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

Commission file number: 001-32567
ALON USA ENERGY, INC.
(Exact name of Registrant as specified in its charter)
___________________________________________________

Delaware
 
74-2966572
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
12700 Park Central Dr., Suite 1600, Dallas, Texas 75251
(Address of principal executive offices) (Zip Code)

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes  þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:
Large accelerated filer o
Accelerated filer þ
Non-accelerated filer o
Smaller reporting company o
 
(Do not check if a smaller reporting company)
Indicate by check whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The number of shares of the Registrant’s common stock, par value $0.01 per share, outstanding as of 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.
1

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands except per share data)

 
For the Three Months Ended
 
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.
2

Table of Contents

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.
3

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.
4

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.

5

Table of Contents
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


9

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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


10

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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
 
 
 
Financial Instruments
 
Cash Collateral Pledged
 
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


14

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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.
(c) Revolving Facility and Letters of Credit
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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Table of Contents
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

17

Table of Contents
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.

18

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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
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.


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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


28

Table of Contents

THROUGHPUT AND PRODUCTION DATA:
BIG SPRING REFINERY
For the Three Months Ended
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
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
%

29

Table of Contents

(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.

30

Table of Contents

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