Alon USA Energy 10Q 2014 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

___________________________________________________

FORM 10-Q



þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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 May 1, 2014, was 68,972,609.

TABLE OF CONTENTS

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)



	March 31, 2014			December 31, 2013
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	355,292		$	224,499
Accounts and other receivables, net	194,830			200,398
Income tax receivable	5,869			16,053
Inventories	148,347			128,770
Deferred income tax asset	10,830			13,045
Prepaid expenses and other current assets	22,835			18,629
Total current assets	738,003			601,394
Equity method investments	26,389			26,251
Property, plant and equipment, net	1,385,767			1,429,342
Goodwill	101,913			105,943
Other assets, net	93,652			82,210
Total assets	$	2,345,724		$	2,245,140
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	365,961		$	336,499
Accrued liabilities	95,538			120,858
Current portion of long-term debt	88,208			83,174
Total current liabilities	549,707			540,531
Other non-current liabilities	182,152			189,474
Long-term debt	595,537			529,074
Deferred income tax liability	369,223			360,657
Total liabilities	1,696,619			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 March 31, 2014 and December 31, 2013	682			682
Common stock, par value $0.01, 150,000,000 shares authorized; 68,807,787 and 68,641,428 shares issued and outstanding at March 31, 2014 and December 31, 2013, respectively	688			686
Additional paid-in capital	510,815			509,170
Accumulated other comprehensive loss, net of income tax	(18,132		)	(37,515		)
Retained earnings	121,604			124,936
Total stockholders’ equity	615,657			597,959
Non-controlling interest in subsidiaries	33,448			27,445
Total equity	649,105			625,404
Total liabilities and equity	$	2,345,724		$	2,245,140

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

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ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, dollars in thousands except per share data)



	For the Three Months Ended
	March 31,
	2014			2013
Net sales (1)	$	1,683,245		$	1,651,196
Operating costs and expenses:
Cost of sales	1,506,545			1,378,257
Direct operating expenses	70,678			74,222
Selling, general and administrative expenses	39,389			41,741
Depreciation and amortization	29,878			31,163
Total operating costs and expenses	1,646,490			1,525,383
Gain on disposition of assets	2,205			18
Operating income	38,960			125,831
Interest expense	(28,015		)	(21,292		)
Equity losses of investees	(459		)	(381		)
Other income (loss), net	(17		)	83
Income before income tax expense	10,469			104,241
Income tax expense	2,094			30,590
Net income	8,375			73,651
Net income attributable to non-controlling interest	7,590			19,467
Net income available to stockholders	$	785		$	54,184
Earnings per share, basic	$	0.01		$	0.86
Weighted average shares outstanding, basic (in thousands)	68,617			61,957
Earnings per share, diluted	$	0.01		$	0.80
Weighted average shares outstanding, diluted (in thousands)	69,067			67,616
Cash dividends per share	$	0.06		$	0.04

___________


(1)	Includes excise taxes on sales by the retail segment of $17,810 and $17,305 for the three months ended March 31, 2014 and 2013, respectively.

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

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ALON USA ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited, dollars in thousands)



	For the Three Months Ended
	March 31,
	2014		2013
Net income	$	8,375	$	73,651
Other comprehensive income:
Commodity contracts designated as cash flow hedges:
Unrealized holding gain arising during period	23,582		9,381
Loss reclassified to earnings - cost of sales	—		24
Amortization of unrealized loss on de-designated cash flow hedges - cost of sales	8,275		—
Net gain, before tax	31,857		9,405
Income tax expense	11,787		3,498
Total other comprehensive income, net of tax	20,070		5,907
Comprehensive income	28,445		79,558
Comprehensive income attributable to non-controlling interest	8,277		19,736
Comprehensive income attributable to stockholders	$	20,168	$	59,822

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 Three Months Ended
	March 31,
	2014			2013
Cash flows from operating activities:
Net income	$	8,375		$	73,651
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	29,878			31,163
Stock compensation	1,566			1,665
Deferred income tax expense (benefit)	(1,006		)	7,549
Equity losses of investees	459			381
Amortization of debt issuance costs	1,175			1,117
Amortization of original issuance discount	1,663			731
Gain on disposition of assets	(2,205		)	(18		)
Unrealized loss on commodity swaps	6,606			—
Changes in operating assets and liabilities:
Accounts and other receivables, net	6,320			19,548
Income tax receivable	10,184			—
Inventories	(20,561		)	(27,282		)
Prepaid expenses and other current assets	(4,206		)	7,137
Other assets, net	(345		)	1,876
Accounts payable	30,380			3,021
Accrued liabilities	(8,124		)	26,788
Other non-current liabilities	2,555			13,443
Net cash provided by operating activities	62,714			160,770
Cash flows from investing activities:
Capital expenditures	(18,160		)	(8,414		)
Capital expenditures for turnarounds and catalysts	(14,847		)	(5,216		)
Contribution to equity method investment	(597		)	—
Proceeds from disposition of assets	40,000			57
Net cash provided by (used in) investing activities	6,396			(13,573		)
Cash flows from financing activities:
Dividends paid to stockholders	(4,102		)	(2,489		)
Dividends paid to non-controlling interest	(135		)	—
Distributions paid to non-controlling interest in the Partnership	(2,070		)	(6,556		)
Deferred debt issuance costs	(1,844		)	(205		)
Revolving credit facilities, net	—			1,000
Additions to long-term debt	145,000			—
Payments on long-term debt	(75,166		)	(2,377		)
Net cash provided by (used in) financing activities	61,683			(10,627		)
Net increase in cash and cash equivalents	130,793			136,570
Cash and cash equivalents, beginning of period	224,499			116,296
Cash and cash equivalents, end of period	$	355,292		$	252,866
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$	28,832		$	12,149
Cash received for income tax	$	(10,184	)	$	(843	)

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 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. The results of operations for the interim periods are not necessarily indicative of the operating results that may be obtained for the year ending December 31, 2014.

The 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.


(2)	Alon USA Partners, LP

The Partnership is a publicly traded limited partnership that was formed to own the assets and operations of the Big Spring refinery and associated wholesale marketing operations. On November 26, 2012, the Partnership completed its initial public offering (NYSE: ALDW) of 11,500,000 common units representing limited partner interests. As of March 31, 2014, the 11,502,476 common units held by the public represent 18.4% of the Partnership’s common units outstanding. We own the remaining 81.6% of the Partnership’s common units and Alon USA Partners GP, LLC (the “General Partner”), our wholly-owned subsidiary, owns 100% of the non-economic General Partner interest in the Partnership.

The 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 it generates each quarter, as defined in the partnership agreement and subject to the approval of the board of directors of the General Partner. The per unit amount of available cash to be distributed each quarter, if any, will be distributed within 60 days following the end of such quarter.

On March 3, 2014, the Partnership paid a cash distribution of $11,250, or $0.18 per unit. The total cash distribution paid to non-affiliated common unitholders was $2,070.


(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.

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

(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 214,000 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 three months ended March 31, 2014 and 2013, we did not process crude oil at our California refineries.

We supply gasoline and diesel to 639 Alon branded retail sites, including our retail segment convenience stores. During 2014, approximately 56% of the gasoline and 27% 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 86 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 (“Wright”) 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.

Segment data as of and for the three month periods ended March 31, 2014 and 2013 are presented below:



	Refining and Marketing		Asphalt			Retail			Corporate			Consolidated Total
Three Months Ended March 31, 2014
Net sales to external customers	$	1,365,826	$	96,171		$	221,248		$	—		$	1,683,245
Intersegment sales/purchases	139,092		(16,983		)	(122,109		)	—			—
Depreciation and amortization	25,368		1,200			2,714			596			29,878
Operating income (loss)	40,004		(3,205		)	2,933			(772		)	38,960
Total assets	2,010,694		107,995			204,088			22,947			2,345,724
Turnarounds, catalysts and capital expenditures	27,043		1,718			3,381			865			33,007



	Refining and Marketing		Asphalt			Retail			Corporate			Consolidated Total
Three Months Ended March 31, 2013
Net sales to external customers	$	1,272,226	$	154,865		$	224,105		$	—		$	1,651,196
Intersegment sales/purchases	141,899		(16,559		)	(125,340		)	—			—
Depreciation and amortization	26,505		1,549			2,268			841			31,163
Operating income (loss)	126,708		(4,401		)	4,540			(1,016		)	125,831
Total assets	2,001,498		129,941			203,508			20,775			2,355,722
Turnarounds, catalysts and capital expenditures	11,185		1,792			640			13			13,630

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

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

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


(4)	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 for the purchase of RINs to satisfy the requirement to blend biofuels into the products we have produced. Our RINs obligation is based on the RINs deficit and the market price of those RINs as of the balance sheet date. The RINs obligation is categorized as level 2 of the fair value hierarchy and is measured at fair value using the market approach based on quoted prices from an independent pricing service.

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the consolidated balance sheets at March 31, 2014 and December 31, 2013:



	Level 1		Level 2		Level 3		Total
As of March 31, 2014
Liabilities:
Commodity contracts (futures and forwards)	$	2,295	$	—	$	—	$	2,295
Commodity contracts (swaps)	—		1,644		—		1,644
Fair value hedges	—		5,946		—		5,946

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

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

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. As quoted forward market prices for these commodities became available during the three months ended March 31, 2014, we reclassified the related financial liability to level 2.

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 three months ended March 31, 2014:



	For the Three Months Ended
	March 31, 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

Mark to Market

Commodity Derivatives. We selectively utilize crude oil and refined product commodity derivative contracts to reduce the risk associated with potential price changes on committed obligations. 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.

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 March 31, 2014, we have accounted for certain commodity contracts as fair value hedges with contract purchase volumes of 756 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 March 31, 2014, we have accounted for certain commodity swap contracts as cash flow hedges with contract purchase volumes of 5,220 thousand barrels of crude oil and net contract sales volumes of 5,220 thousand barrels of refined products with the longest remaining contract term of twenty-one months. Related to these transactions in Other Comprehensive Income (“OCI”), we recognized unrealized gains of $31,857 and $9,405 for the three months ended March 31, 2014 and 2013, respectively.

In November 2013, we elected to de-designate certain commodity swap contracts that were previously designated as cash flow hedges. Consequently, hedge accounting was discontinued for the commodity swap contracts and prospectively all changes in fair value were recorded in cost of sales in the consolidated statements of operations. The commodity derivative contracts were subsequently re-designated as cash flow hedges as of December 31, 2013 on a product basis. As of March 31, 2014, we have unrealized losses of $21,707 classified in OCI that related to the application of hedge accounting prior to de-designation that will be recorded into earnings as the underlying forecasted transactions occur through the remainder of 2014.

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

During the three months ended March 31, 2014, we reclassified $8,275 of losses related to these de-dedesignated cash flow hedges from OCI into cost of sales.

For the three months ended March 31, 2014 and 2013, there was no hedge ineffectiveness recognized in income. No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.

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



	As of March 31, 2014
	Asset Derivatives				Liability Derivatives
	Balance Sheet				Balance Sheet
	Location	Fair Value			Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	706		Accrued liabilities	$	3,001
Commodity contracts (swaps)	Accounts receivable	(790		)		—
Total derivatives not designated as hedging instruments		$	(84	)		$	3,001

Derivatives designated as hedging instruments:
Commodity contracts (swaps)	Accounts receivable	$	1,544		Other non-current liabilities	$	2,398
Fair value hedges		—			Other non-current liabilities	5,946
Total derivatives designated as hedging instruments		1,544				8,344
Total derivatives		$	1,460			$	11,345



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

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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 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 March 31, 2014
Commodity contracts (swaps)	$	31,857	Cost of sales	$	(8,275	)		$	—
Total derivatives	$	31,857		$	(8,275	)		$	—

For the Three Months Ended March 31, 2013
Commodity contracts (swaps)	$	9,405	Cost of sales	$	(24	)		$	—
Total derivatives	$	9,405		$	(24	)		$	—

Derivatives in fair value hedging relationships:



		Gain (Loss) Recognized in Income
		For the Three Months Ended
		March 31,
	Location	2014			2013
Fair value hedges	Cost of sales	$	(2,607	)	$	(2,819	)
Total derivatives		$	(2,607	)	$	(2,819	)

Derivatives not designated as hedging instruments:



		Gain (Loss) Recognized in Income
		For the Three Months Ended
		March 31,
	Location	2014			2013
Commodity contracts (futures & forwards)	Cost of sales	$	(985	)	$	7,987
Commodity contracts (swaps)	Cost of sales	2,037			—
Total derivatives		$	1,052		$	7,987

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

Offsetting Assets and Liabilities

Our 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 March 31, 2014 and December 31, 2013:



	Gross Amounts of Recognized Assets/Liabilities		Gross Amounts offset in the Statement of Financial Position			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position		Gross Amounts Not offset in the Statement of Financial Position					Net Amount
	Gross Amounts of Recognized Assets/Liabilities		Gross Amounts offset in the Statement of Financial Position					Financial Instruments			Cash Collateral Pledged		Net Amount
As of March 31, 2014
Commodity Derivative Assets:
Futures & forwards	$	1,297	$	(591	)	$	706	$	(706	)	$	—	$	—
Swaps	1,544		(790		)	754		(754		)	—		—
Commodity Derivative Liabilities:
Futures & forwards	$	3,592	$	(591	)	$	3,001	$	(706	)	$	—	$	2,295
Swaps	3,188		(790		)	2,398		(754		)	—		1,644
Fair value hedges	5,946		—			5,946		—			—		5,946

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

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 $8,013 for the three months ended March 31, 2014. This amount is reflected in cost of sales. For the three months ended March 31, 2013, we utilized carryover RINs from 2012 to completely offset our RINs deficit.


(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.

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

Carrying value of inventories consisted of the following:



	March 31, 2014		December 31, 2013
Crude oil, refined products, asphalt and blendstocks	$	45,764	$	34,326
Crude oil inventory consigned to others	49,925		44,081
Materials and supplies	21,954		21,685
Store merchandise	22,459		20,526
Store fuel	8,245		8,152
Total inventories	$	148,347	$	128,770

Market values of crude oil, refined products, asphalt and blendstock inventories exceeded LIFO costs by $68,173 and $61,199 at March 31, 2014 and December 31, 2013, respectively.


(7)	Inventory Financing Agreements

Alon has entered into Supply and Offtake Agreements and other associated agreements (together the “Supply and Offtake Agreements”) with J. Aron & Company (“J. Aron”), to support the operations of the Big Spring, Krotz Springs and California refineries 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 market prices at that time.

In association with the Supply and Offtake Agreement at the Krotz Springs refinery, we entered into a secured Credit Agreement (the “Krotz Springs Standby LC Facility”) by and between Alon, as Borrower, and Goldman Sachs Bank USA, as Issuing Bank. The Krotz Springs Standby LC Facility provides for up to $200,000 of letters of credit to be issued to J. Aron. Obligations under the Krotz Springs Standby LC Facility are secured by a first priority lien on the existing and future accounts receivable and inventory of Alon Refining Krotz Springs, Inc. and its subsidiaries (“ARKS”), 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. At this time there is no further availability under the Krotz Springs Standby LC Facility. The Krotz Springs Standby LC Facility matures in July 2016.

As of March 31, 2014 and December 31, 2013, we had net current payables to J. Aron for purchases of $16,670 and $16,917, respectively, non-current liabilities related to the original financing of $72,987 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 $1,901 and $539 at March 31, 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.

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)


(8)	Property, Plant and Equipment, Net

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



	March 31, 2014			December 31, 2013
Refining facilities	$	1,771,926		$	1,804,445
Pipelines and terminals	43,445			43,445
Retail	187,037			184,858
Other	16,046			15,326
Property, plant and equipment, gross	2,018,454			2,048,074
Accumulated depreciation	(632,687		)	(618,732		)
Property, plant and equipment, net	$	1,385,767		$	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. A before-tax gain of $2,166 was recognized and has been included in gain on disposition of assets in our consolidated statement of operations.


(9)	Goodwill

The following table provides a summary of changes to our goodwill balance by segment for the three months ended March 31, 2014:



	Refining and Marketing			Retail		Total
Balance at December 31, 2013	$	55,754		$	50,189	$	105,943
Disposition of assets with allocated goodwill	(4,030		)	—		(4,030		)
Balance at March 31, 2014	$	51,724		$	50,189	$	101,913

During the three months ended March 31, 2014, we sold our Willbridge, Oregon asphalt terminal that was allocated goodwill of $4,030.


(10)	Additional Financial Information

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


(a)	Other Assets, Net



	March 31, 2014		December 31, 2013
Deferred turnaround and catalyst cost	$	22,427	$	12,271
Environmental receivables	3,137		4,273
Deferred debt issuance costs	13,271		12,602
Intangible assets, net	8,053		7,497
Receivable from supply agreements	26,179		26,179
Other, net	20,585		19,388
Total other assets	$	93,652	$	82,210

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)


(b)	Accrued Liabilities and Other Non-Current Liabilities



	March 31, 2014		December 31, 2013
Accrued Liabilities:
Taxes other than income taxes, primarily excise taxes	$	30,597	$	37,645
Employee costs	14,549		13,793
Commodity contracts	3,001		16,526
Accrued finance charges	5,787		8,733
Environmental accrual (Note 16)	12,898		12,898
Other	28,706		31,263
Total accrued liabilities	$	95,538	$	120,858

Other Non-Current Liabilities:
Pension and other postemployment benefit liabilities, net	$	40,587	$	40,351
Environmental accrual (Note 16)	44,043		45,484
Asset retirement obligations	11,894		12,468
Consignment inventory obligations	72,987		67,889
Commodity contracts	2,398		11,569
Other	10,243		11,713
Total other non-current liabilities	$	182,152	$	189,474


(11)	Postretirement Benefits

We have four defined benefit pension plans covering substantially all of our employees, excluding employees of our retail segment. The benefits are based on years of service and the employee’s final average monthly compensation. Our funding policy is to contribute annually not less than the minimum required nor more than the maximum amount that can be deducted for federal income tax purposes. Contributions are intended to provide not only for benefits attributed to service to date, but also for those benefits expected to be earned in the future. Our estimated contributions during 2014 to our pension plans have not changed significantly from amounts previously disclosed in the consolidated financial statements for the year ended December 31, 2013. For the three months ended March 31, 2014 and 2013, we contributed $1,160 and $915, respectively, to our qualified pension plans.

The components of net periodic benefit cost related to our benefit plans were as follows for the three months ended March 31, 2014 and 2013:



	For the Three Months Ended
	March 31,
	2014			2013
Components of net periodic benefit cost:
Service cost	$	856		$	1,116
Interest cost	1,238			1,100
Expected return on plan assets	(1,370		)	(1,157		)
Amortization of net loss	596			1,005
Net periodic benefit cost	$	1,320		$	2,064

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)


(12)	Indebtedness

Debt consisted of the following:



	March 31, 2014		December 31, 2013
Term loan credit facilities	$	268,832	$	244,322
Revolving credit facility	100,000		100,000
Senior secured notes	73,988		73,706
Convertible senior notes	122,336		121,090
Retail credit facilities	118,589		73,130
Total debt	683,745		612,248
Less: Current portion	88,208		83,174
Total long-term debt	$	595,537	$	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 accrue interest at an annual rate equal to LIBOR plus a margin of 3.75%. We are required to pledge 2,200,000 of the Partnership’s common units as collateral for the Alon Energy Term Loan. Additionally, Alon Assets, Inc. (“Alon Assets”) was named as a guarantor, guaranteeing 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 will be used to purchase equipment for a capital project at our Big Spring refinery.

At March 31, 2014, the Alon Energy Term Loan had an outstanding balance of $25,000.

(b) Retail Credit Facilities

Southwest Convenience Stores, LLC and Skinny’s LLC, (“Alon Retail”) were party 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. At March 31, 2014, the Alon Retail Credit Agreement had an outstanding balance of $118,167.

Borrowings under the Alon Retail Credit Agreement bear interest at a Eurodollar rate plus an applicable margin between 2.00% and 2.75%, which is determined quarterly based upon the leverage ratio of Alon Retail. 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 its obligations under the Credit Agreement of $72,689, pay a dividend distribution of $40,000 to Alon Brands, Inc., our wholly-owned subsidiary, with the remainder used for general corporate purposes.

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

We had borrowings of $100,000 and $100,000 and letters of credit of $103,363 and $109,772 outstanding under the Alon USA LP $240,000 revolving credit facility at March 31, 2014 and December 31, 2013, respectively.

(d) Senior Secured Notes

In May 2014, we redeemed $40,000 of the principal balance on the 13.50% senior secured notes (“Senior Secured Notes”) due October 2014, reducing the principal balance to approximately $35,600.

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

(e) Financial Covenants

We have certain credit agreements that contain restrictive covenants, including maintenance financial covenants. At March 31, 2014, we were in compliance with these covenants.


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

Our overall executive incentive compensation program includes the granting of awards in the form of options to purchase common stock, Stock Appreciation Rights (“SARs”), restricted shares of common stock, restricted common stock units, performance shares, performance units and senior executive plan bonuses to our directors, officers and key employees.

Restricted Stock. As of March 31, 2014 and December 31, 2013, we had 448,694 non-vested restricted shares. Compensation expense for restricted stock awards amounted to $488 and $517 for the three months ended March 31, 2014 and 2013, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.

Restricted Stock Units. In May 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. Compensation expense for the restricted stock units amounted to $374 and $374 for the three months ended March 31, 2014 and 2013, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.

Unrecognized Compensation. As of March 31, 2014, there was $4,905 of total unrecognized compensation cost related to non-vested share-based compensation arrangements. That cost is expected to be recognized over a weighted-average period of 1.3 years.


(14)	Equity (share values in dollars)

Changes to equity during the three months ended March 31, 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	19,383			687			20,070
Stock compensation	1,635			(69		)	1,566
Dividends of common stock on preferred stock	(3		)	—			(3		)
Distributions to non-controlling interest in the Partnership	—			(2,070		)	(2,070		)
Dividends	(4,102		)	(135		)	(4,237		)
Net income	785			7,590			8,375
Balance at March 31, 2014	$	615,657		$	33,448		$	649,105

(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 three months ended March 31, 2014, 164,822 shares of our common stock were issued in exchange for 881.12 shares of Alon Assets with 1,754,889 shares of our common stock available for exchange at March 31, 2014.

Compensation expense associated with the difference in value between the participants’ ownership of Alon Assets compared to our common stock of $697 and $764 was recognized for the three months ended March 31, 2014 and 2013, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)


(b)	Dividends

Common Stock Dividends. On March 14, 2014, we paid a regular quarterly cash dividend of $0.06 per share on common stock to stockholders of record at the close of business on February 28, 2014.

Preferred Stock Dividends. We issued 738 shares of common stock for payment of the quarterly 8.5% preferred stock dividend to preferred stockholders for the three months ended March 31, 2014.


(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	14,333			—			14,333
Amounts reclassified from accumulated other comprehensive loss	5,050			—			5,050
Net current-period other comprehensive income	19,383			—			19,383
Balance at March 31, 2014	$	1,135		$	(19,267	)	$	(18,132	)


(15)	Earnings Per Share

Basic earnings per share is calculated as net income available to common stockholders divided by the average number of participating shares of common stock outstanding. Diluted earnings per share include the dilutive effect of SARs, granted restricted stock units, 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 per share, basic and diluted, for the three months ended March 31, 2014 and 2013, is as follows (shares in thousands, per share value in dollars):



	For the Three Months Ended
	March 31,
	2014		2013
Net income available to stockholders	$	785	$	54,184
Less: preferred stock dividends	15		758
Net income available to common stockholders	770		53,426

Weighted average number of shares of common stock outstanding	68,617		61,957
Dilutive SARs, RSUs, convertible debt, warrants and convertible preferred stock	450		5,659
Weighted average number of shares of common stock outstanding assuming dilution	69,067		67,616
Earnings per share – basic	$	0.01	$	0.86
Earnings per share – diluted	$	0.01	$	0.80

For the three months ended March 31, 2014, we have excluded 101 common stock equivalents from the weighted average number of diluted shares outstanding as the effect of including such shares would be anti-dilutive. For the three months ended March 31, 2013, the weighted average number of diluted shares includes all potentially dilutive securities.


(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. These agreements 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 commercial arrangement to resolve the dispute have been unsuccessful to this point. A pre-trial ruling by the trial court is

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ALON USA ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

currently being appealed and therefore the matter 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 $56,941 ($12,898 current liability and $44,043 non-current liability) at March 31, 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 $9,100 and $9,100 and non-current receivables of $779 and $1,774 at March 31, 2014 and December 31, 2013, respectively.

We have an indemnification agreement with a prior owner for part of the remediation expenses at certain West Coast assets. We have recorded current receivables of $418 and $418 and non-current receivables of $2,358 and $2,499 at March 31, 2014 and December 31, 2013, respectively.


(17)	Subsequent Events

Repayment of Senior Secured Notes

In May 2014, we redeemed $40,000 of the principal balance on the Senior Secured Notes due October 2014, reducing the principal balance to approximately $35,600.

Dividend Declared

On April 30, 2014, our board of directors declared the regular quarterly cash dividend of $0.06 per share payable on our common stock, payable on June 16, 2014, to holders of record at the close of business on May 30, 2014.

Partnership Distribution

On May 1, 2014, the board of directors of the General Partner declared a cash distribution to the Partnership’s common unitholders of approximately $43,125, or $0.69 per common unit. The cash distribution will be paid on May 21, 2014 to unitholders of record at the close of business on May 14, 2014. The total cash distribution payable to non-affiliated common unitholders will be approximately $7,935.

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

Forward-Looking Statements

Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.

Forward-looking statements reflect our current expectations of future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations and cash flows.

Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:


•	changes in general economic conditions and capital markets;


•	changes in the underlying demand for our products;


•	the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;


•	changes in the spread between West Texas Intermediate (“WTI”) 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, we are obligated to repurchase all consigned inventories and certain other inventories upon termination of our Supply and Offtake Agreements;


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


•	disruptions due to equipment interruption, pipeline disruptions or failures at our or third-party facilities;


•	the execution of planned capital projects;


•	adverse changes in the credit ratings assigned to our debt instruments;


•	the effects of and cost of compliance with the Renewable Fuel Standards 2 (“RFS2”) requirements, 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 214,000 barrels per day (“bpd”). Our refineries produce petroleum products including various grades of gasoline, diesel fuel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum-based products.

Refining and Marketing Segment. Our refining and marketing segment includes sour and heavy crude oil refineries located in Big Spring, Texas; and Paramount, Bakersfield and Long Beach, California; and a light sweet crude oil refinery located in Krotz Springs, Louisiana. We refer to the Paramount, Bakersfield and Long Beach refineries together as our “California refineries.” The refineries in our refining and marketing segment have a combined throughput capacity of approximately 214,000 bpd. At 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 the first quarter of 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 639 Alon branded retail sites, including our retail segment convenience stores. In the first quarter of 2014, approximately 56% of the gasoline and 27% 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 86 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 (“Wright”), 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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First Quarter Operational and Financial Highlights

Operating income for the first quarter of 2014 was $39.0 million, compared to $125.8 million in the same period last year. Our operational and financial highlights for the first quarter of 2014 include the following:

•

Combined refinery average throughput for the first quarter of 2014 was 135,363 bpd, consisting of 73,296 bpd at the Big Spring refinery and 62,067 bpd at the Krotz Springs refinery, compared to a combined refinery average throughput of 117,915 bpd for the first quarter of 2013, consisting of 59,476 bpd at the Big Spring refinery and 58,439 bpd at the Krotz Springs refinery. The higher throughput rates were due to maintenance work at both refineries during the first quarter of 2013.


•	Operating margin at the Big Spring refinery was $14.77 per barrel for the first quarter of 2014 compared to $28.76 per barrel for the same period in 2013. This decrease was primarily due to lower Gulf Coast 3/2/1 crack spreads and a narrowing of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread.


•	Operating margin at the Krotz Springs refinery was $7.39 per barrel for the first quarter of 2014 compared to $13.14 per barrel for the same period in 2013. This decrease was primarily due to a narrowing of both the LLS to WTI Cushing spread and the WTI Cushing to WTI Midland spread, partially offset by higher Gulf Coast 2/1/1 high sulfur diesel crack spreads.

•

The average Gulf Coast 3/2/1 crack spread was $16.81 per barrel for the first quarter of 2014 compared to $28.40 per barrel for the first quarter of 2013, which was primarily influenced by a reduction in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for the first quarter of 2014 was $10.46 per barrel compared to $19.25 per barrel for the same period in 2013. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the first quarter of 2014 was $10.75 per barrel compared to $8.20 per barrel for the first quarter of 2013.

•

The average WTI Cushing to WTS spread for the first quarter of 2014 was $3.67 per barrel compared to $11.41 per barrel for the same period in 2013. The average WTI Cushing to WTI Midland spread for the first quarter of 2014 was $3.54 per barrel compared to $7.72 per barrel for the same period in 2013. The average LLS to WTI Cushing spread for the first quarter of 2014 was $6.00 per barrel compared to $20.22 per barrel for the same period in 2013.

•

Asphalt margins in the first quarter of 2014 were $79.59 per ton compared to $61.51 per ton in the first quarter of 2013. This increase was primarily due to lower costs of purchased asphalt sold during the first quarter of 2014 compared to 2013. The average blended asphalt sales price increased 1.1% from $540.48 per ton in the first quarter of 2013 to $546.21 per ton in the first quarter of 2014 and the average non-blended asphalt sales price decreased 0.7% from $391.77 per ton in the first quarter of 2013 to $389.14 per ton in the first quarter of 2014.


•	Retail fuel sales volume increased by 2.5% to 45.5 million gallons in the first quarter of 2014 from 44.4 million gallons in the first quarter of 2013.

•

RINs costs at our Big Spring refinery were $2.9 million for the first quarter of 2014. For the first quarter of 2013, we utilized carryover RINs from 2012 to completely offset our RINs deficit at the Big Spring refinery. The Krotz Springs refinery had RINs costs of $5.1 million for the first quarter of 2014. The Krotz Springs refinery received an exemption from the RFS2 requirements for 2013 and as a result did not record costs associated with RINs. The California refineries did not process crude oil in the first quarter of 2014 or 2013 and as a result were not subject to the RFS2 requirements.

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.

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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.

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 in Cushing, Oklahoma. Although West Texas crudes are typically transported to Cushing for sale, current logistical and infrastructure constraints at Cushing are limiting the ability of Permian Basin producers to transport their production to Cushing. 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 set 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

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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.

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 months ended March 31, 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 three months ended March 31, 2013, the Big Spring refinery was shut down for eleven days to perform maintenance on the crude vacuum tower as well as complete a reformer catalyst regeneration and a diesel hydro-treater catalyst replacement. Additionally, the Krotz Springs refinery was shut down for a week during the three months ended March 31, 2013 for crude unit maintenance and reformer catalyst regeneration.

Certain Derivative Impacts

Included in the consolidated statements of operations in cost of sales for the three months ended March 31, 2014 are losses on commodity swaps of $6.2 million.

Renewable Fuel Standard

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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 includes 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 months ended March 31, 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
	March 31,
	2014			2013
	(dollars in thousands, except per share data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	1,683,245		$	1,651,196
Operating costs and expenses:
Cost of sales	1,506,545			1,378,257
Direct operating expenses	70,678			74,222
Selling, general and administrative expenses (2)	39,389			41,741
Depreciation and amortization (3)	29,878			31,163
Total operating costs and expenses	1,646,490			1,525,383
Gain on disposition of assets (4)	2,205			18
Operating income	38,960			125,831
Interest expense	(28,015		)	(21,292		)
Equity losses of investees	(459		)	(381		)
Other income (loss), net	(17		)	83
Income before income tax expense	10,469			104,241
Income tax expense	2,094			30,590
Net income	8,375			73,651
Net income attributable to non-controlling interest	7,590			19,467
Net income available to stockholders	$	785		$	54,184
Earnings per share, basic	$	0.01		$	0.86
Weighted average shares outstanding, basic (in thousands)	68,617			61,957
Earnings per share, diluted	$	0.01		$	0.80
Weighted average shares outstanding, diluted (in thousands)	69,067			67,616
Cash dividends per share	$	0.06		$	0.04
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	62,714		$	160,770
Investing activities	6,396			(13,573		)
Financing activities	61,683			(10,627		)
OTHER DATA:
Adjusted EBITDA (5)	$	66,157		$	156,678
Capital expenditures (6)	18,160			8,414
Capital expenditures for turnarounds and catalysts	14,847			5,216

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	March 31, 2014		December 31, 2013
BALANCE SHEET DATA (end of period):	(dollars in thousands)
Cash and cash equivalents	$	355,292	$	224,499
Working capital	188,296		60,863
Total assets	2,345,724		2,245,140
Total debt	683,745		612,248
Total debt less cash and cash equivalents	328,453		387,749
Total equity	649,105		625,404


(1)	Includes excise taxes on sales by the retail segment of $17,810 and $17,305 for the three months ended March 31, 2014 and 2013, respectively.


(2)	Includes corporate headquarters selling, general and administrative expenses of $175 and $175 for the three months ended March 31, 2014 and 2013, respectively, which are not allocated to our three operating segments.


(3)	Includes corporate depreciation and amortization of $596 and $841 for the three months ended March 31, 2014 and 2013, respectively, which are not allocated to our three operating segments.


(4)	Gain on disposition of assets for the three months ended March 31, 2014 is primarily the gain recognized on the sale of our Willbridge, Oregon asphalt terminal.

(5)

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

Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:


•	Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;


•	Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;


•	Adjusted EBITDA does not reflect the prior claim that non-controlling interest have on the income generated by non-wholly-owned subsidiaries;


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


•	Our calculation of Adjusted EBITDA may differ from EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.

Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.

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The following table reconciles net income available to stockholders to Adjusted EBITDA for the three months ended March 31, 2014 and 2013, respectively:



	For the Three Months Ended
	March 31,
	2014			2013
	(dollars in thousands)
Net income available to stockholders	$	785		$	54,184
Net income attributable to non-controlling interest	7,590			19,467
Income tax expense	2,094			30,590
Interest expense	28,015			21,292
Depreciation and amortization	29,878			31,163
Gain on disposition of assets	(2,205		)	(18		)
Adjusted EBITDA	$	66,157		$	156,678

Adjusted EBITDA does not exclude unrealized losses on commodity swaps of $6,606 for the three months ended March 31, 2014, which are included in net income available to stockholders.


(6)	Includes corporate capital expenditures of $865 and $13 for the three months ended March 31, 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
	March 31,
	2014		2013
	(dollars in thousands, except per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	1,504,918	$	1,414,125
Operating costs and expenses:
Cost of sales	1,368,214		1,183,322
Direct operating expenses	60,798		63,669
Selling, general and administrative expenses	10,534		13,921
Depreciation and amortization	25,368		26,505
Total operating costs and expenses	1,464,914		1,287,417
Operating income	$	40,004	$	126,708
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin – Big Spring (2)	$	14.77	$	28.76
Refinery operating margin – Krotz Springs (2)	7.39		13.14
Refinery direct operating expense – Big Spring (3)	4.39		5.68
Refinery direct operating expense – Krotz Springs (3)	4.56		4.42
Capital expenditures	$	12,196	$	5,969
Capital expenditures for turnarounds and catalysts	14,847		5,216
PRICING STATISTICS:
Crack spreads (3/2/1) (per barrel):
Gulf Coast	$	16.81	$	28.40
Crack spreads (2/1/1) (per barrel):
Gulf Coast high sulfur diesel	$	10.75	$	8.20
WTI Cushing crude oil (per barrel)	$	98.65	$	94.27
Crude oil differentials (per barrel):
WTI Cushing less WTI Midland	$	3.54	$	7.72
WTI Cushing less WTS	3.67		11.41
LLS less WTI Cushing	6.00		20.22
Brent less LLS	4.80		(0.33		)
Brent less WTI Cushing	10.46		19.25
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	2.66	$	2.84
Gulf Coast ultra-low sulfur diesel	2.93		3.09
Gulf Coast high sulfur diesel	2.84		3.01
Natural gas (per MMBtu)	4.72		3.48

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THROUGHPUT AND PRODUCTION DATA: BIG SPRING REFINERY	For the Three Months Ended
THROUGHPUT AND PRODUCTION DATA: BIG SPRING REFINERY	March 31,
	2014			2013
	bpd	%		bpd	%
Refinery throughput:
WTS crude	35,345	48.2		45,220	76.0
WTI crude	35,982	49.1		11,549	19.4
Blendstocks	1,969	2.7		2,707	4.6
Total refinery throughput (4)	73,296	100.0		59,476	100.0
Refinery production:
Gasoline	36,290	49.6		29,785	50.4
Diesel/jet	24,674	33.6		19,298	32.6
Asphalt	3,406	4.6		3,359	5.7
Petrochemicals	4,412	6.0		3,726	6.3
Other	4,557	6.2		2,969	5.0
Total refinery production (5)	73,339	100.0		59,137	100.0
Refinery utilization (6)		101.9	%		92.4	%



THROUGHPUT AND PRODUCTION DATA: KROTZ SPRINGS REFINERY	For the Three Months Ended
THROUGHPUT AND PRODUCTION DATA: KROTZ SPRINGS REFINERY	March 31,
	2014			2013
	bpd	%		bpd	%
Refinery throughput:
WTI crude	24,040	38.7		25,083	43.0
Gulf Coast sweet crude	35,710	57.6		31,516	53.9
Blendstocks	2,317	3.7		1,840	3.1
Total refinery throughput (4)	62,067	100.0		58,439	100.0
Refinery production:
Gasoline	30,888	48.9		26,916	45.0
Diesel/jet	25,873	41.0		22,382	37.5
Heavy Oils	594	0.9		1,773	3.0
Other	5,819	9.2		8,687	14.5
Total refinery production (5)	63,174	100.0		59,758	100.0
Refinery utilization (6)		80.7	%		80.5	%

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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 months ended March 31, 2014 excludes $7,134 of negative inventory effects and losses on commodity swaps of $6,238.

The refinery operating margin for the three months ended March 31, 2013 excludes $2,965 of positive inventory effects.


(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
	March 31,
	2014			2013
	(dollars in thousands, except per ton data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	96,171		$	154,865
Operating costs and expenses:
Cost of sales (1)(2)	87,734			145,516
Direct operating expenses	9,880			10,553
Selling, general and administrative expenses	2,728			1,648
Depreciation and amortization	1,200			1,549
Total operating costs and expenses	101,542			159,266
Gain on disposition of assets (3)	2,166			—
Operating loss	$	(3,205	)	$	(4,401	)
KEY OPERATING STATISTICS:
Blended asphalt sales volume (tons in thousands) (4)	84			130
Non-blended asphalt sales volume (tons in thousands) (5)	22			22
Blended asphalt sales price per ton (4)	$	546.21		$	540.48
Non-blended asphalt sales price per ton (5)	389.14			391.77
Asphalt margin per ton (6)	79.59			61.51
Capital expenditures	$	1,718		$	1,792


(1)	Net sales and cost of sales for the three months ended March 31, 2014 and 2013 include approximately $42,000 and $76,000, respectively, of asphalt purchases sold as part of a supply and offtake arrangement. The volumes associated with these sales are excluded from the Key Operating Statistics.


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


(3)	Gain on disposition of assets for the three months ended March 31, 2014 is primarily the gain on the sale of our Willbridge, Oregon asphalt terminal.


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


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


(6)	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
	March 31,
	2014			2013
	(dollars in thousands, except per gallon data)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	221,248		$	224,105
Operating costs and expenses:
Cost of sales (2)	189,689			191,318
Selling, general and administrative expenses	25,952			25,997
Depreciation and amortization	2,714			2,268
Total operating costs and expenses	218,355			219,583
Gain on disposition of assets	40			18
Operating income	$	2,933		$	4,540
KEY OPERATING STATISTICS:
Number of stores (end of period) (3)	296			298
Retail fuel sales (thousands of gallons)	45,516			44,406
Retail fuel sales (thousands of gallons per site per month)(3)	53			52
Retail fuel margin (cents per gallon) (4)	18.3			20.3
Retail fuel sales price (dollars per gallon) (5)	$	3.25		$	3.39
Merchandise sales	$	73,335		$	73,333
Merchandise sales (per site per month) (3)	$	83		$	82
Merchandise margin (6)	31.5		%	32.3		%
Capital expenditures	$	3,381		$	640


(1)	Includes excise taxes on sales of $17,810 and $17,305 for the three months ended March 31, 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 March 31, 2014, we had 296 retail convenience stores of which 285 sold fuel. At March 31, 2013, we had 298 retail convenience stores of which 286 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 March 31, 2014 Compared to the Three Months Ended March 31, 2013

Net Sales

Consolidated. Net sales for the three months ended March 31, 2014 were $1,683.2 million, compared to $1,651.2 million for the three months ended March 31, 2013, an increase of $32.0 million. This increase was primarily due to higher refinery throughput volumes, partially offset by lower refined product prices.

Refining and Marketing Segment. Net sales for our refining and marketing segment were $1,504.9 million for the three months ended March 31, 2014, compared to $1,414.1 million for the three months ended March 31, 2013, an increase of $90.8 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 March 31, 2014 was 135,363 bpd, consisting of 73,296 bpd at the Big Spring refinery and 62,067 bpd at the Krotz Springs refinery, compared to a combined refinery average throughput of 117,915 bpd for the three months ended March 31, 2013, consisting of 59,476 bpd at the Big Spring refinery and 58,439 bpd at the Krotz Springs refinery. The higher refinery throughput rates during the three months ended March 31, 2014 reflect the impact of unplanned downtime at both refineries during the three months ended March 31, 2013. During the three months ended March 31, 2014, refinery throughput at the Krotz Springs refinery was impacted by scheduled downtime.

Refined product prices decreased for all of our products during the three months ended March 31, 2014, compared to the three months ended March 31, 2013. The average per gallon price of Gulf Coast gasoline for the three months ended March 31, 2014 decreased $0.18, or 6.3%, to $2.66, compared to $2.84 for the three months ended March 31, 2013. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the three months ended March 31, 2014 decreased $0.16, or 5.2%, to $2.93, compared to $3.09 for the three months ended March 31, 2013. The average per gallon price of Gulf Coast high sulfur diesel for the three months ended March 31, 2014, decreased $0.17, or 5.6%, to $2.84, compared to $3.01 for the three months ended March 31, 2013.

Asphalt Segment. Net sales for our asphalt segment were $96.2 million for the three months ended March 31, 2014, compared to $154.9 million for the three months ended March 31, 2013, a decrease of $58.7 million, or 37.9%. This decrease was primarily due to lower asphalt sales as part of a supply and offtake arrangement of approximately $34.0 million and decreased sales volumes, partially offset by higher blended asphalt sales prices. The asphalt sales volume decreased 30.3% to 106 thousand tons for the three months ended March 31, 2014 from 152 thousand tons for the three months ended March 31, 2013. The average blended asphalt sales price increased 1.1% to $546.21 per ton for the three months ended March 31, 2014 from $540.48 per ton for the three months ended March 31, 2013.

Retail Segment. Net sales for our retail segment were $221.2 million for the three months ended March 31, 2014, compared to $224.1 million for the three months ended March 31, 2013, a decrease of $2.9 million, or 1.3%. This decrease was primarily due to lower retail fuel sales prices, partially offset by a 2.5% increase in retail fuel sales volume.

Cost of Sales

Consolidated. Cost of sales for the three months ended March 31, 2014 were $1,506.5 million, compared to $1,378.3 million for the three months ended March 31, 2013, an increase of $128.2 million, or 9.3%. This increase was primarily due to higher refinery throughput as well as higher crude oil prices.

Refining and Marketing Segment. Cost of sales for our refining and marketing segment were $1,368.2 million for the three months ended March 31, 2014, compared to $1,183.3 million for the three months ended March 31, 2013, an increase of $184.9 million, or 15.6%. This increase was primarily due to higher refinery throughput, higher crude oil prices and narrowing of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread. Cost of sales for the three months ended March 31, 2014 was also impacted by $8.0 million of costs to purchase RINs needed to satisfy our obligation to blend biofuels into the products we produce.

The average price of WTI Cushing increased 4.6% to $98.65 per barrel for the three months ended March 31, 2014 from $94.27 per barrel for the three months ended March 31, 2013. The WTI Cushing to WTS spread narrowed 67.8% to $3.67 per barrel for the three months ended March 31, 2014, compared to $11.41 per barrel for the three months ended March 31, 2013. The WTI Cushing to WTI Midland spread narrowed 54.1% to $3.54 per barrel for the three months ended March 31, 2014, compared to $7.72 per barrel for the three months ended March 31, 2013.

Asphalt Segment. Cost of sales for our asphalt segment were $87.7 million for the three months ended March 31, 2014, compared to $145.5 million for the three months ended March 31, 2013, a decrease of $57.8 million, or 39.7%. This decrease was primarily due to lower asphalt purchases as part of a supply and offtake arrangement as well as decreased sales volumes during the three months ended March 31, 2014, compared to the three months ended March 31, 2013.

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Retail Segment. Cost of sales for our retail segment were $189.7 million for the three months ended March 31, 2014, compared to $191.3 million for the three months ended March 31, 2013, a decrease of $1.6 million, or 0.8%. This decrease was primarily due to lower retail fuel prices, partially offset by increases in retail fuel sales volumes.

Direct Operating Expenses

Consolidated. Direct operating expenses were $70.7 million for the three months ended March 31, 2014, compared to $74.2 million for the three months ended March 31, 2013, a decrease of $3.5 million, or 4.7%.

Refining and Marketing Segment. Direct operating expenses for our refining and marketing segment for the three months ended March 31, 2014 were $60.8 million, compared to $63.7 million for the three months ended March 31, 2013, a decrease of $2.9 million, or 4.6%. This decrease was primarily due to higher costs associated with the operational maintenance and reformer catalyst regeneration work performed at both refineries during the three months ended March 31, 2013.

Asphalt Segment. Direct operating expenses for our asphalt segment for the three months ended March 31, 2014 were $9.9 million, compared to $10.6 million for the three months ended March 31, 2013, a decrease of $0.7 million, or 6.6%. This decrease was primarily due to reduced facilities maintenance costs and reduced insurance costs, partially offset by higher natural gas costs during the three months ended March 31, 2014.

Selling, General and Administrative Expenses

Consolidated. SG&A expenses for the three months ended March 31, 2014 were $39.4 million, compared to $41.7 million for the three months ended March 31, 2013, a decrease of $2.3 million, or 5.5%. This decrease was primarily due to lower employee incentive compensation costs.

Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the three months ended March 31, 2014 were $10.5 million, compared to $13.9 million for the three months ended March 31, 2013, a decrease of $3.4 million, or 24.5%. This decrease was primarily due to lower employee incentive compensation costs and marketing expenses for the three months ended March 31, 2014.

Asphalt Segment. SG&A expenses for our asphalt segment for the three months ended March 31, 2014 were $2.7 million, compared to $1.6 million for the three months ended March 31, 2013, an increase of $1.1 million, or 68.8%. This increase was primarily due to higher corporate expense allocated to the asphalt segment.

Depreciation and Amortization

Depreciation and amortization for the three months ended March 31, 2014 was $29.9 million, compared to $31.2 million for the three months ended March 31, 2013, a decrease of $1.3 million, or 4.2%.

Operating Income

Consolidated. Operating income for the three months ended March 31, 2014 was $39.0 million, compared to $125.8 million for the three months ended March 31, 2013, a decrease of $86.8 million. This decrease was primarily due to reduced refinery margins, partially offset by higher refinery throughput.

Refining and Marketing Segment. Operating income for our refining and marketing segment was $40.0 million for the three months ended March 31, 2014, compared to $126.7 million for the three months ended March 31, 2013, a decrease of $86.7 million. This decrease was primarily due to reduced refinery margins, partially offset by higher refinery throughput.

Refinery operating margin at the Big Spring refinery was $14.77 per barrel for the three months ended March 31, 2014, compared to $28.76 per barrel for the three months ended March 31, 2013. This decrease was primarily due to lower Gulf Coast 3/2/1 crack spreads, narrowing of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread as well as the impact of RINs costs. The average Gulf Coast 3/2/1 crack spread decreased 40.8% to $16.81 per barrel for the three months ended March 31, 2014, compared to $28.40 per barrel for the three months ended March 31, 2013, which was primarily influenced by a reduction in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for the three months ended March 31, 2014 was $10.46 per barrel compared to $19.25 per barrel for the three months ended March 31, 2013. For the three months ended March 31, 2014, the Big Spring refinery was impacted by $2.9 million of costs to purchase RINs needed to satisfy our obligation to blend biofuels into the products we produce. For the first quarter of 2013, we utilized carryover RINs from 2012 to completely offset our RINs deficit at the Big Spring refinery.

Refinery operating margin at the Krotz Springs refinery was $7.39 per barrel for the three months ended March 31, 2014, compared to $13.14 per barrel for the three months ended March 31, 2013. This decrease was primarily due to narrowing of both the LLS to WTI Cushing spread and the WTI Cushing to WTI Midland spread as well as the impact of RINs costs, partially offset by higher Gulf Coast 2/1/1 high sulfur diesel crack spreads during the three months ended March 31, 2014. The

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LLS to WTI Cushing spread narrowed $14.22 per barrel to $6.00 per barrel for the three months ended March 31, 2014, compared to $20.22 per barrel for the three months ended March 31, 2013. For the three months ended March 31, 2014, the Krotz Springs refinery was impacted by $5.1 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 RFS2 requirements for 2013 and as a result did not record costs associated with RINs. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the three months ended March 31, 2014 was $10.75 per barrel, compared to $8.20 per barrel for the three months ended March 31, 2013.

Asphalt Segment. Operating loss for our asphalt segment was $3.2 million for the three months ended March 31, 2014, compared to $4.4 million for the three months ended March 31, 2013, a decrease of $1.2 million. This decrease was primarily due to the gain on the sale of our Willbridge, Oregon asphalt terminal for $2.2 million and higher asphalt margins, partially offset by lower sales volumes. Asphalt margins for the three months ended March 31, 2014 were $79.59 per ton compared to $61.51 per ton for the three months ended March 31, 2013.

Retail Segment. Operating income for our retail segment was $2.9 million for the three months ended March 31, 2014, compared to $4.5 million for the three months ended March 31, 2013, a decrease of $1.6 million. This decrease was primarily due to lower retail fuel margins and lower merchandise margins.

Interest Expense

Interest expense was $28.0 million for the three months ended March 31, 2014, compared to $21.3 million for the three months ended March 31, 2013, an increase of $6.7 million, or 31.5%. 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 lower third party interest for the three months ended March 31, 2014 compared to the three months ended March 31, 2013.

Income Tax Expense

Income tax expense was $2.1 million for the three months ended March 31, 2014, compared to $30.6 million for the three months ended March 31, 2013. The decrease resulted from our lower pre-tax income for the three months ended March 31, 2014 compared to the three months ended March 31, 2013, and a decrease in the effective tax rate. Our effective tax rate was 20.0% for the three months ended March 31, 2014, compared to an effective tax rate of 29.3% for the three months ended March 31, 2013. This lower 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 represents the proportional share of net income related to non-voting common stock owned by non-controlling interest shareholders in our subsidiary, Alon Assets, Inc. Net income attributable to non-controlling interest was $7.6 million for the three months ended March 31, 2014, compared to $19.5 million for the three months ended March 31, 2013, a decrease of $11.9 million.

Net Income Available to Stockholders

Net income available to stockholders was $0.8 million for the three months ended March 31, 2014, compared to $54.2 million for the three months ended March 31, 2013, a decrease of $53.4 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.

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Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or equity securities, or other possible capital markets transactions, the proceeds of which could be used to refinance current indebtedness, extend or replace existing revolving credit facilities or for other corporate purposes.

Cash Flows

The following table sets forth our consolidated cash flows for the three months ended March 31, 2014, and 2013:



	For the Three Months Ended
	March 31,
	2014		2013
	(dollars in thousands)
Cash provided by (used in):
Operating activities	$	62,714	$	160,770
Investing activities	6,396		(13,573		)
Financing activities	61,683		(10,627		)
Net increase in cash and cash equivalents	$	130,793	$	136,570

Cash Flows Provided by Operating Activities

Net cash provided by operating activities was $62.7 million during the three months ended March 31, 2014, compared to $160.8 million during the three months ended March 31, 2013. The reduction in net cash provided by operating activities of $98.1 million was primarily attributable to a decrease in net income after adjusting for non-cash items of $69.7 million, decreased cash provided by accounts payable and accrued liabilities of $7.6 million, decrease in cash provided by other non-current liabilities of $10.9 million, reduced cash collected on accounts receivable of $3.0 million and increased cash used for prepaid expenses and other current assets of $11.3 million. These changes were partially offset by reduced cash used for inventories of $6.7 million.

Cash Flows Provided by (Used In) Investing Activities

Net cash provided by investing activities was $6.4 million during the three months ended March 31, 2014, compared to net cash used in investing activities of $13.6 million during the three months ended March 31, 2013. The change in cash flows from investing activities of $20.0 million was primarily attributable to cash proceeds from the sale of the Willbridge, Oregon asphalt terminal of $40.0 million, partially offset by increased cash used for capital expenditures and capital expenditures for turnarounds and catalysts of $19.4 million during the three months ended March 31, 2014, compared to the three months ended March 31, 2013. The increase in capital expenditures and capital expenditures for turnarounds and catalysts is related to the planned major turnaround at our Big Spring refinery scheduled to be completed during the second quarter of 2014.

Cash Flows Provided by (Used In) Financing Activities

Net cash provided by financing activities was $61.7 million during the three months ended March 31, 2014, compared to net cash used in financing activities of $10.6 million during the three months ended March 31, 2013. The change in cash flows from financing activities of $72.3 million was primarily attributable to increased cash provided by net additions to long-term debt of $71.2 million for the three months ended March 31, 2014, compared to the three months ended March 31, 2013.

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 accrue interest at an annual rate equal to LIBOR plus a margin of 3.75%. We are required to pledge 2,200,000 of the Partnership’s common units as collateral for the Alon Energy Term Loan. Additionally, Alon Assets, Inc. was named as a guarantor, guaranteeing 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 will be used to purchase equipment for a capital project at our Big Spring refinery.

At March 31, 2014, the Alon Energy Term Loan had an outstanding balance of $25.0 million.

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Retail Credit Facilities. Southwest Convenience Stores, LLC and Skinny’s LLC, (“Alon Retail”) were party 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.

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. At March 31, 2014, the Alon Retail Credit Agreement had an outstanding balance of $118.2 million.

Proceeds from the Alon Retail Credit Agreement were used to fully repay its obligations under the Credit Agreement of $72.7 million, pay a dividend distribution of $40.0 million to Alon Brands, Inc., our wholly-owned subsidiary, with the remainder used for general corporate purposes.

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 March 31, 2014 and December 31, 2013, we had letters of credit outstanding under this facility of $56.8 million and $56.8 million, respectively.

Alon USA, LP 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 $100.0 million and $100.0 million and letters of credit of $103.4 million and $109.8 million were outstanding under this facility at March 31, 2014 and December 31, 2013, respectively.

Senior Secured Notes. In May 2014, we redeemed $40.0 million of the principal balance on the 13.50% senior secured notes due October 2014, reducing the principal balance to approximately $35.6 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 budget, including expenditures for catalysts and turnarounds, for 2014 is $149.1 million. Approximately $33.0 million has been spent during the three months ended March 31, 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.

Off-Balance Sheet Arrangements

We have no material off-balance sheet arrangements.

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Critical Accounting Policies

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

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

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 March 31, 2014, we held 1.4 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 $68.2 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 $1.4 million.

All commodity contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section or accumulated other comprehensive income of our consolidated financial statements. “Forwards” represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period. “Futures” represent trades which have been executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period. A “long” represents an obligation to purchase product and a “short” represents an obligation to sell product.

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The following table provides information about our commodity contracts as of March 31, 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)	523,233		$	93.69	$	—	$	49,023		$	49,035		$	12
Forwards-short (Crude)	(106,115	)	—		112.51		(11,939		)	(12,062		)	(123		)
Forwards-long (Gasoline)	363,959		121.63		—		44,270			43,958			(312		)
Forwards-short (Gasoline)	(67,091	)	—		118.08		(7,922		)	(7,865		)	57
Forwards-long (Distillate)	202,304		120.89		—		24,457			24,434			(23		)
Forwards-short (Distillate)	(6,051	)	—		124.63		(754		)	(752		)	2
Forwards-long (Jet)	86,155		121.79		—		10,493			10,408			(85		)
Forwards-short (Jet)	(52,083	)	—		120.81		(6,292		)	(6,283		)	9
Forwards-long (Slurry)	33,340		83.31		—		2,778			2,760			(18		)
Forwards-short (Slurry)	(700	)	—		88.26		(62		)	(61		)	1
Forwards-long (Catfeed)	21,727		117.94		—		2,563			2,547			(16		)
Forwards-short (Catfeed)	(127,695	)	—		117.94		(15,061		)	(14,969		)	92
Forwards-long (Slop)	4,592		90.51		—		416			421			5
Forwards-short (Slop)	(23,444	)	—		93.61		(2,195		)	(2,220		)	(25		)
Forwards-short (Propane)	(2,527	)	—		54.44		(138		)	(139		)	(1		)
Forwards-short (Asphalt)	(465,306	)	—		94.05		(43,764		)	(45,021		)	(1,257		)
Futures-long (Crude)	139,000		98.19		—		13,649			13,986			337
Futures-short (Crude)	(610,000	)	—		99.85		(60,909		)	(61,961		)	(1,052		)
Futures-short (Gasoline)	(384,000	)	—		122.72		(47,125		)	(47,060		)	65
Futures-long (Distillate)	26,000		123.42		—		3,209			3,199			(10		)
Futures-short (Distillate)	(272,000	)	—		123.23		(33,517		)	(33,470		)	47

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)	5,220,000		$	21.60	$	21.76	$	(112,741	)	$	(113,595	)	$	(854	)
Futures-swaps (long products, short crude)	(1,350,000	)	19.06		18.48		25,731			24,941			(790		)

Interest Rate Risk

As of March 31, 2014, $490.0 million, excluding discounts, of our outstanding debt was at floating interest rates out of which $100.0 million was at the Eurodollar rate plus 3.50%, subject to a minimum interest rate of 4.00%, and $246.9 million was at the Eurodollar rate (with a floor of 1.25%) plus a margin of 8.00%. An increase of 1% in the Eurodollar rate on indebtedness, net of the instruments subject to minimum interest rates, would result in an increase in our interest expense of approximately $2.1 million per year.

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ITEM 4. CONTROLS AND PROCEDURES


(1)	Evaluation of disclosure controls and procedures.

Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosures.


(2)	Changes in internal control over financial reporting.

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

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PART II. OTHER INFORMATION

ITEM 6. EXHIBITS



Exhibit
Number		Description of Exhibit
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 March 31, 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:	May 2, 2014	By:	/s/ David Wiessman
			David Wiessman
			Executive Chairman of the Board


Date:	May 2, 2014	By:	/s/ Paul Eisman
			Paul Eisman
			President and Chief Executive Officer


Date:	May 2, 2014	By:	/s/ Shai Even
			Shai Even
			Senior Vice President and Chief Financial Officer
			(Principal Accounting Officer)

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Legalese
Litigous
Readability	8th grade Good

Alon USA Energy (ALJ) Inactive 10-Q2014 Q1 Quarterly report

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