Alon USA Energy (ALJ) 10-Q 2013 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

___________________________________________________

FORM 10-Q

þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2013

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.)

12700 Park Central Dr., Suite 1600, 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 August 1, 2013, was 63,104,550.

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 COMPREHENSIVE INCOME	3
CONSOLIDATED STATEMENTS OF CASH FLOWS	4
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	5
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-10.2 SECOND AMENDMENT TO CREDIT AGREEMENT, DATED AS OF JULY 31, 2013, TO THE CREDIT AGREEMENT, DATED MAY 28, 2010, BY AND BETWEEN ALON REFINING KROTZ SPRINGS, INC., AND GOLDMAN SACHS BANK USA
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)

	June 30, 2013			December 31, 2012
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	134,468		$	116,296
Accounts and other receivables, net	218,197			184,138
Inventories	204,627			183,919
Deferred income tax asset	9,474			5,223
Prepaid expenses and other current assets	17,307			19,322
Total current assets	584,073			508,898
Equity method investments	23,892			21,582
Property, plant and equipment, net	1,443,082			1,492,493
Goodwill	105,943			105,943
Other assets, net	89,675			94,658
Total assets	$	2,246,665		$	2,223,574
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	296,507		$	309,573
Accrued liabilities	104,484			102,579
Current portion of long-term debt	9,478			9,504
Total current liabilities	410,469			421,656
Other non-current liabilities	268,047			254,946
Long-term debt	520,286			577,513
Deferred income tax liability	363,411			348,273
Total liabilities	1,562,213			1,602,388
Commitments and contingencies (Note 16)
Stockholders’ equity:
Preferred stock, par value $0.01, 15,000,000 shares authorized; 3,568,180 and 4,220,000 shares issued and outstanding at June 30, 2013 and December 31, 2012, respectively	35,682			42,200
Common stock, par value $0.01, 150,000,000 shares authorized; 62,897,637 and 61,272,429 shares issued and outstanding at June 30, 2013 and December 31, 2012, respectively	629			613
Additional paid-in capital	455,358			444,022
Accumulated other comprehensive loss, net of income tax	(23,320		)	(30,447		)
Retained earnings	176,256			128,319
Total stockholders’ equity	644,605			584,707
Non-controlling interest in subsidiaries	39,847			36,479
Total equity	684,452			621,186
Total liabilities and equity	$	2,246,665		$	2,223,574

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 Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Net sales (1)	$	1,676,595		$	1,910,489		$	3,327,791		$	3,702,622
Operating costs and expenses:
Cost of sales	1,497,712			1,686,876			2,875,969			3,305,550
Unrealized (gains) losses on commodity swaps	—			(12,871		)	—			32,441
Direct operating expenses	71,446			76,874			145,668			149,083
Selling, general and administrative expenses	43,101			36,208			84,842			71,348
Depreciation and amortization	30,798			30,419			61,961			61,130
Total operating costs and expenses	1,643,057			1,817,506			3,168,440			3,619,552
Gain (loss) on disposition of assets	8,494			(345		)	8,512			(214		)
Operating income	42,032			92,638			167,863			82,856
Interest expense	(20,261		)	(24,300		)	(41,553		)	(55,340		)
Equity earnings of investees	2,110			1,509			1,729			1,570
Other income (loss), net	46			1,107			129			(6,993		)
Income before income tax expense	23,927			70,954			128,168			22,093
Income tax expense	3,985			25,680			34,575			7,929
Net income	19,942			45,274			93,593			14,164
Net income attributable to non-controlling interest	8,446			2,183			27,913			440
Net income available to stockholders	$	11,496		$	43,091		$	65,680		$	13,724
Earnings per share, basic	$	0.17		$	0.77		$	1.03		$	0.24
Weighted average shares outstanding, basic (in thousands)	62,614			56,238			62,285			56,133
Earnings per share, diluted	$	0.17		$	0.65		$	0.97		$	0.21
Weighted average shares outstanding, diluted (in thousands)	68,071			66,635			67,743			66,562
Cash dividends per share	$	0.22		$	0.04		$	0.26		$	0.08

___________

(1) Includes excise taxes on sales by the retail segment of $18,531 and $16,198 for the three months and $35,836 and $32,322 for the six months ended June 30, 2013 and 2012, respectively.

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

2

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited, dollars in thousands)

	For the Three Months Ended					For the Six Months Ended
	June 30,					June 30,
	2013		2012			2013		2012
Net income	$	19,942	$	45,274		$	93,593	$	14,164
Other comprehensive income (loss), before tax:
Interest rate derivatives designated as cash flow hedges:
Unrealized holding loss arising during period	—		(13		)	—		(184		)
Less: reclassification to earnings - interest expense	—		(1,014		)	—		(2,009		)
Net gain	—		1,001			—		1,825
Commodity contracts designated as cash flow hedges:
Unrealized holding gain (loss) arising during period	12,369		9,589			21,750		(39,199		)
Less: reclassification to earnings - cost of sales	10,018		(14,399		)	9,994		(22,352		)
Net gain (loss)	2,351		23,988			11,756		(16,847		)
Total other comprehensive income (loss), before tax	2,351		24,989			11,756		(15,022		)
Income tax expense (benefit) related to items of other comprehensive income	862		8,987			4,360		(5,426		)
Total other comprehensive income (loss), net of tax	1,489		16,002			7,396		(9,596		)
Comprehensive income	21,431		61,276			100,989		4,568
Comprehensive income (loss) attributable to non-controlling interest	8,446		3,052			28,182		(170		)
Comprehensive income attributable to stockholders	$	12,985	$	58,224		$	72,807	$	4,738

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

3

ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited, dollars in thousands)
	For the Six Months Ended
	June 30,
	2013			2012
Cash flows from operating activities:
Net income	$	93,593		$	14,164
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	61,961			61,130
Stock compensation	3,008			1,496
Deferred income tax expense	6,527			4,665
Equity earnings of investees (net of dividends)	(1,729		)	(1,570		)
Amortization of debt issuance costs	2,272			3,297
Amortization of original issuance discount	1,504			1,344
Write-off of unamortized original issuance discount	—			9,624
(Gain) loss on disposition of assets	(8,512		)	214
Unrealized losses on commodity swaps	—			32,441
Changes in operating assets and liabilities:
Accounts and other receivables, net	(22,000		)	28,207
Inventories	(20,708		)	(71,881		)
Prepaid expenses and other current assets	9,732			(15,615		)
Other assets, net	2,662			(17,258		)
Accounts payable	(13,066		)	6,099
Accrued liabilities	2,485			(9,506		)
Other non-current liabilities	12,025			67,371
Net cash provided by operating activities	129,754			114,222
Cash flows from investing activities:
Capital expenditures	(30,622		)	(40,525		)
Capital expenditures for turnarounds and catalysts	(6,624		)	(8,757		)
Contribution to equity method investment	(581		)	—
Proceeds from disposition of assets	25,745			16
Net cash used in investing activities	(12,082		)	(49,266		)
Cash flows from financing activities:
Dividends paid to stockholders	(16,228		)	(4,481		)
Dividends paid to non-controlling interest	(731		)	(269		)
Distributions paid to non-controlling interest in the Partnership	(23,579		)	—
Deferred debt issuance costs	(205		)	(2,643		)
Revolving credit facilities, net	(54,000		)	(151,341		)
Payments on long-term debt	(4,757		)	(5,772		)
Net cash used in financing activities	(99,500		)	(164,506		)
Net increase (decrease) in cash and cash equivalents	18,172			(99,550		)
Cash and cash equivalents, beginning of period	116,296			157,066
Cash and cash equivalents, end of period	$	134,468		$	57,516
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$	37,829		$	43,832
Taxes paid (refunds received) for income tax	$	19,100		$	(1,378	)
Non-cash activity:
Financing activity — payment on long-term debt from issuance of preferred stock	$	—		$	(30,000	)

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

4

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited, dollars in thousands except as noted)

(1) Basis of Presentation

The consolidated financial statements include the accounts of Alon USA Energy, Inc. and its subsidiaries (collectively, “Alon”). The term “Alon” generally includes Alon USA Partners, LP (“ALDW”) and its subsidiaries as consolidated subsidiaries of Alon USA Energy with certain exceptions where there are transactions or obligations between ALDW and Alon USA Energy or its other subsidiaries. When used in descriptions of agreements and transactions, “ALDW” or the “Partnership” refers to ALDW and its consolidated subsidiaries.

These consolidated financial statements and notes 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. All significant intercompany balances and transactions have been eliminated in consolidation. Certain prior year balances may have been aggregated or disaggregated in order to conform to the current year presentation. 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, 2013.

The consolidated balance sheet as of December 31, 2012, 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, 2012.

New Accounting Standards

Effective January 1, 2013, Alon adopted Accounting Standards Update (“ASU”) No. 2011- 11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities and ASU No. 2013- 01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities issued by the Financial Accounting Standards Board (“FASB”). These updates require an entity to disclose both gross information and net information of recognized derivative instruments, repurchase agreements and securities borrowing and lending transactions offset in the consolidated balance sheet. The updated guidance was applied retrospectively, effective January 1, 2013. The adoption concerns disclosure only and did not have any financial impact on the consolidated financial statements.

ASU No. 2013- 02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013- 02”), was issued in February 2013. This ASU does not change the current requirements for reporting net income or other comprehensive income in financial statements. However, ASU 2013- 02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross- reference to other disclosures required under GAAP that provide additional detail about those amounts. The updated guidance was applied retrospectively, effective January 1, 2013. The adoption concerns disclosure only and did not have any financial impact on the consolidated financial statements.

(2) Alon USA Partners, LP

ALDW is a publicly traded limited partnership that was formed to own the assets and operations of the Big Spring refinery and associated wholesale marketing operations. On November 26, 2012, the Partnership completed its initial public offering (NYSE: ALDW) of 11,500,000 common units representing limited partner interests. As of June 30, 2013, the 11,502,476 common units held by the public represent 18.4% of the Partnership's common units outstanding. Alon owns the remaining 81.6% of the Partnership's common units and Alon USA Partners GP, LLC (the "General Partner"), Alon's wholly-owned subsidiary, owns 100% of the non-economic General Partner interest in the Partnership.

The limited partner interests in the Partnership not owned by Alon are reflected in the results of operations as net income attributable to non-controlling interests and in Alon's balance sheet in non-controlling interests in subsidiaries. The Partnership is consolidated within the refining and marketing segment.

5

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

The Partnership has adopted a policy pursuant to which it will distribute all of the available cash, as defined in the partnership agreement, it generates each quarter. The available cash for distribution each quarter will be determined by the board of directors of the General Partner within 60 days following the end of such quarter.

Alon has agreements with the Partnership which establish fees for certain administrative and operational services provided by Alon and its subsidiaries to the Partnership, provide certain indemnification obligations and other matters and establish terms for the supply of products by the Partnership to Alon.

(3) Segment Data

Alon’s revenues are derived from three operating segments: (i) refining and marketing, (ii) asphalt and (iii) retail. 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.

In the fourth quarter of 2012, based on a change in our internal reporting structure as a result of the Partnership's initial public offering, the branded marketing operations have been combined with the refining and marketing segment and are no longer included with the retail segment. Information for the three and six months ended June 30, 2012 has been recast to provide a comparison to the current year results.

(a) Refining and Marketing Segment

Alon’s refining and 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. Alon's refineries have a combined throughput capacity of approximately 214,000 barrels per day (“bpd”). At these refineries, Alon refines crude oil into products including gasoline, diesel, jet fuel, petrochemicals, feedstocks, asphalts and other petroleum products, which are marketed primarily in the South Central, Southwestern and Western regions of the United States. Finished products and blendstocks are also marketed through sales and exchanges with other major oil companies, state and federal governmental entities, unbranded wholesale distributors and various other third parties. Alon also acquires finished products through exchange agreements and third-party suppliers.

Alon supplies gasoline and diesel to approximately 640 Alon branded retail sites, including its retail segment convenience stores. Approximately 65% of the gasoline and 29% of the diesel motor fuel produced at Alon's Big Spring refinery was transferred to Alon's retail segment convenience stores at prices substantially determined by wholesale market prices. Additionally, Alon licenses the use of the Alon brand name and provides credit card processing services to 99 licensed locations that are not under fuel supply agreements.

(b) Asphalt Segment

Alon’s asphalt segment includes the Willbridge, Oregon refinery and 11 refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Oregon (Willbridge), Washington (Richmond Beach), Arizona (Phoenix and Flagstaff), 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 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 Segment

Alon’s retail segment operates 298 convenience stores located 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 Alon brand names. Substantially all of the motor fuel sold through Alon’s retail segment is 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.

6

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

Segment data as of and for the three and six month periods ended June 30, 2013 and 2012, are presented below:

	Refining and  Marketing		Asphalt			Retail			Corporate			Consolidated Total
Three Months Ended June 30, 2013
Net sales to external customers	$	1,287,571	$	144,191		$	244,833		$	—		$	1,676,595
Intersegment sales/purchases	156,043		(24,732		)	(131,311		)	—			—
Depreciation and amortization	26,107		1,563			2,554			574			30,798
Operating income (loss)	33,014		2,021			7,764			(767		)	42,032
Total assets	1,880,858		141,515			204,252			20,040			2,246,665
Turnaround, chemical catalyst and capital expenditures	14,054		2,599			6,537			426			23,616

	Refining and  Marketing		Asphalt			Retail			Corporate			Consolidated Total
Three Months Ended June 30, 2012
Net sales to external customers	$	1,525,339	$	152,911		$	232,239		$	—		$	1,910,489
Intersegment sales/purchases	228,504		(106,056		)	(122,448		)	—			—
Depreciation and amortization	25,758		1,414			2,623			624			30,419
Operating income (loss)	79,360		6,404			7,689			(815		)	92,638
Total assets	1,888,729		171,517			193,838			15,280			2,269,364
Turnaround, chemical catalyst and capital expenditures	24,128		5,969			1,866			657			32,620

	Refining and Marketing		Asphalt			Retail			Corporate			Consolidated Total
Six Months Ended June 30, 2013
Net sales to external customers	$	2,559,797	$	299,056		$	468,938		$	—		$	3,327,791
Intersegment sales/purchases	297,942		(41,291		)	(256,651		)	—			—
Depreciation and amortization	52,612		3,112			4,822			1,415			61,961
Operating income (loss)	159,722		(2,380		)	12,304			(1,783		)	167,863
Total assets	1,880,858		141,515			204,252			20,040			2,246,665
Turnaround, chemical catalyst and capital expenditures	25,239		4,391			7,177			439			37,246

	Refining and Marketing		Asphalt			Retail			Corporate			Consolidated Total
Six Months Ended June 30, 2012
Net sales to external customers	$	3,008,281	$	245,460		$	448,881		$	—		$	3,702,622
Intersegment sales/purchases	381,370		(137,245		)	(244,125		)	—			—
Depreciation and amortization	52,035		2,796			5,122			1,177			61,130
Operating income (loss)	68,431		4,983			11,000			(1,558		)	82,856
Total assets	1,888,729		171,517			193,838			15,280			2,269,364
Turnaround, chemical catalyst and capital expenditures	34,934		7,460			6,105			783			49,282

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.

7

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

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

(4) Fair Value

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.

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. Derivative instruments and the Renewable Identification Numbers ("RINs") obligation are the only financial assets and liabilities measured at fair value on a recurring basis.

The RINs obligation represents the period-end deficit for the purchase of RINs to satisfy the requirement to blend biofuels into the products Alon has produced. Alon's RINs obligation is based on the RINs deficit and the price of those RINs as of the balance sheet date. The RINs obligation is categorized as Level 2 of the fair value hierarchy and is measured at fair value using the market approach based on quoted prices from an independent pricing service.

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 June 30, 2013 and December 31, 2012, 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 June 30, 2013
Assets:
Commodity contracts (futures and forwards)	$	616	$	—	$	—	$	616
Commodity contracts (swaps)	—		13,270		—		13,270
Liabilities:
Fair value hedges	—		3,578		—		3,578
RINs obligation	—		8,016		—		8,016
As of December 31, 2012
Assets:
Commodity contracts (futures and forwards)	$	2,072	$	—	$	—	$	2,072
Commodity contracts (swaps)	—		1,514		—		1,514
Liabilities:
Fair value hedges	—		1,720		—		1,720

(5) Derivative Financial Instruments

Mark to Market

Commodity Derivatives. Alon selectively utilizes commodity derivatives to manage its exposure to commodity price fluctuations and uses crude oil and refined product 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 substantially mitigated by transacting with counterparties meeting established collateral and credit criteria.

8

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

Fair Value Hedges

Fair value hedges are used to hedge price volatility in certain refining inventories and firm commitments to purchase inventories. The level of activity for fair value hedges is based on the level of operating inventories. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting loss or gain on the hedged item attributable to the hedged risk, is recognized currently in income in the same period.

As of June 30, 2013, Alon has accounted for certain commodity contracts as fair value hedges with contract purchase volumes of 1,323 thousand barrels of crude oil with remaining contract terms through May 2019.

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.

Commodity Derivatives. As of June 30, 2013, Alon has accounted for certain commodity swap contracts as cash flow hedges with contract purchase volumes of 7,560 thousand barrels of crude oil and contract sales volumes of 7,560 thousand barrels of refined products with the longest remaining contract term of eighteen months. Related to these transactions in Other Comprehensive Income ("OCI"), Alon recognized unrealized gains (losses) of $2,351 and $23,988 for the three months ended and $11,756 and $(16,847) for the six months ended June 30, 2013 and 2012, respectively. There were no amounts reclassified from OCI into cost of sales as a result of the discontinuance of cash flow hedge accounting.

For the three and six months ended June 30, 2013 and 2012, 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.

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 June 30, 2013, Alon did not have any outstanding interest rate swap agreements.

Alon recognized in OCI unrealized gains of $1,001 and $1,825 during the three and six months ended June 30, 2012, respectively, for the fair value measurement of the interest rate swap agreements.

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

	As of June 30, 2013
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	2,111	Accrued liabilities	$	(1,495	)
Total derivatives not designated as hedging instruments		$	2,111		$	(1,495	)
Derivatives designated as hedging instruments:
Commodity contracts (swaps)	Accounts receivable	$	14,346	Other non-current liabilities	$	(1,076	)
Fair value hedges		—		Other non-current liabilities	(3,578		)
Total derivatives designated as hedging instruments		14,346			(4,654		)
Total derivatives		$	16,457		$	(6,149	)

9

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

	As of December 31, 2012
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	2,743	Accrued liabilities	$	(671	)
Total derivatives not designated as hedging instruments		$	2,743		$	(671	)
Derivatives designated as hedging instruments:
Commodity contracts (swaps)	Accounts receivable	$	2,287	Accrued liabilities	$	(773	)
Fair value hedges		—		Other non-current liabilities	(1,720		)
Total derivatives designated as hedging instruments		2,287			(2,493		)
Total derivatives		$	5,030		$	(3,164	)

The following tables present the effect of derivative instruments on Alon’s consolidated statements of operations and accumulated other comprehensive income:

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 June 30, 2013
Commodity contracts (swaps)	$	2,351	Cost of sales	$	10,018			$	—
Total derivatives	$	2,351		$	10,018			$	—
For the Three Months Ended June 30, 2012
Commodity contracts (swaps)	$	23,988	Cost of sales	$	(14,399	)		$	—
Interest rate swap	1,001		Interest expense	(1,014		)		—
Total derivatives	$	24,989		$	(15,413	)		$	—

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 Six Months Ended June 30, 2013
Commodity contracts (swaps)	$	11,756		Cost of sales	$	9,994			$	—
Total derivatives	$	11,756			$	9,994			$	—
For the Six Months Ended June 30, 2012
Commodity contracts (swaps)	$	(16,847	)	Cost of sales	$	(22,352	)		$	—
Interest rate swap	1,825			Interest expense	(2,009		)		—
Total derivatives	$	(15,022	)		$	(24,361	)		$	—

10

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

Derivatives in fair value hedging relationships:

		Gain (Loss) Recognized in Income
		For the Three Months Ended				For the Six Months Ended
		June 30,				June 30,
	Location	2013		2012		2013			2012
Fair value hedges	Cost of sales	$	961	$	—	$	(1,858	)	$	—
Total derivatives		$	961	$	—	$	(1,858	)	$	—

Derivatives not designated as hedging instruments:

		Gain (Loss) Recognized in Income
		For the Three Months Ended					For the Six Months Ended
		June 30,					June 30,
	Location	2013		2012			2013		2012
Commodity contracts (futures & forwards)	Cost of sales	$	2,532	$	13,861		$	10,519	$	15,575
Commodity contracts (swaps)	Cost of sales	—		(5,825		)	—		(12,206		)
Commodity contracts (swaps)	Unrealized gains (losses) on commodity swaps	—		12,871			—		(32,441		)
Commodity contracts (call options)	Other income (loss), net	—		856			—		(7,297		)
Total derivatives		$	2,532	$	21,763		$	10,519	$	(36,369	)

Offsetting Assets and Liabilities

Alon's derivative financial instruments are subject to master netting arrangements to manage counterparty credit risk associated with derivatives, however, Alon does not offset on its consolidated balance sheets the fair value amounts recorded for derivative instruments under these agreements.

The following table presents offsetting information regarding Alon's derivatives by type of transaction as of June 30, 2013 and December 31, 2012:

	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset in the Statement of Financial Position		Net Amounts of Assets (Liabilities) Presented in the Statement of Financial Position			Gross Amounts Not offset in the Statement of Financial Position					Net Amount
									Financial Instruments			Cash Collateral Pledged
As of June 30, 2013
Commodity Derivative Assets:
Futures & forwards	$	2,111		$	—	$	2,111		$	(1,495	)	$	—	$	616
Swaps	14,346			—		14,346			—			—		14,346
Commodity Derivative Liabilities:
Futures & forwards	$	(1,495	)	$	—	$	(1,495	)	$	1,495		$	—	$	—
Swaps	(1,076		)	—		(1,076		)	—			—		(1,076		)
As of December 31, 2012
Commodity Derivative Assets:
Futures & forwards	$	2,743		$	—	$	2,743		$	(671	)	$	—	$	2,072
Swaps	2,287			—		2,287			—			—		2,287
Commodity Derivative Liabilities:
Futures & forwards	$	(671	)	$	—	$	(671	)	$	671		$	—	$	—
Swaps	(773		)	—		(773		)	—			—		(773		)

11

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

(6) Inventories

Alon’s inventories (including inventory consigned to others) 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:

	June 30, 2013		December 31, 2012
Crude oil, refined products, asphalt and blendstocks	$	42,989	$	40,068
Crude oil inventory consigned to others	107,256		91,876
Materials and supplies	22,981		21,919
Store merchandise	22,758		22,139
Store fuel	8,643		7,917
Total inventories	$	204,627	$	183,919

Market values of crude oil, refined products, asphalt and blendstock inventories exceeded LIFO costs by $66,421 and $58,213 at June 30, 2013 and December 31, 2012, respectively.

(7) Inventory Financing Agreements

Alon has entered into Supply and Offtake Agreements and other associated agreements (together the "Supply and Offtake Agreements") with J. Aron & Company ("J. Aron"), to support the operations of the Big Spring, Krotz Springs and California refineries. Pursuant to the Supply and Offtake Agreements, (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 refineries and (ii) Alon agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced at the refineries.

The Supply and Offtake Agreements also 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 facilities, and to identify prospective purchasers of refined products on J. Aron's behalf. The Supply and Offtake Agreements were amended in February 2013 and have initial terms that expire in May 2019. J. Aron may elect to terminate the Supply and Offtake Agreements prior to the expiration of the initial term in May 2016 and upon each anniversary thereof, on six months prior notice. Alon may elect to terminate in May 2018 on six months prior notice.

Following expiration or termination of the Supply and Offtake Agreements, Alon is obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the leased storage facilities at market prices at that time.

In association with the supply and offtake agreement at the Krotz Springs refinery, Alon entered into a secured Credit Agreement (the “Krotz Springs Standby LC Facility”) by and between Alon, as Borrower, and Goldman Sachs Bank USA, as Issuing Bank. The Krotz Springs Standby LC Facility provides for up to $200,000 of letters of credit to be issued to J. Aron. Obligations under the Krotz Springs Standby LC Facility are secured by a first priority lien on the existing and future accounts receivable and inventory of Alon Refining Krotz Springs, Inc. and its subsidiaries ("ARKS"), a wholly owned subsidiary of Alon. The Krotz Springs Standby LC Facility includes customary events of default and restrictions on the activities of ARKS. The Krotz Springs Standby LC Facility contains no maintenance financial covenants. At this time there is no further availability under the Krotz Springs Standby LC Facility. In August 2013, Alon amended the Krotz Springs Standby LC Facility to extend the maturity date to July 2016.

As of June 30, 2013 and December 31, 2012, Alon had net current payables to J. Aron for purchases of $34,754 and $37,940, respectively, non-current liabilities related to the original financing of $129,606 and $115,955, respectively, and a consignment inventory receivable representing a deposit paid to J. Aron of $26,179 and $26,179, respectively.

Additionally, Alon had net current payables of $1,125 and net current receivables of $5,878 at June 30, 2013 and December 31, 2012, respectively, for forward commitments related to month-end consignment inventory target levels differing from projected levels and the associated pricing with these inventory level differences.

12

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

(8) Property, Plant and Equipment, Net

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

	June 30, 2013			December 31, 2012
Refining facilities	$	1,776,492		$	1,781,701
Pipelines and terminals	43,445			43,445
Retail	172,269			164,998
Other	14,760			14,296
Property, plant and equipment, gross	2,006,966			2,004,440
Less accumulated depreciation	(563,884		)	(511,947		)
Property, plant and equipment, net	$	1,443,082		$	1,492,493

(9) Additional Financial Information

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

(a) Other Assets, Net

	June 30, 2013		December 31, 2012
Deferred turnaround and chemical catalyst cost	$	14,574	$	15,978
Environmental receivables	10,696		13,563
Deferred debt issuance costs	12,638		14,705
Intangible assets, net	7,898		9,384
Receivable from supply agreements	26,179		26,179
Other, net	17,690		14,849
Total other assets	$	89,675	$	94,658

(b) Accrued Liabilities and Other Non-Current Liabilities

	June 30, 2013		December 31, 2012
Accrued Liabilities:
Taxes other than income taxes, primarily excise taxes	$	29,797	$	37,888
Employee costs	13,058		18,995
Commodity contracts	1,495		1,444
Accrued finance charges	11,581		11,633
Environmental accrual	7,631		6,730
RINs obligation	8,016		—
Other	32,906		25,889
Total accrued liabilities	$	104,484	$	102,579
Other Non-Current Liabilities:
Pension and other postemployment benefit liabilities, net	$	60,456	$	58,270
Environmental accrual (Note 16)	51,008		54,672
Asset retirement obligations	12,183		11,867
Consignment inventory	129,606		115,955
Commodity contracts	1,076		—
Other	13,718		14,182
Total other non-current liabilities	$	268,047	$	254,946

13

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

(10) Postretirement Benefits

Alon has four defined benefit pension plans covering substantially all of its employees, excluding employees of Alon's retail segment. 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 2013 to its pension plans have not changed significantly from amounts previously disclosed in Alon’s consolidated financial statements for the year ended December 31, 2012. For the six months ended June 30, 2013 and 2012, Alon contributed $2,075 and $2,920, 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 six months ended June 30, 2013 and 2012:

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Components of net periodic benefit cost:
Service cost	$	1,116		$	943		$	2,232		$	1,886
Interest cost	1,100			1,031			2,200			2,063
Expected return on plan assets	(1,157		)	(1,076		)	(2,314		)	(2,153		)
Amortization of net loss	1,005			645			2,010			1,291
Net periodic benefit cost	$	2,064		$	1,543		$	4,128		$	3,087

(11) Indebtedness

Debt consisted of the following:

	June 30, 2013			December 31, 2012
Term loan credit facility	$	245,312		$	246,311
Revolving credit facility	—			49,000
Senior secured notes	212,826			211,573
Retail credit facilities	71,626			80,133
Total debt	529,764			587,017
Less current portion	(9,478		)	(9,504		)
Total long-term debt	$	520,286		$	577,513

Alon had outstanding letters of credit under the Alon Energy Letter of Credit Facility of $59,450 and $59,485 at June 30, 2013 and December 31, 2012, respectively.

Alon had borrowings of $0 and $49,000 and letters of credit of $100,528 and $58,759 outstanding under the Alon USA LP revolving credit facility at June 30, 2013 and December 31, 2012, respectively.

Alon has certain credit agreements that contain restrictive covenants, including maintenance financial covenants. At June 30, 2013, Alon was in compliance with these maintenance financial covenants.

(12) Stock-Based Compensation (share values in dollars)

Alon’s overall executive incentive compensation program includes 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.

14

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

Restricted Stock. Non-employee directors, and non-employee directors of Alon's subsidiaries who are designated by Alon's directors, are awarded an annual grant of $25 in shares of restricted stock. In May 2013, Alon granted awards of 4,257 restricted shares at a grant date price of $17.62 per share. The restricted shares granted to the non-employee directors vest over a period of three years, assuming continued service at vesting.

In May 2013, Alon granted awards of 255,000 restricted shares to certain executive officers at a grant date price of $17.25 per share. These May 2013 restricted shares will vest as follows:  50% in May 2014 and 50% in May 2016, assuming continued service at vesting.

The following table summarizes the restricted share activity from January 1, 2012:

			Weighted Average Grant Date Fair Values
Nonvested Shares	Shares		(per share)
Nonvested at January 1, 2012	194,906		$	13.26
Granted	228,648		9.63
Vested	(97,424	)	13.27
Forfeited	—		—
Nonvested at December 31, 2012	326,130		$	10.71
Granted	259,247		17.28
Vested	(136,693	)	10.24
Forfeited	—		—
Nonvested at June 30, 2013	448,684		$	14.65

Compensation expense for restricted stock awards amounted to $620 and $545 for the three months ended June 30, 2013 and 2012, respectively, and $1,137 and $719 for the six months ended June 30, 2013 and 2012, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.

As of June 30, 2013, there was $5,401 of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 2.4 years. The fair value of shares vested in 2013 was $2,379.

Restricted Stock Units. In May 2011, Alon granted 500,000 restricted stock units to the CEO and President of Alon at a grant date fair value of $11.47 per share. 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 $374 for the three months ended June 30, 2013 and 2012, respectively, and $748 and $748 for the six months ended June 30, 2013 and 2012, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.

Stock Appreciation Rights. Through June 30, 2013, Alon has granted awards of 599,165 SARs to certain officers and key employees of Alon of which 60% of these SARs have a grant price of $28.46 per share and the remaining SARs have grant prices ranging from $10.00 to $16.00 per share. As of June 30, 2013, 437,165 SARs have expired without being exercised with 134,752 SARs remaining outstanding at June 30, 2013.

Compensation expense for the SARs grants amounted to $6 and $14 for the three months ended June 30, 2013 and 2012, respectively, and $12 and $29 for the six months ended June 30, 2013 and 2012, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.

(13) Equity (share values in dollars)

(a) Common Stock

Amended Shareholder Agreement. In 2011, an agreement was reached with one of the non-controlling interest shareholders of Alon Assets, Inc. ("Alon Assets"),whereby the participant would exchange 2,019 shares of Alon Assets ratably over a three year period for up to 377,710 shares of Alon's common stock. One-third of the Alon Assets shares were exchanged in each of October 2012 and October 2011, and the remaining one-third will be exchanged in October 2013.

In 2012, Alon signed agreements with the two remaining non-controlling interest shareholders of Alon Assets. Alon has the right to exchange 581,699shares of its common stock over a period of 12 quarters and 2,326,946shares of its common stock over a period of 20 quarters, beginning July 2012, for 15,549.3shares of Alon Assets.

15

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

During the six months ended June 30, 2013, 329,644shares of Alon's common stock were issued in exchange for 1,762.24 shares of Alon Assets with 2,249,356 shares of Alon's common stock available for exchange at June 30, 2013.

Compensation expense associated with the difference in value between the participants' ownership of Alon Assets compared to Alon's common stock of $734 and $1,498was recognized for the three and six months ended June 30, 2013 and is included in selling, general and administrative expenses in the consolidated statements of operations.

(b) Preferred stock

Preferred Stock Conversion. During the six months ended June 30, 2013, certain shareholders of Alon Israel and their affiliates converted 651,820 shares of Series B Preferred Stock to 967,107 shares of Alon's common stock.

(c) Dividends

Common Stock Dividends. On March 15, 2013, 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 March 1, 2013.

On June 14, 2013, Alon paid a regular quarterly cash dividend of $0.06 per share and a special non-recurring dividend of $0.16 per share on Alon's common stock to stockholders of record at the close of business on May 31, 2013.

Preferred Stock Dividends. Alon issued 91,789 shares of common stock for payment of the quarterly 8.5% preferred stock dividend to preferred stockholders for the six months ended June 30, 2013.

Partnership Distributions. On March 1, 2013, the Partnership paid a cash distribution of $35,626, or $0.57 per unit, for the period of November 27, 2012 through and including December 31, 2012. The total cash distribution paid to non-affiliated common unitholders was $6,556.

On May 15, 2013, the Partnership paid a cash distribution of $92,503, or $1.48 per unit, for the period of January 1, 2013 through and including March 31, 2013. The total cash distribution paid to non-affiliated common unitholders was $17,023.

(d) Accumulated Other Comprehensive Loss

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

	Unrealized Gain on Cash Flow Hedges		Defined Benefit Pension Plans			Total
Balance at December 31, 2012	$	455	$	(30,902	)	$	(30,447	)
Current period other comprehensive income, net of tax	7,127		—			7,127
Balance at June 30, 2013	$	7,582	$	(30,902	)	$	(23,320	)

(14) Earnings Per Share

Basic earnings per share is calculated as net income 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 and granted restricted stock units using the treasury stock method and the dilutive effect of convertible preferred shares using the if-converted method.

16

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

The calculation of earnings per share, basic and diluted, for the three and six months ended June 30, 2013 and 2012, is as follows:

	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Net income available to stockholders	$	11,496	$	43,091	$	65,680	$	13,724
less: preferred stock dividends	757		—		1,515		—
Net income available to common stockholders	10,739		43,091		64,165		13,724
Weighted average number of shares of common stock outstanding	62,614		56,238		62,285		56,133
Dilutive SARs, RSUs and convertible preferred stock	5,457		10,397		5,458		10,429
Weighted average number of shares of common stock outstanding assuming dilution	68,071		66,635		67,743		66,562
Earnings per share – basic	$	0.17	$	0.77	$	1.03	$	0.24
Earnings per share – diluted	$	0.17	$	0.65	$	0.97	$	0.21

For the three and six months ended June 30, 2013 and 2012, the weighted average number of diluted shares includes all potentially dilutive securities.

(15) Related-Party Transactions

In March 2012, pursuant to the terms of the Series B Convertible Preferred Stock Agreement, Alon issued 1,200,000 shares of 8.5% Series B Convertible Preferred Stock for $12,000 to certain shareholders of Alon Israel and their affiliates. In 2012 and January 2013, 480,000 and 651,820 shares, respectively, of Series B Convertible Preferred Stock were converted into shares of Alon's common stock. At June 30, 2013, 68,180 shares of Series B Convertible Preferred Stock remain outstanding.

(16) Commitments and Contingencies

(a) Commitments

In the normal course of business, Alon has long-term commitments to purchase, at market prices, 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.

(b) Contingencies

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

(c) Environmental

Alon is subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These laws and regulations govern 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 contingent obligations relate to sites owned by Alon and its past or present operations. Alon is currently participating in environmental investigations, assessments and cleanups pertaining to its 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 are unknown and will depend on factors such as the 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

17

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

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 $58,639 ($7,631 accrued liability and $51,008 non-current liability) at June 30, 2013, and $61,402 ($6,730 accrued liability and $54,672 non-current liability) at December 31, 2012.

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 current receivables of $3,239 and $3,239 and non-current receivables of $9,240 and $11,599 at June 30, 2013 and December 31, 2012, respectively.

Alon has indemnification agreements with prior owners for part of the remediation expenses at certain West Coast assets. Alon has recorded current receivables of $604 and $604 and non-current receivables of $1,456 and $1,964 at June 30, 2013 and December 31, 2012, respectively.

(17)    Subsequent Events

Dividend Declared

On August 6, 2013, Alon declared a regular quarterly cash dividend of $0.06 per share payable on September 19, 2013, to stockholders of record at the close of business on September 5, 2013.

Partnership Distribution Declared

On August 5, 2013 the Board of the General Partner declared a cash distribution to the Partnership's common unitholders for the period from April 1, 2013 through and including June 30, 2013 of approximately $44,375, or $0.71 per common unit. The cash distribution will be paid on August 23, 2013 to unitholders of record at the close of business on August 16, 2013. The total cash distribution to be paid to non-affiliated common unitholders is approximately $8,165.

New Supply and Offtake Agreements

In July 2013, Alon entered into offtake agreements with two investment grade oil companies that provides for the sale, at market prices, of light cycle oil and high sulfur distillate blendstock through June 2015. Both agreements will automatically extend for successive one year terms unless either Alon or the other party cancels the agreement by delivering written notice of termination to the other at least 180 days prior to the end of the then current term.

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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, 2012. In this document, the words “Alon,” “the Company,” “we” and “our” refer to Alon USA Energy, Inc. and its subsidiaries or to Alon USA Energy, Inc. or an individual subsidiary, and not to any other person. Generally, the words "we", "our" and "us" include Alon USA Partners, LP and its subsidiaries (the "Partnership") as consolidated subsidiaries of Alon USA Energy, Inc.

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 of 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 spread between West Texas Intermediate ("WTI") crude oil and West Texas Sour ("WTS") crude oil;

• changes in the spread between WTI crude oil and Light Louisiana Sweet ("LLS") crude oil, 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;

• termination of our Supply and Offtake Agreements with J. Aron & Company (“J. Aron”), which include all our refineries and most of our asphalt terminals, of which J. Aron is our largest supplier of crude oil and our largest customer of refined products. Additionally, we are obligated to repurchase all consigned inventories and certain other inventories upon termination of these Supply and Offtake Agreements;

• changes in fuel and utility costs incurred by our facilities;

• disruptions due to equipment interruption, pipeline disruptions or failures 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 the Renewable Fuel Standard, including the availability, cost and price volatility of Renewable Identification Numbers ("RINs");

• the effects of and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;

• operating hazards, natural disasters, casualty losses and other matters beyond our control;

• the effect of any national or international financial crisis 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, 2012 under the caption “Risk Factors”.

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Any one of these factors or a combination of these factors could materially affect our future results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.

Company Overview

We are an independent refiner and marketer of petroleum products operating primarily in the 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 214,000 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 Marketing Segment. Our refining and 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 Paramount, Bakersfield and Long Beach refineries together as our “California refineries.” The refineries in our refining and marketing segment have a combined throughput capacity of approximately 214,000 bpd. At these refineries we refine crude oil into petroleum products, including gasoline, diesel fuel, jet fuel, petrochemicals, petrochemical feedstocks and asphalts, which are marketed primarily in the South Central, Southwestern, and Western United States.

Alon owns the Big Spring refinery and wholesale marketing operations through Alon USA Partners, LP (the "Partnership") (NYSE: ALDW). Alon markets transportation fuels produced at its Big Spring refinery in West and Central Texas, Oklahoma, New Mexico and Arizona. Alon refers to its operations in these regions as its “physically integrated system” because it supplies its Alon branded and unbranded distributors in these regions with motor fuels produced at its Big Spring refinery and distributed through a network of pipelines and terminals which it either owns or has access to through leases or long-term throughput agreements.

We supply gasoline and diesel to approximately 640 Alon branded retail sites, including our retail segment convenience stores. Approximately 65% of the gasoline and 29% of the diesel motor fuel produced at the Big Spring refinery was transferred to our retail segment convenience stores at prices substantially determined by wholesale market prices. Additionally, we license the use of the Alon brand name and provide credit card processing services to approximately 99 licensed locations that are not under fuel supply agreements.

We market refined products purchased by third parties or produced by our California refineries to wholesale distributors, other refiners and third parties primarily on the West Coast. In December 2012, the California refineries suspended operations.

We market refined products produced by our Krotz Springs refinery to other refiners and third parties. The refinery’s location provides access to upriver markets on the Mississippi and Ohio Rivers. The refinery also uses its direct access to the Colonial Pipeline to transport products to markets in the Southern and Eastern United States. The Krotz Springs refinery 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.

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 11 refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Oregon (Willbridge), Washington (Richmond Beach), Arizona (Phoenix and Flagstaff) and Nevada (Fernley) (50% interest) as well as through 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 Segment. Our retail segment operates 298 convenience stores located 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 Alon brand names. Substantially all of the motor fuel sold through our retail segment is supplied by our Big Spring refinery.

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Second Quarter Operational and Financial Highlights

Operating income for the second quarter of 2013 was $42.0 million, compared to operating income of $92.6 million in the same period last year. Our operational and financial highlights for the second quarter of 2013 include the following:

• Combined refinery throughput for the second quarter of 2013 averaged 130,928 bpd, consisting of 72,124 bpd at the Big Spring refinery and 58,804 bpd at the Krotz Springs refinery, compared to 160,071 bpd for the second quarter of 2012, consisting of 64,558 bpd at the Big Spring refinery, 31,206 bpd at the California refineries and 64,307 bpd at the Krotz Springs refinery. The lower throughput rates were due to the California refineries being shut down during the first half of 2013 as well as the impact of the Krotz Springs refinery unplanned shut down and repair of the reformer unit for approximately one month during the second quarter of 2013.

• Operating margin at the Big Spring refinery was $16.21 per barrel for the second quarter of 2013 compared to $25.79 per barrel for the same period in 2012. This decrease in operating margin is mainly due to lower Gulf Coast 3/2/1 crack spreads and a narrowing of the WTI to WTS spread.

• Operating margin at the Krotz Springs refinery was $2.30 per barrel for the second quarter of 2013 compared to $5.28 per barrel for the same period in 2012. This decrease is mainly due to costs incurred from the unplanned shut down and repair of the reformer unit and lower Gulf Coast 2/1/1 crack spreads, partially offset by the higher utilization of lower cost WTI priced crude oils.

• The average Gulf Coast 3/2/1 crack spread was $21.17 per barrel for the second quarter of 2013 compared to $26.04 per barrel for the second quarter of 2012. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the second quarter of 2013 was $4.15 per barrel compared to $7.72 per barrel for the second quarter of 2012.

• The average WTI to WTS spread for the second quarter of 2013 was $0.36 per barrel compared to $5.36 per barrel for the same period in 2012. The average LLS to WTI spread for the second quarter of 2013 was $15.07 per barrel compared to $18.11 per barrel for the same period in 2012.

• Asphalt margins in the second quarter of 2013 were $83.27 per ton compared to $67.31 per ton in the second quarter of 2012. This increase is primarily due to lower costs winter fill asphalt sold during the second quarter of 2013. The average blended asphalt sales price decreased 2.8% from $608.81 per ton in the second quarter of 2012 to $591.81 per ton in the second quarter of 2013 and the average non-blended asphalt sales price decreased 18.0% from $471.41 per ton in the second quarter of 2012 to $386.40 per ton in the second quarter of 2013.

• Retail fuel sales volume increased by 14.5% from 41.5 million gallons in the second quarter of 2012 to 47.5 million gallons in the second quarter of 2013.

• RINs costs for the three and six months ended June 30, 2013 were $8.0 million. We were not subject to the Renewable Fuel Standard requirements in 2012, which resulted in RINs carryforward credits. These 2012 RINs carryforward credits were used to offset our entire RINs obligations, net of RINs generated, during the three months ended March 31, 2013.

Major Influences on Results of Operations

Refining and Marketing. Earnings and cash flows from our refining and marketing segment are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. These prices 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 calculate this margin for each refinery by dividing the refinery’s gross margin by its throughput volumes. Gross margin is the difference between net sales and cost of sales (exclusive of substantial hedge positions and certain inventory adjustments). Each refinery is compared to an industry benchmark that is intended to approximate that refinery's crude slate and product yield.

We compare our Big Spring refinery’s operating margin to the Gulf Coast 3/2/1 crack spread. A Gulf Coast 3/2/1 crack spread is calculated assuming that three barrels of WTI crude oil are converted, or cracked, into two barrels of Gulf Coast conventional gasoline and one barrel of Gulf Coast ultra-low sulfur diesel.

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We compare our California refineries’ operating margin to the West Coast 3/1/1/1 crack spread. A West Coast 3/1/1/1 crack spread is calculated assuming that three barrels of Buena Vista crude oil are converted into one barrel of West Coast LA CARBOB pipeline gasoline, one barrel of LA ultra-low sulfur pipeline diesel and one barrel of LA 380 pipeline CST fuel oil.

We compare our Krotz Springs refinery’s operating margin to the Gulf Coast 2/1/1 crack spread. A Gulf Coast 2/1/1 crack spread is calculated assuming that two barrels of LLS crude oil are converted into one barrel of Gulf Coast conventional gasoline and one barrel of Gulf Coast high sulfur diesel.

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 and the value of West Texas Sour, or WTS, a medium, sour crude oil. We refer to this differential as the WTI/WTS, or 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 and 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 is primarily comprised of LLS crude oil and WTI crude oil. We measure the cost of refining the LLS crude oil by calculating the difference between the average value of LLS crude oil and 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 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 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 or asphalt purchased from third parties. Asphalt is transferred to our asphalt segment from our refining and marketing segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices. At times when refining margins are unfavorable we opportunistically purchase asphalt from other producers for resale. A portion of our asphalt sales are made using fixed price contracts for delivery at future dates. Because these contracts are priced at the market prices for asphalt at the time of the contract, a change in the cost of crude oil between the time we enter into the contract and the time we produce the asphalt can positively or negatively influence the earnings of our asphalt segment. Demand for paving asphalt products is higher during warmer months than during colder months due to seasonal increases in road construction work. As a result, revenues from our asphalt segment for the first and fourth calendar quarters are expected to be lower than those for the second and third calendar quarters.

Retail. Earnings and cash flows from our retail segment are primarily affected by merchandise and retail fuel sales volumes and margins at our convenience stores. 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. Retail fuel margin is equal to retail fuel sales less the delivered cost of fuel and excise taxes, measured on a cents per gallon (“cpg”) basis. Our retail fuel margins are driven by local supply, demand and competitor pricing. Our retail sales are seasonal and peak in the second and third quarters of the year, while the first and fourth quarters usually experience lower overall sales.

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Factors Affecting Comparability

Our financial condition and operating results over the six months ended June 30, 2013 and 2012, have been influenced by the following factors which are fundamental to understanding comparisons of our period-to-period financial performance.

Maintenance and Reduced Crude Oil Throughput

During the three and six months ended June 30, 2013, the Krotz Springs refinery was impacted by the unplanned shut down and repair of the reformer unit for approximately one month.

The California refineries were not in operation for the three and six months ended June 30, 2013 and the first quarter of 2012. The California refineries were in operation for the three months ended June 30, 2012.

Certain Derivative Impacts

Included in unrealized (gains) losses on commodity swaps and cost of sales in the consolidated statements of operations for the three and six months ended June 30, 2013 are total gains of $10.0 million and $10.0 million, respectively, compared to total losses of $7.4 million and $67.0 million for the three and six months ended June 30, 2012, respectively.

Included in other income (loss), net in the consolidated statements of operations are losses on heating oil call option crack spread contracts of $7.3 million for the six months ended June 30, 2012.

Initial Public Offering of Alon USA Partners, LP

On November 26, 2012, the Partnership completed its initial public offering of 11,500,000 common units representing limited partner interests. As of June 30, 2013, the 11,502,476 common units held by the public represent 18.4% of the Partnership's common units outstanding. We own the remaining 81.6% of the Partnership's common units and Alon USA Partners GP, LLC (the "General Partner"), our wholly-owned subsidiary, owns 100% of the non-economic general partner interest in the Partnership. The Partnership is consolidated within the refining and marketing segment.

The non-controlling interest in subsidiaries on the consolidated balance sheets includes the investment by partners other than us, including those partners’ share of net income and distributions of the Partnership since the close of its initial public offering on November 26, 2012. Net income attributable to non-controlling interest on the consolidated statements of operations includes those partners’ share of net income of the Partnership.

Renewable Fuel Standard

RINs costs for the three and six months ended June 30, 2013 were $8.0 million. We were not subject to the Renewable Fuel Standard requirements in 2012, which resulted in RINs carryforward credits. These 2012 RINs carryforward credits were used to offset our entire RINs obligations, net of RINs generated, during the three months ended March 31, 2013.

Costs Associated with Early Repayment of Debt

Interest expense for the six months ended June 30, 2012 includes a charge of $9.6 million for the write-off of unamortized original issuance discount associated with a term loan repayment.

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Results of Operations

The period-to-period comparison of our results of operations has been prepared using the historical periods included in our consolidated financial statements. We refer to our financial statement line items in the explanation of our period-to-period changes in results of operations. Below are general definitions of what those line items include and represent.

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

For the refining and marketing segment, net sales consist of gross sales, net of customer rebates, discounts and excise taxes and includes inter-segment sales to our asphalt and retail segments, which are eliminated through consolidation of our financial statements. Asphalt sales consist of gross sales, net of any discounts and applicable 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. Retail net sales consist of gross merchandise sales, less rebates, commissions and discounts, and gross fuel sales, including excise taxes. Our retail merchandise sales are affected primarily by competition and seasonal influences.

Cost of Sales. Refining and marketing cost of sales includes crude oil and other raw materials, inclusive of transportation costs. Asphalt cost of sales includes costs of purchased asphalt, blending materials and transportation costs. Retail cost of sales includes cost of sales for retail fuels and for merchandise. Retail fuel cost of sales represents the cost of purchased fuel, including transportation costs and associated excises 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 marketing segment and asphalt segment, 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. Corporate overhead and marketing expenses are also included in SG&A expenses for the refining and marketing segment and asphalt segment.

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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 six months ended June 30, 2013 and 2012. 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, 2012 is unaudited.

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(dollars in thousands, except per share data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	1,676,595		$	1,910,489		$	3,327,791		$	3,702,622
Operating costs and expenses:
Cost of sales	1,497,712			1,686,876			2,875,969			3,305,550
Unrealized (gains) losses on commodity swaps	—			(12,871		)	—			32,441
Direct operating expenses	71,446			76,874			145,668			149,083
Selling, general and administrative expenses (2)	43,101			36,208			84,842			71,348
Depreciation and amortization (3)	30,798			30,419			61,961			61,130
Total operating costs and expenses	1,643,057			1,817,506			3,168,440			3,619,552
Gain (loss) on disposition of assets	8,494			(345		)	8,512			(214		)
Operating income	42,032			92,638			167,863			82,856
Interest expense (4)	(20,261		)	(24,300		)	(41,553		)	(55,340		)
Equity earnings of investees	2,110			1,509			1,729			1,570
Other income (loss), net (5)	46			1,107			129			(6,993		)
Income before income tax expense	23,927			70,954			128,168			22,093
Income tax expense	3,985			25,680			34,575			7,929
Net income	19,942			45,274			93,593			14,164
Net income attributable to non-controlling interest	8,446			2,183			27,913			440
Net income available to stockholders	$	11,496		$	43,091		$	65,680		$	13,724
Earnings per share, basic	$	0.17		$	0.77		$	1.03		$	0.24
Weighted average shares outstanding, basic (in thousands)	62,614			56,238			62,285			56,133
Earnings per share, diluted	$	0.17		$	0.65		$	0.97		$	0.21
Weighted average shares outstanding, diluted (in thousands)	68,071			66,635			67,743			66,562
Cash dividends per share	$	0.22		$	0.04		$	0.26		$	0.08
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	(31,016	)	$	83,349		$	129,754		$	114,222
Investing activities	1,491			(32,615		)	(12,082		)	(49,266		)
Financing activities	(88,873		)	(43,507		)	(99,500		)	(164,506		)
OTHER DATA:
Adjusted EBITDA (6)	$	66,492		$	126,018		$	223,170		$	138,777
Capital expenditures (7)	22,208			25,968			30,622			40,525
Capital expenditures for turnaround and chemical catalyst	1,408			6,652			6,624			8,757

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	June 30, 2013		December 31, 2012
BALANCE SHEET DATA (end of period):	(dollars in thousands)
Cash and cash equivalents	$	134,468	$	116,296
Working capital	173,604		87,242
Total assets	2,246,665		2,223,574
Total debt	529,764		587,017
Total debt less cash and cash equivalents	395,296		470,721
Total equity	684,452		621,186

(1) Includes excise taxes on sales by the retail segment of $18,531 and $16,198 for the three months ended June 30, 2013 and 2012, respectively, and $35,836 and $32,322 for the six months ended June 30, 2013 and 2012, respectively.

(2) Includes corporate headquarters selling, general and administrative expenses of $193 and $191 for the three months ended June 30, 2013 and 2012, respectively, and $368 and $381 for the six months ended June 30, 2013 and 2012, respectively, which are not allocated to our three operating segments.

(3) Includes corporate depreciation and amortization of $574 and $624 for the three months ended June 30, 2013 and 2012, respectively, and $1,415 and $1,177 for the six months ended June 30, 2013 and 2012, respectively, which are not allocated to our three operating segments.

(4) Interest expense for the six months ended June 30, 2012 includes a charge of $9,624 for the write-off of unamortized original issuance discount associated with a term loan repayment.

(5) Other income (loss), net for the three and six months ended June 30, 2012 is substantially the gain (loss) on heating oil call option crack spread contracts.

(6) Adjusted EBITDA represents earnings before net income attributable to non-controlling interest, income tax expense, interest expense, depreciation and amortization and gain (loss) 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 net income attributable to non-controlling interest, income tax expense, interest expense, gain (loss) 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.

The following table reconciles net income available to stockholders to Adjusted EBITDA for the three and six months ended June 30, 2013 and 2012, respectively:

26

	For the Three Months Ended					For the Six Months Ended
	June 30,					June 30,
	2013			2012		2013			2012
	(dollars in thousands)
Net income available to stockholders	$	11,496		$	43,091	$	65,680		$	13,724
Net income attributable to non-controlling interest	8,446			2,183		27,913			440
Income tax expense	3,985			25,680		34,575			7,929
Interest expense	20,261			24,300		41,553			55,340
Depreciation and amortization	30,798			30,419		61,961			61,130
(Gain) loss on disposition of assets	(8,494		)	345		(8,512		)	214
Adjusted EBITDA	$	66,492		$	126,018	$	223,170		$	138,777

Adjusted EBITDA does not exclude unrealized (gains) losses on commodity swaps of $(12,871) and $32,441 for the three and six months ended June 30, 2012, respectively. Adjusted EBITDA also does not exclude (gains) losses on heating oil call option crack spread contracts of $(856) and $7,297 for the three and six months ended June 30, 2012, respectively.

(7) Includes corporate capital expenditures of $426 and $657 for the three months ended June 30, 2013 and 2012, respectively, and $439 and $783 for the six months ended June 30, 2013 and 2012, respectively, which are not allocated to our three operating segments.

27

REFINING AND MARKETING SEGMENT (A)
	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(dollars in thousands, except per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	1,443,614		$	1,753,843		$	2,857,739		$	3,389,651
Operating costs and expenses:
Cost of sales	1,316,953			1,584,004			2,500,275			3,087,397
Unrealized (gains) losses on commodity swaps	—			(12,871		)	—			32,441
Direct operating expenses	60,347			68,523			124,016			131,742
Selling, general and administrative expenses	14,598			9,073			28,519			17,609
Depreciation and amortization	26,107			25,758			52,612			52,035
Total operating costs and expenses	1,418,005			1,674,487			2,705,422			3,321,224
Gain on disposition of assets	7,405			4			7,405			4
Operating income	$	33,014		$	79,360		$	159,722		$	68,431
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin – Big Spring (2)	$	16.21		$	25.79		$	21.85		$	20.32
Refinery operating margin – CA Refineries (2)	N/A			2.55			N/A			3.11
Refinery operating margin – Krotz Springs (2)	2.30			5.28			7.67			5.55
Refinery direct operating expense – Big Spring (3)	4.16			4.27			4.85			3.92
Refinery direct operating expense – CA Refineries (3)	N/A			7.41			N/A			12.96
Refinery direct operating expense – Krotz Springs (3)	4.63			3.83			4.53			3.91
Capital expenditures	$	12,646		$	17,476		$	18,615		$	26,177
Capital expenditures for turnaround and chemical catalyst	1,408			6,652			6,624			8,757
PRICING STATISTICS:
Crack spreads (3/2/1) (per barrel):
Gulf Coast	$	21.17		$	26.04		$	24.76		$	25.41
Crack spreads (3/1/1/1) (per barrel):
West Coast	$	9.78		$	11.46		$	10.42		$	12.05
Crack spreads (2/1/1) (per barrel):
Gulf Coast high sulfur diesel	$	4.15		$	7.72		$	6.16		$	10.09
WTI crude oil (per barrel)	$	94.20		$	93.45		$	94.23		$	98.23
Crude oil differentials (per barrel):
WTI less WTS	$	0.36		$	5.36		$	5.86		$	3.76
LLS less WTI	15.07			18.11			17.63			15.36
WTI less Buena Vista	(10.50		)	(14.80		)	(13.12		)	(13.89		)
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	2.69		$	2.80		$	2.77		$	2.89
Gulf Coast ultra-low sulfur diesel	2.86			2.95			2.97			3.05
Gulf Coast high sulfur diesel	2.71			2.89			2.86			3.00
West Coast LA CARBOB (unleaded gasoline)	2.99			3.03			3.04			3.11
West Coast LA ultra-low sulfur diesel	2.89			2.97			3.01			3.11
Natural gas (per MMBtu)	4.02			2.35			3.76			2.43

(A) In the fourth quarter of 2012, based on a change in our internal reporting structure as a result of the Partnership's initial public offering, the branded marketing operations have been combined with the refining and marketing segment and are no longer included with the retail segment. Information for the three and six months ended June 30, 2012 has been recast to provide a comparison to the current period results.

28

THROUGHPUT AND PRODUCTION DATA: BIG SPRING REFINERY	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
WTS crude	53,627	74.4		52,250	81.0		49,446	75.1		53,898	80.4
WTI crude	17,180	23.8		10,738	16.6		14,380	21.8		11,472	17.1
Blendstocks	1,317	1.8		1,570	2.4		2,009	3.1		1,665	2.5
Total refinery throughput (4)	72,124	100.0		64,558	100.0		65,835	100.0		67,035	100.0
Refinery production:
Gasoline	35,057	48.7		30,885	47.8		32,436	49.4		33,012	49.2
Diesel/jet	24,748	34.4		21,242	32.9		22,038	33.6		21,739	32.5
Asphalt	4,453	6.2		4,041	6.2		3,909	6.0		4,288	6.4
Petrochemicals	4,628	6.4		3,838	5.9		4,179	6.4		3,988	6.0
Other	3,088	4.3		4,655	7.2		3,029	4.6		3,921	5.9
Total refinery production (5)	71,974	100.0		64,661	100.0		65,591	100.0		66,948	100.0
Refinery utilization (6)		101.2	%		98.9	%		97.1	%		97.8	%

THROUGHPUT AND PRODUCTION DATA: CALIFORNIA REFINERIES	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
Medium sour crude	—	—		4,910	15.7		—	—		3,167	19.8
Heavy crude	—	—		23,367	74.9		—	—		11,368	71.0
Blendstocks	—	—		2,929	9.4		—	—		1,465	9.2
Total refinery throughput (4)	—	—		31,206	100.0		—	—		16,000	100.0
Refinery production:
Gasoline	—	—		3,406	11.0		—	—		1,700	10.7
Diesel/jet	—	—		7,328	23.7		—	—		3,663	23.1
Asphalt	—	—		9,920	32.1		—	—		5,086	32.1
Light unfinished	—	—		684	2.2		—	—		506	3.2
Heavy unfinished	—	—		8,983	29.1		—	—		4,596	29.0
Other	—	—		599	1.9		—	—		300	1.9
Total refinery production (5)	—	—		30,920	100.0		—	—		15,851	100.0
Refinery utilization (6)		—	%		39.0	%		—	%		20.0	%

THROUGHPUT AND PRODUCTION DATA: KROTZ SPRINGS REFINERY	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
WTI crude	31,060	52.8		17,378	27.0		28,088	47.9		13,344	20.5
Gulf Coast sweet crude	26,226	44.6		46,905	73.0		28,857	49.2		51,128	78.7
Blendstocks	1,518	2.6		24	—		1,677	2.9		520	0.8
Total refinery throughput (4)	58,804	100.0		64,307	100.0		58,622	100.0		64,992	100.0
Refinery production:
Gasoline	22,710	37.9		26,486	40.6		24,800	41.5		26,400	40.3
Diesel/jet	24,267	40.5		27,270	41.9		23,330	39.0		27,991	42.8
Heavy Oils	521	0.9		2,511	3.9		1,144	1.9		2,830	4.3
Other	12,410	20.7		8,822	13.6		10,559	17.6		8,223	12.6
Total refinery production (5)	59,908	100.0		65,089	100.0		59,833	100.0		65,444	100.0
Refinery utilization (6)		68.9	%		77.4	%		71.5	%		77.6	%

29

(1) Net sales include intersegment sales to our asphalt and retail 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 hedge positions and certain inventory adjustments) attributable to each refinery by the refinery's throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margins to these crack spreads to assess our operating performance relative to other participants in our industry.

The refinery operating margin for the three and six months ended June 30, 2013 includes $3,830 and $6,794 of negative inventory effects. The refinery operating margin for the three and six months ended June 30, 2012 includes $648 and $337 of positive inventory effects.

The refinery operating margin excludes realized gains on commodity swaps of $10,018 and $9,994 for the three and six months ended June 30, 2013, as well as charges of $9,318 related to environmental compliance obligations for the three and six months ended June 30, 2013.

The refinery operating margin excludes realized losses on commodity swaps of $20,087 and $34,421 for the three and six months ended June 30, 2012.

(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 by the applicable refinery’s total throughput volumes.

(4) Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process. The California refineries suspended operations in December 2012 and therefore, no throughput data has been presented for the three and six months ended June 30, 2013. Throughput data for the California refineries for the six months ended June 30, 2012 reflects substantially three months of operations as the California refineries were not in operation for the first quarter of 2012.

(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.

30

ASPHALT SEGMENT
	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	2013		2012		2013			2012
	(dollars in thousands, except per ton data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	144,191	$	152,911	$	299,056		$	245,460
Operating costs and expenses:
Cost of sales (1)(2)	127,953		135,748		273,469			218,420
Direct operating expenses	11,099		8,351		21,652			17,341
Selling, general and administrative expenses	1,555		994		3,203			1,920
Depreciation and amortization	1,563		1,414		3,112			2,796
Total operating costs and expenses	142,170		146,507		301,436			240,477
Operating income (loss)	$	2,021	$	6,404	$	(2,380	)	$	4,983
KEY OPERATING STATISTICS:
Blended asphalt sales volume (tons in thousands) (3)	180		238		310			374
Non-blended asphalt sales volume (tons in thousands) (4)	15		17		37			60
Blended asphalt sales price per ton (3)	$	591.81	$	608.81	$	570.28		$	595.62
Non-blended asphalt sales price per ton (4)	386.40		471.41		389.59			378.30
Asphalt margin per ton (5)	83.27		67.31		73.74			62.30
Capital expenditures	$	2,599	$	5,969	$	4,391		$	7,460

(1) Net sales and cost of sales for the three and six months ended June 30, 2013 includes approximately $32,000 and $108,000 of inventory asphalt purchases sold as part of a supply and offtake arrangement. The volumes associated with these sales are excluded from the Key Operating Statistics.

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

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

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

(5) 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.

31

RETAIL SEGMENT (A)
	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(dollars in thousands, except per gallon data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	244,833		$	232,239		$	468,938		$	448,881
Operating costs and expenses:
Cost of sales (2)	208,849			195,628			400,167			381,103
Selling, general and administrative expenses	26,755			25,950			52,752			51,438
Depreciation and amortization	2,554			2,623			4,822			5,122
Total operating costs and expenses	238,158			224,201			457,741			437,663
Gain (loss) on disposition of assets	1,089			(349		)	1,107			(218		)
Operating income	$	7,764		$	7,689		$	12,304		$	11,000
KEY OPERATING STATISTICS:
Number of stores (end of period) (3)	298			300			298			300
Retail fuel sales (thousands of gallons)	47,490			41,538			91,896			82,867
Retail fuel sales (thousands of gallons per site per month)(3)	55			48			54			48
Retail fuel margin (cents per gallon) (4)	20.2			22.5			20.2			20.2
Retail fuel sales price (dollars per gallon) (5)	$	3.40		$	3.60		$	3.40		$	3.53
Merchandise sales	$	83,243		$	82,511		$	156,576		$	155,993
Merchandise sales (per site per month) (3)	$	93		$	92		$	88		$	87
Merchandise margin (6)	31.6		%	32.9		%	31.9		%	32.6		%
Capital expenditures	$	6,537		$	1,866		$	7,177		$	6,105

(A) In the fourth quarter of 2012, based on a change in our internal reporting structure as a result of the Partnership's initial public offering, the branded marketing operations have been combined with the refining and marketing segment and are no longer included with the retail segment. Information for the three and six months ended June 30, 2012 has been recast to provide a comparison to the current period results.

(1) Includes excise taxes on sales of $18,531 and $16,198 for the three months ended June 30, 2013 and 2012, respectively, and $35,836 and $32,322 for the six months ended June 30, 2013 and 2012, respectively.

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

(3) At June 30, 2013, we had 298 retail convenience stores of which 286 sold fuel. At June 30, 2012, we had 300 retail convenience stores of which 287 sold fuel.

(4) Retail fuel margin represents the difference between retail fuel sales revenue and the net cost of purchased retail fuel, including transportation costs and associated motor fuel taxes, expressed on a cents-per-gallon basis. Retail fuel margins are frequently used in the retail industry to measure operating results related to retail fuel sales.

(5) Retail fuel sales price per gallon represents the average sales price for retail 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.

32

Three Months Ended June 30, 2013 Compared to the Three Months Ended June 30, 2012

Net Sales

Consolidated. Net sales for the three months ended June 30, 2013 were $1,676.6 million, compared to $1,910.5 million for the three months ended June 30, 2012, a decrease of $233.9 million. This decrease was primarily due to lower refinery throughput volumes, lower refined product prices and lower asphalt sales volumes and prices, partially offset by increased retail fuel sales volumes.

Refining and Marketing Segment. Net sales for our refining and marketing segment were $1,443.6 million for the three months ended June 30, 2013, compared to $1,753.8 million for the three months ended June 30, 2012, a decrease of $310.2 million, or 17.7%. This decrease was primarily due to lower refinery throughput volumes and lower refined product prices in the three months ended June 30, 2013 compared to the same period last year.

Combined refinery throughput for the three months ended June 30, 2013 averaged 130,928 bpd, consisting of 72,124 bpd at the Big Spring refinery and 58,804 bpd at the Krotz Springs refinery, compared to a combined average throughput of 160,071 bpd for the three months ended June 30, 2012, consisting of 64,558 bpd at the Big Spring refinery, 31,206 bpd at the California refineries and 64,307 bpd at the Krotz Springs refinery. The lower throughput rate for the three months ended June 30, 2013 was primarily due to the California refineries being shut down during the first half of 2013 as well as the impact of the Krotz Springs refinery unplanned shut down and repair of the reformer unit for approximately one month during the three months ended June 30, 2013.

Refined product prices decreased for all of our products in the three months ended June 30, 2013, compared to the three months ended June 30, 2012. The average per gallon price of Gulf Coast gasoline for the three months ended June 30, 2013 decreased $0.11, or 3.9%, to $2.69, compared to $2.80 for the three months ended June 30, 2012. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the three months ended June 30, 2013 decreased $0.09, or 3.1%, to $2.86, compared to $2.95 for the three months ended June 30, 2012. The average per gallon price for Gulf Coast high sulfur diesel for the three months ended June 30, 2013 decreased $0.18, or 6.2%, to $2.71, compared to $2.89 for the three months ended June 30, 2012.

Asphalt Segment. Net sales for our asphalt segment were $144.2 million for the three months ended June 30, 2013, compared to $152.9 million for the three months ended June 30, 2012, a decrease of $8.7 million, or 5.7%. The decrease was primarily due to lower asphalt sales volumes and lower asphalt sales prices partially offset by approximately $32 million of asphalt sales to J. Aron as part of a supply and offtake arrangement. The asphalt sales volume decreased 23.5% from 255 thousand tons for the three months ended June 30, 2012 to 195 thousand tons for the three months ended June 30, 2013. The average blended asphalt sales price decreased 2.8% from $608.81 per ton for the three months ended June 30, 2012 to $591.81 per ton for the three months ended June 30, 2013, and the average non-blended asphalt sales price decreased 18.0% from $471.41 per ton for the three months ended June 30, 2012, to $386.40 per ton for the three months ended June 30, 2013.

Retail Segment. Net sales for our retail segment were $244.8 million for the three months ended June 30, 2013, compared to $232.2 million for the three months ended June 30, 2012, an increase of $12.6 million, or 5.4%. This increase was primarily attributable to a 14.5% increase in retail fuel sales volumes, partially offset by a decrease in retail fuel sales prices.

Cost of Sales

Consolidated. Cost of sales were $1,497.7 million for the three months ended June 30, 2013, compared to $1,686.9 million for the three months ended June 30, 2012, a decrease of $189.2 million. This decrease was primarily due to lower refinery throughput volumes and lower asphalt sales volumes, partially offset by higher crude oil prices and increased retail fuel sales volumes.

Refining and Marketing Segment. Cost of sales for our refining and marketing segment were $1,317.0 million for the three months ended June 30, 2013, compared to $1,584.0 million for the three months ended June 30, 2012, a decrease of $267.0 million. This decrease was primarily due to lower refinery throughput volumes, partially offset by an increase in the cost of WTI and a narrowing of the WTI to WTS spread. The average price of WTI increased 0.8% from $93.45 per barrel for the three months ended June 30, 2012, to $94.20 per barrel for the three months ended June 30, 2013. The WTI to WTS spread narrowed to $0.36 per barrel, a decrease of 93.3%, for the three months ended June 30, 2013 compared to $5.36 per barrel for the three months ended June 30, 2012.

Asphalt Segment. Cost of sales for our asphalt segment were $128.0 million for the three months ended June 30, 2013, compared to $135.7 million for the three months ended June 30, 2012, a decrease of $7.7 million, or 5.7%. This decrease was primarily due to lower sales volumes for the three months ended June 30, 2013 compared to the three months ended June 30, 2012, partially offset by approximately $32 million of asphalt purchases sold to J. Aron as part of a supply and offtake arrangement.

33

Retail Segment. Cost of sales for our retail segment were $208.8 million for the three months ended June 30, 2013, compared to $195.6 million for the three months ended June 30, 2012, an increase of $13.2 million, or 6.7%. This increase was primarily attributable to increases in retail fuel sales volumes.

Direct Operating Expenses

Consolidated. Direct operating expenses were $71.4 million for the three months ended June 30, 2013, compared to $76.9 million for the three months ended June 30, 2012, a decrease of $5.5 million, or 7.2%.

Refining and Marketing Segment. Direct operating expenses for our refining and marketing segment for the three months ended June 30, 2013 were $60.3 million, compared to $68.5 million for the three months ended June 30, 2012, a decrease of $8.2 million, or 12.0%. This decrease was primarily due to the California refineries being shut down for the three months ended June 30, 2013.

Asphalt Segment. Direct operating expenses for our asphalt segment for the three months ended June 30, 2013 were $11.1 million, compared to $8.4 million for the three months ended June 30, 2012, an increase of $2.7 million, or 32.1%. This increase was primarily due to higher natural gas costs and higher facilities maintenance costs.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for the three months ended June 30, 2013 were $43.1 million, compared to $36.2 million for the three months ended June 30, 2012, an increase of $6.9 million, or 19.1%, primarily due to higher employee incentive compensation costs.

Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the three months ended June 30, 2013 were $14.6 million, compared to $9.1 million for the three months ended June 30, 2012, an increase of $5.5 million, or 60.4%. This increase was primarily due to higher employee incentive compensation costs for the three months ended June 30, 2013.

Asphalt Segment. SG&A expenses for our asphalt segment for the three months ended June 30, 2013 were $1.6 million, compared to $1.0 million for the three months ended June 30, 2012. This increase was primarily due to higher employee incentive compensation costs.

Retail Segment. SG&A expenses for our retail segment for the three months ended June 30, 2013 were $26.8 million, compared to $26.0 million for the three months ended June 30, 2012, an increase of $0.8 million, or 3.1%.

Depreciation and Amortization

Depreciation and amortization for the three months ended June 30, 2013 was $30.8 million, compared to $30.4 million for the three months ended June 30, 2012, an increase of $0.4 million, or 1.3%.

Operating Income

Consolidated. Operating income for the three months ended June 30, 2013 was $42.0 million, compared to $92.6 million for the three months ended June 30, 2012, a decrease of $50.6 million. This decrease was primarily due to lower refinery operating margins and lower throughput volumes.

Refining and Marketing Segment. Operating income for our refining and marketing segment was $33.0 million for the three months ended June 30, 2013, compared to $79.4 million for the three months ended June 30, 2012, a decrease of $46.4 million. This decrease was primarily due to lower refinery operating margins and lower throughput volumes at our refineries partially offset by the impacts of commodity swaps. We recorded gains associated with commodity swaps of $10.0 million for the three months ended June 30, 2013 compared to recorded losses on commodity swaps of $7.4 million for the three months ended June 30, 2012.

Refinery operating margin at the Big Spring refinery was $16.21 per barrel for the three months ended June 30, 2013, compared to $25.79 per barrel for the three months ended June 30, 2012. This decrease was due to lower Gulf Coast 3/2/1 crack spreads and a narrowing WTI to WTS spread. The average Gulf Coast 3/2/1 crack spread decreased to $21.17 per barrel for the three months ended June 30, 2013, compared to $26.04 per barrel for the three months ended June 30, 2012. The WTI to WTS spread was $0.36 per barrel for the three months ended June 30, 2013 compared to $5.36 per barrel for the three months ended June 30, 2012. Also impacting operating income at the Big Spring refinery was approximately $8.0 million of costs associated with RINs obligations for the three months ended June 30, 2013.

Refinery operating margin at the Krotz Springs refinery was $2.30 per barrel for the three months ended June 30, 2013, compared to $5.28 per barrel for the three months ended June 30, 2012. This decrease is mainly due to costs incurred from the unplanned shut down and repair of the reformer unit and lower Gulf Coast 2/1/1 crack spreads, partially offset by the higher

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utilization of lower cost WTI priced crude oils. We increased our utilization of WTI priced crudes from 27.0% of total throughput for the three months ended June 30, 2012 to 52.8% for the three months ended June 30, 2013. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the three months ended June 30, 2013 was $4.15 per barrel compared to $7.72 per barrel for the three months ended June 30, 2012.

Asphalt Segment. Operating income for our asphalt segment was $2.0 million for the three months ended June 30, 2013, compared to $6.4 million for the three months ended June 30, 2012, an decrease of $4.4 million. This decrease was primarily due to lower sales volumes and higher direct operating expenses.

Retail Segment. Operating income for our retail marketing segment was $7.8 million for the three months ended June 30, 2013, compared to $7.7 million for the three months ended June 30, 2012, an increase of $0.1 million.

Interest Expense

Interest expense was $20.3 million for the three months ended June 30, 2013, compared to $24.3 million for the three months ended June 30, 2012, a decrease of $4.0 million, or 16.5%. This decrease was primarily due to lower net debt balances for the three months ended June 30, 2013 compared to the three months ended June 30, 2012.

Income Tax Expense

Income tax expense was $4.0 million for the three months ended June 30, 2013, compared to $25.7 million for the three months ended June 30, 2012. The decrease resulted from our lower pre-tax income in the three months ended June 30, 2013, compared to the three months ended June 30, 2012. Additionally, the three months ended June 30, 2013 includes a change in the projected effective income tax rate for the year from 29% to 27%. This lower effective tax rate compared to the prior period is due to the impact of the non-controlling interest's share of Partnership income as a result of the Partnership's initial public offering in November 2012.

Net Income Attributable to Non-controlling Interest

Net income attributable to non-controlling interest represents the proportional share of net income related to non-voting common stock owned by non-controlling interests in our subsidiary, Alon Assets, Inc. In addition, net income attributable to non-controlling interest for the three months ended June 30, 2013 includes the limited partnership unit holders proportional share of the Partnership's income as a result of the Partnership's initial public offering in November 2012. Net income attributable to non-controlling interest was $8.4 million for the three months ended June 30, 2013, compared to $2.2 million for the three months ended June 30, 2012, an increase of $6.2 million.

Net Income Available to Stockholders

Net income available to stockholders was $11.5 million for the three months ended June 30, 2013, compared to income of $43.1 million for the three months ended June 30, 2012, a decrease in income of $31.6 million. This decrease was attributable to the factors discussed above.

Six Months EndedJune 30, 2013 Compared to the Six Months EndedJune 30, 2012

Net Sales

Consolidated. Net sales for the six months ended June 30, 2013 were $3,327.8 million, compared to $3,702.6 million for the six months ended June 30, 2012, a decrease of $374.8 million. This decrease was primarily due to lower refinery throughput volumes and lower refined product prices.

Refining and Marketing Segment. Net sales for our refining and marketing segment were $2,857.7 million for the six months ended June 30, 2013, compared to $3,389.7 million for the six months ended June 30, 2012, a decrease of $532.0 million. The decrease was due to decreased refinery throughput and lower refined product prices.

Combined refinery throughput for the six months ended June 30, 2013 averaged 124,457 bpd, consisting of 65,835 bpd at the Big Spring refinery and 58,622 bpd at the Krotz Springs refinery, compared to 148,027 bpd for the six months ended June 30, 2012, consisting of 67,035 bpd at the Big Spring refinery, 16,000 bpd at the California refineries and 64,992 bpd at the Krotz Springs refinery. The lower throughput rate for the six months ended June 30, 2013 was the result of the California refineries being shut down during 2013 compared to being in operation for the second quarter of 2012 as well as the impact of the Krotz Springs refinery unplanned shut down and repair of the reformer unit for approximately one month during the three months ended June 30, 2013.

The average per gallon price of Gulf Coast gasoline for the six months ended June 30, 2013 decreased $0.12, or 4.2%, to $2.77, compared to $2.89 for the six months ended June 30, 2012. The average per gallon price of Gulf Coast ultra low-sulfur

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diesel for the six months ended June 30, 2013 decreased $0.08, or 2.6%, to $2.97, compared to $3.05 for the six months ended June 30, 2012. The average per gallon price for Gulf Coast high-sulfur diesel for the six months ended June 30, 2013, decreased $0.14, or 4.7%, to $2.86, compared to $3.00 for the six months ended June 30, 2012.

Asphalt Segment. Net sales for our asphalt segment were $299.1 million for the six months ended June 30, 2013, compared to $245.5 million for the six months ended June 30, 2012, an increase of $53.6 million, or 21.8%. This increase was primarily due to approximately $108 million of asphalt sales to J. Aron as part of a supply and offtake arrangement, offset by decreased sales volumes and lower blended asphalt sales prices.

The asphalt sales volume decreased 20.0% from 434 thousand tons for the six months ended June 30, 2012, to 347 thousand tons for the six months ended June 30, 2013. The average blended asphalt sales price decreased 4.3% from $595.62 per ton for the six months ended June 30, 2012, to $570.28 per ton for the six months ended June 30, 2013.

Retail Segment. Net sales for our retail segment were $468.9 million for the six months ended June 30, 2013, compared to $448.9 million for the six months ended June 30, 2012, an increase of $20.0 million or 4.5%. This increase was primarily attributable to a 10.9% increase in retail fuel sales volume, partially offset by lower retail fuel sales prices.

Cost of Sales

Consolidated. Cost of sales was $2,876.0 million for the six months ended June 30, 2013, compared to $3,305.6 million for the six months ended June 30, 2012, a decrease of $429.6 million, or 13.0%. This decrease was primarily due to lower refinery throughput and lower crude oil prices.

Refining and Marketing Segment. Cost of sales for our refining and marketing segment were $2,500.3 million for the six months ended June 30, 2013, compared to $3,087.4 million for the six months ended June 30, 2012, a decrease of $587.1 million, or 19.0%. This decrease was primarily due to lower refinery throughput and lower crude oil prices. The average price of WTI decreased 4.1% from $98.23 per barrel for the six months ended June 30, 2012, to $94.23 per barrel for the six months ended June 30, 2013.

Asphalt Segment. Cost of sales for our asphalt segment were $273.5 million for the six months ended June 30, 2013, compared to $218.4 million for the six months ended June 30, 2012, an increase of $55.1 million, or 25.2%. This increase was primarily due to approximately $108 million of inventory asphalt purchases sold to J. Aron as part of a supply and offtake arrangement, offset by decreased sales volumes for the six months ended June 30, 2013 compared to the six months ended June 30, 2012.

Retail Segment. Cost of sales for our retail segment were $400.2 million for the six months ended June 30, 2013, compared to $381.1 million for the six months ended June 30, 2012, an increase of $19.1 million, or 5.0%. This increase was primarily attributable to increases in retail fuel sales volumes, partially offset by lower retail fuel prices.

Direct Operating Expenses

Consolidated. Direct operating expenses were $145.7 million for the six months ended June 30, 2013, compared to $149.1 million for the six months ended June 30, 2012, a decrease of $3.4 million, or 2.3%.

Refining and Marketing Segment. Direct operating expenses for our refining and marketing segment for the six months ended June 30, 2013 were $124.0 million, compared to $131.7 million for the six months ended June 30, 2012, a decrease of $7.7 million, or 5.8%. This decrease was primarily due to the California refineries being shut down during 2013 compared to being in operation for the second quarter of 2012.

Asphalt Segment. Direct operating expenses for our asphalt segment for the six months ended June 30, 2013, were $21.7 million, compared to $17.3 million for the six months ended June 30, 2012, an increase of $4.4 million, or 25.4%. This increase was primarily due to higher natural gas costs and higher facilities maintenance costs for the six months ended June 30, 2013.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for the six months ended June 30, 2013 were $84.8 million, compared to $71.3 million for the six months ended June 30, 2012, an increase of $13.5 million, or 18.9%. This is primarily due to higher employee incentive compensation costs and advertising costs related to rebranding efforts.

Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the six months ended June 30, 2013 were $28.5 million, compared to $17.6 million for the six months ended June 30, 2012, an increase of $10.9 million or 61.9%. This increase was primarily due to higher employee incentive compensation costs.

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Asphalt Segment. SG&A expenses for our asphalt segment for the six months ended June 30, 2013 were $3.2 million, compared to $1.9 million for the six months ended June 30, 2012, an increase of $1.3 million, or 68.4%. This increase was primarily due to higher employee incentive compensation costs.

Retail Segment. SG&A expenses for our retail segment for the six months ended June 30, 2013 were $52.8 million, compared to $51.4 million for the six months ended June 30, 2012, an increase of $1.4 million, or 2.7%.

Depreciation and Amortization

Depreciation and amortization for the six months ended June 30, 2013 was $62.0 million, compared to $61.1 million for the six months ended June 30, 2012, an increase of $0.9 million, or 1.5%.

Operating Income

Consolidated. Operating income for the six months ended June 30, 2013 was $167.9 million, compared to $82.9 million for the six months ended June 30, 2012, an increase of $85.0 million. This increase was primarily due to improved refinery and asphalt margins, the impact of commodity swaps transactions and lower direct operating costs, partially offset by higher SG&A expenses.

Refining and Marketing Segment. Operating income for our refining and marketing segment was $159.7 million for the six months ended June 30, 2013, compared to $68.4 million for the six months ended June 30, 2012, an increase of $91.3 million. This increase was primarily due to gains on commodity swaps during the six months ended June 30, 2013 of $10.0 million, compared to losses on commodity swaps during the six months ended June 30, 2012 of $67.0 million and also improved refinery operating margins partially offset by higher employee incentive compensation costs.

Refinery operating margin at the Big Spring refinery was $21.85 per barrel for the six months ended June 30, 2013, compared to $20.32 per barrel for the six months ended June 30, 2012. This increase in operating margin is primarily due to a widening of the WTI to WTS spread, partially offset by lower Gulf Coast 3/2/1 crack spreads. The WTI to WTS spread increased 55.9% to $5.86 per barrel for the six months ended June 30, 2013, compared to $3.76 per barrel for the six months ended June 30, 2012. The average Gulf Coast 3/2/1 crack spread decreased 2.6% to $24.76 per barrel for the six months ended June 30, 2013, compared to $25.41 per barrel for the six months ended June 30, 2012. Also impacting operating income at the Big Spring refinery was approximately $8.0 million of costs associated with RINs obligations for the six months ended June 30, 2013.

Refinery operating margin at the Krotz Springs refinery was $7.67 per barrel for the six months ended June 30, 2013, compared to $5.55 per barrel for the six months ended June 30, 2012. This increase is primarily due to increased utilization of WTI priced crude oils during the six months ended June 30, 2013, partially offset by a widening of the LLS to WTI spread and lower Gulf Coast 2/1/1 high sulfur diesel crack spreads. We increased our utilization of WTI priced crudes from 20.5% of total throughput in the six months ended June 30, 2012 to 47.9% in the six months ended June 30, 2013. The LLS to WTI spread increased $2.27 per barrel to $17.63 per barrel for the six months ended June 30, 2013, compared to $15.36 per barrel for the six months ended June 30, 2012. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the six months ended June 30, 2013 was $6.16 per barrel, compared to $10.09 per barrel for the six months ended June 30, 2012.

Asphalt Segment. Operating loss for our asphalt segment was $2.4 million for the six months ended June 30, 2013, compared to operating income of $5.0 million for the six months ended June 30, 2012, a decrease of $7.4 million. This decrease was primarily due to lower sales volumes and prices and also higher direct operating and SG&A expenses.

Retail Segment. Operating income for our retail segment was $12.3 million for the six months ended June 30, 2013, compared to $11.0 million for the six months ended June 30, 2012, an increase of $1.3 million. This increase was primarily due to higher retail fuel sales volumes.

Interest Expense

Interest expense was $41.6 million for the six months ended June 30, 2013, compared to $55.3 million for the six months ended June 30, 2012, a decrease of $13.7 million, or 24.8%. The decrease is primarily due to lower net debt balances for the six months ended June 30, 2013 compared to the six months ended June 30, 2012 and a charge during the six months ended June 30, 2012 of $9.6 million for the write-off of unamortized original issuance discount associated with a term loan repayment.

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Income Tax Expense

Income tax expense was $34.6 million for the six months ended June 30, 2013, compared to $7.9 million for the six months ended June 30, 2012. The increase resulted from our higher pre-tax income for the six months ended June 30, 2013, compared to the six months ended June 30, 2012. Our effective tax rate was 27.0% for the six months ended June 30, 2013, compared to an effective tax rate of 35.9% for the six months ended June 30, 2012. This lower effective tax rate compared to the prior period is due to the impact of the non-controlling interest's share of Partnership income as a result of the Partnership's initial public offering in November 2012.

Net Income Attributable to Non-controlling Interest

Net income attributable to non-controlling interest represents the proportional share of net income related to non-voting common stock owned by non-controlling interests in our subsidiary, Alon Assets, Inc. In addition, net income attributable to non-controlling interest for the six months ended June 30, 2013 includes the limited partnership unit holders proportional share of the Partnership's income as a result of the Partnership's initial public offering in November 2012. Net income attributable to non-controlling interest was $27.9 million for the six months ended June 30, 2013, compared to $0.4 million for the six months ended June 30, 2012, an increase of $27.5 million.

Net Income Available to Stockholders

Net income available to stockholders was $65.7 million for the six months ended June 30, 2013, compared to $13.7 million for the six months ended June 30, 2012, an increase of $52.0 million. This increase was attributable to the factors discussed above.

Liquidity and Capital Resources

Our primary sources of liquidity are cash on hand, cash generated from our operating activities, borrowings under our revolving credit facilities, inventory supply and offtake agreements, other credit lines and advances from affiliates.

We have agreements with J. Aron for the supply of crude oil that will support the operations of the Big Spring refinery, the Krotz Springs refinery and the California refineries as well as the asphalt segment. These agreements substantially reduce our need to issue letters of credit to support crude oil and asphalt purchases. In addition, the structure allows us to acquire crude oil and asphalt without the constraints of a maximum facility size during periods of high crude oil prices.

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 twelve 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.

Cash Flows

The following table sets forth our consolidated cash flows for the six months ended June 30, 2013, and 2012:

	For the Six Months Ended
	June 30,
	2013			2012
	(dollars in thousands)
Cash provided by (used in):
Operating activities	$	129,754		$	114,222
Investing activities	(12,082		)	(49,266		)
Financing activities	(99,500		)	(164,506		)
Net increase (decrease) in cash and cash equivalents	$	18,172		$	(99,550	)

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Cash Flows Provided by Operating Activities

Net cash provided by operating activities during the six months ended June 30, 2013, was $129.8 million, compared to $114.2 million during the six months ended June 30, 2012. The increase in net cash provided by operating activities of $15.6 million was primarily attributable to an increase in net income after adjusting for non-cash items of $31.8 million, a decrease in inventories of $51.2 million, a decrease in prepaid expenses and other current assets of $25.3 million and a decrease in other non-current assets of $19.9 million. These changes were partially offset by a decrease in other non-current liabilities of $55.3 million and less cash collected on accounts receivable of $50.2 million.

Cash Flows Used In Investing Activities

Net cash used in investing activities was $12.1 million during the six months ended June 30, 2013, compared to $49.3 million during the six months ended June 30, 2012. The reduction in net cash used in investing activities of $37.2 million was primarily attributable to an increase in asset sale proceeds of $25.7 million due to the sale of equipment during the six months ended June 30, 2013, as well as a decrease in capital expenditures and capital expenditures for turnarounds and catalysts of $12.0 million for the six months ended June 30, 2013, compared to the six months ended June 30, 2012.

Cash Flows Used In Financing Activities

Net cash used in financing activities was $99.5 million during the six months ended June 30, 2013, compared to $164.5 million during the six months ended June 30, 2012. The reduction in net cash used in financing activities of $65.0 million was primarily attributable to lower net payments on debt of $98.4 million and debt issuance costs of $2.4 million partially offset by higher distributions paid to non-controlling interests of $23.6 million and higher dividends paid to stockholders of $11.7 million during the six months ended June 30, 2013.

Indebtedness

Alon USA Energy, Inc. Letter of Credit Facility. In March 2010, we entered into an unsecured credit facility with Israel Discount Bank of New York (the “Alon Energy Letter of Credit Facility”) for the issuance of letters of credit in an amount not to exceed $60.0 million with a sub-limit for borrowings not to exceed $30.0 million. This facility will terminate in August 2013. The Alon Energy Letter of Credit Facility contains certain restrictive covenants including maintenance financial covenants. At June 30, 2013 and December 31, 2012, we had outstanding letters of credit under this facility of $59.5 million and $59.5 million, respectively.

Alon USA, LP Credit Facility. We have a $240.0 million revolving credit facility (the “Alon USA LP Credit Facility”) that will mature in March 2016. The Alon USA LP Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility or the amount of the borrowing base under the facility. Borrowings under the Alon USA LP Credit Facility bear interest at the Eurodollar rate plus 3.50% per annum subject to an overall minimum interest rate of 4.00%. The Alon USA LP Credit Facility contains certain restrictive covenants including maintenance financial covenants.

There were no outstanding borrowings under the Alon USA LP Credit Facility at June 30, 2013, which had an outstanding balance of $49.0 million at December 31, 2012. At June 30, 2013 and December 31, 2012, outstanding letters of credit under the Alon USA LP Credit Facility were $100.5 million and $58.8 million, respectively.

Financial Covenants. We have certain credit agreements that contain restrictive covenants, including maintenance financial covenants. At June 30, 2013, we were in compliance with these maintenance financial 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 plan for 2013 is $97.5 million. Approximately $37.2 million has been spent during the six months ended June 30, 2013.

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, 2012.

Off-Balance Sheet Arrangements

We have no material off-balance sheet arrangements.

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Critical Accounting Policies

We prepare our consolidated financial statements in conformity with GAAP. In order to apply these principles, we must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events, some of which we may have little or no control over.

Our critical accounting policies are described under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2012. 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, 2012.

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 June 30, 2013, we held approximately 2.1 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 $66.4 million. We refer to this excess as our LIFO reserve. If the market value of these inventories had been $1.00 per barrel lower, our LIFO reserve would have been reduced by $2.1 million.

In accordance with fair value provisions of ASC 825-10, all commodity contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section or accumulated other comprehensive income 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 June 30, 2013:

Description	Contract Volume		Wtd Avg Purchase		Wtd Avg Sales		Contract			Market			Gain
of Activity	(barrels)		Price/BBL		Price/BBL		Value			Value			(Loss)
							(in thousands)
Forwards-long (Crude)	756,739		$	97.20	$	—	$	73,554		$	74,269		$	715
Forwards-long (Gasoline)	168,492		116.79		—		19,678			19,245			(433		)
Forwards-short (Gasoline)	(31,592	)	—		113.12		(3,574		)	(3,492		)	82
Forwards-long (Distillate)	114,218		123.02		—		14,050			13,894			(156		)
Forwards-short (Distillate)	(72,531	)	—		116.76		(8,469		)	(8,370		)	99
Forwards-long (Jet)	45,117		116.39		—		5,251			5,177			(74		)
Forwards-short (Jet)	(19,502	)	—		118.91		(2,319		)	(2,287		)	32
Forwards-long (Slurry)	17,359		83.98		—		1,458			1,440			(18		)
Forwards-short (Slurry)	(1,034	)	—		88.98		(92		)	(91		)	1
Forwards-long (Catfeed)	288,265		113.75		—		32,789			32,152			(637		)
Forwards-short (Catfeed)	(27,468	)	—		113.75		(3,124		)	(3,064		)	60
Forwards-long (Slop)	28,226		85.80		—		2,422			2,443			21
Forwards-short (Slop)	(22,635	)	—		88.29		(1,998		)	(2,016		)	(18		)
Forwards-short (Propane)	(28,010	)	—		36.88		(1,033		)	(1,017		)	16
Forwards-short (Asphalt)	(270,301	)	—		92.44		(24,987		)	(25,346		)	(359		)
Futures-short (Crude)	(762,000	)	—		96.15		(73,265		)	(73,579		)	(314		)
Futures-short (Gasoline)	(360,000	)	—		118.31		(42,590		)	(41,060		)	1,530
Futures-long (Distillate)	7,000		121.47		—		850			840			(10		)
Futures-short (Distillate)	(86,000	)	—		120.99		(10,405		)	(10,326		)	79
Description	Contract Volume		Wtd Avg Contract		Wtd Avg Market		Contract			Market			Gain
of Activity	(barrels)		Spread		Spread		Value			Value			(Loss)
							(in thousands)
Futures-swaps	(7,560,000	)	$	22.65	$	20.89	$	(171,225	)	$	(157,955	)	$	13,270

Interest Rate Risk

As of June 30, 2013, $316.4 million of our outstanding debt was at floating interest rates out of which approximately $248.8 million, excluding discounts, was at the Eurodollar rate (with a floor of 1.25%) plus a margin of 8.00%. An increase of 1% in the Eurodollar rate on indebtedness, net of the instrument subject to a minimum interest rate, would result in an increase in our interest expense of approximately $0.7 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
10.1	Second Amended Revolving Credit Agreement, dated as of May 23, 2013, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 24, 2013, SEC File No. 001-32567).
10.2	Second Amendment to Credit Agreement, dated as of July 31, 2013, to the Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc., and Goldman Sachs Bank USA, as Issuing Bank.
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 June 30, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows and (v) 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:	August 8, 2013	By:	/s/ David Wiessman
			David Wiessman
			Executive Chairman of the Board
Date:	August 8, 2013	By:	/s/ Paul Eisman
			Paul Eisman
			President and Chief Executive Officer
Date:	August 8, 2013	By:	/s/ Shai Even
			Shai Even
			Senior Vice President and Chief Financial Officer
			(Principal Accounting Officer)

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EXHIBITS

Exhibit
Number	Description of Exhibit
10.1	Second Amended Revolving Credit Agreement, dated as of May 23, 2013, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 24, 2013, SEC File No. 001-32567).
10.2	Second Amendment to Credit Agreement, dated as of July 31, 2013, to the Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc., and Goldman Sachs Bank USA, as Issuing Bank.
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 June 30, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows and (v) Notes to the Consolidated Financial Statements.

46