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, 2015
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, 2015, was 70,334,361.

 
 



TABLE OF CONTENTS

 
Page


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,
2015
 
December 31,
2014
 
(unaudited)
 
 
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
190,465

 
$
214,961

Accounts and other receivables, net
193,688

 
153,859

Income tax receivable

 
9,196

Inventories
102,047

 
122,803

Deferred income tax asset
14,774

 
11,228

Prepaid expenses and other current assets
25,339

 
26,315

Total current assets
526,313

 
538,362

Equity method investments
24,822

 
25,376

Property, plant and equipment, net
1,358,336

 
1,372,344

Goodwill
101,913

 
101,913

Other assets, net
163,039

 
162,879

Total assets
$
2,174,423

 
$
2,200,874

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
266,154

 
$
292,217

Accrued liabilities
100,570

 
104,391

Current portion of long-term debt
15,089

 
15,089

Total current liabilities
381,813

 
411,697

Other non-current liabilities
188,139

 
182,659

Long-term debt
536,330

 
548,598

Deferred income tax liability
378,484

 
384,142

Total liabilities
1,484,766

 
1,527,096

Commitments and contingencies (Note 15)

 

Stockholders’ equity:
 
 
 
Preferred stock, par value $0.01, 15,000,000 shares authorized; 0 and 68,180 shares issued and outstanding at March 31, 2015 and December 31, 2014, respectively

 
682

Common stock, par value $0.01, 150,000,000 shares authorized; 70,174,290 and 69,606,944 shares issued and outstanding at March 31, 2015 and December 31, 2014, respectively
702

 
696

Additional paid-in capital
516,877

 
517,127

Accumulated other comprehensive loss, net of tax
(10,138
)
 
(8,458
)
Retained earnings
146,861

 
126,851

Total stockholders’ equity
654,302

 
636,898

Non-controlling interest in subsidiaries
35,355

 
36,880

Total equity
689,657

 
673,778

Total liabilities and equity
$
2,174,423

 
$
2,200,874


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,
 
2015
 
2014
Net sales (1)
$
1,103,240

 
$
1,683,245

Operating costs and expenses:
 
 
 
Cost of sales
894,488

 
1,506,545

Direct operating expenses
64,205

 
70,678

Selling, general and administrative expenses
45,596

 
39,389

Depreciation and amortization
31,962

 
29,878

Total operating costs and expenses
1,036,251

 
1,646,490

Gain on disposition of assets
572

 
2,205

Operating income
67,561

 
38,960

Interest expense
(21,037
)
 
(28,015
)
Equity losses of investees
(554
)
 
(459
)
Other income (loss), net
46

 
(17
)
Income before income tax expense
46,016

 
10,469

Income tax expense
11,961

 
2,094

Net income
34,055

 
8,375

Net income attributable to non-controlling interest
7,116

 
7,590

Net income available to stockholders
$
26,939

 
$
785

Earnings per share, basic
$
0.39

 
$
0.01

Weighted average shares outstanding, basic (in thousands)
69,485

 
68,617

Earnings per share, diluted
$
0.38

 
$
0.01

Weighted average shares outstanding, diluted (in thousands)
71,142

 
69,067

Cash dividends per share
$
0.10

 
$
0.06

___________
(1)
Includes excise taxes on sales by the retail segment of $18,056 and $17,810 for the three months ended March 31, 2015 and 2014, respectively.

The accompanying notes are an integral part of these consolidated financial statements.
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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,
 
2015
 
2014
Net income
$
34,055

 
$
8,375

Other comprehensive income (loss):
 
 
 
Interest rate derivatives designated as cash flow hedges:
 
 
 
Unrealized holding loss arising during period
(930
)
 

Loss reclassified to earnings - interest expense
15

 

Net loss, before tax
(915
)
 

Income tax benefit
(339
)
 

Net loss, net of tax
(576
)
 

Commodity contracts designated as cash flow hedges:
 
 
 
Unrealized holding gain arising during period
6,070

 
23,582

Amortization of unrealized (gain) loss on de-designated cash flow hedges - cost of sales
(7,982
)
 
8,275

Net gain (loss), before tax
(1,912
)
 
31,857

Income tax expense (benefit)
(708
)
 
11,787

Net gain (loss), net of tax
(1,204
)
 
20,070

Total other comprehensive income (loss), net of tax
(1,780
)
 
20,070

Comprehensive income
32,275

 
28,445

Comprehensive income attributable to non-controlling interest
7,016

 
8,277

Comprehensive income attributable to stockholders
$
25,259

 
$
20,168



The accompanying notes are an integral part of these consolidated financial statements.
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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,
 
2015
 
2014
Cash flows from operating activities:
 
 
 
Net income
$
34,055

 
$
8,375

Adjustments to reconcile net income to cash provided by (used in) operating activities:
 
 
 
Depreciation and amortization
31,962

 
29,878

Stock compensation
1,539

 
1,566

Deferred income taxes
(8,159
)
 
(1,006
)
Equity losses of investees
554

 
459

Amortization of debt issuance costs
808

 
1,175

Amortization of original issuance discount
1,503

 
1,663

Gain on disposition of assets
(572
)
 
(2,205
)
Unrealized (gain) loss on commodity swaps
(18,403
)
 
6,606

Changes in operating assets and liabilities:
 
 
 
Accounts and other receivables, net
(23,434
)
 
6,320

Income tax receivable
9,196

 
10,184

Inventories
20,756

 
(20,561
)
Prepaid expenses and other current assets
976

 
(4,206
)
Other assets, net
(5,979
)
 
(345
)
Accounts payable
(61,223
)
 
30,380

Accrued liabilities
(7,365
)
 
(8,124
)
Other non-current liabilities
4,565

 
2,555

Net cash provided by (used in) operating activities
(19,221
)
 
62,714

Cash flows from investing activities:
 
 
 
Capital expenditures
(10,749
)
 
(18,160
)
Capital expenditures for turnarounds and catalysts
(2,333
)
 
(14,847
)
Contribution to equity method investment

 
(597
)
Proceeds from disposition of assets
1,469

 
40,000

Net cash provided by (used in) investing activities
(11,613
)
 
6,396

Cash flows from financing activities:
 
 
 
Dividends paid to stockholders
(6,914
)
 
(4,102
)
Dividends paid to non-controlling interest
(82
)
 
(135
)
Distributions paid to non-controlling interest in the Partnership
(8,055
)
 
(2,070
)
Inventory agreement transactions
35,160

 

Deferred debt issuance costs

 
(1,844
)
Revolving credit facilities, net
(10,000
)
 

Additions to long-term debt

 
145,000

Payments on long-term debt
(3,771
)
 
(75,166
)
Net cash provided by financing activities
6,338

 
61,683

Net increase (decrease) in cash and cash equivalents
(24,496
)
 
130,793

Cash and cash equivalents, beginning of period
214,961

 
224,499

Cash and cash equivalents, end of period
$
190,465

 
$
355,292

Supplemental cash flow information:
 
 
 
Cash paid for interest, net of capitalized interest
$
19,519

 
$
28,832

Refunds received for income tax
$
(29
)
 
$
(10,184
)
Supplemental disclosure of non-cash activity:
 
 
 
Capital expenditures included in accounts payable and accrued liabilities
$
661

 
$


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 consolidated subsidiaries.
These consolidated financial statements and notes are unaudited and have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements.
In the opinion of our management, the information included in these consolidated financial statements reflects all adjustments, consisting of normal and recurring adjustments, which are necessary for a fair presentation of our consolidated financial position and results of operations for the interim periods presented. All significant intercompany balances and transactions have been eliminated in consolidation. Certain prior year balances may have been aggregated or disaggregated in order to conform to the current year presentation. Our results of operations for the three months ended March 31, 2015 are not necessarily indicative of the operating results that may be realized for the year ending December 31, 2015.
Our consolidated balance sheet as of December 31, 2014 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, 2014.
New Accounting Standards
In May 2014, the Financial Accounting Standards Board (“FASB”) and the International Accounting Standards Board jointly issued a comprehensive new revenue recognition standard that provides accounting guidance for all revenue arising from contracts to provide goods or services to customers. This standard is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets. The requirements of the new standard (unless amended) are effective for interim and annual periods beginning after December 15, 2016, and early adoption is not permitted. The standard allows for either full retrospective adoption or modified retrospective adoption. We are evaluating the guidance to determine the method of adoption and the impact of this standard on our consolidated financial statements.
In February 2015, the FASB issued an accounting standards update making targeted changes to the current consolidation guidance. The new standard changes the way certain decisions are made related to substantive rights, related parties, and decision making fees when applying the variable interest entity consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The requirements from the updated standard are effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. We are evaluating the effect that adopting the updated guidance will have on our consolidated financial statements and related disclosures.
In April 2015, the FASB issued an accounting standards update simplifying the presentation of debt issuance costs. The new standard requires that all cost incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. The requirements from the updated standard are effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. We are evaluating the effect that adopting the updated guidance will have on our consolidated financial statements and related disclosures.
(2)
Alon USA Partners, LP
The Partnership (NYSE: ALDW) is a publicly-traded limited partnership that owns the assets and conducts the operations of the Big Spring refinery and the associated wholesale marketing operations. As of March 31, 2015, the 11,506,550 common units held by the public represent 18.4% of the Partnership’s common units outstanding. We own the remaining 81.6% of the Partnership’s common units and Alon USA Partners GP, LLC (the “General Partner”), our wholly-owned subsidiary, owns 100% of the non-economic general partner interest in the Partnership.
The limited partner interests in the Partnership not owned by us are reflected in the consolidated statements of operations in net income attributable to non-controlling interest and in our consolidated balance sheets 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.

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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)


Partnership Distributions
The Partnership has adopted a policy pursuant to which it will distribute all of the available cash generated each quarter, as defined in the partnership agreement, subject to the approval of the board of directors of the General Partner. 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 2, 2015, the Partnership paid a cash distribution of $43,755, or $0.70 per unit. The total cash distribution paid to non-affiliated common unitholders was $8,055.
(3)
Segment Data
Our revenues are derived from three operating segments: (i) refining and marketing, (ii) asphalt and (iii) retail. The reportable operating segments are strategic business units that offer different products and services. The segments are managed separately as each segment requires unique technology, marketing strategies and distinct operational emphasis. Each operating segment’s performance is evaluated primarily based on operating income.
(a)Refining and Marketing Segment
Our refining and marketing segment includes a sour crude oil refinery located in Big Spring, Texas, a light sweet crude oil refinery located in Krotz Springs, Louisiana and heavy crude oil refineries located in Paramount, Bakersfield and Long Beach, California (the “California refineries”). Our refineries have a combined crude oil throughput capacity of approximately 217,000 barrels per day (“bpd”). We refine crude oil into petroleum products including various grades of gasoline, diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum-based products, which are marketed primarily in the South Central, Southwestern and Western United States. Our California refineries did not process crude oil during the three months ended March 31, 2015 and 2014 due to the high cost of crude oil relative to product yield and low asphalt demand.
We supply gasoline and diesel to 642 Alon branded retail sites, including our retail segment convenience stores. During 2015, approximately 53% of the gasoline and 24% 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 67 licensed locations that are not under fuel supply agreements.
(b)Asphalt Segment
We own or operate 10 asphalt terminals located in Texas (Big Spring), Washington (Richmond Beach), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Arizona (Phoenix and Flagstaff), and Nevada (Fernley) (50% interest) as well as through a 50% interest in Wright Asphalt Products Company, LLC, which specializes in patented ground tire rubber modified asphalt products. 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 293 convenience stores located in Central and West Texas and New Mexico. These convenience stores typically offer various grades of gasoline, diesel fuel, food products, food service, tobacco products, non-alcoholic and alcoholic beverages, general merchandise as well as money orders to the public, primarily under the 7-Eleven and Alon brand names. Substantially all of the motor fuel sold through our retail segment is supplied by our Big Spring refinery.
(d)Corporate
Operations that are not included in any of the three segments are included in the corporate category. These operations consist primarily of corporate headquarters operating and depreciation expenses.

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Table of Contents
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


Segment data as of and for the three month periods ended March 31, 2015 and 2014 are presented below:
 
Refining and
Marketing
 
Asphalt
 
Retail
 
Corporate
 
Consolidated
Total
Three Months Ended March 31, 2015
 
 
 
 
 
 
 
 
 
Net sales to external customers
$
876,603

 
$
50,652

 
$
175,985

 
$

 
$
1,103,240

Intersegment sales (purchases)
82,889

 
(10,931
)
 
(71,958
)
 

 

Depreciation and amortization
27,311

 
1,145

 
3,037

 
469

 
31,962

Operating income (loss)
75,647

 
(14,431
)
 
6,990

 
(645
)
 
67,561

Total assets
1,836,655

 
113,785

 
203,056

 
20,927

 
2,174,423

Turnarounds, catalysts and capital expenditures
6,739

 
1,406

 
3,316

 
1,621

 
13,082

 
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
1,997,998

 
120,691

 
204,088

 
22,947

 
2,345,724

Turnarounds, catalysts and capital expenditures
27,043

 
1,718

 
3,381

 
865

 
33,007

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 are our only assets and liabilities measured at fair value on a recurring basis.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


The following table 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, 2015 and December 31, 2014:
 
Level 1
 
Level 2
 
Level 3
 
Total
As of March 31, 2015
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts (swaps)
$

 
$
59,231

 
$

 
$
59,231

Fair value hedges

 
30,691

 

 
30,691

Liabilities:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
882

 

 

 
882

Interest rate swaps

 
2,153

 

 
2,153

 
 
 
 
 
 
 
 
As of December 31, 2014
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts (swaps)
$

 
$
42,740

 
$

 
$
42,740

Fair value hedges

 
24,903

 

 
24,903

Liabilities:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
333

 

 

 
333

Interest rate swaps

 
1,238

 

 
1,238

(5)
Derivative Financial Instruments
We selectively utilize crude oil and refined product commodity derivative contracts to reduce the risk associated with potential price changes on committed obligations as well as to reduce earnings volatility. We also utilize interest rate swaps to manage our exposure to interest rate risk. We do not speculate using derivative instruments. Credit risk on our derivative instruments is mitigated by transacting with counterparties meeting established collateral and credit criteria.
Mark to Market
We have certain contracts that serve as economic hedges, which are derivatives used for risk management but not designated as hedges for financial accounting purposes. All economic hedge transactions are recorded at fair value and any changes in fair value between periods are recognized in earnings.
We have contracts that are used to fix prices on forecasted purchases of inventory. Forwards represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period. Futures represent trades executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period.
We also have economic hedges in the form of swap contracts that fix price differentials between different types of crude oil and the crack spreads between certain refined products and the crude oil that we use at our refineries. At March 31, 2015, these swap contracts had aggregate purchase volumes of 7,830 thousand barrels of crude oil and refined products with contract terms through December 2016.
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.
We have certain commodity contracts associated with the Supply and Offtake Agreements discussed in Note 7 that have been accounted for as fair value hedges, which had purchase volumes of 802 thousand barrels of crude oil as of March 31, 2015.
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 hedged item. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the hedged item. If, during the term of the derivative, the hedge is determined to be no longer highly effective, hedge accounting is

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


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, 2015, we did not have any commodity swap contracts accounted for as cash flow hedges. In January 2015, we elected to de-designate the commodity swap contracts that were previously designated as cash flow hedges. As of March 31, 2015, these contracts were accounted for as economic hedges, as mentioned above. As of March 31, 2015, unrealized gains of $33,966 were classified in OCI that related to the application of hedge accounting prior to de-designation, which will be reclassified into earnings as the underlying transactions occur through the remainder of 2015. During the three months ended March 31, 2015, we reclassified $7,982 of gains from OCI into cost of sales related to these de-designated cash flow hedges. During the three months ended March 31, 2014, we reclassified $8,275 of losses from OCI into cost of sales related to previously de-designated cash flow hedges that settled in 2014.
Related to commodity swap cash flow hedges in other comprehensive income (“OCI”), we recognized unrealized gains (losses) of $(1,912) and $31,857 for the three months ended March 31, 2015 and 2014, respectively.
Interest Rate Derivatives. In April 2014, we entered into three interest rate swap agreements, maturing March 2019, that effectively fix the variable LIBOR interest component of the term loan feature within the retail credit agreement. The interest rate swaps have been accounted for as cash flow hedges. The aggregate notional amount under these agreements covers approximately 75% of the outstanding principal of the term loan throughout the duration of the interest rate swaps. As of March 31, 2015, the outstanding principal of the term loan was $100,833. The interest rate swaps lock in an average fixed interest rate of 0.60% in 2015; 1.47% in 2016; 2.35% in 2017; 3.09% in 2018 and 3.28% in 2019. Related to these transactions in OCI, we recognized unrealized losses of $915 for the three months ended March 31, 2015.
For the three months ended March 31, 2015 and 2014, there was no cash flow hedge ineffectiveness recognized in income. No component of our cash flow hedges’ gains or losses was excluded from the assessment of hedge effectiveness.
As of March 31, 2015, we have net unrealized gains of $31,813 classified in OCI related to cash flow hedges, including amounts related to the de-designated cash flow hedges. Assuming interest rates remain unchanged, unrealized gains of $33,693 will be reclassified from OCI into earnings over the next twelve-month period as the underlying transactions occur.
The following tables present the effect of derivative instruments on the consolidated balance sheets:
 
As of March 31, 2015
 
Asset Derivatives
 
Liability Derivatives
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
Accounts receivable
 
$
1,050

 
Accrued liabilities
 
$
1,932

Commodity contracts (swaps)
Accounts receivable
 
47,513

 
 
 

Commodity contracts (swaps)
Other assets
 
11,718

 
 
 

Total derivatives not designated as hedging instruments
 
 
60,281

 
 
 
1,932

 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Interest rate swaps
 
 
$

 
Other non-current liabilities
 
$
2,153

Fair value hedges
Other assets
 
30,691

 
 
 

Total derivatives designated as hedging instruments
 
 
30,691

 
 
 
2,153

Total derivatives
 
 
$
90,972

 
 
 
$
4,085


9

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


 
As of December 31, 2014
 
Asset Derivatives
 
Liability Derivatives
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
Accounts receivable
 
$
7,168

 
Accrued liabilities
 
$
7,501

Commodity contracts (swaps)
Accounts receivable
 
6,809

 
 
 

Commodity contracts (swaps)
Other assets
 
11,622

 
 
 

Total derivatives not designated as hedging instruments
 
 
25,599

 
 
 
7,501

 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (swaps)
Accounts receivable
 
$
24,309

 
 
 
$

Interest rate swaps
 
 

 
Other non-current liabilities
 
1,238

Fair value hedges
Other assets
 
24,903

 
 
 

Total derivatives designated as hedging instruments
 
 
49,212

 
 
 
1,238

Total derivatives
 
 
$
74,811

 
 
 
$
8,739

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, 2015
 
 
 
 
 
 
 
 
Commodity contracts (swaps)
 
$
(1,912
)
 
Cost of sales
 
$
7,982

 
 
 
$

Interest rate swaps
 
(915
)
 
Interest expense
 
(15
)
 
 
 

Total derivatives
 
$
(2,827
)
 
 
 
$
7,967

 
 
 
$

 
 
 
 
 
 
 
 
 
 
 
For the Three Months Ended March 31, 2014
 
 
 
 
 
 
 
 
Commodity contracts (swaps)
 
$
31,857

 
Cost of sales
 
$
(8,275
)
 
 
 
$

Total derivatives
 
$
31,857

 
 
 
$
(8,275
)
 
 
 
$

Derivatives in fair value hedging relationships:
 
 
 
Gain (Loss) Recognized in Income
 
 
 
For the Three Months Ended
 
 
 
March 31,
 
Location
 
2015
 
2014
Fair value hedges (1)
Interest expense
 
$
5,788

 
$
(2,607
)
Total derivatives
 
 
$
5,788

 
$
(2,607
)
___________
(1)
Changes in the fair value hedges are substantially offset by changes in the hedged items.

10

Table of Contents
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


Derivatives not designated as hedging instruments:
 
 
 
Gain (Loss) Recognized in Income
 
 
 
For the Three Months Ended
 
 
 
March 31,
 
Location
 
2015
 
2014
Commodity contracts (futures and forwards)
Cost of sales
 
$
(5,358
)
 
$
(985
)
Commodity contracts (swaps)
Cost of sales
 
21,861

 
2,037

Total derivatives
 
 
$
16,503

 
$
1,052

Offsetting Assets and Liabilities
Our derivative 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, 2015 and December 31, 2014:
 
Gross Amounts of Recognized Assets/Liabilities
 
Gross Amounts offset in the Statement of Financial Position
 
Net Amounts Presented in the Statement of Financial Position
 
Gross Amounts Not offset in the Statement of Financial Position
 
Net Amount
 
 
 
Financial Instruments
 
Cash Collateral Pledged
 
As of March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
Derivative Assets:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
1,699

 
$
(649
)
 
$
1,050

 
$
(1,050
)
 
$

 
$

Commodity contracts (swaps)
65,050

 
(5,819
)
 
59,231

 

 

 
59,231

Fair value hedges
30,691

 

 
30,691

 

 

 
30,691

Derivative Liabilities:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
2,581

 
$
(649
)
 
$
1,932

 
$
(1,050
)
 
$

 
$
882

Commodity contracts (swaps)
5,819

 
(5,819
)
 

 

 

 

Interest rate swaps
2,153

 

 
2,153

 

 

 
2,153

 
 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
Derivative Assets:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
8,508

 
$
(1,340
)
 
$
7,168

 
$
(7,168
)
 
$

 
$

Commodity contracts (swaps)
49,204

 
(6,464
)
 
42,740

 

 

 
42,740

Fair value hedges
24,903

 

 
24,903

 

 

 
24,903

Derivative Liabilities:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
8,841

 
$
(1,340
)
 
$
7,501

 
$
(7,168
)
 
$

 
$
333

Commodity contracts (swaps)
6,464

 
(6,464
)
 

 

 

 

Interest rate swaps
1,238

 

 
1,238

 

 

 
1,238

Compliance Program Market Risk
We are obligated by government regulations to blend a certain percentage of biofuels into the products that we produce and 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 renewable identification number, or 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. Alternatively, if we have a RINs surplus, some of those RINs could be sold. Any such sales would be subject to our normal credit evaluation process.

11

Table of Contents
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


We are exposed to market risk related to the volatility in the price of credits needed to comply with these governmental and regulatory programs. 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 $12,696 and $7,781 for the three months ended March 31, 2015 and 2014, respectively. These amounts are reflected in cost of sales in the consolidated statements of operations.
(6)
Inventories
Carrying value of inventories consisted of the following:
 
March 31,
2015
 
December 31,
2014
Crude oil, refined products, asphalt and blendstocks
$
36,067

 
$
48,027

Crude oil consignment inventory (Note 7)
13,393

 
18,350

Materials and supplies
24,410

 
22,269

Store merchandise
22,774

 
27,418

Store fuel
5,403

 
6,739

Total inventories
$
102,047

 
$
122,803

The market value of refined products, asphalt and blendstock inventories exceeded last-in, first-out (“LIFO”) costs by $8,186 and $7,713 at March 31, 2015 and December 31, 2014, respectively. Crude oil inventories on a LIFO cost basis, net of the fair value hedged items, were lower than the market value of crude oil inventories by $25,118 and $17,754 at March 31, 2015 and December 31, 2014, respectively.
(7)
Inventory Financing Agreements
We have 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 our 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 beginning 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.
In February 2015, the Supply and Offtake Agreements for the Big Spring and Krotz Springs refineries were amended and the initial term was extended to May 2021. J. Aron may elect to terminate the Supply and Offtake Agreements for the Big Spring and Krotz Springs refineries prior to the expiration of the initial term beginning in May 2018 and upon each anniversary thereof, on six months prior notice. We may elect to terminate in May 2020 on six months prior notice.
Following expiration or termination of the Supply and Offtake Agreements, we are obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the leased storage facilities at then current market prices.
Associated with the Supply and Offtake Agreements, we have fair value hedges of our inventory purchase commitments with J. Aron and crude oil inventory consigned to J. Aron (“crude oil consignment inventory”). Additionally, financing charges related to the Supply and Offtake Agreements are recorded as interest expense in the consolidated statements of operations.
In connection with the Supply and Offtake Agreement for our Krotz Springs refinery, we have granted a security interest to J. Aron in all of its accounts and inventory to secure its obligations to J. Aron. In addition, we have granted a security interest in all of its real property and equipment to J. Aron to secure its obligations under a commodity hedge and sale agreement in lieu of posting cash collateral and being subject to cash margin calls.
At March 31, 2015 and December 31, 2014, we had net current payables to J. Aron for purchases of $7,132 and $46,303, respectively, and a consignment inventory receivable representing a deposit paid to J. Aron of $26,179 and $26,179,

12

Table of Contents
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


respectively. At March 31, 2015 and December 31, 2014, we had non-current liabilities for the original financing of $39,861 and $39,060, respectively, net of the related fair value hedges.
Additionally, we had net current payables of $672 and $4,212 at March 31, 2015 and December 31, 2014, respectively, for forward commitments related to month-end consignment inventory target levels differing from projected levels and the associated pricing with these inventory level differences.
(8)
Property, Plant and Equipment, Net
Property, plant and equipment, net consisted of the following:
 
March 31,
2015
 
December 31,
2014
Refining facilities
$
1,827,657

 
$
1,820,565

Pipelines and terminals
43,439

 
43,439

Retail
202,623

 
200,354

Other
19,554

 
17,988

Property, plant and equipment, gross
2,093,273

 
2,082,346

Accumulated depreciation
(734,937
)
 
(710,002
)
Property, plant and equipment, net
$
1,358,336

 
$
1,372,344

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 allocated goodwill of $4,030. For the three months ended March 31, 2014, a pre-tax gain of $1,943 was recognized and has been included in gain on disposition of assets in our consolidated statements of operations.
(9)
Additional Financial Information
The following tables provide additional financial information related to the consolidated financial statements.
(a)
Other Assets, Net
 
March 31,
2015
 
December 31,
2014
Deferred turnaround and catalyst cost
$
56,372

 
$
60,753

Environmental receivables (Note 15)
2,843

 
3,030

Deferred debt issuance costs
9,761

 
10,569

Intangible assets, net
7,511

 
7,647

Receivable from supply and offtake agreements (Note 7)
26,179

 
26,179

Commodity contracts
11,718

 
11,622

Fair value hedges (Note 7)
30,691

 
24,903

Other, net
17,964

 
18,176

Total other assets
$
163,039

 
$
162,879


13

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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,
2015
 
December 31,
2014
Accrued Liabilities:
 
 
 
Taxes other than income taxes, primarily excise taxes
$
33,295

 
$
47,071

Employee costs
20,849

 
13,297

Commodity contracts
1,932

 
7,501

Accrued finance charges
847

 
1,826

Environmental accrual (Note 15)
8,189

 
8,189

Other
35,458

 
26,507

Total accrued liabilities
$
100,570

 
$
104,391

 
 
 
 
Other Non-Current Liabilities:
 
 
 
Pension and other postemployment benefit liabilities, net
$
52,689

 
$
52,135

Environmental accrual (Note 15)
41,185

 
43,546

Asset retirement obligations
12,326

 
12,328

Consignment inventory obligations (Note 7)
70,552

 
63,963

Interest rate swaps
2,153

 
1,238

Other
9,234

 
9,449

Total other non-current liabilities
$
188,139

 
$
182,659

(10)
Postretirement Benefits
The components of net periodic benefit cost related to our benefit plans for the three months ended March 31, 2015 and 2014 consisted of the following:
 
For the Three Months Ended
 
March 31,
 
2015
 
2014
Components of net periodic benefit cost:
 
 
 
Service cost
$
996

 
$
856

Interest cost
1,256

 
1,238

Expected return on plan assets
(1,582
)
 
(1,370
)
Amortization of net loss
839

 
596

Net periodic benefit cost
$
1,509

 
$
1,320

Our estimated contributions to our pension plans during 2015 have not changed significantly from amounts previously disclosed in the consolidated financial statements for the year ended December 31, 2014. For the three months ended March 31, 2015 and 2014, we contributed $1,030 and $1,160, respectively, to our qualified pension plans.
(11)
Indebtedness
Debt consisted of the following:
 
March 31,
2015
 
December 31,
2014
Term loan credit facilities
$
262,586

 
$
264,359

Alon USA, LP Credit Facility
50,000

 
60,000

Convertible senior notes
127,657

 
126,298

Retail credit facilities
111,176

 
113,030

Total debt
551,419

 
563,687

Less: Current portion
15,089

 
15,089

Total long-term debt
$
536,330

 
$
548,598


14

Table of Contents
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


(a) Letter of Credit Facility and Alon USA, LP Revolving Credit Facility
We had letters of credit outstanding under our $60,000 letter of credit facility of $55,751 and $54,227 at March 31, 2015 and December 31, 2014, respectively.
We had borrowings of $50,000 and $60,000 and letters of credit of $36,863 and $23,511 outstanding under the Alon USA, LP $240,000 revolving credit facility at March 31, 2015 and December 31, 2014, respectively.
In May 2015, the Alon USA, LP $240,000 revolving credit facility was amended to, among other matters, extend the expiration date to May 2019.
(b) Convertible Senior Notes
The conversion rate for the Convertible Senior Notes is subject to adjustment upon the occurrence of certain events, including cash dividend adjustments, but will not be adjusted for any accrued and unpaid interest. As of March 31, 2015, the conversion rate was adjusted to 69.116 shares of our common stock per each $1 (in thousands) principal amount of Convertible Senior Notes, equivalent to a conversion price of approximately $14.47 per share, to reflect cash dividend adjustments. The strike price for the warrants was adjusted to $19.66 per share. Any future quarterly cash dividend payments in excess of $0.06 per share will cause further adjustment based on the formula contained in the indenture. The Convertible Senior Notes holders may require us to render a make-whole payment to holders under certain circumstances, including in the event of a change in control, as defined in the indenture. As of March 31, 2015, there have been no conversions of the Convertible Senior Notes.
(c) Financial Covenants
We have certain credit agreements that contain maintenance financial covenants. At March 31, 2015, we were in compliance with these covenants.
(12)
Stock-Based Compensation (share values in dollars)
Our overall executive incentive compensation program permits the granting of awards to our directors, officers and key employees in the form of options to purchase common stock, stock appreciation rights, restricted shares of common stock, restricted common stock units, performance shares, performance units and senior executive plan bonuses.
Restricted Stock. As of March 31, 2015 and December 31, 2014, we had 643,999 non-vested restricted shares.
Compensation expense for restricted stock awards amounted to $799 and $488 for the three months ended March 31, 2015 and 2014, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.
Restricted Stock Units. In 2011, we granted 500,000 restricted stock units to our CEO and President at a grant date fair value of $11.47 per share. Each restricted unit represents the right to receive one share of our common stock upon the vesting of the restricted stock unit. All 500,000 restricted stock units vested on March 1, 2015. Compensation expense for restricted stock units amounted to $249 and $374 for the three months ended March 31, 2015 and 2014, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.
Unrecognized Compensation Cost. As of March 31, 2015, there was $3,467 of total unrecognized compensation cost related to non-vested share-based compensation arrangements, which is expected to be recognized over a weighted-average period of 1.0 year.

15

Table of Contents
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


(13)
Equity (share values in dollars)
Changes to equity during the three months ended March 31, 2015 are presented below:
 
 
Total Stockholders’ Equity
 
Non-controlling Interest
 
Total Equity
Balance at December 31, 2014
 
$
636,898

 
$
36,880

 
$
673,778

Other comprehensive income
 
(1,680
)
 
(100
)
 
(1,780
)
Stock compensation
 
(937
)
 
(404
)
 
(1,341
)
Dividends of common stock on preferred stock
 
(4
)
 

 
(4
)
Distributions to non-controlling interest in the Partnership
 

 
(8,055
)
 
(8,055
)
Dividends
 
(6,914
)
 
(82
)
 
(6,996
)
Net income
 
26,939

 
7,116

 
34,055

Balance at March 31, 2015
 
$
654,302

 
$
35,355

 
$
689,657

(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, 2015, 164,822 shares of our common stock were issued in exchange for 881.12 shares of Alon Assets. At March 31, 2015, 1,095,600 shares of our common stock are available to be exchanged for the outstanding shares held by non-controlling interest shareholders of Alon Assets.
We recognized compensation expense associated with the difference in value between the participants' ownership of Alon Assets compared to our common stock of $484 and $697 for the three months ended March 31, 2015 and 2014, respectively. These amounts are included in selling, general and administrative expenses in the consolidated statements of operations.
(b)
Preferred Stock
Preferred Stock Conversion. During the three months ended March 31, 2015, the remaining 68,180 shares of our preferred stock were converted to 101,150 shares of our common stock.
(c)
Dividends
Common Stock Dividends. On March 16, 2015, we paid a regular quarterly cash dividend of $0.10 per share on common stock to stockholders of record at the close of business on February 26, 2015.
Preferred Stock Dividends. During the three months ended March 31, 2015, we issued 771 shares of common stock for payment of the quarterly 8.5% preferred stock dividend to preferred stockholders, prior to the preferred stock conversion into our common stock.
(d)
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, 2014
$
21,330

 
$
(29,788
)
 
$
(8,458
)
Other comprehensive income before reclassifications
3,241

 

 
3,241

Amounts reclassified from accumulated other comprehensive loss
(4,921
)
 

 
(4,921
)
Net current-period other comprehensive loss
(1,680
)
 

 
(1,680
)
Balance at March 31, 2015
$
19,650

 
$
(29,788
)
 
$
(10,138
)
(14)
Earnings Per Share
Basic earnings per share is calculated as net income available to common stockholders divided by the average number of participating shares of common stock outstanding. Diluted earnings per share includes the dilutive effect of granted stock appreciation rights, granted restricted common stock units, granted restricted common stock awards, convertible debt and warrants using the treasury stock method and the dilutive effect of convertible preferred shares using the if-converted method.

16

Table of Contents
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


The calculation of earnings per share, basic and diluted, for the three months ended March 31, 2015 and 2014, is as follows (shares in thousands, per share value in dollars):
 
For the Three Months Ended
 
March 31,
 
2015
 
2014
Net income available to stockholders
$
26,939

 
$
785

Less: preferred stock dividends
15

 
15

Net income available to common stockholders
26,924

 
770

 
 
 
 
Weighted average shares outstanding, basic
69,485

 
68,617

Dilutive common stock equivalents
1,657

 
450

Weighted average shares outstanding, diluted
71,142

 
69,067

Earnings per share, basic
$
0.39

 
$
0.01

Earnings per share, diluted
$
0.38

 
$
0.01

For the three months ended March 31, 2015, the weighted average diluted shares includes all potentially dilutive common stock equivalents. For the three months ended March 31, 2014, we have excluded 101 common stock equivalents from the weighted average diluted shares outstanding as the effect of including such shares would be anti-dilutive.
(15)
Commitments and Contingencies
(a)
Commitments
In the normal course of business, we have long-term commitments to purchase, at market prices, utilities such as natural gas, electricity and water for use by our refineries, terminals, pipelines and retail locations. We are also party to various refined product and crude oil supply and exchange agreements, which are typically short-term in nature or provide terms for cancellation.
(b)
Contingencies
We are involved in various legal actions arising in the ordinary course of business. We believe the ultimate disposition of these matters will not have a material effect on our financial position, results of operations or liquidity.
One of our subsidiaries is a party to a lawsuit alleging breach of contract pertaining to an asphalt supply agreement. We believe that we have valid counterclaims as well as affirmative defenses that will preclude recovery. Attempts to reach a commercial arrangement to resolve the dispute have been unsuccessful to this point. This matter is currently scheduled for trial in October 2015. 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 $49,374 ($8,189 current liability and $41,185 non-current liability) at March 31, 2015, and $51,735 ($8,189 current liability and $43,546 non-current liability) at December 31, 2014.

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ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


We have an indemnification agreement with a prior owner for remediation expenses at the Bakersfield refinery. We have recorded current receivables of $717 and $3,350 at March 31, 2015 and December 31, 2014, respectively.
In addition to the indemnification agreement related to the Bakersfield refinery, we have an indemnification agreement with a prior owner for part of the remediation expenses at certain other West Coast assets. We have recorded current receivables of $784 and $784 and non-current receivables of $2,843 and $3,030 at March 31, 2015 and December 31, 2014, respectively.
(16)
Subsequent Events
Alon USA, LP Credit Facility
In May 2015, the Alon USA, LP $240,000 revolving credit facility was amended to, among other matters, extend the expiration date to May 2019.
Dividend Declared
On May 5, 2015, our board of directors declared an increase in the regular quarterly cash dividend of $0.10 to $0.15 per share on our common stock, payable on June 5, 2015, to holders of record at the close of business on May 19, 2015.
Partnership Distribution
On May 4, 2015, the board of directors of the General Partner declared a cash distribution to the Partnership’s common unitholders of approximately $44,380, or $0.71 per common unit. The cash distribution will be paid on May 26, 2015 to unitholders of record at the close of business on May 18, 2015. The total cash distribution payable to non-affiliated common unitholders will be approximately $8,170.
Delek US Holdings, Inc. Share Purchase Agreement
On April 14, 2015, Delek US Holdings, Inc. entered into a definitive stock purchase agreement with Alon Israel Oil Company, Ltd. to purchase approximately 48% of our common stock. This transaction, which has received Hart-Scott-Rodino clearance, is expected to close as early as May 12, 2015.

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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, 2014. In this document, the words “Alon,” “the Company,” “we,” “our” and “us” refer to Alon USA Energy, Inc. and its consolidated subsidiaries or to Alon USA Energy, Inc. or an individual subsidiary, and not to any other person. Generally, the words “we,” “our” and “us” include Alon USA Partners, LP and its subsidiaries (the “Partnership”) as consolidated subsidiaries of Alon USA Energy, Inc.
Forward-Looking Statements
Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.
Forward-looking statements reflect our current expectations of future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations and cash flows.
Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:
changes in general economic conditions and capital markets;
changes in the underlying demand for our products;
the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;
changes in the spread between West Texas Intermediate (“WTI”) Cushing crude oil and West Texas Sour (“WTS”) crude oil or WTI Midland crude oil;
changes in the spread between WTI Cushing crude oil and Light Louisiana Sweet (“LLS”) crude oil;
changes in the spread between Brent crude oil and WTI Cushing crude oil;
changes in the spread between Brent crude oil and LLS crude oil;
the effects of transactions involving forward contracts and derivative instruments;
actions of customers and competitors;
termination of our Supply and Offtake Agreements with J. Aron & Company (“J. Aron”), which include all our refineries and most of our asphalt terminals, of which J. Aron is our largest supplier of crude oil and our largest customer of refined products. Additionally upon termination of the Supply and Offtake Agreements, we are obligated to purchase the crude oil and refined product inventories then owned by J. Aron at then current market prices;
changes in fuel and utility costs incurred by our facilities;
disruptions due to equipment interruption, pipeline disruptions or failures at our or third-party facilities;
the execution of planned capital projects;
adverse changes in the credit ratings assigned to our debt instruments;
the effects of and cost of compliance with the renewable fuel standards program, including the availability, cost and price volatility of renewable identification numbers;
the effects and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;
operating hazards, accidents, fires, severe weather, floods and other natural disasters, casualty losses and other matters beyond our control, which could result in unscheduled downtime;

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the effects of seasonality on demand for our products;
the level of competition from other petroleum refiners;
the easing of logistical and infrastructure constraints at Cushing;
the effect of any national or international financial crisis on our business and financial condition; and
the other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2014 under the caption “Risk Factors.”
Any one of these factors or a combination of these factors could materially affect our future results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.
Company Overview
We are an independent refiner and marketer of petroleum products operating primarily in the South Central, Southwestern and Western regions of the United States. Our crude oil refineries are located in Texas, California, Oregon and Louisiana and have a combined throughput capacity of approximately 217,000 barrels per day (“bpd”). We are a leading marketer of asphalt, which we distribute primarily through asphalt terminals located predominately in the Southwestern and Western United States. We are the largest 7-Eleven licensee in the United States and operate 293 convenience stores in Central and West Texas and New Mexico.
Refining and Marketing Segment. Our refining and marketing segment includes a sour crude oil refinery located in Big Spring, Texas, a light sweet crude oil refinery located in Krotz Springs, Louisiana and heavy crude oil refineries located in Paramount, Bakersfield and Long Beach, California (“California refineries”). Our refineries have a combined crude oil throughput capacity of approximately 217,000 bpd. We refine crude oil into petroleum products, including various grades of gasoline, diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum-based products, which are marketed primarily in the South Central, Southwestern and Western United States. Our California refineries did not process crude oil in 2015 and 2014 due to the high cost of crude oil relative to product yield and low asphalt demand.
We own the Big Spring refinery and wholesale marketing operations through Alon USA Partners, LP (the “Partnership”) (NYSE: ALDW). Our marketing of transportation fuels produced at the Big Spring refinery is focused on West and Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in these regions as our “physically integrated system” because our distributors in this region are supplied primarily 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 642 Alon branded retail sites, including our retail segment convenience stores. In 2015, approximately 53% of the gasoline and 24% 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 67 licensed locations that are not under fuel supply agreements.
We market transportation fuel production from our Krotz Springs refinery through bulk sales and exchange channels. These bulk sales and exchange arrangements are entered into with various oil companies and traders and are transported to markets on the Mississippi River and the Atchafalaya River as well as to the Colonial Pipeline.
Asphalt Segment. We own or operate 10 asphalt terminals located in Texas (Big Spring), Washington (Richmond Beach), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Arizona (Phoenix and Flagstaff) and Nevada (Fernley) (50% interest), as well as through a 50% interest in Wright Asphalt Products Company, LLC, which specializes in patented ground tire rubber modified asphalt products. 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.
We purchase non-blended asphalt from third parties in addition to non-blended asphalt produced at the Big Spring refinery. We market asphalt through our terminals as blended and non-blended 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 market asphalt primarily as paving asphalt to road and materials manufacturers and highway construction/maintenance contractors as GTR, polymer modified or emulsion asphalt. Sales of asphalt are seasonal with the majority of sales occurring between May and October.

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Retail Segment. Our convenience stores typically offer various grades of gasoline, diesel fuel, food products, food service, tobacco products, non-alcoholic and alcoholic beverages, general merchandise as well as money orders to the 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.
For additional information on each of our operating segments, see Items 1. and 2. “Business and Properties” included in our Annual Report on Form 10-K for the year ended December 31, 2014.
First Quarter Operational and Financial Highlights
Operating income for the first quarter of 2015 was $67.6 million, compared to $39.0 million in the same period last year. Our operational and financial highlights for the first quarter of 2015 include the following:
Combined refinery average throughput for the first quarter of 2015 was 145,229 bpd, compared to a combined refinery average throughput of 135,363 bpd for the first quarter of 2014. The Big Spring refinery average throughput for the first quarter of 2015 was 72,360 bpd, compared to 73,296 bpd for the first quarter of 2014. The Krotz Springs refinery average throughput for the first quarter of 2015 was 72,869 bpd, compared to 62,067 bpd for the first quarter of 2014. During a portion of the three months ended March 31, 2014, our Krotz Springs refinery was shut down for crude unit maintenance.
Refinery operating margin at the Big Spring refinery was $13.80 per barrel for the first quarter of 2015 compared to $14.77 per barrel for the same period in 2014. This decrease was primarily due to a narrowing of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread, partially offset by a higher Gulf Coast 3/2/1 crack spread.
Refinery operating margin at the Krotz Springs refinery was $9.52 per barrel for the first quarter of 2015 compared to $7.39 per barrel for the same period in 2014. This increase was primarily due to a higher Gulf Coast 2/1/1 high sulfur diesel crack spread, partially offset by a narrowing of both the WTI Cushing to WTI Midland spread and the LLS to WTI Cushing spread.
The average Gulf Coast 3/2/1 crack spread was $17.74 per barrel for the first quarter of 2015 compared to $16.81 per barrel for the first quarter of 2014. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the first quarter of 2015 was $13.41 per barrel compared to $10.75 per barrel for the first quarter of 2014.
The average WTI Cushing to WTS spread for the first quarter of 2015 was $1.76 per barrel compared to $3.67 per barrel for the same period in 2014. The average WTI Cushing to WTI Midland spread for the first quarter of 2015 was $1.95 per barrel compared to $3.54 per barrel for the same period in 2014. The average LLS to WTI Cushing spread for the first quarter of 2015 was $2.64 per barrel compared to $6.00 per barrel for the same period in 2014.
Asphalt margins in the first quarter of 2015 were $84.76 per ton compared to $79.59 per ton in the first quarter of 2014. This increase was primarily due to lower costs of asphalt purchased during the first quarter of 2015 compared to 2014.
Retail fuel sales volume increased to 46.1 million gallons in the first quarter of 2015 from 45.5 million gallons in the first quarter of 2014. Merchandise margins increased to 33.2% in the first quarter of 2015 from 31.5% in the first quarter of 2014.
During the quarter, a new four-year labor agreement was reached with the employees of the Big Spring refinery that were covered by a collective bargaining agreement.
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, not necessarily fluctuations in those prices, that affects 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

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inventory adjustments). Each refinery is compared to an industry benchmark that is intended to approximate that refinery’s crude slate and product yield.
We compare our Big Spring refinery’s operating margin to the Gulf Coast 3/2/1 crack spread. A Gulf Coast 3/2/1 crack spread is calculated assuming that three barrels of WTI Cushing crude oil are converted, or cracked, into two barrels of Gulf Coast conventional gasoline and one barrel of Gulf Coast ultra-low sulfur diesel.
We compare our Krotz Springs refinery’s operating margin to the Gulf Coast 2/1/1 high sulfur diesel crack spread. A Gulf Coast 2/1/1 high sulfur diesel crack spread is calculated assuming that two barrels of LLS crude oil are converted into one barrel of Gulf Coast conventional gasoline and one barrel of Gulf Coast high sulfur diesel.
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 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 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 and infrastructure constraints in the Permian Basin. Although West Texas crudes are typically transported to Cushing and to the Gulf Coast for sale, current logistical and infrastructure constraints are limiting the ability of Permian Basin producers to transport their production to Cushing and to the Gulf Coast. The resulting oversupply of West Texas crudes at Midland has depressed Midland crude prices and enabled us to obtain an increased portion of our crude supply at discounted prices to Cushing. Moreover, by sourcing West Texas crudes 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 will favorably influence the operating margin for both our Big Spring and Krotz Springs refineries. Alternatively, an easing of the current logistical and infrastructure constraints through new pipeline construction or expansion could reduce this differential, which will have an adverse effect on our margins.
Global product prices are influenced by the price of Brent crude which is a global benchmark crude. Global product prices influence product prices in the U.S. As a result, both our Big Spring and Krotz Springs refineries are influenced by the spread between Brent crude and WTI Cushing. 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 will favorably influence both the Big Spring and Krotz Springs refineries’ operating margins. Also, the Krotz Springs refinery is influenced by the spread between Brent crude and LLS. 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 will 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 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.

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Asphalt. Earnings and cash flows from our asphalt segment depend primarily upon the margin between the price at which we sell our asphalt and the price asphalt is purchased from third parties or the transfer price for asphalt produced at the Big Spring refinery. Asphalt is transferred to our asphalt segment from our refining and marketing segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices. A portion of our asphalt sales are made using fixed price contracts for delivery at future dates. Because these contracts are priced using market prices for asphalt at the time of the contract, a change in the cost of crude oil between the time we enter into the contract and the time we produce the asphalt can positively or negatively influence the earnings of our asphalt segment. Demand for paving asphalt products is higher during warmer months than during colder months due to seasonal increases in road construction work. As a result, revenues from our asphalt segment for the first and fourth calendar quarters are expected to be lower than those for the second and third calendar quarters.
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, 2015 and 2014 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 a portion of the three months ended March 31, 2014, our Krotz Springs refinery was shut down for crude unit maintenance.
Certain Derivative Impacts
Included in the consolidated statements of operations in cost of sales for the three months ended March 31, 2015 and 2014 are realized and unrealized gains (losses) on commodity swaps of $29.8 million and $(6.2) million, respectively.
Crude Oil Pricing Environment
A component of our supply and offtake agreements fees, which affects our interest expense, is related to the crude oil price environment whereby a backwardated environment adds to our expense and a contango environment reduces our expense. Interest expense in the first quarter 2015 compared to the first quarter 2014 was lower because crude oil prices moved from backwardation into contango.

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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.
Refining and marketing net sales consist of gross sales, net of customer rebates, discounts and excise taxes and include intersegment sales to our asphalt and retail segments, which are eliminated through consolidation of our financial statements. Asphalt net sales consist of gross sales, net of any discounts and applicable taxes. Our petroleum and asphalt product 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, which include costs associated with our crude oil and product pipelines. 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.
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 wholesale 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, 2015 and 2014. 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, 2014 is unaudited.
 
For the Three Months Ended
 
March 31,
 
2015
 
2014
 
(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
 
 
 
Net sales (1)
$
1,103,240

 
$
1,683,245

Operating costs and expenses:
 
 
 
Cost of sales
894,488

 
1,506,545

Direct operating expenses
64,205

 
70,678

Selling, general and administrative expenses (2)
45,596

 
39,389

Depreciation and amortization (3)
31,962

 
29,878

Total operating costs and expenses
1,036,251

 
1,646,490

Gain on disposition of assets
572

 
2,205

Operating income
67,561

 
38,960

Interest expense
(21,037
)
 
(28,015
)
Equity losses of investees
(554
)
 
(459
)
Other income (loss), net
46

 
(17
)
Income before income tax expense
46,016

 
10,469

Income tax expense
11,961

 
2,094

Net income
34,055

 
8,375

Net income attributable to non-controlling interest
7,116

 
7,590

Net income available to stockholders
$
26,939

 
$
785

Earnings per share, basic
$
0.39

 
$
0.01

Weighted average shares outstanding, basic (in thousands)
69,485

 
68,617

Earnings per share, diluted
$
0.38

 
$
0.01

Weighted average shares outstanding, diluted (in thousands)
71,142

 
69,067

Cash dividends per share
$
0.10

 
$
0.06

CASH FLOW DATA:
 
 
 
Net cash provided by (used in):
 
 
 
Operating activities
$
(19,221
)
 
$
62,714

Investing activities
(11,613
)
 
6,396

Financing activities
6,338

 
61,683

OTHER DATA:
 
 
 
Adjusted EBITDA (4)
$
98,443

 
$
66,157

Capital expenditures (5)
10,749

 
18,160

Capital expenditures for turnarounds and catalysts
2,333

 
14,847



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March 31,
2015
 
December 31,
2014
BALANCE SHEET DATA (end of period):
(dollars in thousands)
Cash and cash equivalents
$
190,465

 
$
214,961

Working capital
144,500

 
126,665

Total assets
2,174,423

 
2,200,874

Total debt
551,419

 
563,687

Total debt less cash and cash equivalents
360,954

 
348,726

Total equity
689,657

 
673,778

(1)
Includes excise taxes on sales by the retail segment of $18,056 and $17,810 for the three months ended March 31, 2015 and 2014, respectively.
(2)
Includes corporate headquarters selling, general and administrative expenses of $176 and $175 for the three months ended March 31, 2015 and 2014, respectively, which are not allocated to our three operating segments.
(3)
Includes corporate depreciation and amortization of $469 and $596 for the three months ended March 31, 2015 and 2014, respectively, which are not allocated to our three operating segments.
(4)
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, 2015 and 2014:
 
For the Three Months Ended
 
March 31,
 
2015
 
2014
 
(dollars in thousands)
Net income available to stockholders
$
26,939

 
$
785

Net income attributable to non-controlling interest
7,116

 
7,590

Income tax expense
11,961

 
2,094

Interest expense
21,037

 
28,015

Depreciation and amortization
31,962

 
29,878

Gain on disposition of assets
(572
)
 
(2,205
)
Adjusted EBITDA
$
98,443

 
$
66,157

Adjusted EBITDA does not exclude unrealized (gains) losses on commodity swaps of $(18,403) and $6,606 for the three months ended March 31, 2015 and 2014, respectively, which are included in net income available to stockholders. Additionally, adjusted EBITDA for the three months ended March 31, 2015 does not exclude a loss of $10,666 resulting from a price adjustment related to winter-fill asphalt inventory.
(5)
Includes corporate capital expenditures of $1,621 and $865 for the three months ended March 31, 2015 and 2014, 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,
 
2015
 
2014
 
(dollars in thousands, except per barrel data and pricing statistics)
STATEMENT OF OPERATIONS DATA:
 
 
 
Net sales (1)
$
959,492

 
$
1,504,918

Operating costs and expenses:
 
 
 
Cost of sales
783,391

 
1,368,214

Direct operating expenses
56,326

 
60,798

Selling, general and administrative expenses
17,339

 
10,534

Depreciation and amortization
27,311

 
25,368

Total operating costs and expenses
884,367

 
1,464,914

Gain on disposition of assets
522

 

Operating income
$
75,647

 
$
40,004

KEY OPERATING STATISTICS:
 
 
 
Per barrel of throughput:
 
 
 
Refinery operating margin – Big Spring (2)
$
13.80

 
$
14.77

Refinery operating margin – Krotz Springs (2)
9.52

 
7.39

Refinery direct operating expense – Big Spring (3)
3.60

 
4.39

Refinery direct operating expense – Krotz Springs (3)
3.80

 
4.56

Capital expenditures
$
4,406

 
$
12,196

Capital expenditures for turnarounds and catalysts
2,333

 
14,847

PRICING STATISTICS:
 
 
 
Crack spreads (3/2/1) (per barrel):
 
 
 
Gulf Coast
$
17.74

 
$
16.81

Crack spreads (2/1/1) (per barrel):
 
 
 
Gulf Coast high sulfur diesel
$
13.41

 
$
10.75

WTI Cushing crude oil (per barrel)
$
48.48

 
$
98.65

Crude oil differentials (per barrel):
 
 
 
WTI Cushing less WTI Midland
$
1.95

 
$
3.54

WTI Cushing less WTS
1.76

 
3.67

LLS less WTI Cushing
2.64

 
6.00

Brent less LLS
0.84

 
6.97

Brent less WTI Cushing
5.44

 
10.46

Product price (dollars per gallon):
 
 
 
Gulf Coast unleaded gasoline
$
1.52

 
$
2.66

Gulf Coast ultra-low sulfur diesel
1.69

 
2.93

Gulf Coast high sulfur diesel
1.55

 
2.84

Natural gas (per MMBtu)
2.81

 
4.72


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THROUGHPUT AND PRODUCTION DATA:
BIG SPRING REFINERY
For the Three Months Ended
March 31,
 
2015
 
2014
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
WTS crude
44,865

 
62.0

 
35,345

 
48.2

WTI crude
24,137

 
33.4

 
35,982

 
49.1

Blendstocks
3,358

 
4.6

 
1,969

 
2.7

Total refinery throughput (4)
72,360

 
100.0

 
73,296

 
100.0

Refinery production:
 
 
 
 
 
 
 
Gasoline
36,192

 
49.7

 
36,290

 
49.6

Diesel/jet
26,086

 
35.9

 
24,674

 
33.6

Asphalt
3,278

 
4.5

 
3,406

 
4.6

Petrochemicals
4,810

 
6.6

 
4,412

 
6.0

Other
2,394

 
3.3

 
4,557

 
6.2

Total refinery production (5)
72,760

 
100.0

 
73,339

 
100.0

Refinery utilization (6)
 
 
94.5
%
 
 
 
101.9
%
THROUGHPUT AND PRODUCTION DATA:
KROTZ SPRINGS REFINERY
For the Three Months Ended
March 31,
 
2015
 
2014
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
WTI crude
30,353

 
41.7

 
24,040

 
38.7

Gulf Coast sweet crude
37,038

 
50.8

 
35,710

 
57.6

Blendstocks
5,478

 
7.5

 
2,317

 
3.7

Total refinery throughput (4)
72,869

 
100.0

 
62,067

 
100.0

Refinery production:
 
 
 
 
 
 
 
Gasoline
34,527

 
46.3

 
30,888

 
48.9

Diesel/jet
30,690

 
41.2

 
25,873

 
41.0

Heavy Oils
1,334

 
1.8

 
594

 
0.9

Other
7,995

 
10.7

 
5,819

 
9.2

Total refinery production (5)
74,546

 
100.0

 
63,174

 
100.0

Refinery utilization (6)
 
 
91.1
%
 
 
 
80.7
%

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