Alon USA Energy, Inc. - FORM 10-Q

Attached files

file	filename
EX-32.1 - CERTIFICATION - Alon USA Energy, Inc.	alj-ex321_2014930xq3.htm
EX-31.1 - CERTIFICATION - Alon USA Energy, Inc.	alj-ex311_2014930xq3.htm
EX-31.2 - CERTIFICATION - Alon USA Energy, Inc.	alj-ex312_2014930xq3.htm
EXCEL - IDEA: XBRL DOCUMENT - Alon USA Energy, Inc.	Financial_Report.xls

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

___________________________________________________

FORM 10-Q



þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2014



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 October 24, 2014, was 69,606,019.

TABLE OF CONTENTS



	Page
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	21
FORWARD-LOOKING STATEMENTS	21
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	44
ITEM 4. CONTROLS AND PROCEDURES	46
PART II. OTHER INFORMATION	47
ITEM 6. EXHIBITS	47
SIGNATURES	48

Table of Contents

PART I. FINANCIAL INFORMATION


ITEM 1.	FINANCIAL STATEMENTS

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(dollars in thousands except per share data)



	September 30, 2014			December 31, 2013
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	193,568		$	224,499
Accounts and other receivables, net	198,871			200,398
Income tax receivable	—			16,053
Inventories	147,340			128,770
Deferred income tax asset	11,377			13,045
Prepaid expenses and other current assets	25,842			18,629
Total current assets	576,998			601,394
Equity method investments	28,297			26,251
Property, plant and equipment, net	1,383,988			1,429,342
Goodwill	101,913			105,943
Other assets, net	131,956			82,210
Total assets	$	2,223,152		$	2,245,140
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	323,331		$	336,499
Accrued liabilities	113,052			120,858
Current portion of long-term debt	15,083			83,174
Total current liabilities	451,466			540,531
Other non-current liabilities	175,220			189,474
Long-term debt	540,875			529,074
Deferred income tax liability	364,346			360,657
Total liabilities	1,531,907			1,619,736
Commitments and contingencies (Note 16)
Stockholders’ equity:
Preferred stock, par value $0.01, 15,000,000 shares authorized; 68,180 shares issued and outstanding at September 30, 2014 and December 31, 2013	682			682
Common stock, par value $0.01, 150,000,000 shares authorized; 69,441,197 and 68,641,428 shares issued and outstanding at September 30, 2014 and December 31, 2013, respectively	694			686
Additional paid-in capital	515,213			509,170
Accumulated other comprehensive loss, net of tax	(6,830		)	(37,515		)
Retained earnings	141,540			124,936
Total stockholders’ equity	651,299			597,959
Non-controlling interest in subsidiaries	39,946			27,445
Total equity	691,245			625,404
Total liabilities and equity	$	2,223,152		$	2,245,140

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

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, dollars in thousands except per share data)



	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Net sales (1)	$	1,850,097		$	1,892,836		$	5,276,225		$	5,220,627
Operating costs and expenses:
Cost of sales	1,608,080			1,789,320			4,695,072			4,665,289
Direct operating expenses	70,356			72,035			208,664			217,703
Selling, general and administrative expenses	44,114			40,224			129,836			125,066
Depreciation and amortization	32,170			30,988			91,501			92,949
Total operating costs and expenses	1,754,720			1,932,567			5,125,073			5,101,007
Gain (loss) on disposition of assets	(1,372		)	334			745			8,846
Operating income (loss)	94,005			(39,397		)	151,897			128,466
Interest expense	(28,202		)	(22,263		)	(85,473		)	(63,816		)
Equity earnings of investees	1,982			3,426			2,801			5,155
Other income, net	20			91			641			220
Income (loss) before income tax expense	67,805			(58,143		)	69,866			70,025
Income tax expense (benefit)	14,331			(24,958		)	14,454			9,617
Net income (loss)	53,474			(33,185		)	55,412			60,408
Net income (loss) attributable to non-controlling interest	14,992			(4,476		)	23,662			23,437
Net income (loss) available to stockholders	$	38,482		$	(28,709	)	$	31,750		$	36,971
Earnings (loss) per share, basic	$	0.56		$	(0.47	)	$	0.46		$	0.56
Weighted average shares outstanding, basic (in thousands)	69,153			62,901			68,873			62,490
Earnings (loss) per share, diluted	$	0.55		$	(0.47	)	$	0.46		$	0.54
Weighted average shares outstanding, diluted (in thousands)	69,556			62,901			69,261			67,989
Cash dividends per share	$	0.10		$	0.06		$	0.22		$	0.32

___________


(1)	Includes excise taxes on sales by the retail segment of $19,012 and $19,307 for the three months and $55,923 and $55,143 for the nine months ended September 30, 2014 and 2013, respectively.

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

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited, dollars in thousands)



	For the Three Months Ended					For the Nine Months Ended
	September 30,					September 30,
	2014		2013			2014			2013
Net income (loss)	$	53,474	$	(33,185	)	$	55,412		$	60,408
Other comprehensive income (loss):
Interest rate derivatives designated as cash flow hedges:
Unrealized holding gain (loss) arising during period	283		—			(519		)	—
Loss reclassified to earnings - interest expense	21		—			35			—
Net gain (loss), before tax	304		—			(484		)	—
Income tax expense (benefit)	111		—			(179		)	—
Net gain (loss), net of tax	193		—			(305		)	—
Commodity contracts designated as cash flow hedges:
Unrealized holding gain arising during period	5,051		7,208			37,558			28,958
Gain reclassified to earnings - cost of sales	—		(11,339		)	—			(21,333		)
Amortization of unrealized loss on de-designated cash flow hedges - cost of sales	2,753		—			13,181			—
Net gain (loss), before tax	7,804		(4,131		)	50,739			7,625
Income tax expense (benefit)	2,888		(1,529		)	18,773			2,831
Net gain (loss), net of tax	4,916		(2,602		)	31,966			4,794
Total other comprehensive income (loss), net of tax	5,109		(2,602		)	31,661			4,794
Comprehensive income (loss)	58,583		(35,787		)	87,073			65,202
Comprehensive income (loss) attributable to non-controlling interest	15,100		(4,555		)	24,638			23,627
Comprehensive income (loss) attributable to stockholders	$	43,483	$	(31,232	)	$	62,435		$	41,575

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

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited, dollars in thousands)

	For the Nine Months Ended
	September 30,
	2014			2013
Cash flows from operating activities:
Net income	$	55,412		$	60,408
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	91,501			92,949
Stock compensation	5,776			5,070
Deferred income tax expense (benefit)	(13,237		)	613
Equity earnings of investees	(1,449		)	(4,286		)
Amortization of debt issuance costs	2,955			3,474
Amortization of original issuance discount	4,805			2,591
Write-off of unamortized original issuance discount	391			—
Write-off of unamortized debt issuance costs	358			—
Gain on disposition of assets	(745		)	(8,846		)
Unrealized loss on commodity swaps	10,774			—
Changes in operating assets and liabilities:
Accounts and other receivables, net	12,604			(8,572		)
Income tax receivable	16,053			—
Inventories	(19,554		)	(48,667		)
Prepaid expenses and other current assets	(7,213		)	3,626
Other assets, net	(773		)	5,091
Accounts payable	(19,163		)	(24,350		)
Accrued liabilities	8,603			14,352
Other non-current liabilities	(2,514		)	16,208
Net cash provided by operating activities	144,584			109,661
Cash flows from investing activities:
Capital expenditures	(73,796		)	(48,311		)
Capital expenditures for turnarounds and catalysts	(51,392		)	(6,843		)
Contribution to equity method investment	(597		)	(781		)
Proceeds from disposition of assets	41,032			25,745
Net cash used in investing activities	(84,753		)	(30,190		)
Cash flows from financing activities:
Dividends paid to stockholders	(15,102		)	(19,988		)
Dividends paid to non-controlling interest	(389		)	(731		)
Distributions paid to non-controlling interest in the Partnership	(11,506		)	(31,746		)
Equity issuance costs	—			(1,012		)
Inventory agreement transactions	(200		)	—
Deferred debt issuance costs	(2,079		)	(4,126		)
Revolving credit facilities, net	(50,000		)	31,000
Additions to long-term debt	145,000			150,000
Payments on long-term debt	(156,486		)	(12,765		)
Proceeds from issuance of warrants	—			13,230
Payments for purchases of hedges on convertible debt	—			(28,455		)
Net cash provided by (used in) financing activities	(90,762		)	95,407
Net increase (decrease) in cash and cash equivalents	(30,931		)	174,878
Cash and cash equivalents, beginning of period	224,499			116,296
Cash and cash equivalents, end of period	$	193,568		$	291,174
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$	85,261		$	50,534
Cash paid (refunds received) for income tax	$	(6,619	)	$	19,101
Supplemental disclosure of non-cash activity:
Capital expenditures included in accounts payable and accrued liabilities	$	4,495		$	—

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

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited, dollars in thousands except as noted)


(1)	Basis of Presentation

As used in this report, unless otherwise specified, the terms “Alon,” “we,” “us” or “our” refer to Alon USA Energy, Inc. and its consolidated subsidiaries or to Alon USA Energy, Inc. or an individual subsidiary. The “Partnership,” as used in this report, refers to Alon USA Partners, LP and its consolidated subsidiaries.

These consolidated financial statements and notes 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 our 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 our 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. Our results of operations for the three and nine month periods ended September 30, 2014 are not necessarily indicative of the operating results that may be realized for the year ending December 31, 2014.

Our consolidated balance sheet as of December 31, 2013, 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 our Annual Report on Form 10-K for the year ended December 31, 2013.

New Accounting Standards

In May 2014, the Financial Accounting Standards Board and the International Accounting Standards Board jointly issued a comprehensive new revenue recognition standard that provides accounting guidance for all revenue arising from contracts to provide goods or services to customers. This standard is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets. The requirements from the new standard are effective for interim and annual periods beginning after December 15, 2016, and early adoption is not permitted. The standard allows for either full retrospective adoption or modified retrospective adoption. We are evaluating the guidance to determine the method of adoption and the impact of this standard on our consolidated financial statements.


(2)	Alon USA Partners, LP

The Partnership (NYSE: ALDW) is a publicly-traded limited partnership that owns the assets and conducts the operations of the Big Spring refinery and the associated wholesale marketing operations. As of September 30, 2014, the 11,506,550 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 limited partner interests in the Partnership not owned by us are reflected in the results of operations in net income attributable to non-controlling interest and in our balance sheet in non-controlling interest in subsidiaries. The Partnership is consolidated within the refining and marketing segment.

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

Partnership Distributions

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

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

During the nine months ended September 30, 2014, the Partnership paid the following cash distributions:



Date Paid	Distribution Amount Per Unit		Total Distribution Amount		Distribution Paid to Non-Affiliated Common Unitholders
March 3, 2014	$	0.18	$	11,250	$	2,070
May 21, 2014	0.69		43,130		7,940
August 25, 2014	0.13		8,126		1,496


(3)	Segment Data

Our 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.

(a)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 (the “California refineries”); and a light sweet crude oil refinery located in Krotz Springs, Louisiana. Our refineries have a combined throughput capacity of approximately 217,000 barrels per day (“bpd”). At these refineries, we refine crude oil into petroleum products including gasoline, diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum-based products, which are marketed primarily in the South Central, Southwestern and Western regions of the United States. During the nine months ended September 30, 2014 and 2013, we did not process crude oil at our California refineries.

We supply gasoline and diesel to 641 Alon branded retail sites, including our retail segment convenience stores. During 2014, approximately 63% of the gasoline and 29% of the diesel produced at our Big Spring refinery was transferred to our branded marketing business 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 75 licensed locations that are not under fuel supply agreements.

(b)Asphalt Segment

Our asphalt segment includes 10 refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), 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, which specializes in marketing patented tire rubber modified asphalt products. The operations in which we have 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. Asphalt produced by our Big Spring refinery 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.

(c)Retail Segment

Our retail segment operates 296 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.

(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.

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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 nine month periods ended September 30, 2014 and 2013 are presented below:



	Refining and Marketing		Asphalt			Retail			Corporate			Consolidated Total
Three Months Ended September 30, 2014
Net sales to external customers	$	1,463,985	$	136,992		$	249,120		$	—		$	1,850,097
Intersegment sales (purchases)	153,296		(18,846		)	(134,450		)	—			—
Depreciation and amortization	27,506		1,219			2,847			598			32,170
Operating income (loss)	98,028		(10,097		)	6,850			(776		)	94,005
Total assets	1,868,545		115,696			218,127			20,784			2,223,152
Turnarounds, catalysts and capital expenditures	36,591		1,053			5,872			748			44,264



	Refining and Marketing			Asphalt			Retail			Corporate			Consolidated Total
Three Months Ended September 30, 2013
Net sales to external customers	$	1,446,918		$	194,230		$	251,688		$	—		$	1,892,836
Intersegment sales (purchases)	164,339			(27,131		)	(137,208		)	—			—
Depreciation and amortization	26,255			1,588			2,538			607			30,988
Operating income (loss)	(47,587		)	1,723			7,250			(783		)	(39,397		)
Total assets	2,032,798			145,313			209,122			23,109			2,410,342
Turnarounds, catalysts and capital expenditures	11,754			1,556			4,369			229			17,908



	Refining and Marketing		Asphalt			Retail			Corporate			Consolidated Total
Nine Months Ended September 30, 2014
Net sales to external customers	$	4,202,358	$	350,840		$	723,027		$	—		$	5,276,225
Intersegment sales (purchases)	441,165		(45,062		)	(396,103		)	—			—
Depreciation and amortization	77,587		3,581			8,544			1,789			91,501
Operating income (loss)	154,797		(17,191		)	16,609			(2,318		)	151,897
Total assets	1,868,545		115,696			218,127			20,784			2,223,152
Turnarounds, catalysts and capital expenditures	106,715		4,272			12,094			2,107			125,188



	Refining and Marketing		Asphalt			Retail			Corporate			Consolidated Total
Nine Months Ended September 30, 2013
Net sales to external customers	$	4,006,715	$	493,286		$	720,626		$	—		$	5,220,627
Intersegment sales (purchases)	462,281		(68,422		)	(393,859		)	—			—
Depreciation and amortization	78,867		4,700			7,360			2,022			92,949
Operating income (loss)	112,135		(657		)	19,554			(2,566		)	128,466
Total assets	2,032,798		145,313			209,122			23,109			2,410,342
Turnarounds, catalysts and capital expenditures	36,993		5,947			11,546			668			55,154

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

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

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)


(4)	Fair Value

We 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. We classify financial assets and financial liabilities into the following fair value hierarchy:


•	Level 1 - valued based on quoted prices in active markets for identical assets and liabilities;


•	Level 2 - valued based on quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability; and


•	Level 3 - valued based on unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.

As required, we utilize 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. We generally apply 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 our 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 instruments are carried at fair value, which are based on quoted market prices. Derivative instruments and the Renewable Identification Numbers (“RINs”) obligation are our only assets and liabilities measured at fair value on a recurring basis.

The RINs obligation represents the period-end deficit, if any, after considering any RINs acquired or under contract, necessary to meet our requirements to blend biofuels into the products we have produced. 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 September 30, 2014 and December 31, 2013:



	Level 1		Level 2		Level 3		Total
As of September 30, 2014
Assets:
Commodity contracts (swaps)	$	—	$	13,068	$	—	$	13,068
Liabilities:
Commodity contracts (futures and forwards)	2,501		—		—		2,501
Interest rate swaps	—		484		—		484
Fair value hedges	—		1,740		—		1,740

As of December 31, 2013
Assets:
Commodity contracts (futures and forwards)	$	335	$	—	$	—	$	335
Liabilities:
Commodity contracts (swaps)	—		15,328		11,569		26,897
Fair value hedges	—		3,339		—		3,339
RINs obligation	—		334		—		334

Level 3 Financial Instruments

As of December 31, 2013, we had commodity price swap contracts related to forecasted sales of jet fuel and forecasted purchases of crude oil for which quoted forward market prices were not readily available. The forward rate used to value these commodity price swaps was derived using a projected forward rate using quoted market rates for similar products, adjusted for product grade differentials, a level 3 input. In January 2014, quoted forward market prices for these commodities became available, and the related financial liability was reclassified to level 2.

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

The following table presents the changes in fair value of our level 3 assets and liabilities (all related to commodity price swap contracts) for the nine months ended September 30, 2014:



	For the Nine Months Ended September 30, 2014
Balance at beginning of period	$	(11,569	)
Change in fair value of level 3 trades open at the beginning of the period	—
Fair value of trades entered into during the period	—
Fair value of reclassification from level 3 to level 2	11,569
Settlement value of contractual maturities - Recognized in cost of sales	—
Balance at end of period	$	—


(5)	Derivative Financial Instruments

We selectively utilize crude oil and refined product commodity derivative contracts to reduce the risk associated with potential price changes on committed obligations as well as to reduce earnings volatility. We also utilize interest rate swaps to manage our exposure to interest rate risk. We do not speculate using derivative instruments. Credit risk on our derivative instruments is mitigated by transacting with counterparties meeting established collateral and credit criteria.

Mark to Market

We have certain contracts that serve as economic hedges, which are derivatives used for risk management but not designated as hedges for financial accounting purposes. All economic hedge transactions are recorded at fair value and any changes in fair value between periods are recognized in earnings.

We have contracts that are used to fix prices on forecasted purchases of inventory. 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 executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period.

We also have economic hedges in the form of swap contracts that fix the price differential between Brent crude oil and the crude oil that we process at our refineries. At September 30, 2014, we have swap contracts for 2,160 thousand barrels of crude oil, with contract terms through December 2015.

Fair Value Hedges

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

As of September 30, 2014, we have accounted for certain commodity contracts as fair value hedges with contract purchase volumes of 821 thousand barrels of crude oil with remaining contract terms through May 2019.

Cash Flow Hedges

To designate a derivative as a cash flow hedge, we document 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 transactions occur.

Commodity Derivatives. As of September 30, 2014, we have accounted for certain commodity swap contracts as cash flow hedges with net contract purchase volumes of 3,600 thousand barrels of crude oil and net contract sales volumes of 3,600 thousand barrels of refined products with the longest remaining contract term of fifteen months. Related to these transactions in other comprehensive income (“OCI”), we recognized unrealized gains (losses) of $7,804 and $(4,131) for the three months and$50,739 and $7,625 for the nine months ended September 30, 2014 and 2013, respectively.

In November 2013 and April 2014, we elected to de-designate certain commodity swap contracts that were previously designated as cash flow hedges. As of September 30, 2014, we have total net unrealized losses of $2,391 classified in OCI that related to the application of hedge accounting prior to de-designation, which will be recorded into earnings as the underlying

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

transactions occur through the remainder of 2014. During the three and nine months ended September 30, 2014, we reclassified $2,753 and $13,181 of losses, respectively, related to these de-designated cash flow hedges from OCI into cost of sales.

Interest Rate Derivatives. In April 2014, we entered into three interest rate swap agreements, maturing March 2019, that effectively fix the variable LIBOR interest component of the term loan within the Alon Retail Credit Agreement, as defined in Note 12. The aggregate notional amount under these agreements covers approximately 75% of the outstanding principal of the term loan throughout the duration of the interest rate swaps. As of September 30, 2014, the outstanding principal of the term loan was $104,500. The interest rate swaps lock in an average fixed interest rate of 0.25% in 2014; 0.60% in 2015; 1.47% in 2016; 2.35% in 2017; 3.09% in 2018 and 3.28% thereafter. The interest rate swaps have been accounted for as cash flow hedges. Related to these transactions in OCI, we recognized unrealized gains (losses) of $304 and $(484) during the three and nine months ended September 30, 2014, respectively.

For the three and nine months ended September 30, 2014 and 2013, there was no cash flow hedge ineffectiveness recognized in income. No component of our cash flow hedges’ gains or losses was excluded from the assessment of hedge effectiveness.

As of September 30, 2014, we have net unrealized gains of $20,274 classified in OCI related to cash flow hedges. Assuming commodity prices and interest rates remain unchanged, unrealized gains of $14,257 will be reclassified from OCI into earnings as the underlying transactions occur over the next twelve-month period.

The following tables present the effect of derivative instruments on the consolidated statements of financial position:



	As of September 30, 2014
	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	2,918	Accrued liabilities	$	5,419
Commodity contracts (swaps)	Accounts receivable	1,814		Accrued liabilities	368
Commodity contracts (swaps)	Other assets, net	94		Other non-current liabilities	51
Total derivatives not designated as hedging instruments		$	4,826		$	5,838

Derivatives designated as hedging instruments:
Commodity contracts (swaps)	Accounts receivable	$	9,263		$	—
Commodity contracts (swaps)	Other assets, net	2,316			—
Interest rate swaps		—		Other non-current liabilities	484
Fair value hedges		—		Other non-current liabilities	1,740
Total derivatives designated as hedging instruments		11,579			2,224
Total derivatives		$	16,405		$	8,062

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)



	As of December 31, 2013
	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	1,533	Accrued liabilities	$	1,198
Total derivatives not designated as hedging instruments		$	1,533		$	1,198

Derivatives designated as hedging instruments:
Commodity contracts (swaps)		$	—	Accrued liabilities	$	15,328
Commodity contracts (swaps)		—		Other non-current liabilities	11,569
Fair value hedges		—		Other non-current liabilities	3,339
Total derivatives designated as hedging instruments		—			30,236
Total derivatives		$	1,533		$	31,434

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

Derivatives designated as hedging instruments:



Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				Gain (Loss) Reclassified from Accumulated OCI into Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
				Location	Amount			Location	Amount
For the Three Months Ended September 30, 2014
Commodity contracts (swaps)	$	7,804		Cost of sales	$	(2,753	)		$	—
Interest rate swaps	304			Interest expense	(21		)		—
Total derivatives	$	8,108			$	(2,774	)		$	—

For the Three Months Ended September 30, 2013
Commodity contracts (swaps)	$	(4,131	)	Cost of sales	$	11,339			$	—
Total derivatives	$	(4,131	)		$	11,339			$	—



Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				Gain (Loss) Reclassified from Accumulated OCI into Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
				Location	Amount			Location	Amount
For the Nine Months Ended September 30, 2014
Commodity contracts (swaps)	$	50,739		Cost of sales	$	(13,181	)		$	—
Interest rate swaps	(484		)	Interest expense	(35		)		—
Total derivatives	$	50,255			$	(13,216	)		$	—

For the Nine Months Ended September 30, 2013
Commodity contracts (swaps)	$	7,625		Cost of sales	$	21,333			$	—
Total derivatives	$	7,625			$	21,333			$	—

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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 Nine Months Ended
		September 30,					September 30,
	Location	2014		2013			2014		2013
Fair value hedges	Cost of sales	$	8,650	$	(7,888	)	$	1,599	$	(9,746	)
Total derivatives		$	8,650	$	(7,888	)	$	1,599	$	(9,746	)

Derivatives not designated as hedging instruments:



		Gain (Loss) Recognized in Income
		For the Three Months Ended						For the Nine Months Ended
		September 30,						September 30,
	Location	2014			2013			2014			2013
Commodity contracts (futures & forwards)	Cost of sales	$	(6,674	)	$	(1,757	)	$	(12,792	)	$	8,762
Commodity contracts (swaps)	Cost of sales	1,489			—			3,290			—
Total derivatives		$	(5,185	)	$	(1,757	)	$	(9,502	)	$	8,762

Offsetting Assets and Liabilities

Our commodity derivative financial instruments are subject to master netting arrangements to manage counterparty credit risk associated with derivatives and we offset the fair value amounts recorded for derivative instruments to the extent possible under these agreements on our consolidated balance sheets.

The following table presents offsetting information regarding our derivatives by type of transaction as of September 30, 2014 and December 31, 2013:



	Gross Amounts of Recognized Assets/Liabilities		Gross Amounts offset in the Statement of Financial Position			Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not offset in the Statement of Financial Position					Net Amount
	Gross Amounts of Recognized Assets/Liabilities		Gross Amounts offset in the Statement of Financial Position					Financial Instruments			Cash Collateral Pledged		Net Amount
As of September 30, 2014
Derivative Assets:
Commodity contracts (futures & forwards)	$	3,240	$	(322	)	$	2,918	$	(2,918	)	$	—	$	—
Commodity contracts (swaps)	13,487		—			13,487		(419		)	—		13,068
Derivative Liabilities:
Commodity contracts (futures & forwards)	$	5,741	$	(322	)	$	5,419	$	(2,918	)	$	—	$	2,501
Commodity contracts (swaps)	419		—			419		(419		)	—		—
Interest rate swaps	484		—			484		—			—		484
Fair value hedges	1,740		—			1,740		—			—		1,740

As of December 31, 2013
Derivative Assets:
Commodity contracts (futures & forwards)	$	2,287	$	(754	)	$	1,533	$	(1,198	)	$	—	$	335
Derivative Liabilities:
Commodity contracts (futures & forwards)	$	1,952	$	(754	)	$	1,198	$	(1,198	)	$	—	$	—
Commodity contracts (swaps)	26,897		—			26,897		—			—		26,897
Fair value hedges	3,339		—			3,339		—			—		3,339

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

Compliance Program Market Risk

We are obligated by government regulations to blend a certain percentage of biofuels into the products we produce that are consumed in the U.S. We purchase biofuels from third parties and blend those biofuels into our products, and each gallon of biofuel purchased includes a RIN. To the degree we are unable to blend biofuels at the required percentage, a RINs deficit is generated and we must acquire that number of RINs by the annual reporting deadline in order to remain in compliance with applicable regulations.

We are exposed to market risk related to the volatility in the price of RINs needed to comply with these government regulations. We manage this risk by purchasing RINs when prices are deemed favorable utilizing fixed price purchase contracts. Some of these contracts are derivative instruments; however, we elect the normal purchase and sale exception and do not record these contracts at their fair values.

The cost of meeting our obligations under these compliance programs was $8,469 and $1,178 for the three months ended and $20,823 and $9,194 for the nine months ended September 30, 2014 and 2013, respectively. These amounts are reflected in cost of sales.


(6)	Inventories

Our 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:



	September 30, 2014		December 31, 2013
Crude oil, refined products, asphalt and blendstocks	$	42,336	$	34,326
Crude oil inventory consigned to others	51,336		44,081
Materials and supplies	21,853		21,685
Store merchandise	23,713		20,526
Store fuel	8,102		8,152
Total inventories	$	147,340	$	128,770

Market values of crude oil, refined products, asphalt and blendstock inventories exceeded LIFO costs by $57,264 and $61,199 at September 30, 2014 and December 31, 2013, respectively.


(7)	Inventory Financing Agreements

Alon has 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 and most of our asphalt terminals. Pursuant to the Supply and Offtake Agreements, (i) J. Aron agreed to sell to us, and we agreed to buy from J. Aron, at market prices, crude oil for processing at the refineries and (ii) we 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 our 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 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. We may elect to terminate in May 2018 on six months prior notice.

Following expiration or termination of the Supply and Offtake Agreements, we are obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the leased storage facilities at then current market prices. Financing charges related to the Supply and Offtake Agreements are recorded as interest expense in the consolidated statements of operations.

In association with the Supply and Offtake Agreement at the Krotz Springs refinery, we have 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

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

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”), our wholly-owned subsidiary. 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. As of September 30, 2014, there is no further availability under the Krotz Springs Standby LC Facility. The Krotz Springs Standby LC Facility matures in July 2016.

As of September 30, 2014 and December 31, 2013, we had net current payables to J. Aron for purchases of $24,915 and $16,917, respectively, non-current liabilities related to the original financing of $74,222 and $67,889, respectively, and a consignment inventory receivable representing a deposit paid to J. Aron of $26,179 and $26,179, respectively.

Additionally, we had net current payables of $4,799 and $539 at September 30, 2014 and December 31, 2013, 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.


(8)	Property, Plant and Equipment, Net

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



	September 30, 2014			December 31, 2013
Refining facilities	$	1,811,482		$	1,804,445
Pipelines and terminals	43,439			43,445
Retail	195,600			184,858
Other	17,319			15,326
Property, plant and equipment, gross	2,067,840			2,048,074
Accumulated depreciation	(683,852		)	(618,732		)
Property, plant and equipment, net	$	1,383,988		$	1,429,342

Disposition of Assets

In January 2014, we sold our Willbridge, Oregon asphalt terminal for $40,000. The terminal was included in our asphalt segment and at the time of disposition was allocated goodwill of $4,030. For the nine months ended September 30, 2014, a before-tax gain of $1,987 was recognized and has been included in gain (loss) on disposition of assets in our consolidated statements of operations.


(9)	Goodwill

The following table provides a summary of changes to our goodwill balance for the nine months ended September 30, 2014:



Balance at December 31, 2013	$	105,943
Disposition of assets with allocated goodwill	(4,030		)
Balance at September 30, 2014	$	101,913

During the nine months ended September 30, 2014, we sold our Willbridge, Oregon asphalt terminal, which was allocated goodwill of $4,030 at the time of disposition.

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)


(10)	Additional Financial Information

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


(a)	Other Assets, Net



	September 30, 2014		December 31, 2013
Deferred turnaround and catalyst cost	$	60,300	$	12,271
Environmental receivables	1,959		4,273
Deferred debt issuance costs	11,368		12,602
Intangible assets, net	7,782		7,497
Receivable from supply agreements	26,179		26,179
Commodity contracts	2,410		—
Other, net	21,958		19,388
Total other assets	$	131,956	$	82,210


(b)	Accrued Liabilities and Other Non-Current Liabilities



	September 30, 2014		December 31, 2013
Accrued Liabilities:
Taxes other than income taxes, primarily excise taxes	$	32,067	$	37,645
Employee costs	14,388		13,793
Commodity contracts	5,787		16,526
Accrued finance charges	824		8,733
Environmental accrual (Note 16)	12,898		12,898
Other	47,088		31,263
Total accrued liabilities	$	113,052	$	120,858

Other Non-Current Liabilities:
Pension and other postemployment benefit liabilities, net	$	38,675	$	40,351
Environmental accrual (Note 16)	39,930		45,484
Asset retirement obligations	12,165		12,468
Consignment inventory obligations	74,222		67,889
Commodity contracts	51		11,569
Other	10,177		11,713
Total other non-current liabilities	$	175,220	$	189,474


(11)	Postretirement Benefits

The components of net periodic benefit cost related to our benefit plans for the three and nine months ended September 30, 2014 and 2013 consisted of the following:



	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	856		$	1,116		$	2,568		$	3,348
Interest cost	1,238			1,100			3,714			3,300
Expected return on plan assets	(1,370		)	(1,158		)	(4,109		)	(3,472		)
Amortization of net loss	596			1,006			1,787			3,016
Net periodic benefit cost	$	1,320		$	2,064		$	3,960		$	6,192

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

Our estimated contributions to our pension plans during 2014 have not changed significantly from amounts previously disclosed in the consolidated financial statements for the year ended December 31, 2013. For the nine months ended September 30, 2014 and 2013, we contributed $5,865 and $5,005, respectively, to our qualified pension plans.


(12)	Indebtedness

Debt consisted of the following:



	September 30, 2014		December 31, 2013
Term loan credit facilities	$	266,134	$	244,322
Alon USA, LP revolving credit facility	50,000		100,000
Senior secured notes	—		73,706
Convertible senior notes	124,940		121,090
Retail credit facilities	114,884		73,130
Total debt	555,958		612,248
Less: Current portion	15,083		83,174
Total long-term debt	$	540,875	$	529,074

(a) Alon Energy Term Loan

In March 2014, we entered into a five-year term loan agreement (“Alon Energy Term Loan”) for a principal amount of $25,000, maturing in March 2019. Repayments are monthly, commencing June 2014. Borrowings under this agreement incur interest at an annual rate equal to LIBOR plus a margin of 3.75%. We pledged 2,200,000 of the Partnership’s common units as collateral for the Alon Energy Term Loan. Additionally, Alon Assets, Inc. (“Alon Assets”) guarantees all payments under the Alon Energy Term Loan. The Alon Energy Term Loan contains certain restrictive covenants, including maintenance financial covenants.

Proceeds from the Alon Energy Term Loan were used to purchase equipment for a capital project at the Big Spring refinery.

At September 30, 2014, the Alon Energy Term Loan had an outstanding balance of $23,276.

(b) Retail Credit Facilities

Southwest Convenience Stores, LLC and Skinny’s LLC (“Alon Retail”) were parties to a credit agreement (the “Credit Agreement”) with a maturity in December 2015. At December 31, 2013, the outstanding balance under the Credit Agreement was $72,689. In March 2014, Alon Retail entered into a new credit agreement (“Alon Retail Credit Agreement”) and repaid in full its obligations under the Credit Agreement.

The Alon Retail Credit Agreement will mature in March 2019 and includes a $110,000 term loan and a $10,000 revolving credit loan. The Alon Retail Credit Agreement also includes an accordion feature that provides for incremental term loans up to $30,000 to fund store rebuilds, new builds and acquisitions. Borrowings under the Alon Retail Credit Agreement bear interest at a Eurodollar rate plus an applicable margin between 2.00% and 2.75%, determined quarterly based upon Alon Retail’s leverage ratio. Principal payments are made in quarterly installments based on a 15-year amortization schedule. Obligations under the Alon Retail Credit Agreement are secured by a first lien on substantially all of the assets of Alon Retail. The Alon Retail Credit Agreement also contains certain restrictive covenants including maintenance financial covenants.

Proceeds from the Alon Retail Credit Agreement were used to fully repay the remaining obligations under the Credit Agreement and pay a dividend distribution of $40,000 to Alon Brands, Inc., our wholly-owned subsidiary, with the remainder used for general corporate purposes.

At September 30, 2014, the Alon Retail Credit Agreement had an outstanding balance of $114,500, consisting of a term loan balance of $104,500 and a revolving credit loan balance of $10,000.

We had letters of credit outstanding under the Alon Energy $60,000 letter of credit facility of $58,227 and $56,827 at September 30, 2014 and December 31, 2013, respectively.

We had borrowings of $50,000 and $100,000 and letters of credit of $90,656 and $109,772 outstanding under the Alon USA, LP $240,000 revolving credit facility at September 30, 2014 and December 31, 2013, respectively.

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

(d) Senior Secured Notes

During the nine months ended September 30, 2014, we redeemed the remaining principal balance on the 13.50% senior secured notes (“Senior Secured Notes”) due October 2014. As a result of the prepayment of the Senior Secured Notes, write-offs of unamortized original issuance discount and debt issuance costs of $137 and $105, respectively, were charged to interest expense for the three months ended September 30, 2014, and $391 and $358, respectively, for the nine months ended September 30, 2014.

At December 31, 2013, the Senior Secured Notes had an outstanding balance of $73,706.

(e) Convertible Senior Notes

In August 2014, our board of directors increased the regular quarterly cash dividend on our common stock from $0.06 per share to $0.10 per share. This increase prompted an adjustment to the initial conversion price for both the convertible senior notes and the call overlay transactions. The conversion price for the convertible senior notes and convertible note hedge decreased to $14.75 from the initial conversion price of $14.79. The strike price for the warrants decreased to $20.04 from the initial strike price of $20.09. Any future regular quarterly cash dividend payments in excess of $0.06 per share will cause further adjustment based on the formula contained in the indenture.

(f) Financial Covenants

We have certain credit agreements that contain maintenance financial covenants. At September 30, 2014, we were in compliance with these covenants.


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

Our overall executive incentive compensation program permits the granting of awards to our directors, officers and key employees in the form of options to purchase common stock, stock appreciation rights, restricted shares of common stock, restricted common stock units, performance shares, performance units and senior executive plan bonuses.

Restricted Stock. Non-employee directors are awarded an annual grant of $25 in shares of restricted stock, which vest over a period of three years, assuming continued service at vesting. In May 2014, we granted awards to our non-employee directors of 4,965 restricted shares at a grant date price of $15.11 per share.

In May 2014, we granted awards of 255,000 restricted shares to certain executive officers at a grant date price of $15.11 per share. These May 2014 restricted shares will vest as follows: 50% in May 2015 and 50% in May 2016, assuming continued service at vesting.

In August 2014, we granted awards of 69,980 restricted shares to certain executive officers at a grant date price of $13.65 per share. These August 2014 restricted shares will vest as follows: 50% in August 2015 and 50% in August 2019, assuming continued service at vesting.

The following table summarizes the restricted share activity from January 1, 2014:



			Weighted Average Grant Date Fair Values
Nonvested Shares	Shares		(per share)
Nonvested at January 1, 2014	448,694		$	14.64
Granted	329,945		14.80
Vested	(134,640	)	16.95
Forfeited	—		—
Nonvested at September 30, 2014	643,999		$	14.24

Compensation expense for restricted stock awards amounted to $1,308 and $1,117 for the three months ended September 30, 2014 and 2013, respectively, and $2,796 and $2,254 for the nine months ended September 30, 2014 and 2013, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations. The fair value of shares vested in 2014 was $2,044.

Restricted Stock Units. In 2011, we granted 500,000 restricted stock units to our CEO and President at a grant date fair value of $11.47 per share. Each restricted unit represents the right to receive one share of our 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.

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

Compensation expense for restricted stock units amounted to $374 and $374 for the three months ended September 30, 2014 and 2013, respectively, and $1,122 and $1,122 for the nine months ended September 30, 2014 and 2013, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.

Unrecognized Compensation Cost. As of September 30, 2014, there was $6,245 of total unrecognized compensation cost related to non-vested share-based compensation arrangements, which is expected to be recognized over a weighted-average period of 1.6 years.


(14)	Equity (share values in dollars)

Changes to equity during the nine months ended September 30, 2014 are presented below:



	Total Stockholders’ Equity			Non-controlling Interest			Total Equity
Balance at December 31, 2013	$	597,959		$	27,445		$	625,404
Other comprehensive income	30,685			976			31,661
Stock compensation	6,018			(242		)	5,776
Dividends of common stock on preferred stock	(11		)	—			(11		)
Distributions to non-controlling interest in the Partnership	—			(11,506		)	(11,506		)
Dividends	(15,102		)	(389		)	(15,491		)
Net income	31,750			23,662			55,412
Balance at September 30, 2014	$	651,299		$	39,946		$	691,245

(a)Common Stock

Amended Shareholder Agreement. In 2012, we signed agreements with the remaining non-controlling interest shareholders of Alon Assets whereby the participants would exchange shares of Alon Assets for shares of our common stock. During the nine months ended September 30, 2014, 494,467 shares of our common stock were issued in exchange for 2,643.36 shares of Alon Assets. At September 30, 2014, 1,425,245 shares of our common stock are available to be exchanged for the outstanding shares held by non-controlling interest shareholders of Alon Assets.

We recognized compensation expense associated with the difference in value between the participants' ownership of Alon Assets compared to our common stock of $540 and $561 for the three months ended September 30, 2014 and 2013, respectively, and $1,845 and $2,059 for the nine months ended September 30, 2014 and 2013, respectively. These amounts are included in selling, general and administrative expenses in the consolidated statements of operations.


(b)	Dividends

Common Stock Dividends. During the nine months ended September 30, 2014, we paid the following dividends:



Date Paid	Record Date	Dividend Amount Per Share
March 14, 2014	February 28, 2014	$	0.06
June 16, 2014	May 30, 2014	0.06
September 22, 2014	September 8, 2014	0.10

Preferred Stock Dividends. During the nine months ended September 30, 2014, we issued 2,267 shares of common stock for payment of the quarterly 8.5% preferred stock dividend to preferred stockholders.

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)


(c)	Accumulated Other Comprehensive Loss

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



	Unrealized Gain (Loss) on Cash Flow Hedges			Postretirement Benefit Plans			Total
Balance at December 31, 2013	$	(18,248	)	$	(19,267	)	$	(37,515	)
Other comprehensive income before reclassifications	22,571			—			22,571
Amounts reclassified from accumulated other comprehensive loss	8,114			—			8,114
Net current-period other comprehensive income	30,685			—			30,685
Balance at September 30, 2014	$	12,437		$	(19,267	)	$	(6,830	)


(15)	Earnings (Loss) Per Share

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

The calculation of earnings (loss) per share, basic and diluted, for the three and nine months ended September 30, 2014 and 2013, is as follows (shares in thousands, per share value in dollars):



	For the Three Months Ended					For the Nine Months Ended
	September 30,					September 30,
	2014		2013			2014		2013
Net income (loss) available to stockholders	$	38,482	$	(28,709	)	$	31,750	$	36,971
Less: preferred stock dividends	15		760			44		2,275
Net income (loss) available to common stockholders	38,467		(29,469		)	31,706		34,696

Weighted average shares outstanding, basic	69,153		62,901			68,873		62,490
Dilutive common stock equivalents	403		—			388		5,499
Weighted average shares outstanding, diluted	69,556		62,901			69,261		67,989
Earnings (loss) per share, basic	$	0.56	$	(0.47	)	$	0.46	$	0.56
Earnings (loss) per share, diluted	$	0.55	$	(0.47	)	$	0.46	$	0.54

For the three months ended September 30, 2013, we have excluded 5,419 common stock equivalents from the weighted average diluted shares outstanding as the effect of including such shares would be anti-dilutive. For the three and nine months ended September 30, 2014 and the nine months ended September 30, 2013, the weighted average diluted shares includes all potentially dilutive common stock equivalents.


(16)	Commitments and Contingencies


(a)	Commitments

In the normal course of business, we have long-term commitments to purchase, at market prices, utilities such as natural gas, electricity and water for use by our refineries, terminals, pipelines and retail locations. We are also party to various refined product and crude oil supply and exchange agreements, which are typically short-term in nature or provide terms for cancellation.


(b)	Contingencies

We are involved in various legal actions arising in the ordinary course of business. We believe the ultimate disposition of these matters will not have a material effect on our financial position, results of operations or liquidity.

One of our subsidiaries is a party to a lawsuit alleging breach of contract pertaining to an asphalt supply agreement. We believe that we have valid counterclaims as well as affirmative defenses that will preclude recovery. Attempts to reach a

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

commercial arrangement to resolve the dispute have been unsuccessful to this point. This matter currently is not scheduled for trial. Due to the uncertainties of litigation, we cannot predict with certainty the ultimate resolution of this lawsuit.


(c)	Environmental

We are 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 us 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 and to compensate others for damage to property and natural resources. These contingent obligations relate to sites that we own and are associated with past or present operations. We are currently participating in environmental investigations, assessments and cleanups pertaining to our refineries, service stations, pipelines and terminals. We may be involved in additional future 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 our liability in proportion to other responsible parties.

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

We have accrued environmental remediation obligations of $52,828 ($12,898 current liability and $39,930 non-current liability) at September 30, 2014, and $58,382 ($12,898 current liability and $45,484 non-current liability) at December 31, 2013.

We have an indemnification agreement with a prior owner for remediation expenses at the Bakersfield refinery. We are required to make indemnification claims to the prior owner by March 15, 2015. We have recorded current receivables of $7,586 and $9,100 at September 30, 2014 and December 31, 2013, respectively, and a non-current receivable of $1,774 at December 31, 2013.

In addition to the indemnification agreement related to the Bakersfield refinery, we have an indemnification agreement with a prior owner for part of the remediation expenses at certain other West Coast assets. We have recorded current receivables of $418 and $418 and non-current receivables of $1,959 and $2,499 at September 30, 2014 and December 31, 2013, respectively.


(17)	Subsequent Events

Dividend Declared

On October 28, 2014, our board of directors declared the regular quarterly cash dividend of $0.10 per share and a special non-recurring dividend of $0.21 per share on our common stock, both payable on December 18, 2014, to holders of record at the close of business on December 2, 2014.

Partnership Distribution

On October 27, 2014, the board of directors of the General Partner declared a cash distribution to the Partnership’s common unitholders of approximately $63,760, or $1.02 per common unit. The cash distribution will be paid on November 28, 2014 to unitholders of record at the close of business on November 10, 2014. The total cash distribution payable to non-affiliated common unitholders will be approximately $11,730.

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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, 2013. In this document, the words “Alon,” “the Company,” “we”, “our” and “us” 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”) Cushing crude oil and West Texas Sour (“WTS”) crude oil or WTI Midland crude oil;


•	changes in the spread between WTI Cushing crude oil and Light Louisiana Sweet (“LLS”) crude oil;


•	changes in the spread between Brent crude oil and WTI Cushing crude oil;


•	changes in the spread between Brent crude oil and LLS crude oil;


•	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 upon termination of the Supply and Offtake Agreements, we are obligated to purchase the crude oil and refined product inventories then owned by J. Aron at then current market prices;


•	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 debt instruments;


•	the effects of and cost of compliance with the renewable fuel standards program (“RFS”), including the availability, cost and price volatility of Renewable Identification Numbers (“RINs”);


•	the effects 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

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•	the other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2013 under the caption “Risk Factors.”

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

Company Overview

We are an independent refiner and marketer of petroleum products operating primarily in the South Central, Southwestern and Western regions of the United States. Our crude oil refineries are located in Texas, California, Oregon and Louisiana and have a combined throughput capacity of approximately 217,000 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 217,000 bpd. At our refineries, we refine crude oil into petroleum products, including gasoline, diesel fuel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum-based products, which are marketed primarily in the South Central, Southwestern and Western United States. In 2014, we did not process crude oil at our California refineries.

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

We supply gasoline and diesel to 641 Alon branded retail sites, including our retail segment convenience stores. In 2014, approximately 63% of the gasoline and 29% of the diesel produced at the Big Spring refinery was transferred to our branded marketing business 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 75 licensed locations that are not under fuel supply agreements.

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.

Asphalt Segment. Our asphalt segment includes 10 asphalt refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), 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, which specializes in patented ground tire rubber modified asphalt products.

As part of our efforts to maximize the return generated by the production of asphalt, we have an exclusive license to use advanced asphalt-blending technology in West Texas, Arizona, New Mexico and Colorado, and a non-exclusive license in Idaho, Montana, Nevada, North Dakota, Utah and Wyoming, with respect to asphalt produced at our Big Spring refinery, and a ground tire rubber (“GTR”) asphalt manufacturing process with respect to asphalt sold in California.

Asphalt produced by our Big Spring refinery 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. We sell asphalt produced at our Big Spring refinery or purchased from third parties primarily as paving asphalt to road and materials manufacturers and highway construction/maintenance contractors as GTR, polymer modified or emulsion asphalt.

Retail Segment. Our retail segment operates 296 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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Third Quarter Operational and Financial Highlights

Operating income for the third quarter of 2014 was $94.0 million, compared to operating loss of $(39.4) million in the same period last year. Our operational and financial highlights for the third quarter of 2014 include the following:

•

Combined refinery average throughput for the third quarter of 2014 was 151,772 bpd, consisting of 74,838 bpd at the Big Spring refinery and 76,934 bpd at the Krotz Springs refinery, compared to a combined refinery average throughput of 132,159 bpd for the third quarter of 2013, consisting of 63,090 bpd at the Big Spring refinery and 69,069 bpd at the Krotz Springs refinery. The increased refinery throughput at the Big Spring refinery was due to the completion of both the planned turnaround and the vacuum tower project during the second quarter of 2014 and the impact of unplanned downtime at the Big Spring refinery during the third quarter of 2013.


•	Refinery operating margin at the Big Spring refinery was $19.98 per barrel for the third quarter of 2014 compared to $6.46 per barrel for the same period in 2013. This increase in operating margin was primarily due to a higher Gulf Coast 3/2/1 crack spread as well as a widening of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread.

•

Refinery operating margin at the Krotz Springs refinery was $9.48 per barrel for the third quarter of 2014 compared to $1.23 per barrel for the same period in 2013. This increase was primarily due to a higher Gulf Coast 2/1/1 high sulfur diesel crack spread and a widening WTI Cushing to WTI Midland spread, partially offset by a narrowing LLS to WTI Cushing spread. The Krotz Springs refinery operating margin was negatively impacted during the third quarter of 2014 by RINs costs of $6.0 million. The Krotz Springs refinery received an exemption from the RFS requirements for 2013 and as a result did not record costs associated with RINs.


•	The average Gulf Coast 3/2/1 crack spread was $15.90 per barrel for the third quarter of 2014 compared to $14.23 per barrel for the third quarter of 2013. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the third quarter of 2014 was $11.07 per barrel compared to $6.58 per barrel for the third quarter of 2013.

•

The average WTI Cushing to WTS spread for the third quarter of 2014 was $8.14 per barrel compared to $0.08 per barrel for the same period in 2013. The average WTI Cushing to WTI Midland spread for the third quarter of 2014 was $9.93 per barrel compared to $0.27 per barrel for the same period in 2013. The average LLS to WTI Cushing spread for the third quarter of 2014 was $3.41 per barrel compared to $6.60 per barrel for the same period in 2013.


•	Asphalt margins in the third quarter of 2014 were $14.31 per ton compared to $63.93 per ton in the third quarter of 2013. This decrease was primarily due to higher costs of asphalt purchased during the third quarter of 2014 compared to 2013.


•	Retail merchandise sales increased to $84.8 million in the third quarter of 2014 from $83.6 million in the third quarter of 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 Cushing crude oil are converted, or cracked, into two barrels of Gulf Coast conventional gasoline and one barrel of Gulf Coast ultra-low sulfur diesel.

We compare our Krotz Springs refinery’s operating margin to the Gulf Coast 2/1/1 high sulfur diesel crack spread. A Gulf Coast 2/1/1 high sulfur diesel 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.

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Our Big Spring refinery is capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate and sweet crude oils. We measure the cost advantage of refining sour crude oil by calculating the difference between the price of WTI Cushing crude oil and the price of WTS, a medium, sour crude oil. We refer to this differential as the WTI Cushing/WTS, or sweet/sour, spread. A widening of the sweet/sour spread can favorably influence the operating margin for our Big Spring refinery. The Big Spring refinery’s crude oil input is primarily comprised of WTS and WTI Midland priced crude oil.

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 Midland priced crude oil.

In addition, we have been able to capitalize on the oversupply of West Texas crudes in Midland, the largest origination terminal for West Texas crude oil, resulting from increased production in the Permian Basin coupled with infrastructure constraints. Although West Texas crudes are typically transported to Cushing and to the Gulf Coast for sale, current logistical and infrastructure constraints are limiting the ability of Permian Basin producers to transport their production to Cushing and to the Gulf Coast. The resulting oversupply of West Texas crudes at Midland has depressed Midland crude prices and enabled us to obtain an increased portion of our crude supply at discounted prices to Cushing. Moreover, by sourcing West Texas crude oils at Midland, we are able to eliminate the cost of transporting crude to and from Cushing. The WTI Cushing less WTI Midland spread represents the differential between the average per barrel price of WTI Cushing crude oil and the average per barrel price of WTI Midland crude oil. A widening of the WTI Cushing less WTI Midland spread can favorably influence the operating margin for both our Big Spring and Krotz Springs refineries.

Global product prices are influenced by the price of Brent crude which is a global benchmark crude. Global product prices influence product prices in the U.S. As a result, both our Big Spring and Krotz Springs refineries are influenced by the spread between Brent crude and WTI Cushing. For both our Big Spring and Krotz Springs refineries, the Brent less WTI Cushing spread represents the differential between the average per barrel price of Brent crude oil and the average per barrel price of WTI Cushing crude oil. A widening of the spread between Brent and WTI Cushing can favorably influence both refineries’ operating margins. Also, the Krotz Springs refinery is influenced by the spread between Brent crude and LLS. For our Krotz Springs refinery, the Brent less LLS spread represents the differential between the average per barrel price of Brent crude oil and the average per barrel price of LLS crude oil. A widening of the spread between Brent and LLS can favorably influence the Krotz Springs refinery operating margins.

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 the Big Spring refinery or the price for 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. A portion of our asphalt sales are made using fixed price contracts for delivery at future dates. Because these contracts are priced using 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.

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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.

Factors Affecting Comparability

Our financial condition and operating results over the three and nine months ended September 30, 2014 and 2013 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 nine months ended September 30, 2014, we completed both the planned turnaround and vacuum tower project at the Big Spring refinery, which reduced our refinery throughput. However, these events had a positive impact on the Big Spring refinery throughput during the three months ended September 30, 2014.

During the nine months ended September 30, 2013, the Big Spring refinery was impacted by an unplanned first quarter shut down to perform maintenance on the crude unit vacuum tower as well as unplanned downtime in the third quarter.

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

Certain Derivative Impacts

Included in the consolidated statements of operations in cost of sales for the three and nine months ended September 30, 2014 are losses on commodity swaps of $1.3 million and $9.9 million, respectively, compared to gains on commodity swaps of $11.3 million and $21.3 million for the three and nine months ended September 30, 2013, respectively.

Renewable Fuel Standards

RINs costs at our Krotz Springs refinery were $6.0 million and $16.6 million for the three and nine months ended September 30, 2014, respectively. The Krotz Springs refinery received an exemption from the RFS requirements for 2013 and as a result did not record costs associated with RINs.

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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 motor fuels through our retail segment.

For the refining and marketing segment, net sales consist of gross sales, net of customer rebates, discounts and excise taxes and include intersegment 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 principally crude oil, blending materials, other raw materials and transportation costs. Asphalt cost of sales includes costs of purchased asphalt, blending materials and transportation costs. Retail cost of sales includes motor fuels and merchandise. Retail fuel cost of sales represents the cost of purchased fuel, including transportation costs and associated excise 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, which is presented separately in the consolidated statements of operations.

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

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 and asphalt segments.

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ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED

Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for Alon and our three operating segments for the three and nine months ended September 30, 2014 and 2013. 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, 2013 is unaudited.



	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(dollars in thousands, except per share data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	1,850,097		$	1,892,836		$	5,276,225		$	5,220,627
Operating costs and expenses:
Cost of sales	1,608,080			1,789,320			4,695,072			4,665,289
Direct operating expenses	70,356			72,035			208,664			217,703
Selling, general and administrative expenses (2)	44,114			40,224			129,836			125,066
Depreciation and amortization (3)	32,170			30,988			91,501			92,949
Total operating costs and expenses	1,754,720			1,932,567			5,125,073			5,101,007
Gain (loss) on disposition of assets	(1,372		)	334			745			8,846
Operating income (loss)	94,005			(39,397		)	151,897			128,466
Interest expense	(28,202		)	(22,263		)	(85,473		)	(63,816		)
Equity earnings of investees	1,982			3,426			2,801			5,155
Other income, net	20			91			641			220
Income (loss) before income tax expense	67,805			(58,143		)	69,866			70,025
Income tax expense (benefit)	14,331			(24,958		)	14,454			9,617
Net income (loss)	53,474			(33,185		)	55,412			60,408
Net income (loss) attributable to non-controlling interest	14,992			(4,476		)	23,662			23,437
Net income (loss) available to stockholders	$	38,482		$	(28,709	)	$	31,750		$	36,971
Earnings (loss) per share, basic	$	0.56		$	(0.47	)	$	0.46		$	0.56
Weighted average shares outstanding, basic (in thousands)	69,153			62,901			68,873			62,490
Earnings (loss) per share, diluted	$	0.55		$	(0.47	)	$	0.46		$	0.54
Weighted average shares outstanding, diluted (in thousands)	69,556			62,901			69,261			67,989
Cash dividends per share	$	0.10		$	0.06		$	0.22		$	0.32
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	112,942		$	(20,093	)	$	144,584		$	109,661
Investing activities	(43,746		)	(18,108		)	(84,753		)	(30,190		)
Financing activities	(72,779		)	194,907			(90,762		)	95,407
OTHER DATA:
Adjusted EBITDA (4)	$	129,549		$	(5,226	)	$	246,095		$	217,944
Capital expenditures (5)	19,141			17,689			73,796			48,311
Capital expenditures for turnarounds and catalysts	25,123			219			51,392			6,843

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	September 30, 2014		December 31, 2013
BALANCE SHEET DATA (end of period):	(dollars in thousands)
Cash and cash equivalents	$	193,568	$	224,499
Working capital	125,532		60,863
Total assets	2,223,152		2,245,140
Total debt	555,958		612,248
Total debt less cash and cash equivalents	362,390		387,749
Total equity	691,245		625,404


(1)	Includes excise taxes on sales by the retail segment of $19,012 and $19,307 for the three months ended September 30, 2014 and 2013, respectively, and $55,923 and $55,143 for the nine months ended September 30, 2014 and 2013, respectively.


(2)	Includes corporate headquarters selling, general and administrative expenses of $178 and $176 for the three months ended September 30, 2014 and 2013, respectively, and $528 and $544 for the nine months ended September 30, 2014 and 2013, respectively, which are not allocated to our three operating segments.


(3)	Includes corporate depreciation and amortization of $598 and $607 for the three months ended September 30, 2014 and 2013, respectively, and $1,789 and $2,022 for the nine months ended September 30, 2014 and 2013, respectively, which are not allocated to our three operating segments.

(4)

Adjusted EBITDA represents earnings before net income (loss) attributable to non-controlling interest, income tax expense (benefit), 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 (loss) attributable to non-controlling interest, income tax expense (benefit), 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.

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The following table reconciles net income (loss) available to stockholders to Adjusted EBITDA for the three and nine months ended September 30, 2014 and 2013:



	For the Three Months Ended					For the Nine Months Ended
	September 30,					September 30,
	2014		2013			2014			2013
	(dollars in thousands)
Net income (loss) available to stockholders	$	38,482	$	(28,709	)	$	31,750		$	36,971
Net income (loss) attributable to non-controlling interest	14,992		(4,476		)	23,662			23,437
Income tax expense (benefit)	14,331		(24,958		)	14,454			9,617
Interest expense	28,202		22,263			85,473			63,816
Depreciation and amortization	32,170		30,988			91,501			92,949
(Gain) loss on disposition of assets	1,372		(334		)	(745		)	(8,846		)
Adjusted EBITDA	$	129,549	$	(5,226	)	$	246,095		$	217,944

Adjusted EBITDA does not exclude unrealized losses on commodity swaps of $1,264 and $10,774 for the three and nine months ended September 30, 2014, which are included in net income (loss) available to stockholders.


(5)	Includes corporate capital expenditures of $748 and $229 for the three months ended September 30, 2014 and 2013, respectively, and $2,107 and $668 for the nine months ended September 30, 2014 and 2013, respectively, which are not allocated to our three operating segments.

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REFINING AND MARKETING SEGMENT
	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(dollars in thousands, except per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	1,617,281		$	1,611,257		$	4,643,523		$	4,468,996
Operating costs and expenses:
Cost of sales	1,414,827			1,561,164			4,186,884			4,061,439
Direct operating expenses	60,086			60,972			178,362			184,988
Selling, general and administrative expenses	15,637			10,411			44,637			38,930
Depreciation and amortization	27,506			26,255			77,587			78,867
Total operating costs and expenses	1,518,056			1,658,802			4,487,470			4,364,224
Gain (loss) on disposition of assets	(1,197		)	(42		)	(1,256		)	7,363
Operating income (loss)	$	98,028		$	(47,587	)	$	154,797		$	112,135
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin – Big Spring (2)	$	19.98		$	6.46		$	17.35		$	16.35
Refinery operating margin – Krotz Springs (2)	9.48			1.23			8.68			5.16
Refinery direct operating expense – Big Spring (3)	3.74			4.53			4.69			4.74
Refinery direct operating expense – Krotz Springs (3)	3.88			3.91			4.01			4.30
Capital expenditures	$	11,468		$	11,535		$	55,323		$	30,150
Capital expenditures for turnarounds and catalysts	25,123			219			51,392			6,843
PRICING STATISTICS:
Crack spreads (3/2/1) (per barrel):
Gulf Coast	$	15.90		$	14.23		$	16.37		$	21.21
Crack spreads (2/1/1) (per barrel):
Gulf Coast high sulfur diesel	$	11.07		$	6.58		$	11.43		$	6.30
WTI Cushing crude oil (per barrel)	$	97.55		$	105.82		$	99.74		$	98.14
Crude oil differentials (per barrel):
WTI Cushing less WTI Midland	$	9.93		$	0.27		$	7.31		$	2.69
WTI Cushing less WTS	8.14			0.08			6.58			3.91
LLS less WTI Cushing	3.41			6.60			4.09			13.91
Brent less LLS	1.72			(0.70		)	4.43			(0.66		)
Brent less WTI Cushing	5.13			5.91			8.52			13.25
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	2.65		$	2.78		$	2.71		$	2.77
Gulf Coast ultra-low sulfur diesel	2.80			3.02			2.88			2.99
Gulf Coast high sulfur diesel	2.68			2.89			2.78			2.87
Natural gas (per MMBtu)	3.95			3.56			4.41			3.69

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THROUGHPUT AND PRODUCTION DATA: BIG SPRING REFINERY	For the Three Months Ended						For the Nine Months Ended
THROUGHPUT AND PRODUCTION DATA: BIG SPRING REFINERY	September 30,						September 30,
	2014			2013			2014			2013
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
WTS crude	37,566	50.2		36,340	57.6		28,524	45.7		45,029	69.3
WTI crude	34,633	46.3		25,169	39.9		31,330	50.2		18,016	27.8
Blendstocks	2,639	3.5		1,581	2.5		2,528	4.1		1,865	2.9
Total refinery throughput (4)	74,838	100.0		63,090	100.0		62,382	100.0		64,910	100.0
Refinery production:
Gasoline	36,842	49.0		30,861	49.2		30,207	48.4		31,905	49.4
Diesel/jet	28,857	38.4		20,999	33.4		21,964	35.2		21,688	33.5
Asphalt	3,052	4.1		3,312	5.3		2,705	4.3		3,708	5.7
Petrochemicals	4,305	5.7		3,599	5.7		3,514	5.6		3,984	6.2
Other	2,078	2.8		4,045	6.4		4,030	6.5		3,371	5.2
Total refinery production (5)	75,134	100.0		62,816	100.0		62,420	100.0		64,656	100.0
Refinery utilization (6)		98.9	%		87.9	%		97.0	%		93.8	%



THROUGHPUT AND PRODUCTION DATA: KROTZ SPRINGS REFINERY	For the Three Months Ended						For the Nine Months Ended
THROUGHPUT AND PRODUCTION DATA: KROTZ SPRINGS REFINERY	September 30,						September 30,
	2014			2013			2014			2013
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
WTI crude	31,182	40.5		32,801	47.5		28,346	39.5		29,677	47.8
Gulf Coast sweet crude	44,473	57.8		34,639	50.1		42,139	58.8		30,805	49.5
Blendstocks	1,279	1.7		1,629	2.4		1,195	1.7		1,661	2.7
Total refinery throughput (4)	76,934	100.0		69,069	100.0		71,680	100.0		62,143	100.0
Refinery production:
Gasoline	35,532	45.2		32,402	46.1		33,459	45.7		27,363	43.2
Diesel/jet	34,246	43.6		29,449	41.8		31,292	42.8		25,392	40.0
Heavy Oils	1,421	1.8		1,293	1.8		1,129	1.5		1,194	1.9
Other	7,414	9.4		7,282	10.3		7,289	10.0		9,454	14.9
Total refinery production (5)	78,613	100.0		70,426	100.0		73,169	100.0		63,403	100.0
Refinery utilization (6)		102.2	%		91.1	%		95.2	%		83.1	%

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(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 nine months ended September 30, 2014 excludes losses on commodity swaps of $1,264 and $9,891, respectively, as well as negative inventory effects of $2,942 and $10,983, respectively.

The refinery operating margin for the three and nine months ended September 30, 2013 excludes gains on commodity swaps of $11,339 and $21,333, respectively, as well as positive inventory effects of $1,346 and $8,140, respectively.


(3)	Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses at our Big Spring 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.


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


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

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ASPHALT SEGMENT
	For the Three Months Ended					For the Nine Months Ended
	September 30,					September 30,
	2014			2013		2014			2013
	(dollars in thousands, except per ton data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	136,992		$	194,230	$	350,840		$	493,286
Operating costs and expenses:
Cost of sales (1)(2)	134,116			177,289		329,651			450,758
Direct operating expenses	10,270			11,063		30,302			32,715
Selling, general and administrative expenses	1,348			2,567		6,375			5,770
Depreciation and amortization	1,219			1,588		3,581			4,700
Total operating costs and expenses	146,953			192,507		369,909			493,943
Gain (loss) on disposition of assets	(136		)	—		1,878			—
Operating income (loss)	$	(10,097	)	$	1,723	$	(17,191	)	$	(657	)
KEY OPERATING STATISTICS:
Blended asphalt sales volume (tons in thousands) (3)	186			247		412			557
Non-blended asphalt sales volume (tons in thousands) (4)	15			18		41			55
Blended asphalt sales price per ton (3)	$	587.31		$	585.68	$	571.15		$	577.11
Non-blended asphalt sales price per ton (4)	422.93			358.61		393.07			379.45
Asphalt margin per ton (5)	14.31			63.93		46.77			69.49
Capital expenditures	$	1,053		$	1,556	$	4,272		$	5,947


(1)	Net sales and cost of sales include asphalt purchases sold as part of a supply and offtake arrangement of approximately $21,000 and $43,000 for the three months ended September 30, 2014 and 2013 and approximately $99,000 and $151,000 for the nine months ended September 30, 2014 and 2013, respectively. 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.

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RETAIL SEGMENT
	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(dollars in thousands, except per gallon data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	249,120		$	251,688		$	723,027		$	720,626
Operating costs and expenses:
Cost of sales (2)	212,433			215,206			619,702			615,373
Selling, general and administrative expenses	26,951			27,070			78,296			79,822
Depreciation and amortization	2,847			2,538			8,544			7,360
Total operating costs and expenses	242,231			244,814			706,542			702,555
Gain (loss) on disposition of assets	(39		)	376			124			1,483
Operating income	$	6,850		$	7,250		$	16,609		$	19,554
KEY OPERATING STATISTICS:
Number of stores (end of period) (3)	296			297			296			297
Retail fuel sales (thousands of gallons)	48,567			49,363			142,850			141,259
Retail fuel sales (thousands of gallons per site per month)(3)	57			58			56			55
Retail fuel margin (cents per gallon) (4)	20.8			18.6			19.5			19.7
Retail fuel sales price (dollars per gallon) (5)	$	3.38		$	3.40		$	3.37		$	3.40
Merchandise sales	$	84,794		$	83,614		$	241,311		$	240,190
Merchandise sales (per site per month) (3)	$	95		$	94		$	91		$	90
Merchandise margin (6)	31.2		%	32.5		%	31.1		%	32.1		%
Capital expenditures	$	5,872		$	4,369		$	12,094		$	11,546


(1)	Includes excise taxes on sales of $19,012 and $19,307 for the three months ended September 30, 2014 and 2013, respectively, and $55,923 and $55,143 for the nine months ended September 30, 2014 and 2013, 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 September 30, 2014, we had 296 retail convenience stores of which 284 sold fuel. At September 30, 2013, we had 297 retail convenience stores of which 285 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 excise 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.

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Three Months Ended September 30, 2014 Compared to the Three Months Ended September 30, 2013

Net Sales

Consolidated. Net sales for the three months ended September 30, 2014 were $1,850.1 million, compared to $1,892.8 million for the three months ended September 30, 2013, a decrease of $42.7 million. This decrease was primarily due to lower refined product prices, lower asphalt sales volumes and lower retail fuel sales volumes and prices, partially offset by higher refinery throughput.

Refining and Marketing Segment. Net sales for our refining and marketing segment were $1,617.3 million for the three months ended September 30, 2014, compared to $1,611.3 million for the three months ended September 30, 2013, an increase of $6.0 million. This increase was primarily due to higher refinery throughput, partially offset by lower refined product prices. Combined refinery average throughput for the three months ended September 30, 2014 was 151,772 bpd, consisting of 74,838 bpd at the Big Spring refinery and 76,934 bpd at the Krotz Springs refinery, compared to a combined refinery average throughput of 132,159 bpd for the three months ended September 30, 2013, consisting of 63,090 bpd at the Big Spring refinery and 69,069 bpd at the Krotz Springs refinery. The increased throughput at the Big Spring refinery was due to the completion of both the planned turnaround and the vacuum tower project during the second quarter of 2014 and the impact of unplanned downtime at the Big Spring refinery during the third quarter of 2013.

Refined product prices decreased during the three months ended September 30, 2014, compared to the three months ended September 30, 2013. The average per gallon price of Gulf Coast gasoline for the three months ended September 30, 2014 decreased $0.13, or 4.7%, to $2.65, compared to $2.78 for the three months ended September 30, 2013. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the three months ended September 30, 2014 decreased $0.22, or 7.3%, to $2.80, compared to $3.02 for the three months ended September 30, 2013. The average per gallon price for Gulf Coast high sulfur diesel for the three months ended September 30, 2014 decreased $0.21, or 7.3%, to $2.68, compared to $2.89 for the three months ended September 30, 2013.

Asphalt Segment. Net sales for our asphalt segment were $137.0 million for the three months ended September 30, 2014, compared to $194.2 million for the three months ended September 30, 2013, a decrease of $57.2 million, or 29.5%. This decrease was primarily due to lower asphalt sales volumes and lower asphalt sales as part of a supply and offtake arrangement of approximately $22.0 million. The asphalt sales volume decreased 24.2% to 201 thousand tons for the three months ended September 30, 2014 from 265 thousand tons for the three months ended September 30, 2013.

Retail Segment. Net sales for our retail segment were $249.1 million for the three months ended September 30, 2014, compared to $251.7 million for the three months ended September 30, 2013, a decrease of $2.6 million, or 1.0%. This decrease was primarily attributable to a 1.6% decrease in retail fuel sales volumes and a decrease in retail fuel sales prices.

Cost of Sales

Consolidated. Cost of sales for the three months ended September 30, 2014 were $1,608.1 million, compared to $1,789.3 million for the three months ended September 30, 2013, a decrease of $181.2 million. This decrease was primarily due to lower crude oil prices and lower asphalt sales volumes, partially offset by higher refinery throughput.

Refining and Marketing Segment. Cost of sales for our refining and marketing segment were $1,414.8 million for the three months ended September 30, 2014, compared to $1,561.2 million for the three months ended September 30, 2013, a decrease of $146.4 million. This decrease was primarily due to lower crude oil prices, partially offset by higher refinery throughput and higher RINs costs for the three months ended September 30, 2014.

The average price of WTI Cushing decreased 7.8% to $97.55 per barrel for the three months ended September 30, 2014, compared to $105.82 per barrel for the three months ended September 30, 2013. The average WTI Cushing to WTS spread widened to $8.14 per barrel for the three months ended September 30, 2014, compared to $0.08 per barrel for the three months ended September 30, 2013. The average WTI Cushing to WTI Midland spread widened to $9.93 per barrel for the three months ended September 30, 2014, compared to $0.27 per barrel for the three months ended September 30, 2013. The average LLS to WTI Cushing spread narrowed $3.19 per barrel to $3.41 per barrel for the three months ended September 30, 2014, compared to $6.60 per barrel for the three months ended September 30, 2013. Cost of sales for the three months ended September 30, 2014 and 2013 includes $8.5 million and $1.2 million, respectively, of costs to purchase RINs needed to satisfy our obligation to blend biofuels into the products we produce.

Asphalt Segment. Cost of sales for our asphalt segment were $134.1 million for the three months ended September 30, 2014, compared to $177.3 million for the three months ended September 30, 2013, a decrease of $43.2 million, or 24.4%. This decrease was primarily due to lower asphalt sales volumes and lower asphalt purchases as part of a supply and offtake arrangement of approximately $22.0 million, partially offset by higher costs of asphalt purchased during the three months ended September 30, 2014, compared to the three months ended September 30, 2013.

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Retail Segment. Cost of sales for our retail segment were $212.4 million for the three months ended September 30, 2014, compared to $215.2 million for the three months ended September 30, 2013, a decrease of $2.8 million, or 1.3%. This decrease was primarily due to decreased retail fuel sales volumes.

Direct Operating Expenses

Consolidated. Direct operating expenses were $70.4 million for the three months ended September 30, 2014, compared to $72.0 million for the three months ended September 30, 2013, a decrease of $1.6 million, or 2.2%.

Refining and Marketing Segment. Direct operating expenses for our refining and marketing segment for the three months ended September 30, 2014 were $60.1 million, compared to $61.0 million for the three months ended September 30, 2013, a decrease of $0.9 million, or 1.5%.

Asphalt Segment. Direct operating expenses for our asphalt segment for the three months ended September 30, 2014 were $10.3 million, compared to $11.1 million for the three months ended September 30, 2013, a decrease of $0.8 million, or 7.2%. This decrease was primarily due to reduced insurance costs during the three months ended September 30, 2014.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for the three months ended September 30, 2014 were $44.1 million, compared to $40.2 million for the three months ended September 30, 2013, an increase of $3.9 million, or 9.7%.

Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the three months ended September 30, 2014 were $15.6 million, compared to $10.4 million for the three months ended September 30, 2013, an increase of $5.2 million, or 50.0%. This increase was primarily due to higher employee related costs for the three months ended September 30, 2014.

Asphalt Segment. SG&A expenses for our asphalt segment for the three months ended September 30, 2014 were $1.3 million, compared to $2.6 million for the three months ended September 30, 2013, a decrease of $1.3 million. This decrease was primarily due to reduced professional services fees during the three months ended September 30, 2014.

Retail Segment. SG&A expenses for our retail segment for the three months ended September 30, 2014 were $27.0 million, compared to $27.1 million for the three months ended September 30, 2013, a decrease of $0.1 million.

Depreciation and Amortization

Depreciation and amortization for the three months ended September 30, 2014 was $32.2 million, compared to $31.0 million for the three months ended September 30, 2013, an increase of $1.2 million, or 3.9%.

Operating Income (Loss)

Consolidated. Operating income for the three months ended September 30, 2014 was $94.0 million, compared to operating loss of $39.4 million for the three months ended September 30, 2013, an increase of $133.4 million. This increase was primarily due to higher refinery throughput and increased refinery operating margins, partially offset by reduced asphalt margins.

Refining and Marketing Segment. Operating income for our refining and marketing segment was $98.0 million for the three months ended September 30, 2014, compared to operating loss of $47.6 million for the three months ended September 30, 2013, an increase of $145.6 million. This increase was primarily due to higher refinery throughput and increased refinery operating margins.

Refinery operating margin at the Big Spring refinery was $19.98 per barrel for the three months ended September 30, 2014, compared to $6.46 per barrel for the three months ended September 30, 2013. This increase in operating margin was primarily due to a higher Gulf Coast 3/2/1 crack spread and a widening of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread. The average Gulf Coast 3/2/1 crack spread increased to $15.90 per barrel for the three months ended September 30, 2014, compared to $14.23 per barrel for the three months ended September 30, 2013.

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Refinery operating margin at the Krotz Springs refinery was $9.48 per barrel for the three months ended September 30, 2014, compared to $1.23 per barrel for the three months ended September 30, 2013. This increase was primarily due to a higher Gulf Coast 2/1/1 high sulfur diesel crack spread and a widening WTI Cushing to WTI Midland spread, partially offset by a narrowing LLS to WTI Cushing spread as well as the impact of RINs costs during the three months ended September 30, 2014. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the three months ended September 30, 2014 was $11.07 per barrel, compared to $6.58 per barrel for the three months ended September 30, 2013. For the three months ended September 30, 2014, the Krotz Springs refinery operating margin was negatively impacted by $6.0 million of costs to purchase RINs needed to satisfy our obligation to blend biofuels into the products we produce. The Krotz Springs refinery received an exemption from the RFS requirements for 2013 and as a result did not record costs associated with RINs.

Asphalt Segment. Operating loss for our asphalt segment was $10.1 million for the three months ended September 30, 2014, compared to operating income of $1.7 million for the three months ended September 30, 2013, a decrease of $11.8 million. This decrease was primarily due to lower asphalt sales volumes and lower asphalt margin, which was influenced by higher costs of asphalt purchased during the three months ended September 30, 2014. The asphalt margin was $14.31 per ton for the three months ended September 30, 2014, compared to $63.93 per ton for the three months ended September 30, 2013.

Retail Segment. Operating income for our retail marketing segment was $6.9 million for the three months ended September 30, 2014, compared to $7.3 million for the three months ended September 30, 2013, a decrease of $0.4 million.

Interest Expense

Interest expense was $28.2 million for the three months ended September 30, 2014, compared to $22.3 million for the three months ended September 30, 2013, an increase of $5.9 million, or 26.5%. This increase was primarily due to higher financing costs associated with crude oil purchases as a result of a backwardated crude oil market, partially offset by reduced interest charges during the three months ended September 30, 2014 resulting from prepayments of our senior secured notes.

Income Tax Expense (Benefit)

Income tax expense was $14.3 million for the three months ended September 30, 2014, compared to income tax benefit of $25.0 million for the three months ended September 30, 2013. Income tax expense increased as a result of operating at a pre-tax income during the three months ended September 30, 2014, compared to operating at a pre-tax loss during the three months ended September 30, 2013.

Net Income (Loss) Attributable to Non-controlling Interest

Net income attributable to non-controlling interest includes the proportional share of the Partnership’s income attributable to the limited partner interests held by the public. Additionally, net income attributable to non-controlling interests includes the proportional share of net income related to non-voting common stock of our subsidiary, Alon Assets, Inc., owned by non-controlling interest shareholders. Net income attributable to non-controlling interest was $15.0 million for the three months ended September 30, 2014, compared to net loss attributable to non-controlling interest of $4.5 million for the three months ended September 30, 2013, an increase of $19.5 million.

Net Income (Loss) Available to Stockholders

Net income available to stockholders was $38.5 million for the three months ended September 30, 2014, compared to net loss of $28.7 million for the three months ended September 30, 2013, an increase of $67.2 million. This increase was attributable to the factors discussed above.

Nine Months Ended September 30, 2014 Compared to the Nine Months Ended September 30, 2013

Net Sales

Consolidated. Net sales for the nine months ended September 30, 2014 were $5,276.2 million, compared to $5,220.6 million for the nine months ended September 30, 2013, an increase of $55.6 million. This increase was primarily due to higher refinery throughput, partially offset by lower refined product prices.

Refining and Marketing Segment. Net sales for our refining and marketing segment were $4,643.5 million for the nine months ended September 30, 2014, compared to $4,469.0 million for the nine months ended September 30, 2013, an increase of $174.5 million. This increase was primarily due to higher refinery throughput and increased sales of purchased products, partially offset by lower refined product prices.

Combined refinery average throughput for the nine months ended September 30, 2014 was 134,062 bpd, consisting of 62,382 bpd at the Big Spring refinery and 71,680 bpd at the Krotz Springs refinery, compared to a combined refinery average

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throughput of 127,053 bpd for the nine months ended September 30, 2013, consisting of 64,910 bpd at the Big Spring refinery and 62,143 bpd at the Krotz Springs refinery. During the nine months ended September 30, 2014, we completed both the planned turnaround and the vacuum tower project at the Big Spring refinery, which resulted in reduced refinery throughput at the Big Spring refinery during the nine months ended September 30, 2014. During the nine months ended September 30, 2013, the Krotz Springs refinery was impacted by the unplanned shut down and repair of the reformer unit for approximately one month.

Refined product prices decreased during the nine months ended September 30, 2014, compared to the nine months ended September 30, 2013. The average per gallon price of Gulf Coast gasoline for the nine months ended September 30, 2014 decreased $0.06, or 2.2%, to $2.71, compared to $2.77 for the nine months ended September 30, 2013. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the nine months ended September 30, 2014 decreased $0.11, or 3.7%, to $2.88, compared to $2.99 for the nine months ended September 30, 2013. The average per gallon price of Gulf Coast high sulfur diesel for the nine months ended September 30, 2014 decreased $0.09, or 3.1%, to $2.78, compared to $2.87 for the nine months ended September 30, 2013.

Asphalt Segment. Net sales for our asphalt segment were $350.8 million for the nine months ended September 30, 2014, compared to $493.3 million for the nine months ended September 30, 2013, a decrease of $142.5 million, or 28.9%. This decrease was primarily due to lower asphalt sales as part of a supply and offtake arrangement of approximately $52.0 million, decreased sales volumes and lower blended asphalt sales prices. The asphalt sales volume decreased 26.0% to 453 thousand tons for the nine months ended September 30, 2014 from 612 thousand tons for the nine months ended September 30, 2013. The average blended asphalt sales price decreased 1.0% to $571.15 per ton for the nine months ended September 30, 2014 from $577.11 per ton for the nine months ended September 30, 2013.

Retail Segment. Net sales for our retail segment were $723.0 million for the nine months ended September 30, 2014, compared to $720.6 million for the nine months ended September 30, 2013, an increase of $2.4 million, or 0.3%.

Cost of Sales

Consolidated. Cost of sales for the nine months ended September 30, 2014 were $4,695.1 million, compared to $4,665.3 million for the nine months ended September 30, 2013, an increase of $29.8 million, or 0.6%. This increase was primarily due to higher refinery throughput and higher RINs costs, partially offset by lower crude oil prices at our refineries and lower asphalt sales volumes for the nine months ended September 30, 2014.

Refining and Marketing Segment. Cost of sales for our refining and marketing segment were $4,186.9 million for the nine months ended September 30, 2014, compared to $4,061.4 million for the nine months ended September 30, 2013, an increase of $125.5 million, or 3.1%. This increase was primarily due to higher refinery throughput and higher RINs costs, partially offset by lower crude oil prices at our refineries for the nine months ended September 30, 2014.

The average price of WTI Cushing increased 1.6% to $99.74 per barrel for the nine months ended September 30, 2014 from $98.14 per barrel for the nine months ended September 30, 2013. The average WTI Cushing to WTS spread widened to $6.58 per barrel for the nine months ended September 30, 2014, compared to $3.91 per barrel for the nine months ended September 30, 2013. The average WTI Cushing to WTI Midland spread widened to $7.31 per barrel for the nine months ended September 30, 2014, compared to $2.69 per barrel for the nine months ended September 30, 2013. The average LLS to WTI Cushing spread narrowed $9.82 per barrel to $4.09 per barrel for the nine months ended September 30, 2014, compared to $13.91 per barrel for the nine months ended September 30, 2013. Cost of sales for the nine months ended September 30, 2014 and 2013 includes $20.8 million and $9.2 million, respectively, of costs to purchase RINs needed to satisfy our obligation to blend biofuels into the products we produce.

Asphalt Segment. Cost of sales for our asphalt segment were $329.7 million for the nine months ended September 30, 2014, compared to $450.8 million for the nine months ended September 30, 2013, a decrease of $121.1 million, or 26.9%. This decrease was primarily due to decreased sales volumes as well as lower asphalt purchases as part of a supply and offtake arrangement of approximately $52.0 million, partially offset by higher costs of asphalt purchased during the nine months ended September 30, 2014, compared to the nine months ended September 30, 2013.

Retail Segment. Cost of sales for our retail segment were $619.7 million for the nine months ended September 30, 2014, compared to $615.4 million for the nine months ended September 30, 2013, an increase of $4.3 million, or 0.7%.

Direct Operating Expenses

Consolidated. Direct operating expenses were $208.7 million for the nine months ended September 30, 2014, compared to $217.7 million for the nine months ended September 30, 2013, a decrease of $9.0 million, or 4.1%.

Refining and Marketing Segment. Direct operating expenses for our refining and marketing segment for the nine months ended September 30, 2014 were $178.4 million, compared to $185.0 million for the nine months ended September 30, 2013, a

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decrease of $6.6 million, or 3.6%. This decrease was primarily due to lower major maintenance and insurances costs, partially offset by higher utility costs during the nine months ended September 30, 2014.

Asphalt Segment. Direct operating expenses for our asphalt segment for the nine months ended September 30, 2014 were $30.3 million, compared to $32.7 million for the nine months ended September 30, 2013, a decrease of $2.4 million, or 7.3%. This decrease was primarily due to reduced insurance costs during the nine months ended September 30, 2014.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for the nine months ended September 30, 2014 were $129.8 million, compared to $125.1 million for the nine months ended September 30, 2013, an increase of $4.7 million, or 3.8%.

Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the nine months ended September 30, 2014 were $44.6 million, compared to $38.9 million for the nine months ended September 30, 2013, an increase of $5.7 million, or 14.7%. This increase was primarily due to higher employee related costs for the nine months ended September 30, 2014.

Asphalt Segment. SG&A expenses for our asphalt segment for the nine months ended September 30, 2014 were $6.4 million, compared to $5.8 million for the nine months ended September 30, 2013, an increase of $0.6 million, or 10.3%. This increase was primarily due to higher corporate expense allocated to the asphalt segment and higher employee related costs.

Retail Segment. SG&A expenses for our retail segment for the nine months ended September 30, 2014 were $78.3 million, compared to $79.8 million for the nine months ended September 30, 2013, a decrease of $1.5 million, or 1.9%.

Depreciation and Amortization

Depreciation and amortization for the nine months ended September 30, 2014 was $91.5 million, compared to $92.9 million for the nine months ended September 30, 2013, a decrease of $1.4 million, or 1.5%.

Operating Income

Consolidated. Operating income for the nine months ended September 30, 2014 was $151.9 million, compared to $128.5 million for the nine months ended September 30, 2013, an increase of $23.4 million. This increase was primarily due to increased refinery operating margins and higher refinery throughput.

Refining and Marketing Segment. Operating income for our refining and marketing segment was $154.8 million for the nine months ended September 30, 2014, compared to $112.1 million for the nine months ended September 30, 2013, an increase of $42.7 million. This increase was primarily due to increased refinery operating margins and higher refinery throughput at our Krotz Springs refinery, partially offset by reduced refinery throughput at our Big Spring refinery.

Refinery operating margin at the Big Spring refinery was $17.35 per barrel for the nine months ended September 30, 2014, compared to $16.35 per barrel for the nine months ended September 30, 2013. This increase in operating margin was primarily due to a widening of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread, partially offset by a lower Gulf Coast 3/2/1 crack spread. The average Gulf Coast 3/2/1 crack spread decreased 22.8% to $16.37 per barrel for the nine months ended September 30, 2014, compared to $21.21 per barrel for the nine months ended September 30, 2013, which was primarily influenced by a reduction in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for the nine months ended September 30, 2014 was $8.52 per barrel compared to $13.25 per barrel for the nine months ended September 30, 2013.

Refinery operating margin at the Krotz Springs refinery was $8.68 per barrel for the nine months ended September 30, 2014, compared to $5.16 per barrel for the nine months ended September 30, 2013. This increase in operating margin was primarily due to a higher Gulf Coast 2/1/1 high sulfur diesel crack spread and a widening WTI Cushing to WTI Midland spread, partially offset by a narrowing LLS to WTI Cushing spread as well as the impact of RINs costs during the nine months ended September 30, 2014. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the nine months ended September 30, 2014 was $11.43 per barrel, compared to $6.30 per barrel for the nine months ended September 30, 2013, which was primarily influenced by an increase in the Brent to LLS spread. The average Brent to LLS spread for the nine months ended September 30, 2014 was $4.43 per barrel compared to $(0.66) per barrel for the nine months ended September 30, 2013. For the nine months ended September 30, 2014, the Krotz Springs refinery was negatively impacted by costs of $16.6 million to purchase RINs needed to satisfy our obligation to blend biofuels into the products we produce. The Krotz Springs refinery received an exemption from the RFS requirements for 2013 and as a result did not record costs associated with RINs.

Asphalt Segment. Operating loss for our asphalt segment was $17.2 million for the nine months ended September 30, 2014, compared to $0.7 million for the nine months ended September 30, 2013, an increase in loss of $16.5 million. This increase was primarily due to lower sales volumes and lower asphalt margin, which was influenced by higher costs of asphalt

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purchased, partially offset by the gain on the sale of our Willbridge, Oregon asphalt terminal of $2.0 million. Asphalt margins for the nine months ended September 30, 2014 were $46.77 per ton compared to $69.49 per ton for the nine months ended September 30, 2013.

Retail Segment. Operating income for our retail segment was $16.6 million for the nine months ended September 30, 2014, compared to $19.6 million for the nine months ended September 30, 2013, a decrease of $3.0 million. This decrease was primarily due to lower retail fuel margins, lower merchandise margins and a lower gain on disposition of assets.

Interest Expense

Interest expense was $85.5 million for the nine months ended September 30, 2014, compared to $63.8 million for the nine months ended September 30, 2013, an increase of $21.7 million, or 34.0%. This increase was primarily due to higher financing costs associated with crude oil purchases as a result of a backwardated crude oil market, partially offset by reduced interest charges for the nine months ended September 30, 2014 resulting from prepayments of our senior secured notes.

Income Tax Expense

Income tax expense was $14.5 million for the nine months ended September 30, 2014, compared to $9.6 million for the nine months ended September 30, 2013. Income tax expense increased as a result of our higher pre-tax income for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 and an increase in the effective tax rate. Our effective tax rate was 20.7% for the nine months ended September 30, 2014, compared to an effective tax rate of 13.7% for the nine months ended September 30, 2013. This higher effective tax rate was primarily due to the impact of the non-controlling interest’s share of the Partnership’s income.

Net Income Attributable to Non-controlling Interest

Net income attributable to non-controlling interest includes the proportional share of the Partnership’s income attributable to the limited partner interests held by the public. Additionally, net income attributable to non-controlling interest includes the proportional share of net income related to non-voting common stock of our subsidiary, Alon Assets, Inc., owned by non-controlling interest shareholders. Net income attributable to non-controlling interest was $23.7 million for the nine months ended September 30, 2014, compared to $23.4 million for the nine months ended September 30, 2013, an increase of $0.3 million.

Net Income Available to Stockholders

Net income available to stockholders was $31.8 million for the nine months ended September 30, 2014, compared to $37.0 million for the nine months ended September 30, 2013, a decrease of $5.2 million. This decrease 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 arrangements, other credit lines and advances from affiliates.

We have agreements with J. Aron for the supply of crude oil that supports the operations of all our refineries as well as most of our asphalt terminals. These agreements substantially reduce our physical inventories and our associated 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 existing operations for at least the next twelve months. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive and other factors beyond our control.

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.

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Cash Flows

The following table sets forth our consolidated cash flows for the nine months ended September 30, 2014, and 2013:



	For the Nine Months Ended
	September 30,
	2014			2013
	(dollars in thousands)
Cash provided by (used in):
Operating activities	$	144,584		$	109,661
Investing activities	(84,753		)	(30,190		)
Financing activities	(90,762		)	95,407
Net increase (decrease) in cash and cash equivalents	$	(30,931	)	$	174,878

Cash Flows Provided by Operating Activities

Net cash provided by operating activities was $144.6 million during the nine months ended September 30, 2014, compared to $109.7 million during the nine months ended September 30, 2013. The increase in net cash provided by operating activities of $34.9 million was primarily attributable to increased net income after adjusting for non-cash items of $4.6 million, decreased cash used for inventories of $29.1 million and increased cash collected on receivables of $37.2 million. These changes were partially offset by increased cash used for accounts payable and accrued liabilities of $0.6 million, increased cash used for other non-current liabilities of $18.7 million, increased cash used for prepaid expenses and other current assets of $10.8 million and increased cash used for other assets of $5.9 million.

Cash Flows Used In Investing Activities

Net cash used in investing activities was $84.8 million during the nine months ended September 30, 2014, compared to $30.2 million during the nine months ended September 30, 2013. The change in cash flows used in investing activities of $54.6 million was primarily attributable to increased cash used for capital expenditures and capital expenditures for turnarounds and catalysts of $70.0 million, partially offset by increased cash proceeds from the disposition of assets of $15.3 million. The increase in capital expenditures and capital expenditures for turnarounds and catalysts is related to the completion of the planned turnaround and the vacuum tower project at our Big Spring refinery during the second quarter of 2014.

Cash Flows Provided by (Used In) Financing Activities

Net cash used in financing activities was $90.8 million during the nine months ended September 30, 2014, compared to net cash provided by financing activities of $95.4 million during the nine months ended September 30, 2013. The change in cash flows from financing activities of $186.2 million was primarily attributable to increased net payments on long-term debt of $229.7 million, partially offset by reduced payments to shareholders and non-controlling interests of $25.5 million and net payments during 2013 on our call option overlay transactions of $15.2 million.

Indebtedness

Alon Energy Term Loan. In March 2014, we entered into a five-year term loan agreement (“Alon Energy Term Loan”) for a principal amount of $25.0 million, maturing in March 2019. Repayments are monthly, commencing June 2014. Borrowings under this agreement incur interest at an annual rate equal to LIBOR plus a margin of 3.75%. We pledged 2.2 million of the Partnership’s common units as collateral for the Alon Energy Term Loan. Additionally, Alon Assets, Inc. guarantees all payments under the Alon Energy Term Loan. The Alon Energy Term Loan contains certain restrictive covenants including maintenance financial covenants.

Proceeds from the Alon Energy Term Loan were used to purchase equipment for a capital project at the Big Spring refinery.

At September 30, 2014, the Alon Energy Term Loan had an outstanding balance of $23.3 million.

Retail Credit Facilities. Southwest Convenience Stores, LLC and Skinny’s LLC (“Alon Retail”) were parties to a credit agreement (the “Credit Agreement”) with a maturity in December 2015. At December 31, 2013, the outstanding balance under the Credit Agreement was $72.7 million. In March 2014, Alon Retail entered into a new credit agreement (“Alon Retail Credit Agreement”) and repaid in full its obligations under the Credit Agreement.

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The Alon Retail Credit Agreement will mature in March 2019 and includes a $110.0 million term loan and a $10.0 million revolving credit loan. The Alon Retail Credit Agreement also includes an accordion feature that provides for incremental term loans up to $30.0 million to fund store rebuilds, new builds and acquisitions. Borrowings under the Alon Retail Credit Agreement bear interest at a Eurodollar rate plus an applicable margin between 2.00% and 2.75%, determined quarterly based upon Alon Retail’s leverage ratio. Principal payments are made in quarterly installments based on a 15-year amortization schedule. Obligations under the Alon Retail Credit Agreement are secured by a first lien on substantially all of the assets of Alon Retail. The Alon Retail Credit Agreement also contains certain restrictive covenants including maintenance financial covenants.

Proceeds from the Alon Retail Credit Agreement were used to fully repay the remaining obligations under the Credit Agreement and pay a dividend distribution of $40.0 million to Alon Brands, Inc., our wholly-owned subsidiary, with the remainder used for general corporate purposes.

At September 30, 2014, the Alon Retail Credit Agreement had an outstanding balance of $114.5 million, consisting of a term loan balance of $104.5 million and a revolving credit loan balance of $10.0 million.

Alon USA Energy, Inc. Letter of Credit Facility. We have an unsecured credit facility for the issuance of standby letters of credit in an amount not to exceed $60.0 million. At September 30, 2014 and December 31, 2013, we had letters of credit outstanding under this facility of $58.2 million and $56.8 million, respectively.

Alon USA, LP Revolving Credit Facility. We have a $240.0 million revolving credit facility that can be used both for borrowings and the issuance of letters of credit. Borrowings of $50.0 million and $100.0 million and letters of credit of $90.7 million and $109.8 million were outstanding under this facility at September 30, 2014 and December 31, 2013, respectively.

Senior Secured Notes. During the nine months ended September 30, 2014, we redeemed the remaining principal balance on the 13.50% senior secured notes (“Senior Secured Notes”) due October 2014. As a result of the prepayment of the Senior Secured Notes, write-offs of unamortized original issuance discount and debt issuance costs of $0.1 million and $0.1 million, respectively, were charged to interest expense for the three months ended September 30, 2014, and $0.4 million and $0.4 million, respectively, for the nine months ended September 30, 2014.

At December 31, 2013, the Senior Secured Notes had an outstanding balance of $73.7 million.

Capital Spending

Each year our Board of Directors approves capital projects, including sustaining maintenance, 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, growth and profit improvement projects may be approved. Our total capital expenditure plan, including expenditures for catalysts and turnarounds, for 2014 is $165.0 million. Approximately $125.2 million has been spent during the nine months ended September 30, 2014.

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, 2013.

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Off-Balance Sheet Arrangements

We have no material off-balance sheet arrangements.

Critical Accounting Policies

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

Our critical accounting policies are described under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2013. 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 catalysts replacements. No significant changes to these accounting policies have occurred subsequent to December 31, 2013.

Goodwill Impairment Analysis Update

As of December 31, 2013, we concluded that none of our goodwill was impaired. In addition, we disclosed in our Annual Report on Form 10-K that a significant portion of the fair value of our California refining reporting unit was dependent on cash flows expected to be derived pursuant to receiving a permit to begin logistical operations for crude oil delivered by rail. During September 2014, we received the permit, which supports the conclusions reached by management as of December 31, 2013.

Potential Change to Segment Reporting

We are considering a change to our reporting segment information. We are evaluating whether to move our asphalt segment into the refining and marketing segment as our asphalt business is less strategic to our overall operations as it was in prior periods. Additionally, terminal operations of the asphalt segment are now analyzed in conjunction with the operations of the refineries. We have made recent organizational changes where the person responsible for the refinery operations is also responsible for the asphalt terminal operations.

New Accounting Standards and Disclosures

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

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Changes in commodity prices, purchased fuel prices and interest rates are our primary sources of market risk. Our risk management committee oversees all activities associated with the identification, assessment and management of our market risk exposure.

Commodity Price Risk

We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refinery operations. Our financial results can be affected significantly by fluctuations in these prices, which depend on many factors, including demand for crude oil, gasoline and other refined products, changes in the economy, worldwide production levels, worldwide inventory levels and governmental regulatory initiatives. Our risk management strategy identifies circumstances in which we may utilize the commodity futures market to manage risk associated with these price fluctuations.

In order to manage the uncertainty relating to inventory price volatility, we have consistently applied a policy of maintaining inventories at or below a targeted operating level. In the past, circumstances have occurred, such as timing of crude oil cargo deliveries, turnaround schedules or shifts in market demand that have resulted in variances between our actual inventory level and our desired target level. Upon the review and approval of our risk management committee, we may utilize the commodity futures market to manage these anticipated inventory variances.

We maintain inventories of crude oil, refined products, asphalt and blendstocks, the values of which are subject to wide fluctuations in market prices driven by world economic conditions, regional and global inventory levels and seasonal conditions. As of September 30, 2014, we held 1.5 million barrels of crude oil, refined products and asphalt inventories valued under the LIFO valuation method. Market value exceeded carrying value of LIFO costs by $57.3 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 $1.5 million.

All commodity derivative 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 commodity derivative contracts as of September 30, 2014:



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)	348,077		$	92.97	$	—	$	32,362		$	31,778		$	(584	)
Forwards-short (Crude)	(105,815	)	—		105.03		(11,114		)	(11,023		)	91
Forwards-long (Gasoline)	391,565		107.00		—		41,898			39,421			(2,477		)
Forwards-long (Distillate)	108,532		113.06		—		12,270			12,062			(208		)
Forwards-short (Distillate)	(6,706	)	—		115.90		(777		)	(789		)	(12		)
Forwards-long (Jet)	104,375		115.31		—		12,036			11,427			(609		)
Forwards-short (Jet)	(2,035	)	—		117.16		(238		)	(236		)	2
Forwards-long (Slurry)	47,362		79.95		—		3,787			3,615			(172		)
Forwards-long (Catfeed)	97,595		105.30		—		10,276			9,765			(511		)
Forwards-short (Catfeed)	(28,625	)	—		105.30		(3,014		)	(2,960		)	54
Forwards-long (Slop)	3,934		83.03		—		327			316			(11		)
Forwards-short (Slop)	(16,226	)	—		87.75		(1,424		)	(1,408		)	16
Forwards-short (Propane)	(50,992	)	—		42.88		(2,184		)	(2,031		)	153
Forwards-long (Asphalt)	155,893		102.39		—		15,962			14,978			(984		)
Forwards-short (Asphalt)	(43,607	)	—		114.39		(4,988		)	(4,887		)	101
Futures-long (Crude)	139,000		91.70		—		12,747			12,574			(173		)
Futures-short (Crude)	(242,000	)	—		92.06		(22,278		)	(22,061		)	217
Futures-short (Gasoline)	(467,000	)	—		105.19		(49,123		)	(47,805		)	1,318
Futures-short (Distillate)	(278,000	)	—		115.96		(32,238		)	(30,950		)	1,288

Description	Contract Volume		Wtd Avg Contract		Wtd Avg Market		Contract			Market			Gain
of Activity	(barrels)		Spread		Spread		Value			Value			(Loss)
							(in thousands)
Futures-swaps (long crude, short products)	(3,600,000	)	$	22.58	$	19.36	$	(81,270	)	$	(69,691	)	$	11,579
Futures-swaps (LLS-WTI)	2,160,000		3.21		3.01		6,930			6,511			(419		)
Futures-swaps (Brent-WTI)	(1,800,000	)	10.52		9.46		(18,936		)	(17,028		)	1,908

Interest Rate Risk

As of September 30, 2014, $433.4 million, excluding discounts, of our outstanding debt was subject to floating interest rates, of which $50.0 million was charged interest at the Eurodollar rate plus 3.50%, subject to a minimum interest rate of 4.00%, and $245.6 million was charged interest at the Eurodollar rate (with a floor of 1.25%) plus a margin of 8.00%.

As of September 30, 2014, we had three interest rate swap contracts, maturing March 2019, that effectively fix the variable interest component on approximately 75% of the outstanding principal of the term loan within the Alon Retail Credit Agreement. As of September 30, 2014, the outstanding balance of the term loan was $104.5 million and the interest rate swaps had an average fixed interest rate of 0.25%.

An increase of 1% in the variable rate on our indebtedness, after considering the instruments subject to minimum interest rates and the interest rate swap contracts, would result in an increase to our interest expense of approximately $0.9 million per year.

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ITEM 4. CONTROLS AND PROCEDURES

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.

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. We are transitioning our assessment of our internal control effectiveness over financial reporting from the criteria outlined by the 1992 framework of the Committee of Sponsoring Organizations of the Treadway Commission to its 2013 framework. We expect to complete this transition during 2014.

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PART II. OTHER INFORMATION

ITEM 6. EXHIBITS



Exhibit
Number		Description of Exhibit
31.1		Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2		Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1		Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
101		The following financial information from Alon USA Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, 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:	October 31, 2014	By:	/s/ David Wiessman
			David Wiessman
			Executive Chairman of the Board


Date:	October 31, 2014	By:	/s/ Paul Eisman
			Paul Eisman
			President and Chief Executive Officer


Date:	October 31, 2014	By:	/s/ Shai Even
			Shai Even
			Senior Vice President and Chief Financial Officer
			(Principal Accounting Officer)

Alon USA Energy, Inc. - FORM 10-Q - October 31, 2014

Attached files

Alon USA Energy, Inc. Reports