ended					For the Nine Months Ended
	September 30,					September 30,
	2011			2010		2011			2010
	(dollars in thousands, except per ton data)
STATEMENTS OF OPERATIONS DATA:
Net sales	$	201,081		$	144,610	$	435,135		$	316,715
Operating costs and expenses:
Cost of sales (1)	191,296			120,791		421,480			282,500
Direct operating expenses	11,067			10,737		32,262			33,260
Selling, general and administrative expenses	1,310			2,404		3,833			4,561
Depreciation and amortization	1,522			1,716		4,999			5,148
Total operating costs and expenses	205,195			135,648		462,574			325,469
Operating income (loss)	$	(4,114	)	$	8,962	$	(27,439	)	$	(8,754	)
KEY OPERATING STATISTICS:
Blended asphalt sales volume (tons in thousands) (2)	351			289		727			625
Non-blended asphalt sales volume (tons in thousands) (3)	30			18		127			52
Blended asphalt sales price per ton (2)	$	540.07		$	478.65	$	539.52		$	477.68
Non-blended asphalt sales price per ton (3)	383.87			348.89		337.82			349.29
Asphalt margin per ton (4)	25.68			77.59		15.99			50.54
Capital expenditures	$	125		$	465	$	1,458		$	991

(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.

30

RETAIL AND BRANDED MARKETING SEGMENT
	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(dollars in thousands, except per gallon data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	383,636		$	273,481		$	1,083,455		$	753,464
Operating costs and expenses:
Cost of sales (2)	344,884			236,002			971,865			655,534
Selling, general and administrative expenses	26,993			25,317			78,252			73,511
Depreciation and amortization	2,707			3,353			9,037			10,209
Total operating costs and expenses	374,584			264,672			1,059,154			739,254
Gain on disposition of assets	228			—			149			474
Operating income	$	9,280		$	8,809		$	24,450		$	14,684
KEY OPERATING STATISTICS:
Branded fuel sales (thousands of gallons) (3)	95,160			84,711			272,101			230,031
Branded fuel margin (cents per gallon) (3)	5.5			8.9			5.0			6.7
Number of stores (end of period)	303			306			303			306
Retail fuel sales (thousands of gallons)	40,769			36,759			115,931			104,881
Retail fuel sales (thousands of gallons per site per month)	45			40			43			38
Retail fuel margin (cents per gallon) (4)	15.9			13.4			16.7			12.3
Retail fuel sales price (dollars per gallon) (5)	$	3.52		$	2.67		$	3.47		$	2.68
Merchandise sales	$	79,366		$	74,932		$	225,812		$	211,660
Merchandise sales (per site per month)	$	87		$	82		$	83		$	77
Merchandise margin (6)	32.4		%	32.2		%	33.0		%	31.7		%
Capital expenditures	$	7,777		$	1,322		$	12,271		$	2,149

(1) Includes excise taxes on sales by the retail and branded marketing segment of $15,476 and $14,204 for the three months ended September 30, 2011 and 2010, respectively, and $44,887 and $40,521 for the nine months ended September 30, 2011 and 2010, respectively. Net sales also includes net royalty and related net credit card fees of $1,265 and $873 for the three months ended September 30, 2011 and 2010, respectively, and $4,177 and $2,692 for the nine months ended September 30, 2011 and 2010, respectively.

(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) Branded fuel sales represent 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 branded fuel 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.

31

Three Months Ended September 30, 2011 Compared to the Three Months Ended September 30, 2010

Net Sales

Consolidated. Net sales for the three months ended September 30, 2011, were $2,056.7 million, compared to $1,248.6 million for the three months ended September 30, 2010, an increase of $808.1 million. This increase was primarily due to higher refinery throughput volumes in our refining and unbranded marketing segment, increased sales volumes in our retail and branded marketing segment and higher refined product prices.

Refining and Unbranded Marketing Segment. Net sales for our refining and unbranded marketing segment were $1,862.2 million for the three months ended September 30, 2011, compared to $1,056.5 million for the three months ended September 30, 2010, an increase of $805.7 million, or 76.3%. The increase was due to higher refined product prices and higher refinery throughput in the three months ended September 30, 2011 compared to the same period last year.

Combined refinery throughput for the three months ended September 30, 2011, averaged 162,214 bpd, consisting of 56,828 bpd at the Big Spring refinery, 39,056 bpd at the California refineries and 66,330 bpd at the Krotz Springs refinery, compared to a combined average throughput of 138,253 bpd for the three months ended September 30, 2010, 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.

The increase in refined product prices that our refineries experienced resembled the price increases experienced in each refinery’s respective markets. The average per gallon price of Gulf Coast gasoline for the three months ended September 30, 2011, increased $0.87, or 44.6%, to $2.82, compared to $1.95 for the three months ended September 30, 2010. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the three months ended September 30, 2011, increased $0.92, or 44.0%, to $3.01, compared to $2.09 for the three months ended September 30, 2010. The average per gallon price for Gulf Coast high sulfur diesel for the three months ended September 30, 2011, increased $0.94, or 46.8%, to $2.95, compared to $2.01 for the three months ended September 30, 2010. The average per gallon price of West Coast LA CARBOB gasoline for the three months ended September 30, 2011, increased $0.71, or 32.6%, to $2.89, compared to $2.18 for the three months ended September 30, 2010. The average per gallon price of West Coast LA ultra-low sulfur diesel for the three months ended September 30, 2011, increased $0.87, or 40.3%, to $3.03, compared to $2.16 for the three months ended September 30, 2010.

Asphalt Segment. Net sales for our asphalt segment were $201.1 million for the three months ended September 30, 2011, compared to $144.6 million for the three months ended September 30, 2010, an increase of $56.5 million or 39.1%. The increase was due primarily to an increase in asphalt sales volumes and higher asphalt sales prices for the three months ended September 30, 2011. The asphalt sales volume increased 24.1% from 307 thousand tons for the three months ended September 30, 2010, to 381 thousand tons for the three months ended September 30, 2011. The average blended asphalt sales price increased 12.8% from $478.65 per ton for the three months ended September 30, 2010, to $540.07 per ton for the three months ended September 30, 2011, and the average non-blended asphalt sales price increased 10.0% from $348.89 per ton for the three months ended September 30, 2010, to $383.87 per ton for the three months ended September 30, 2011.

Retail and Branded Marketing Segment. Net sales for our retail and branded marketing segment were $383.6 million for the three months ended September 30, 2011, compared to $273.5 million for the three months ended September 30, 2010, an increase of $110.1 million or 40.3%. This increase was primarily attributable to increases in motor fuel sales volumes and prices and merchandise sales.

Cost of Sales

Consolidated. Cost of sales were $1,827.1 million for the three months ended September 30, 2011, compared to $1,153.7 million for the three months ended September 30, 2010, an increase of $673.4 million. This increase was primarily due to higher refinery throughput volumes in our refining and unbranded marketing segment, increased sales volumes in our retail and branded marketing segment and higher crude oil prices.

Refining and Unbranded Marketing Segment. Cost of sales for our refining and unbranded marketing segment were $1,681.2 million for the three months ended September 30, 2011, compared to $1,023.0 million for the three months ended September 30, 2010, an increase of $658.2 million. This increase was primarily due to increased refinery throughput as well as an increase in the cost of crude oil used by our refineries. The average price of WTI increased 18.0% from $76.05 per barrel for the three months ended September 30, 2010, to $89.75 per barrel for the three months ended September 30, 2011. The average price of Buena Vista crude increased 42.7% from $75.18 per barrel for the three months ended September 30, 2010, to $107.27 per barrel for the three months ended September 30, 2011. The average price of LLS crude increased 42.6% from $79.18 per barrel for the three months ended September 30, 2010, to $112.94 per barrel for the three months ended September 30, 2011.

Asphalt Segment. Cost of sales for our asphalt segment were $191.3 million for the three months ended September 30, 2011, compared to $120.8 million for the three months ended September 30, 2010, an increase of $70.5 million or 58.4%. The

32

increase was due primarily to higher asphalt sales volumes and higher crude oil costs for the three months ended September 30, 2011 compared to the three months ended September 30, 2010.

Retail and Branded Marketing Segment. Cost of sales for our retail and branded marketing segment were $344.9 million for the three months ended September 30, 2011, compared to $236.0 million for the three months ended September 30, 2010, an increase of $108.9 million or 46.1%. This increase was primarily attributable to increases in motor fuel sales volumes and prices and merchandise costs.

Direct Operating Expenses

Consolidated. Direct operating expenses were $83.3 million for the three months ended September 30, 2011, compared to $68.4 million for the three months ended September 30, 2010, an increase of $14.9 million or 21.8%.

Refining and Unbranded Marketing Segment. Direct operating expenses for our refining and unbranded marketing segment for the three months ended September 30, 2011, were $72.3 million, compared to $57.7 million for the three months ended September 30, 2010, an increase of $14.6 million or 25.3%. This increase is due primarily to expenses associated with the startup of operations at our Bakersfield location which began during the three months ended September 30, 2011.

Asphalt Segment. Direct operating expenses for our asphalt segment for the three months ended September 30, 2011, were $11.1 million, compared to $10.7 million for the three months ended September 30, 2010, an increase of $0.4 million or 3.7%.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for the three months ended September 30, 2011, were $34.7 million, compared to $35.0 million for the three months ended September 30, 2010, a decrease of $(0.3) million or (0.9)%.

Refining and Unbranded Marketing Segment. SG&A expenses for our refining and unbranded marketing segment for the three months ended September 30, 2011, were $6.2 million, compared to $7.1 million for the three months ended September 30, 2010, a decrease of $(0.9) million or (12.7)%. The decrease was primarily due to lower employee related costs for the three months ended September 30, 2011.

Asphalt Segment. SG&A expenses for our asphalt segment for the three months ended September 30, 2011, were $1.3 million, compared to $2.4 million for the three months ended September 30, 2010, a decrease of $(1.1) million or (45.8)%. This decrease was due to lower employee related costs for the three months ended September 30, 2011.

Retail and Branded Marketing Segment. SG&A expenses for our retail and branded marketing segment for the three months ended September 30, 2011 were $27.0 million, compared to $25.3 million for the three months ended September 30, 2010, an increase of $1.7 million or 6.7%. The increase was primarily attributable to higher advertising and marketing costs for the three months ended September 30, 2011.

Depreciation and Amortization

Depreciation and amortization for the three months ended September 30, 2011, was $29.8 million, compared to $26.8 million for the three months ended September 30, 2010, an increase of $3.0 million, or 11.2%, due primarily to capital expenditures for the acquisition and integration of the Bakersfield refining assets which began operations during the three months ended September 30, 2011.

Operating Income (Loss)

Consolidated. Operating income (loss) for the three months ended September 30, 2011, was $82.0 million, compared to$(35.4) million for the three months ended September 30, 2010, an increase of $117.4 million. This increase was primarily due to higher refinery margins and throughput, higher retail fuel sales volumes and margins and increased merchandise sales and margins.

Refining and Unbranded Marketing Segment. Operating income (loss) for our refining and unbranded marketing segment was $77.4 million for the three months ended September 30, 2011, compared to $(52.6) million for the three months ended September 30, 2010, an increase of $130.0 million. This increase was primarily due to higher refinery operating margins and increased refinery throughput.

Refinery operating margin at the Big Spring refinery was $23.05 per barrel for the three months ended September 30, 2011, compared to $5.04 per barrel for the three months ended September 30, 2010. The increase is due to higher Gulf Coast 3/2/1 crack spreads and improved operating efficiencies at higher throughputs. The average Gulf Coast 3/2/1 crack spread increased to $31.28 per barrel for the three months ended September 30, 2011, compared to $7.76 per barrel for the three months ended September 30, 2010. Refinery operating margin at the California refineries was $3.64 per barrel for the three

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months ended September 30, 2011, compared to $0.12 per barrel for the three months ended September 30, 2010. This increase reflects higher margin received on greater yield of light products due to the integration of the Bakersfield hydrocracker and a slight increase in the West Coast 3/1/1/1 crack spread. The average West Coast 3/1/1/1 crack spread for the three months ended September 30, 2011 was $11.22 per barrel compared to $9.09 per barrel for the three months ended September 30, 2010. The Krotz Springs refinery operating margin for the three months ended September 30, 2011, was $7.77 per barrel compared to $0.97 per barrel for the three months ended September 30, 2010. The increase is due to higher Gulf Coast 2/1/1 crack spreads. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the three months ended September 30, 2011 was $12.44 per barrel compared to $3.91 per barrel for the three months ended September 30, 2010.

The refining margin at our Big Spring refinery was affected by decreases in the sweet/sour differential. The sweet/sour differential decreased (62.0)% to $0.82 per barrel for the three months ended September 30, 2011, compared to $2.16 per barrel for the three months ended September 30, 2010. The refining margins at our California refineries were negatively affected by a widening of the WTI to Buena Vista spread. The WTI to Buena Vista spread increased $18.39 per barrel to $(17.52) for the three months ended September 30, 2011, compared to $0.87 per barrel for the three months ended September 30, 2010. The refining margins at our Krotz Springs refinery were affected by a widening of the LLS to WTI spread. The LLS to WTI spread increased $15.76 per barrel to $18.87 per barrel for the three months ended September 30, 2011, compared to $3.11 for the three months ended September 30, 2010.

Asphalt Segment.    Operating income (loss) for our asphalt segment was $(4.1) million for the three months ended September 30, 2011, compared to $9.0 million for the three months ended September 30, 2010, a decrease of $13.1 million. The decrease was primarily due to the decrease in asphalt sales margins resulting from the greater increase in crude oil prices relative to the increase in our asphalt sales prices.

Retail and Branded Marketing Segment. Operating income for our retail and branded marketing segment was $9.3 million for the three months ended September 30, 2011, compared to $8.8 million for the three months ended September 30, 2010, an increase of $0.5 million or 5.7%. This increase was primarily due to higher retail fuel sales volumes and margins and higher merchandise sales and margins.

Interest Expense

Interest expense was $22.6 million for the three months ended September 30, 2011, compared to $24.1 million for the three months ended September 30, 2010, a decrease of $1.5 million, or 6.2%.

Income Tax Expense (Benefit)

Income tax expense (benefit) was $17.0 million for the three months ended September 30, 2011, compared to $(21.9) million for the three months ended September 30, 2010. The increase resulted from our higher pre-tax income in the third quarter of 2011, compared to the third quarter of 2010, and a decrease in the effective tax rate. Our effective tax rate was 36.1% for the third quarter of 2011, compared to an effective tax rate of 39.0% for the third quarter of 2010.

Non-Controlling Interest In Income (Loss) Of Subsidiaries

Non-controlling interest in income (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 income (loss) of subsidiaries was $1.5 million for the three months ended September 30, 2011, compared to $(1.2) million for the three months ended September 30, 2010, an increase of $2.7 million.

Net Income (Loss) Available to Common Stockholders

Net income (loss) available to common stockholders was $28.6 million for the three months ended September 30, 2011, compared to $(15.6) million for the three months ended September 30, 2010, an increase of $44.2 million. This increase was attributable to the factors discussed above.

Nine Months EndedSeptember 30, 2011 Compared to the Nine Months EndedSeptember 30, 2010

Net Sales

Consolidated. Net sales for the nine months ended September 30, 2011 were $5,303.4 million, compared to $2,668.2 million for the nine months ended September 30, 2010, an increase of $2,635.2 million. This increase was primarily due to higher refinery throughput volumes in our refining and unbranded marketing segment, increased sales volumes in our retail and branded marketing segment and higher refined product prices.

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Refining and Unbranded Marketing Segment. Net sales for our refining and unbranded marketing segment were $4,797.1 million for the nine months ended September 30, 2011, compared to $2,230.8 million for the nine months ended September 30, 2010, an increase of $2,566.3 million. The increase was due to higher refined product prices and higher refinery throughput in the nine months ended September 30, 2011 compared to the same period last year.

Combined refinery throughput for the nine months ended September 30, 2011, averaged 144,515 bpd, consisting of 60,889 bpd at the Big Spring refinery, 21,357 bpd at the California refineries and 62,269 bpd at the Krotz Springs refinery, compared to a combined average throughput of 94,775 bpd for the nine months ended September 30, 2010, 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. During the nine months ended September 30, 2010, the Krotz Springs refinery was shut down for major turnaround activity and restarted in June 2010. The California refineries were shut down for the first three months of 2011 for the integration of the Bakersfield hydrocracker unit.

The increase in refined product prices that our refineries experienced resembled the price increases experienced in each refinery's respective markets. The average per gallon price of Gulf Coast gasoline for the nine months ended September 30, 2011 increased $0.79, or 39.3%, to $2.80, compared to $2.01 for the nine months ended September 30, 2010. The average per gallon price of Gulf Coast ultra low-sulfur diesel for the nine months ended September 30, 2011 increased $0.88, or 42.1%, to $2.97, compared to $2.09 for the nine months ended September 30, 2010. The average per gallon price for Gulf Coast high sulfur diesel for the nine months ended September 30, 2011, increased $0.88, or 43.3%, to $2.91, compared to $2.03 for the nine months ended September 30, 2010. The average per gallon price of West Coast LA CARBOB gasoline for the nine months ended September 30, 2011 increased $0.74, or 33.9%, to $2.92, compared to $2.18 for the nine months ended September 30, 2010. The average price per gallon of West Coast LA ultra low-sulfur diesel for the nine months ended September 30, 2011 increased $0.91, or 42.5%, to $3.05, compared to $2.14 for the nine months ended September 30, 2010.

Asphalt Segment. Net sales for our asphalt segment were $435.1 million for the nine months ended September 30, 2011, compared to $316.7 million for the nine months ended September 30, 2010, an increase of $118.4 million or 37.4%. The increase was due primarily to an increase in asphalt sales volumes and higher asphalt sales price for our blended asphalt product for the nine months ended September 30, 2011. The asphalt sales volume increased 26.1% from 677 thousand tons for the nine months ended September 30, 2010, to 854 thousand tons for the nine months ended September 30, 2011. The average blended asphalt sales price increased 12.9% from $477.68 per ton for the nine months ended September 30, 2010, to $539.52 per ton for the nine months ended September 30, 2011, and the average non-blended asphalt sales price decreased 3.3% from $349.29 per ton for the nine months ended September 30, 2010, to $337.82 per ton for the nine months ended September 30, 2011.

Retail and Branded Marketing Segment. Net sales for our retail and branded marketing segment were $1,083.5 million for the nine months ended September 30, 2011, compared to $753.5 million for the nine months ended September 30, 2010, an increase of $330.0 million or 43.8%. 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 $4,717.7 million for the nine months ended September 30, 2011, compared to $2,443.5 million for the nine months ended September 30, 2010, an increase of $2,274.2 million. This increase was primarily due to higher refinery throughput volumes in our refining and unbranded marketing segment, increased sales volumes in our retail and branded marketing segment and higher crude oil prices.

Refining and Unbranded Marketing Segment. Cost of sales for our refining and unbranded marketing segment were $4,336.7 million for the nine months ended September 30, 2011, compared to $2,138.3 million for the nine months ended September 30, 2010, an increase of $2,198.4 million. This increase was primarily due to increased refinery throughput as well as an increase in the cost of crude oil used by our refineries. The average price of WTI increased 23.1% from $77.50 per barrel for the nine months ended September 30, 2010, to $95.42 per barrel for the nine months ended September 30, 2011. The average price of Buena Vista crude increased 40.5% from $75.89 per barrel for the nine months ended September 30, 2010, to $106.62 per barrel for the nine months ended September 30, 2011. The average price of LLS crude increased 37.5% from $80.37 per barrel for the nine months ended September 30, 2010, to $110.50 per barrel for the nine months ended September 30, 2011.

Asphalt Segment. Cost of sales for our asphalt segment were $421.5 million for the nine months ended September 30, 2011, compared to $282.5 million for the nine months ended September 30, 2010, an increase of $139.0 million or 49.2%. The increase was due to higher asphalt sales volumes and higher crude oil costs for the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010.

Retail and Branded Marketing Segment. Cost of sales for our retail and branded marketing segment were $971.9 million for the nine months ended September 30, 2011, compared to $655.5 million for the nine months ended September 30,

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2010, an increase of $316.4 million or 48.3%. 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 $202.5 million for the nine months ended September 30, 2011, compared to $192.8 million for the nine months ended September 30, 2010, an increase of $9.7 million or 5.0%.

Refining and Unbranded Marketing Segment. Direct operating expenses for our refining and unbranded marketing segment for the nine months ended September 30, 2011 were $170.2 million, compared to $159.6 million for the nine months ended September 30, 2010, an increase of $10.6 million or 6.6%. This increase is due primarily to expenses associated with the startup of operations at our Bakersfield location which began during the three months ended September 30, 2011.

Asphalt Segment. Direct operating expenses for our asphalt segment for the nine months ended September 30, 2011, were $32.3 million, compared to $33.3 million for the nine months ended September 30, 2010, a decrease of $1.0 million or 3.0%. The decrease is primarily due to lower natural gas costs.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for the nine months ended September 30, 2011 were $107.6 million, compared to $96.0 million for the nine months ended September 30, 2010, an increase of $11.6 million or 12.1%, primarily due to higher employee related costs and higher advertising and marketing costs for the nine months ended September 30, 2011.

Refining and Unbranded Marketing Segment. SG&A expenses for our refining and unbranded marketing segment for the nine months ended September 30, 2011 were $24.9 million, compared to $17.4 million for the nine months ended September 30, 2010, an increase of $7.5 million or 43.1%. The increase was primarily due to higher employee related costs in the nine months ended September 30, 2011 and $2.5 million related to net bad debt recoveries and an insurance premium refund in the nine months ended September 30, 2010.

Asphalt Segment. SG&A expenses for our asphalt segment for the nine months ended September 30, 2011, were $3.8 million, compared to $4.6 million for the nine months ended September 30, 2010, a decrease of $(0.8) million or (17.4)%. This decrease is due primarily to lower employee related costs for the nine months ended September 30, 2011.

Retail and Branded Marketing Segment. SG&A expenses for our retail and branded marketing segment for the nine months ended September 30, 2011 were $78.3 million, compared to $73.5 million for the nine months ended September 30, 2010, an increase of $4.8 million or 6.5%. The increase was primarily attributable to higher advertising and marketing costs.

Depreciation and Amortization

Depreciation and amortization for the nine months ended September 30, 2011 was $80.0 million, compared to $78.5 million for the nine months ended September 30, 2010, an increase of $1.5 million or 1.9% due primarily to capital expenditures for the acquisition and integration of the Bakersfield refining assets which began operations during the three months ended September 30, 2011.

Operating Income (Loss)

Consolidated. Operating income (loss) for the nine months ended September 30, 2011 was $195.8 million, compared to $(142.1) million for the nine months ended September 30, 2010, an increase of $337.9 million. This increase was primarily due to higher refinery margins and throughput, higher retail fuel sales volumes and margins and increased merchandise sales and margins.

Refining and Unbranded Marketing Segment. Operating income (loss) for our refining and unbranded marketing segment was $200.5 million for the nine months ended September 30, 2011, compared to $(146.5) million for the nine months ended September 30, 2010, an increase of $347.0 million. This increase was primarily due to higher refining margins and increased refinery throughput.

Refinery operating margin at the Big Spring refinery was $20.67 per barrel for the nine months ended September 30, 2011, compared to $6.39 per barrel for the nine months ended September 30, 2010. The increase is due to higher Gulf Coast 3/2/1 crack spreads, improved operating efficiencies at higher throughput rates and a widening of the sweet/sour differentials. The average Gulf Coast 3/2/1 crack spread increased 199.1% to $24.53 per barrel for the nine months ended September 30, 2011, compared to $8.20 per barrel for the nine months ended September 30, 2010. Refinery operating margin at the California refineries was $(0.16) per barrel for the nine months ended September 30, 2011, compared to $0.86 per barrel for the nine months ended September 30, 2010. This decrease primarily reflects the impact of the California refineries' shutdown until its restart in late March 2011 offset by the higher West Coast 3/1/1/1 crack spreads. The average West Coast 3/1/1/1 crack spreads

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increased 29.0% to $11.09 per barrel for the nine months ended September 30, 2011, compared to $8.60 per barrel for the nine months ended September 30, 2010. The Krotz Springs refinery operating margin for the nine months ended September 30, 2011, was $5.61 per barrel, compared to $0.35 per barrel for the nine months ended September 30, 2010. The Krotz Springs refinery restarted operations in June 2010 after being down for the first five months of 2010 for a major turnaround. Additionally, the average Gulf Coast 2/1/1 high sulfur diesel crack spread for the nine months ended September 30, 2011 was $9.87 per barrel, compared to $4.59 per barrel for the nine months ended September 30, 2010.

The increases in refining margins at our Big Spring refinery were in part due to improvements in the sweet/sour differential. The sweet/sour differential increased 26.7% to $2.47 per barrel for the nine months ended September 30, 2011, compared to $1.95 per barrel for the nine months ended September 30, 2010. The refining margins at our California refineries were affected by a widening of the WTI to Buena Vista spread. The WTI to Buena Vista spread increased $12.81 per barrel to $(11.20) for the nine months ended September 30, 2011, compared to $1.61 per barrel for the nine months ended September 30, 2010. The refining margins at our Krotz Springs refinery were affected by a widening of the LLS to WTI spread. The LLS to WTI spread increased $11.74 per barrel to $14.55 per barrel for the nine months ended September 30, 2011, compared to $2.81 per barrel for the nine months ended September 30, 2010.

Asphalt Segment. Operating loss for our asphalt segment was $27.4 million for the nine months ended September 30, 2011, compared to $8.8 million for the nine months ended September 30, 2010, an increase of $18.6 million or 211.4%. The increase in loss was primarily due to the decrease in asphalt sales margins resulting from the greater increase in crude oil prices relative to the increase in our asphalt sales prices.

Retail and Branded Marketing Segment. Operating income for our retail and branded marketing segment was $24.5 million for the nine months ended September 30, 2011, compared to $14.7 million for the nine months ended September 30, 2010, an increase of $9.8 million. This increase was primarily due to higher retail fuel sales volumes and margins and higher merchandise sales and margins.

Interest Expense

Interest expense was $63.8 million for the nine months ended September 30, 2011, compared to $72.4 million for the nine months ended September 30, 2010, a decrease of $8.6 million, or 11.9%. The decrease is primarily due to 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 for the nine months ended September 30, 2010.

Income Tax Expense (Benefit)

Income tax expense (benefit) was $27.0 million for the nine months ended September 30, 2011, compared to $(73.7) million for the nine months ended September 30, 2010. The increase resulted from our higher pre-tax income for the nine months ended September 30, 2011, compared to the nine months ended September 30, 2010, and a decrease in the effective tax rate. Our effective tax rate was 31.8% for the nine months ended September 30, 2011, compared to an effective tax rate of 37.6% for the nine months ended September 30, 2010. The lower effective tax rate for the nine months ended September 30, 2011 was from the true-up of prior year income taxes.

Non-Controlling Interest In Income (Loss) Of Subsidiaries

Non-controlling interest in income (loss) of subsidiaries was $2.3 million for the nine months ended September 30, 2011, compared to $(7.2) million for the nine months ended September 30, 2010, an increase of $9.5 million primarily due to its proportional share of the higher income in 2011.

Net Income (Loss) Available to Common Stockholders

Net income (loss) available to common stockholders was $55.4 million for the nine months ended September 30, 2011, compared to $(97.8) million for the nine months ended September 30, 2010, an increase of $153.2 million. This increase was attributable to the factors discussed above.

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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. Our ability to generate sufficient cash from our operating activities depends on our future performance, which may be impacted by general economic, political, financial, competitive and other factors beyond our control.

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.

In January 2011, we completed a Standby Equity Distribution Agreement with YA Global Master SPV, Ltd. ("YA Global") to purchase up to $25.0 million of our common stock over a two-year period. During the nine months ended September 30, 2011, we sold common stock to YA Global that generated total proceeds of $11.9 million.

Cash Flows

The following table sets forth our consolidated cash flows for the nine months ended September 30, 2011, and 2010:

	For the Nine Months Ended
	September 30,
	2011			2010
	(dollars in thousands)
Cash provided by (used in):
Operating activities	$	58,362		$	(37,275	)
Investing activities	(104,130		)	(15,218		)
Financing activities	149,682			51,691
Net increase (decrease) in cash and cash equivalents	$	103,914		$	(802	)

Cash Flows Provided by (Used In) Operating Activities

Net cash provided by (used in) operating activities during the nine months ended September 30, 2011, was $58.4 million, compared to $(37.3) million during the nine months ended September 30, 2010. The change in cash used in operating activities of $95.7 million is primarily attributable to the increase of approximately $274.2 million in net income, adjusted for non-cash adjustments, offset primarily by increases in inventory of $148.9 million due to higher refinery throughput and excess inventories mainly due to the integration of the Bakersfield hydrocracker unit into the operations of the California refineries and an increase in accounts receivable of $73.3 million due to higher refinery throughput.

Cash Flows Used In Investing Activities

Net cash used in investing activities was $104.1 million during the nine months ended September 30, 2011, compared to $15.2 million during the nine months ended September 30, 2010. The change in net cash used in investing activities of $88.9 million was principally due an increase in capital expenditures of $70.6 million, of which $53.9 million was related to the integration of the Bakersfield hydrocracker unit into the operations of the California refineries, and a decrease in proceeds from the disposition of assets of $19.5 million.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities was $149.7 million during the nine months ended September 30, 2011, compared to $51.7 million during the nine months ended September 30, 2010. The net change in cash provided by financing activities of $98.0 million is primarily attributable to increases in revolving credit facilities, net of $131.6 million and net proceeds from the sale of common stock of $11.4 million, partially offset by a decrease in the proceeds from inventory supply agreements of $44.6 million.

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Indebtedness

Alon Brands Term Loans. In March 2011, Alon Brands issued $30.0 million five-year unsecured notes (the "Alon Brands Term Loans") to a group of investors including certain shareholders of Alon Israel and their affiliates. The notes will mature in March 2016. The group of investors have the right to request that principal payments of the loan will be paid in four equal, consecutive annual payments, starting in March 2013. Otherwise, the principal amount will be paid at the maturity date in March 2016. During the third quarter of 2011, certain shareholders of Alon Israel assigned $6.0 million of the Alon Brands Term Loans to Alon Israel.

Borrowings under the Alon Brands Term Loans bear interest at a rate of 7% per annum, payable on a semi-annual basis, provided that the interest rate will increase to 9% per annum solely with respect to the portion of the loan equal to the unexercised portion of the warrants described below.

The Alon Brands Term Loans contain certain restrictive covenants, including maintenance financial covenants.

In conjunction with the issuance of the Alon Brands Term Loans, we issued 3,092,783 warrants to purchase shares of our common stock at an initial exercise price per share of $9.70. The warrants are exercisable in whole or in part until March 2016, five years from the date of issuance. The allocated fair value of the warrants was $11.0 million and was recorded as additional paid-in capital at the time of issuance.

At September 30, 2011, the Alon Brands Term Loans had an outstanding balance of $19.7 million (net of unamortized discount of $10.3 million). We are utilizing the effective interest method to amortize the discount over the five-year life of the Alon Brands Term Loans and have amortized $0.4 million and $0.7 million to interest expense for the three and nine months ended September 30, 2011, respectively.

Paramount Petroleum Revolving Credit Facility. Paramount Petroleum Corporation has 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.

Borrowings under the Paramount Credit Facility bear interest at the Eurodollar rate plus a margin based on excess availability. Based on the excess availability at September 30, 2011, the margin was 1.75%.

Borrowings of $113.2 million which are included in the current portion of long-term debt and $63.1 million, which are included in long-term debt, were outstanding under the Paramount Credit Facility at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011 and December 31, 2010, outstanding letters of credit under the Paramount Credit Facility were $130.3 million and $1.3 million, respectively.

Financial Covenants. We have certain credit facilities that contain restrictive covenants, including maintenance financial covenants. At September 30, 2011, we were in compliance with these covenants.

Capital Spending

Each year our Board of Directors approves capital projects, including regulatory and planned turnaround projects that our management is authorized to undertake in our annual capital budget. Additionally, at times when conditions warrant or as new opportunities arise, other projects or the expansion of existing projects may be approved. Our total capital expenditure and turnaround/chemical catalyst budget for 2011 is $108.9 million, of which $58.0 million is substantially related to the Bakersfield hydrocracker project, $40.6 million is related to sustaining and regulatory compliance projects, and $10.3 million is related to turnaround and chemical catalyst. Approximately $98.1 million has been spent during the nine months ended September 30, 2011.

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, 2010.

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.

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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, 2010. 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, 2010.

New Accounting Standards and Disclosures

New accounting standards if any are disclosed in Note (1) Basis of Presentation included in the consolidated financial statements included in Item 1 of this report.

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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, 2011, we held approximately 2.7 million barrels of crude oil, refined product and asphalt inventories valued under the LIFO valuation method. Market value exceeded carrying value of LIFO costs by $100.5 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 $2.7 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.

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The following table provides information about our derivative commodity instruments as of September 30, 2011:

Description	Contract		Wtd Avg Purchase	Wtd Avg Sales		Contract			Market			Gain
of Activity	Volume		Price/BBL	Price/BBL		Value			Value			(Loss)
						(in thousands)
Forwards-long (Crude)	177,862		101.59	—		$	18,068		$	17,211		$	(857	)
Forwards-long (Gasoline)	356,477		112.58	—		40,133			38,646			(1,487		)
Forwards-long (Distillate)	198,981		123.60	—		24,593			23,782			(811		)
Forwards-short (Distillate)	(8,908	)	—	120.00		(1,068		)	(1,021		)	47
Forwards-long (Jet)	47,591		123.99	—		5,901			5,703			(198		)
Forwards-short (Jet)	(84,790	)	—	121.30		(10,285		)	(10,186		)	99
Forwards-long (Slurry)	16,747		91.63	—		1,535			1,457			(78		)
Forwards-short (Slurry)	(405	)	—	96.63		(39		)	(37		)	2
Forwards-short (Catfeed)	76,004		112.13	—		8,523			8,179			(344		)
Forwards-long (Slop)	2,010		75.63	—		152			139			(13		)
Forwards-short (Slop)	(14,649	)	—	75.61		(1,108		)	(1,014		)	94
Forwards-short (Propane)	(44,307	)	—	62.24		(2,758		)	(2,673		)	85
Forwards-long (Asphalt)	9,586		67.01	—		642			631			(11		)
Futures-short (Crude)	(466,000	)	—	87.49		(40,772		)	(37,490		)	3,282
Futures-short (Gasoline)	(286,000	)	—	116.13		(33,214		)	(31,889		)	1,325
Futures-short (Distillate)	(461,000	)	—	115.79		(53,379		)	(50,896		)	2,483
Description	Contract		Wtd Avg Contract	Wtd Avg Market		Contract			Market			Gain
of Activity	Volume		Spread	Spread		Value			Value			(Loss)
						(in thousands)
Futures-swaps (Heating Oil)	109,600		11.38	(11.80	)	$	1,247		$	(1,293	)	$	(2,540	)
Futures-call options (Heating Oil)	(1,507,000	)	14.26	34.55		(21,487		)	(52,067		)	(30,580		)

Interest Rate Risk

As of September 30, 2011, $724.7 million of our outstanding debt was at floating interest rates out of which approximately $197.0 million was at the Eurodollar rate plus 3.00%, subject to a minimum interest rate of 4.00%. As of September 30, 2011, we had an interest rate swap agreement with a notional amount of $100.0 million with a remaining period of 15 months and a fixed interest rate of 4.25%. An increase of 1% in the Eurodollar rate on indebtedness, net of the interest rate swap agreement outstanding in 2011 and the instrument subject to the minimum interest rate, would result in an increase in our interest expense of approximately $5.7 million per year.

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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.

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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 (incorporated by reference to Exhibit 4.3 to Form 10-Q, filed by the Company on November 9, 2010, SEC File No. 001-32567).
4.4	Specimen 8.50% Series A Convertible Preferred Stock Certificate (incorporated by reference to Exhibit 4.4 to Form 10-Q, filed by the Company on November 9, 2010, SEC File No. 001-32567).
10.1	Supplemental Agreement to Supply and Offtake Agreement, dated October 31, 2011, between Alon Refining Krotz Springs, Inc. and J. Aron & Company.
10.2	Supplemental Agreement to Supply and Offtake Agreement, dated October 31, 2011, between Alon USA, LP and J. Aron & Company.
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.
101	The following financial information from Alon USA Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to the Consolidated Financial Statements.

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SIGNATURES

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

		Alon USA Energy, Inc.
Date:	November 4, 2011	By:	/s/ David Wiessman
			David Wiessman
			Executive Chairman
Date:	November 4, 2011	By:	/s/ Paul Eisman
			Paul Eisman
			Chief Executive Officer
Date:	November 4, 2011	By:	/s/ Shai Even
			Shai Even
			Chief Financial Officer

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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 (incorporated by reference to Exhibit 4.3 to Form 10-Q, filed by the Company on November 9, 2010, SEC File No. 001-32567).
4.4	Specimen 8.50% Series A Convertible Preferred Stock Certificate (incorporated by reference to Exhibit 4.4 to Form 10-Q, filed by the Company on November 9, 2010, SEC File No. 001-32567).
10.1	Supplemental Agreement to Supply and Offtake Agreement, dated October 31, 2011, between Alon Refining Krotz Springs, Inc. and J. Aron & Company.
10.2	Supplemental Agreement to Supply and Offtake Agreement, dated October 31, 2011, between Alon USA, LP and J. Aron & Company.
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.
101	The following financial information from Alon USA Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to the Consolidated Financial Statements.

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