UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
___________________________________________________
FORM 10-Q
þ
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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 July 31, 2015, was 70,783,704.

 
 


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)
 
June 30,
2015
 
December 31,
2014
 
(unaudited)
 
 
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
263,830

 
$
214,961

Accounts and other receivables, net
162,834

 
153,859

Income tax receivable
—

 
9,196

Inventories
117,367

 
122,803

Deferred income tax asset
11,353

 
11,228

Prepaid expenses and other current assets
24,625

 
26,315

Total current assets
580,009

 
538,362

Equity method investments
26,650

 
25,376

Property, plant and equipment, net
1,352,199

 
1,372,344

Goodwill
101,913

 
101,913

Other assets, net
150,789

 
162,879

Total assets
$
2,211,560

 
$
2,200,874

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
309,928

 
$
292,217

Accrued liabilities
101,035

 
104,391

Current portion of long-term debt
15,086

 
15,089

Total current liabilities
426,049

 
411,697

Other non-current liabilities
174,919

 
182,659

Long-term debt
524,127

 
548,598

Deferred income tax liability
372,155

 
384,142

Total liabilities
1,497,250

 
1,527,096

Commitments and contingencies (Note 16)

 

Stockholders’ equity:
 
 
 
Preferred stock, par value $0.01, 15,000,000 shares authorized; 0 and 68,180 shares issued and outstanding at June 30, 2015 and December 31, 2014, respectively
—

 
682

Common stock, par value $0.01, 150,000,000 shares authorized; 70,567,357 and 69,606,944 shares issued and outstanding at June 30, 2015 and December 31, 2014, respectively
706

 
696

Additional paid-in capital
519,234

 
517,127

Accumulated other comprehensive loss, net of tax
(16,132
)
 
(8,458
)
Retained earnings
172,801

 
126,851

Total stockholders’ equity
676,609

 
636,898

Non-controlling interest in subsidiaries
37,701

 
36,880

Total equity
714,310

 
673,778

Total liabilities and equity
$
2,211,560

 
$
2,200,874


The accompanying notes are an integral part of these consolidated financial statements.
1

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

 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
Net sales (1)
$
1,301,341

 
$
1,742,883

 
$
2,404,581

 
$
3,426,128

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales
1,069,931

 
1,580,447

 
1,964,419

 
3,086,992

Direct operating expenses
62,856

 
67,630

 
127,061

 
138,308

Selling, general and administrative expenses
49,193

 
46,333

 
94,789

 
85,722

Depreciation and amortization
31,267

 
29,453

 
63,229

 
59,331

Total operating costs and expenses
1,213,247

 
1,723,863

 
2,249,498

 
3,370,353

Gain (loss) on disposition of assets
—

 
(88
)
 
572

 
2,117

Operating income
88,094

 
18,932

 
155,655

 
57,892

Interest expense
(18,217
)
 
(29,256
)
 
(39,254
)
 
(57,271
)
Equity earnings of investees
1,828

 
1,278

 
1,274

 
819

Other income, net
13

 
638

 
59

 
621

Income (loss) before income tax expense (benefit)
71,718

 
(8,408
)
 
117,734

 
2,061

Income tax expense (benefit)
23,856

 
(1,971
)
 
35,817

 
123

Net income (loss)
47,862

 
(6,437
)
 
81,917

 
1,938

Net income attributable to non-controlling interest
11,452

 
1,080

 
18,568

 
8,670

Net income (loss) available to stockholders
$
36,410

 
$
(7,517
)
 
$
63,349

 
$
(6,732
)
Earnings (loss) per share, basic
$
0.52

 
$
(0.11
)
 
$
0.91

 
$
(0.10
)
Weighted average shares outstanding, basic (in thousands)
69,684

 
68,851

 
69,584

 
68,734

Earnings (loss) per share, diluted
$
0.50

 
$
(0.11
)
 
$
0.87

 
$
(0.10
)
Weighted average shares outstanding, diluted (in thousands)
72,501

 
68,851

 
72,395

 
68,734

Cash dividends per share
$
0.15

 
$
0.06

 
$
0.25

 
$
0.12

___________
(1)
Includes excise taxes on sales by the retail segment of $19,369 and $19,101 for the three months and $37,425 and $36,911 for the six months ended June 30, 2015 and 2014, respectively.

The accompanying notes are an integral part of these consolidated financial statements.
2

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

 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
Net income (loss)
$
47,862

 
$
(6,437
)
 
$
81,917

 
$
1,938

Other comprehensive income (loss):
 
 
 
 
 
 
 
Interest rate derivatives designated as cash flow hedges:
 
 
 
 
 
 
 
Unrealized holding gain (loss) arising during period
89

 
(802
)
 
(841
)
 
(802
)
Loss reclassified to earnings - interest expense
97

 
14

 
112

 
14

Net gain (loss), before tax
186

 
(788
)
 
(729
)
 
(788
)
Income tax expense (benefit)
69

 
(290
)
 
(270
)
 
(290
)
Net gain (loss), net of tax
117

 
(498
)
 
(459
)
 
(498
)
Commodity contracts designated as cash flow hedges:
 
 
 
 
 
 
 
Unrealized holding gain arising during period
—

 
8,925

 
6,070

 
32,507

Amortization of unrealized (gain) loss on de-designated cash flow hedges - cost of sales
(9,955
)
 
2,153

 
(17,937
)
 
10,428

Net gain (loss), before tax
(9,955
)
 
11,078

 
(11,867
)
 
42,935

Income tax expense (benefit)
(3,683
)
 
4,098

 
(4,391
)
 
15,885

Net gain (loss), net of tax
(6,272
)
 
6,980

 
(7,476
)
 
27,050

Total other comprehensive income (loss), net of tax
(6,155
)
 
6,482

 
(7,935
)
 
26,552

Comprehensive income
41,707

 
45

 
73,982

 
28,490

Comprehensive income attributable to non-controlling interest
11,291

 
1,261

 
18,307

 
9,538

Comprehensive income (loss) attributable to stockholders
$
30,416

 
$
(1,216
)
 
$
55,675

 
$
18,952



The accompanying notes are an integral part of these consolidated financial statements.
3

ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, dollars in thousands)
 
For the Six Months Ended
 
June 30,
 
2015
 
2014
Cash flows from operating activities:
 
 
 
Net income
$
81,917

 
$
1,938

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
Depreciation and amortization
63,229

 
59,331

Stock compensation
3,767

 
3,540

Deferred income taxes
(7,451
)
 
(825
)
Equity earnings of investees
(1,274
)
 
—

Amortization of debt issuance costs
1,667

 
2,124

Amortization of original issuance discount
3,070

 
3,309

Write-off of unamortized debt issuance costs
—

 
253

Write-off of unamortized original issuance discount
—

 
254

Gain on disposition of assets
(572
)
 
(2,117
)
Unrealized (gain) loss on commodity swaps
(7,925
)
 
9,510

Changes in operating assets and liabilities:
 
 
 
Accounts and other receivables, net
(9,264
)
 
49,314

Income tax receivable
9,196

 
8,510

Inventories
5,436

 
(41,744
)
Prepaid expenses and other current assets
1,690

 
(10,926
)
Other assets, net
(293
)
 
147

Accounts payable
(12,424
)
 
(31,459
)
Accrued liabilities
(6,409
)
 
(25,458
)
Other non-current liabilities
(8,469
)
 
5,941

Net cash provided by operating activities
115,891

 
31,642

Cash flows from investing activities:
 
 
 
Capital expenditures
(31,051
)
 
(54,655
)
Capital expenditures for turnarounds and catalysts
(4,363
)
 
(26,269
)
Contribution to equity method investment
—

 
(597
)
Dividends from investees, net of equity earnings
—

 
181

Proceeds from disposition of assets
1,469

 
40,333

Net cash used in investing activities
(33,945
)
 
(41,007
)
Cash flows from financing activities:
 
 
 
Dividends paid to stockholders
(17,384
)
 
(8,221
)
Dividends paid to non-controlling interest
(260
)
 
(389
)
Distributions paid to non-controlling interest in the Partnership
(16,224
)
 
(10,010
)
Inventory agreement transactions
30,135

 
(25,200
)
Deferred debt issuance costs
(1,800
)
 
(2,062
)
Revolving credit facilities, net
(20,000
)
 
—

Additions to long-term debt
—

 
145,000

Payments on long-term debt
(7,544
)
 
(117,101
)
Net cash used in financing activities
(33,077
)
 
(17,983
)
Net increase (decrease) in cash and cash equivalents
48,869

 
(27,348
)
Cash and cash equivalents, beginning of period
214,961

 
224,499

Cash and cash equivalents, end of period
$
263,830

 
$
197,151

Supplemental cash flow information:
 
 
 
Cash paid for interest, net of capitalized interest
$
35,660

 
$
57,906

Cash paid (refunds received) for income tax
$
17,853

 
$
(6,740
)
Supplemental disclosure of non-cash activity:
 
 
 
Capital expenditures included in accounts payable and accrued liabilities
$
—

 
$
32,522


The accompanying notes are an integral part of these consolidated financial statements.
4

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
(1)
Basis of Presentation
As used in this report, unless otherwise specified, the terms “Alon,” “we,” “us” or “our” refer to Alon USA Energy, Inc. and its consolidated subsidiaries or to Alon USA Energy, Inc. or an individual subsidiary. The “Partnership,” as used in this report, refers to Alon USA Partners, LP and its consolidated subsidiaries.
These consolidated financial statements and notes are unaudited and have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements.
In the opinion of our management, the information included in these consolidated financial statements reflects all adjustments, consisting of normal and recurring adjustments, which are necessary for a fair presentation of our consolidated financial position and results of operations for the interim periods presented. All significant intercompany balances and transactions have been eliminated in consolidation. Certain prior year balances may have been aggregated or disaggregated in order to conform to the current year presentation. Our results of operations for the three and six months ended June 30, 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 standard allows for either full retrospective adoption or modified retrospective adoption. In July 2015, the FASB voted to approve a one-year deferral of the effective date for the new revenue standard, making the requirements of the standard effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We are evaluating the guidance to determine the method of adoption and the impact this standard will have 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 certain costs 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 currently have debt issuance costs included as deferred charges in our consolidated balance sheets, which will be reclassified as a reduction of debt when we adopt the updated guidance.
In April 2015, the FASB issued an accounting standards update that provides a practical expedient for the measurement date of entities’ defined benefit pension or other postretirement plans. For an entity with a fiscal year-end that does not coincide with a month-end, the guidance allows the entity to measure the defined benefit plan assets and obligations using the month-end that is closest to the entity’s fiscal year-end. For an entity that has a significant event in an interim period that calls for a remeasurement, the guidance allows an entity to remeasure the defined benefit plan assets and obligations using the month-end that is closest to the date of the significant event. The requirements from the updated standard are effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. The adoption of this guidance will not have a material effect on our financial position or results of operations.

5
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


In July 2015, the FASB issued an accounting standards update simplifying the measurement of certain inventory. This updated standard simplifies the measurement of inventory by requiring certain inventory to be measured at the lower of cost or net realizable value. The amendments in this accounting standards update are effective for interim and annual periods beginning after December 15, 2016. This accounting standards update does not apply to the subsequent measurement of inventory measured using the last-in, first-out (“LIFO”) or retail inventory method, therefore the adoption of this guidance will not have a material effect on our financial position or results of operations.
(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 June 30, 2015, the 11,510,039 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.
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.
During the six months ended June 30, 2015, the Partnership paid the following cash distributions:
Date Paid
 
Distribution Amount Per Unit
 
Total Distribution Amount
 
Distribution Paid to Non-Affiliated Common Unitholders
March 2, 2015
 
$
0.70

 
$
43,755

 
$
8,055

May 26, 2015
 
0.71

 
44,380

 
8,169

(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 six months ended June 30, 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 640 Alon branded retail sites, including our retail segment convenience stores. During 2015, approximately 56% of the gasoline and 23% 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.

6
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


(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 294 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.
Segment data as of and for the three and six month periods ended June 30, 2015 and 2014 are presented below:
 
Refining and
Marketing
 
Asphalt
 
Retail
 
Corporate
 
Consolidated
Total
Three Months Ended June 30, 2015
 
 
 
 
 
 
 
 
 
Net sales to external customers
$
1,024,807

 
$
69,900

 
$
206,634

 
$
—

 
$
1,301,341

Intersegment sales (purchases)
101,233

 
(7,925
)
 
(93,308
)
 
—

 
—

Depreciation and amortization
26,692

 
1,207

 
2,943

 
425

 
31,267

Operating income (loss)
83,581

 
(1,723
)
 
6,837

 
(601
)
 
88,094

Total assets
1,848,273

 
115,184

 
226,387

 
21,716

 
2,211,560

Turnarounds, catalysts and capital expenditures
14,500

 
238

 
6,202

 
1,392

 
22,332

 
Refining and
Marketing
 
Asphalt
 
Retail
 
Corporate
 
Consolidated
Total
Three Months Ended June 30, 2014
 
 
 
 
 
 
 
 
 
Net sales to external customers
$
1,372,547

 
$
117,677

 
$
252,659

 
$
—

 
$
1,742,883

Intersegment sales (purchases)
148,777

 
(9,233
)
 
(139,544
)
 
—

 
—

Depreciation and amortization
24,713

 
1,162

 
2,983

 
595

 
29,453

Operating income (loss)
16,765

 
(3,889
)
 
6,826

 
(770
)
 
18,932

Total assets
1,888,299

 
122,506

 
200,510

 
22,792

 
2,234,107

Turnarounds, catalysts and capital expenditures
43,081

 
1,501

 
2,841

 
494

 
47,917

 
Refining and
Marketing
 
Asphalt
 
Retail
 
Corporate
 
Consolidated
Total
Six Months Ended June 30, 2015
 
 
 
 
 
 
 
 
 
Net sales to external customers
$
1,901,410

 
$
120,552

 
$
382,619

 
$
—

 
$
2,404,581

Intersegment sales (purchases)
184,122

 
(18,856
)
 
(165,266
)
 
—

 
—

Depreciation and amortization
54,003

 
2,352

 
5,980

 
894

 
63,229

Operating income (loss)
159,228

 
(16,154
)
 
13,827

 
(1,246
)
 
155,655

Total assets
1,848,273

 
115,184

 
226,387

 
21,716

 
2,211,560

Turnarounds, catalysts and capital expenditures
21,239

 
1,644

 
9,518

 
3,013

 
35,414


7
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


 
Refining and
Marketing
 
Asphalt
 
Retail
 
Corporate
 
Consolidated
Total
Six Months Ended June 30, 2014
 
 
 
 
 
 
 
 
 
Net sales to external customers
$
2,738,373

 
$
213,848

 
$
473,907

 
$
—

 
$
3,426,128

Intersegment sales (purchases)
287,869

 
(26,216
)
 
(261,653
)
 
—

 
—

Depreciation and amortization
50,081

 
2,362

 
5,697

 
1,191

 
59,331

Operating income (loss)
56,769

 
(7,094
)
 
9,759

 
(1,542
)
 
57,892

Total assets
1,888,299

 
122,506

 
200,510

 
22,792

 
2,234,107

Turnarounds, catalysts and capital expenditures
70,124

 
3,219

 
6,222

 
1,359

 
80,924

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.

8
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 June 30, 2015 and December 31, 2014:
 
Level 1
 
Level 2
 
Level 3
 
Total
As of June 30, 2015
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts (swaps)
$
—

 
$
38,797

 
$
—

 
$
38,797

Fair value hedges
—

 
20,113

 
—

 
20,113

Liabilities:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
18

 
—

 
—

 
18

Interest rate swaps
—

 
1,967

 
—

 
1,967

 
 
 
 
 
 
 
 
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, which we refer to as futures and forwards. Futures represent trades executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period. 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.
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 June 30, 2015, these swap contracts had aggregate volumes of 17,230 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 678 thousand barrels of crude oil as of June 30, 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

9
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 June 30, 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 June 30, 2015, these commodity swap contracts were accounted for as economic hedges, as mentioned above. As of June 30, 2015, unrealized gains of $24,010 were classified in other comprehensive income (“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 and six months ended June 30, 2015, we reclassified gains of $9,955 and $17,937, respectively, from OCI into cost of sales related to these de-designated cash flow hedges. During the three and six months ended June 30, 2014, we reclassified losses of $2,153 and $10,428, respectively, 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 OCI, we recognized unrealized gains (losses) of $(9,955) and $11,078 for the three months ended and $(11,867) and $42,935 for the six months ended June 30, 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. These 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 June 30, 2015, the outstanding principal of the term loan was $99,000. 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 interest rate swap cash flow hedges in OCI, we recognized unrealized gains (losses) of $186 and $(788) for the three months ended and $(729) and $(788) for the six months ended June 30, 2015 and 2014, respectively.
For the three and six months ended June 30, 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 June 30, 2015, we have net unrealized gains of $22,043 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 $23,602 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 June 30, 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
 
$
656

 
Accrued liabilities
 
$
674

Commodity contracts (swaps)
Accounts receivable
 
30,829

 
 
 
—

Commodity contracts (swaps)
Other assets
 
7,968

 
 
 
—

Total derivatives not designated as hedging instruments
 
 
39,453

 
 
 
674

 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Interest rate swaps
 
 
$
—

 
Other non-current liabilities
 
$
1,967

Fair value hedges
Other assets
 
20,113

 
 
 
—

Total derivatives designated as hedging instruments
 
 
20,113

 
 
 
1,967

Total derivatives
 
 
$
59,566

 
 
 
$
2,641


10
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 June 30, 2015
 
 
 
 
 
 
 
 
Commodity contracts (swaps)
 
$
(9,955
)
 
Cost of sales
 
$
9,955

 
 
 
$
—

Interest rate swaps
 
186

 
Interest expense
 
(97
)
 
 
 
—

Total derivatives
 
$
(9,769
)
 
 
 
$
9,858

 
 
 
$
—

 
 
 
 
 
 
 
 
 
 
 
For the Three Months Ended June 30, 2014
 
 
 
 
 
 
 
 
Commodity contracts (swaps)
 
$
11,078

 
Cost of sales
 
$
(2,153
)
 
 
 
$
—

Interest rate swaps
 
(788
)
 
Interest expense
 
(14
)
 
 
 
—

Total derivatives
 
$
10,290

 
 
 
$
(2,167
)
 
 
 
$
—


11
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


Cash Flow Hedging Relationships
 
Gain (Loss) Recognized
in OCI
 
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
 
Gain (Loss) Reclassified
from Accumulated OCI into
Income (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)
 
 
 
 
Location
 
Amount
 
Location
 
Amount
For the Six Months Ended June 30, 2015
 
 
 
 
 
 
 
 
Commodity contracts (swaps)
 
$
(11,867
)
 
Cost of sales
 
$
17,937

 
 
 
$
—

Interest rate swaps
 
(729
)
 
Interest expense
 
(112
)
 
 
 
—

Total derivatives
 
$
(12,596
)
 
 
 
$
17,825

 
 
 
$
—

 
 
 
 
 
 
 
 
 
 
 
For the Six Months Ended June 30, 2014
 
 
 
 
 
 
 
 
Commodity contracts (swaps)
 
$
42,935

 
Cost of sales
 
$
(10,428
)
 
 
 
$
—

Interest rate swaps
 
(788
)
 
Interest expense
 
(14
)
 
 
 
—

Total derivatives
 
$
42,147

 
 
 
$
(10,442
)
 
 
 
$
—

Derivatives in fair value hedging relationships:
 
 
 
Gain (Loss) Recognized in Income
 
 
 
For the Three Months Ended
 
For the Six Months Ended
 
 
 
June 30,
 
June 30,
 
Location
 
2015
 
2014
 
2015
 
2014
Fair value hedges (1)
Interest expense
 
$
(10,578
)
 
$
(4,444
)
 
$
(4,790
)
 
$
(7,051
)
Total derivatives
 
 
$
(10,578
)
 
$
(4,444
)
 
$
(4,790
)
 
$
(7,051
)
___________
(1)
Changes in the fair value hedges are substantially offset by changes in the hedged items.
Derivatives not designated as hedging instruments:
 
 
 
Gain (Loss) Recognized in Income
 
 
 
For the Three Months Ended
 
For the Six Months Ended
 
 
 
June 30,
 
June 30,
 
Location
 
2015
 
2014
 
2015
 
2014
Commodity contracts (futures and forwards)
Cost of sales
 
$
1,688

 
$
(5,133
)
 
$
(3,670
)
 
$
(6,118
)
Commodity contracts (swaps)
Cost of sales
 
(2,443
)
 
(236
)
 
19,418

 
1,801

Total derivatives
 
 
$
(755
)
 
$
(5,369
)
 
$
15,748

 
$
(4,317
)

12
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


Offsetting Assets and Liabilities
Our derivative 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 June 30, 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 June 30, 2015
 
 
 
 
 
 
 
 
 
 
 
Derivative Assets:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
1,175

 
$
(519
)
 
$
656

 
$
(656
)
 
$
—

 
$
—

Commodity contracts (swaps)
46,213

 
(7,416
)
 
38,797

 
—

 
—

 
38,797

Fair value hedges
20,113

 
—

 
20,113

 
—

 
—

 
20,113

Derivative Liabilities:
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
1,193

 
$
(519
)
 
$
674

 
$
(656
)
 
$
—

 
$
18

Commodity contracts (swaps)
7,416

 
(7,416
)
 
—

 
—

 
—

 
—

Interest rate swaps
1,967

 
—

 
1,967

 
—

 
—

 
1,967

 
 
 
 
 
 
 
 
 
 
 
 
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.
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 $10,394 and $4,573 for the three months ended and $23,090 and $12,354 for the six months ended June 30, 2015 and 2014, respectively. These amounts are reflected in cost of sales in the consolidated statements of operations.

13
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


(6)
Inventories
Carrying value of inventories consisted of the following:
 
June 30,
2015
 
December 31,
2014
Crude oil, refined products, asphalt and blendstocks
$
44,291

 
$
48,027

Crude oil consignment inventory (Note 7)
18,861

 
18,350

Materials and supplies
25,316

 
22,269

Store merchandise
22,868

 
27,418

Store fuel
6,031

 
6,739

Total inventories
$
117,367

 
$
122,803

The market value of refined products, asphalt and blendstock inventories exceeded LIFO costs by $9,533 and $7,713 at June 30, 2015 and December 31, 2014, respectively. The market value of crude oil inventories exceeded LIFO costs, net of the fair value hedged items, by $24,994 and $17,754 at June 30, 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 June 30, 2015 and December 31, 2014, we had net current payables to J. Aron for purchases of $36,963 and $46,303, respectively, and a consignment inventory receivable representing a deposit paid to J. Aron of $26,179 and $26,179, respectively. At June 30, 2015 and December 31, 2014, we had non-current liabilities for the original financing of $39,236 and $39,060, respectively, net of the related fair value hedges.
Additionally, we had net current payables of $602 and $4,212 at June 30, 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.

14
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


(8)
Property, Plant and Equipment, Net
Property, plant and equipment, net consisted of the following:
 
June 30,
2015
 
December 31,
2014
Refining facilities
$
1,839,394

 
$
1,820,565

Pipelines and terminals
43,439

 
43,439

Retail
208,825

 
200,354

Other
20,959

 
17,988

Property, plant and equipment, gross
2,112,617

 
2,082,346

Accumulated depreciation
(760,418
)
 
(710,002
)
Property, plant and equipment, net
$
1,352,199

 
$
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 six months ended June 30, 2014, a pre-tax gain of $2,014 was recognized and has been included in gain (loss) 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
 
June 30,
2015
 
December 31,
2014
Deferred turnaround and catalyst cost
$
53,280

 
$
60,753

Environmental receivables (Note 16)
2,655

 
3,030

Deferred debt issuance costs
10,702

 
10,569

Intangible assets, net
7,376

 
7,647

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

 
26,179

Commodity contracts
7,968

 
11,622

Fair value hedges (Note 7)
20,113

 
24,903

Other, net
22,516

 
18,176

Total other assets
$
150,789

 
$
162,879


15
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
 
June 30,
2015
 
December 31,
2014
Accrued Liabilities:
 
 
 
Taxes other than income taxes, primarily excise taxes
$
34,967

 
$
47,071

Employee costs
14,883

 
13,297

Commodity contracts
674

 
7,501

Accrued finance charges
1,840

 
1,826

Environmental accrual (Note 16)
8,189

 
8,189

Other
40,482

 
26,507

Total accrued liabilities
$
101,035

 
$
104,391

 
 
 
 
Other Non-Current Liabilities:
 
 
 
Pension and other postemployment benefit liabilities, net
$
53,129

 
$
52,135

Environmental accrual (Note 16)
39,931

 
43,546

Asset retirement obligations
12,599

 
12,328

Consignment inventory obligations (Note 7)
59,349

 
63,963

Interest rate swaps
1,967

 
1,238

Other
7,944

 
9,449

Total other non-current liabilities
$
174,919

 
$
182,659

(10)
Postretirement Benefits
The components of net periodic benefit cost related to our benefit plans for the three and six months ended June 30, 2015 and 2014 consisted of the following:
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
Components of net periodic benefit cost:
 
 
 
 
 
 
 
Service cost
$
997

 
$
856

 
$
1,993

 
$
1,712

Interest cost
1,255

 
1,238

 
2,511

 
2,476

Expected return on plan assets
(1,583
)
 
(1,369
)
 
(3,165
)
 
(2,739
)
Amortization of net loss
840

 
595

 
1,679

 
1,191

Net periodic benefit cost
$
1,509

 
$
1,320

 
$
3,018

 
$
2,640

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 six months ended June 30, 2015 and 2014, we contributed $2,175 and $2,525, respectively, to our qualified pension plans.
(11)
Indebtedness
Debt consisted of the following:
 
June 30,
2015
 
December 31,
2014
Term loan credit facilities
$
260,817

 
$
264,359

Alon USA, LP Credit Facility
40,000

 
60,000

Convertible senior notes
129,074

 
126,298

Retail credit facilities
109,322

 
113,030

Total debt
539,213

 
563,687

Less: Current portion
15,086

 
15,089

Total long-term debt
$
524,127

 
$
548,598


16
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 $44,227 and $54,227 at June 30, 2015 and December 31, 2014, respectively.
We had borrowings of $40,000 and $60,000 and letters of credit of $43,463 and $23,511 outstanding under the Alon USA, LP $240,000 revolving credit facility at June 30, 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. Borrowings under the Alon USA, LP $240,000 revolving credit facility now bear interest at the Eurodollar rate plus 3.00% per annum.
(b) Convertible Senior Notes
The conversion rate for our 3.00% unsecured convertible senior notes (“Convertible 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 June 30, 2015, the conversion rate was adjusted to 69.482 shares of our common stock per each $1 (in thousands) principal amount of Convertible Notes, equivalent to a conversion price of approximately $14.39 per share, to reflect cash dividend adjustments. The strike price of the options was adjusted to $14.39 per share and the strike price of the warrants was adjusted to $19.55 per share. Upon a potential change of control, we may have to settle the value of the warrants in accordance with the indenture. 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 governing the Convertible Notes. As of June 30, 2015, there have been no conversions of the Convertible Notes.
In May 2015, Delek US Holdings, Inc. (“Delek”) acquired approximately 48% of our common stock from Alon Israel Oil Company, Ltd. Delek agreed to a one year standstill provision limiting Delek’s ability to acquire greater than 49.99% of our outstanding common stock, with additional ownership above this threshold subject to the approval of Alon’s independent directors. If Delek were to acquire greater than 50.00% of our outstanding common stock, it could require us to render a make-whole payment to holders of our Convertible Notes of approximately $15,000 as of June 30, 2015, assuming full conversion of the Convertible Notes. In the event of a conversion, the convertible note options will cover our obligation to render payment under the make-whole provision. Under these circumstances, we could also be required to settle the outstanding warrants, which had a value of approximately $50,000 as of June 30, 2015.
(c) Financial Covenants
We have certain credit agreements that contain maintenance financial covenants. At June 30, 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. Non-employee directors, and non-employee directors of Alon's subsidiaries who are designated by Alon's directors, are awarded an annual grant of $25 in shares of restricted stock, which vest over a period of three years, assuming continued service at vesting. In May 2015, Alon granted awards of 6,028 restricted shares at a grant date price of $16.59 per share.
In May 2015, Alon granted awards of 255,000 restricted shares to certain executive officers at a grant date price of $16.59 per share. These May 2015 restricted shares will fully vest in May 2016, assuming continued service at vesting.

17
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


The following table summarizes the restricted share activity from January 1, 2015:
 
 
 
 
Weighted
Average
Grant Date
Fair Values
Nonvested Shares
 
Shares
 
(per share)
Nonvested at January 1, 2015
 
643,999

 
$
14.24

Granted
 
261,028

 
16.59

Vested
 
(134,290
)
 
14.97

Forfeited
 
—

 
—

Nonvested at June 30, 2015
 
770,737

 
$
14.91

Compensation expense for restricted stock awards amounted to $1,515 and $1,000 for the three months ended June 30, 2015 and 2014, respectively, and $2,314 and $1,488 for the six months ended June 30, 2015 and 2014, respectively. These amounts are included in selling, general and administrative expenses in the consolidated statements of operations. The fair value of shares vested in 2015 was $2,257.
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 $0 and $374 for the three months ended June 30, 2015 and 2014, respectively, and $249 and $748 for the six months ended June 30, 2015 and 2014, respectively. These amounts are included in selling, general and administrative expenses in the consolidated statements of operations.
Unrecognized Compensation Cost. As of June 30, 2015, there was $6,282 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 1.2 years.
(13)
Equity (share values in dollars)
Changes to equity during the six months ended June 30, 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 loss
 
(7,674
)
 
(261
)
 
(7,935
)
Stock compensation
 
1,424

 
(1,002
)
 
422

Dividends of common stock on preferred stock
 
(4
)
 
—

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

 
(16,224
)
 
(16,224
)
Dividends
 
(17,384
)
 
(260
)
 
(17,644
)
Net income
 
63,349

 
18,568

 
81,917

Balance at June 30, 2015
 
$
676,609

 
$
37,701

 
$
714,310

(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 six months ended June 30, 2015, 329,644 shares of our common stock were issued in exchange for 1,762.24 shares of Alon Assets. At June 30, 2015, 930,778 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 $699 and $608 for the three months ended June 30, 2015 and 2014, respectively, $1,183 and $1,305 for the six months ended June 30, 2015 and 2014, respectively. These amounts are included in selling, general and administrative expenses in the consolidated statements of operations.

18
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


(b)
Preferred Stock
Preferred Stock Conversion. During the six months ended June 30, 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. During the six months ended June 30, 2015, we paid the following dividends:
Date Paid
 
Record Date
 
Dividend Amount Per Share
March 16, 2015
 
February 26, 2015
 
$
0.10

June 5, 2015
 
May 19, 2015
 
0.15

Preferred Stock Dividends. During the six months ended June 30, 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
3,368

 
—

 
3,368

Amounts reclassified from accumulated other comprehensive loss
(11,042
)
 
—

 
(11,042
)
Net current-period other comprehensive loss
(7,674
)
 
—

 
(7,674
)
Balance at June 30, 2015
$
13,656

 
$
(29,788
)
 
$
(16,132
)
(14)
Earnings (Loss) Per Share
Basic earnings (loss) per share is calculated as net income (loss) available to common stockholders divided by the average number of participating shares of common stock outstanding. Diluted earnings (loss) per share includes the dilutive effect of granted stock appreciation rights, granted restricted common stock units, granted restricted common stock awards, convertible debt and warrants using the treasury stock method and the dilutive effect of convertible preferred shares using the if-converted method.
The calculation of earnings (loss) per share, basic and diluted, for the three and six months ended June 30, 2015 and 2014, is as follows (shares in thousands, per share value in dollars):
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
Net income (loss) available to stockholders
$
36,410

 
$
(7,517
)
 
$
63,349

 
$
(6,732
)
Less: preferred stock dividends
—

 
14

 
15

 
29

Net income (loss) available to common stockholders
36,410

 
(7,531
)
 
63,334

 
(6,761
)
 
 
 
 
 
 
 
 
Weighted average shares outstanding, basic
69,684

 
68,851

 
69,584

 
68,734

Dilutive common stock equivalents
2,817

 
—

 
2,811

 
—

Weighted average shares outstanding, diluted
72,501

 
68,851

 
72,395

 
68,734

Earnings (loss) per share, basic
$
0.52

 
$
(0.11
)
 
$
0.91

 
$
(0.10
)
Earnings (loss) per share, diluted
$
0.50

 
$
(0.11
)
 
$
0.87

 
$
(0.10
)
For the three and six months ended June 30, 2015, the weighted average diluted shares includes all potentially dilutive common stock equivalents. For the three and six months ended June 30, 2014, we have excluded 200 and 195 common stock equivalents, respectively, from the weighted average diluted shares outstanding as the effect of including such shares would be anti-dilutive.

19
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


(15)
Related Party Transactions
Delek US Holdings, Inc.
In May 2015, Delek completed the purchase of approximately 48% of our common stock from Alon Israel Oil Company, Ltd. From the transaction date through June 30, 2015, we purchased $1,944 of refined products from Delek. Accounts payable includes a balance outstanding to Delek of $997 at June 30, 2015.
(16)
Commitments and Contingencies
(a)
Commitments
In the normal course of business, we have long-term commitments to purchase, at market prices, utilities such as natural gas, electricity and water for use by our refineries, terminals, pipelines and retail locations. We are also party to various refined product and crude oil supply and exchange agreements, which are typically short-term in nature or provide terms for cancellation.
(b)
Contingencies
We are involved in various legal actions arising in the ordinary course of business. We believe the ultimate disposition of these matters will not have a material effect on our financial position, results of operations or liquidity.
One of our subsidiaries is a party to a lawsuit alleging breach of contract pertaining to an asphalt supply agreement. We believe that we have valid counterclaims as well as affirmative defenses that will preclude recovery. Attempts to reach a 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 $48,120 ($8,189 current liability and $39,931 non-current liability) at June 30, 2015, and $51,735 ($8,189 current liability and $43,546 non-current liability) at December 31, 2014.
We have an indemnification agreement with a prior owner for part of the remediation expenses at certain West Coast assets. We have recorded current receivables of $784 and $784 and non-current receivables of $2,655 and $3,030 at June 30, 2015 and December 31, 2014, respectively.
We have an indemnification agreement with a prior owner for remediation expenses at the Bakersfield refinery. We have recorded current receivables of $3,350 at December 31, 2014.
(17)
Subsequent Events
Dividend Declared
On July 30, 2015, our board of directors declared the regular quarterly cash dividend of $0.15 per share on our common stock, payable on September 24, 2015, to holders of record at the close of business on September 8, 2015.

20
ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


Partnership Distribution
On July 31, 2015, the board of directors of the General Partner declared a cash distribution to the Partnership’s common unitholders of approximately $65,010, or $1.04 per common unit. The cash distribution will be paid on August 25, 2015 to unitholders of record at the close of business on August 18, 2015. The total cash distribution payable to non-affiliated common unitholders will be approximately $11,970.

21

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;
•
changes in the ownership of our common stock by Delek US Holdings, Inc., which may trigger change of control provisions contained in the agreements and instruments governing our convertible senior notes and the related purchased options and warrant transactions;
•
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;

22

•
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;
•
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 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 294 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 640 Alon branded retail sites, including our retail segment convenience stores. During 2015, approximately 56% of the gasoline and 23% 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,

23

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.
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.
Second Quarter Operational and Financial Highlights
Operating income for the second quarter of 2015 was $88.1 million, compared to $18.9 million in the same period last year. Our operational and financial highlights for the second quarter of 2015 include the following:
•
Combined refinery average throughput for the second quarter of 2015 was 152,092 bpd, compared to a combined refinery average throughput of 114,869 bpd for the second quarter of 2014. The Big Spring refinery average throughput for the second quarter of 2015 was 75,491 bpd, compared to 38,994 bpd for the second quarter of 2014. The Krotz Springs refinery average throughput for the second quarter of 2015 was 76,601 bpd, compared to 75,875 bpd for the second quarter of 2014. During the second quarter of 2014, refinery throughput at the Big Spring refinery was reduced as we completed both the planned turnaround and the vacuum tower project.
•
Refinery operating margin at the Big Spring refinery was $17.22 per barrel for the second quarter of 2015 compared to $17.04 per barrel for the same period in 2014. This increase in operating margin was primarily due to improved light product yields, partially offset by the industry margin environment. The contango environment in the second quarter of 2015 created a cost of crude benefit of $1.90 per barrel compared to the backwardated environment creating a cost of crude detriment of $0.93 per barrel for the same period in 2014 (“second quarter 2015 Contango Benefit”).
•
Refinery operating margin at the Krotz Springs refinery was $7.95 per barrel for the second quarter of 2015 compared to $8.89 per barrel for the same period in 2014. This decrease was primarily due to a lower Gulf Coast 2/1/1 high sulfur diesel crack spread and a narrowing WTI Cushing to WTI Midland spread, partially offset by a widening LLS to WTI Cushing spread and the second quarter 2015 Contango Benefit.
•
The average Gulf Coast 3/2/1 crack spread was $19.71 per barrel for the second quarter of 2015 compared to $16.42 per barrel for the second quarter of 2014. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the second quarter of 2015 was $10.21 per barrel compared to $12.47 per barrel for the second quarter of 2014.
•
The average WTI Cushing to WTS spread for the second quarter of 2015 was $(0.21) per barrel compared to $7.88 per barrel for the same period in 2014. The average WTI Cushing to WTI Midland spread for the second quarter of 2015 was $0.60 per barrel compared to $8.37 per barrel for the same period in 2014. The average LLS to WTI Cushing spread for the second quarter of 2015 was $6.28 per barrel compared to $2.89 per barrel for the same period in 2014.
•
Asphalt margins in the second quarter of 2015 were $100.92 per ton compared to $67.64 per ton in the second quarter of 2014. This increase was primarily due to lower costs of asphalt purchased during the second quarter of 2015 compared to 2014.
•
Retail fuel margins increased to 20.3 cents per gallon in the second quarter of 2015 from 19.4 cents per gallon in the second quarter of 2014. Retail fuel sales volume increased to 49.5 million gallons in the second quarter of 2015 from 48.8 million gallons in the second quarter of 2014. Merchandise margins increased to 31.8% in the second quarter of 2015 from 30.7% in the second quarter of 2014. Merchandise sales increased to $84.9 million in the second quarter of 2015 from $83.2 million in the second quarter of 2014.

24

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 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.
Recently, the additional takeaway capacity moving crude from Midland to the Gulf Coast has caused a contraction of the WTI Cushing less WTI Midland spread. In addition, the relative small growth in WTS production compared to WTI production and the relative high demand for WTS has caused a contraction of the WTI Cushing less WTS spread.
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.

25

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 last-in, first-out (“LIFO”) inventory valuation methodology, price fluctuations generally have little effect on our financial results.
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 and six months ended June 30, 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 the three months ended June 30, 2014, we completed both the planned turnaround and the vacuum tower project at the Big Spring refinery, which increased our distillate yield, improved energy efficiency and allowed us to better optimize our crude slate. Due to these events, refinery throughput was reduced at the Big Spring refinery during the three and six months ended June 30, 2014.
Certain Derivative Impacts
Included in the consolidated statements of operations in cost of sales for the three and six months ended June 30, 2015 are realized and unrealized gains (losses) on commodity swaps of $7.5 million and $37.4 million, respectively, and $(2.4) million and $(8.6) million for the three and six months ended June 30, 2014, 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 2015 compared to 2014 was lower because crude oil prices moved from backwardation into contango.

26

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.

27

ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED
Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for Alon and our three operating segments for the three and six months ended June 30, 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
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
 
(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
 
 
Net sales (1)
$
1,301,341

 
$
1,742,883

 
$
2,404,581

 
$
3,426,128

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales
1,069,931

 
1,580,447

 
1,964,419

 
3,086,992

Direct operating expenses
62,856

 
67,630

 
127,061

 
138,308

Selling, general and administrative expenses (2)
49,193

 
46,333

 
94,789

 
85,722

Depreciation and amortization (3)
31,267

 
29,453

 
63,229

 
59,331

Total operating costs and expenses
1,213,247

 
1,723,863

 
2,249,498

 
3,370,353

Gain (loss) on disposition of assets
—

 
(88
)
 
572

 
2,117

Operating income
88,094

 
18,932

 
155,655

 
57,892

Interest expense
(18,217
)
 
(29,256
)
 
(39,254
)
 
(57,271
)
Equity earnings of investees
1,828

 
1,278

 
1,274

 
819

Other income, net
13

 
638

 
59

 
621

Income (loss) before income tax expense (benefit)
71,718

 
(8,408
)
 
117,734

 
2,061

Income tax expense (benefit)
23,856

 
(1,971
)
 
35,817

 
123

Net income (loss)
47,862

 
(6,437
)
 
81,917

 
1,938

Net income attributable to non-controlling interest
11,452

 
1,080

 
18,568

 
8,670

Net income (loss) available to stockholders
$
36,410

 
$
(7,517
)
 
$
63,349

 
$
(6,732
)
Earnings (loss) per share, basic
$
0.52

 
$
(0.11
)
 
$
0.91

 
$
(0.10
)
Weighted average shares outstanding, basic (in thousands)
69,684

 
68,851

 
69,584

 
68,734

Earnings (loss) per share, diluted
$
0.50

 
$
(0.11
)
 
$
0.87

 
$
(0.10
)
Weighted average shares outstanding, diluted (in thousands)
72,501

 
68,851

 
72,395

 
68,734

Cash dividends per share
$
0.15

 
$
0.06

 
$
0.25

 
$
0.12

CASH FLOW DATA:
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
Operating activities
$
135,112

 
$
(31,072
)
 
$
115,891

 
$
31,642

Investing activities
(22,332
)
 
(47,403
)
 
(33,945
)
 
(41,007
)
Financing activities
(39,415
)
 
(79,666
)
 
(33,077
)
 
(17,983
)
OTHER DATA:
 
 
 
 
 
 
 
Adjusted EBITDA (4)
$
121,202

 
$
50,389

 
$
219,645

 
$
116,546

Capital expenditures (5)
20,302

 
36,495

 
31,051

 
54,655

Capital expenditures for turnarounds and catalysts
2,030

 
11,422

 
4,363

 
26,269



28

 
June 30,
2015
 
December 31,
2014
BALANCE SHEET DATA (end of period):
(dollars in thousands)
Cash and cash equivalents
$
263,830

 
$
214,961

Working capital
153,960

 
126,665

Total assets
2,211,560

 
2,200,874

Total debt
539,213

 
563,687

Total debt less cash and cash equivalents
275,383

 
348,726

Total equity
714,310

 
673,778

(1)
Includes excise taxes on sales by the retail segment of $19,369 and $19,101 for the three months ended June 30, 2015 and 2014, respectively, and $37,425 and $36,911 for the six months ended June 30, 2015 and 2014, respectively.
(2)
Includes corporate headquarters selling, general and administrative expenses of $176 and $175 for the three months ended June 30, 2015 and 2014, respectively, and $352 and $350 for the six months ended June 30, 2015 and 2014, respectively, which are not allocated to our three operating segments.
(3)
Includes corporate depreciation and amortization of $425 and $595 for the three months ended June 30, 2015 and 2014, respectively, and $894 and $1,191 for the six months ended June 30, 2015 and 2014, respectively, which are not allocated to our three operating segments.
(4)
Adjusted EBITDA represents earnings (loss) before net income attributable to non-controlling interest, income tax expense (benefit), interest expense, depreciation and amortization and (gain) loss on disposition of assets. Adjusted EBITDA is not a recognized measurement under GAAP; however, the amounts included in Adjusted EBITDA are derived from amounts included in our consolidated financial statements. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors, and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of net income attributable to non-controlling interest, income tax expense (benefit), interest expense, (gain) loss on disposition of assets and the accounting effects of capital expenditures and acquisitions, items that may vary for different companies for reasons unrelated to overall operating performance.
Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:
•
Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
•
Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;
•
Adjusted EBITDA does not reflect the prior claim that non-controlling interest have on the income generated by non-wholly-owned subsidiaries;
•
Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and
•
Our calculation of Adjusted EBITDA may differ from EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.
Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.

29

The following table reconciles net income (loss) available to stockholders to Adjusted EBITDA for the three and six months ended June 30, 2015 and 2014:
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
 
(dollars in thousands)
Net income (loss) available to stockholders
$
36,410

 
$
(7,517
)
 
$
63,349

 
$
(6,732
)
Net income attributable to non-controlling interest
11,452

 
1,080

 
18,568

 
8,670

Income tax expense (benefit)
23,856

 
(1,971
)
 
35,817

 
123

Interest expense
18,217

 
29,256

 
39,254

 
57,271

Depreciation and amortization
31,267

 
29,453

 
63,229

 
59,331

(Gain) loss on disposition of assets
—

 
88

 
(572
)
 
(2,117
)
Adjusted EBITDA
$
121,202

 
$
50,389

 
$
219,645

 
$
116,546

Adjusted EBITDA does not exclude unrealized (gains) losses on commodity swaps of $10,478 and $2,904 for the three months ended June 30, 2015 and 2014, respectively, and $(7,925) and $9,510 for the six months ended June 30, 2015 and 2014, respectively, which are included in net income (loss) available to stockholders. Additionally, Adjusted EBITDA does not exclude a loss of $3,284 and $13,950 for the three and six months ended June 30, 2015, respectively, resulting from a price adjustment related to asphalt inventory.
(5)
Includes corporate capital expenditures of $1,392 and $494 for the three months ended June 30, 2015 and 2014, respectively, and $3,013 and $1,359 for the six months ended June 30, 2015 and 2014, respectively, which are not allocated to our three operating segments.

30

REFINING AND MARKETING SEGMENT
 
 
 
 
 
 
 
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
 
(dollars in thousands, except per barrel data and pricing statistics)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
 
 
Net sales (1)
$
1,126,040

 
$
1,521,324

 
$
2,085,532

 
$
3,026,242

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales
940,861

 
1,403,843

 
1,724,252

 
2,772,057

Direct operating expenses
55,966

 
57,478

 
112,292

 
118,276

Selling, general and administrative expenses
18,940

 
18,466

 
36,279

 
29,000

Depreciation and amortization
26,692

 
24,713

 
54,003

 
50,081

Total operating costs and expenses
1,042,459

 
1,504,500

 
1,926,826

 
2,969,414

Gain (loss) on disposition of assets
—

 
(59
)
 
522

 
(59
)
Operating income
$
83,581

 
$
16,765

 
$
159,228

 
$
56,769

KEY OPERATING STATISTICS:
 
 
 
 
 
 
 
Per barrel of throughput:
 
 
 
 
 
 
 
Refinery operating margin – Big Spring (2)
$
17.22

 
$
17.04

 
$
15.56

 
$
15.56

Refinery operating margin – Krotz Springs (2)
7.95

 
8.89

 
8.71

 
8.22

Refinery direct operating expense – Big Spring (3)
3.54

 
7.09

 
3.56

 
5.33

Refinery direct operating expense – Krotz Springs (3)
3.49

 
3.70

 
3.64

 
4.09

Capital expenditures
$
12,470

 
$
31,659

 
$
16,876

 
$
43,855

Capital expenditures for turnarounds and catalysts
2,030

 
11,422

 
4,363

 
26,269

PRICING STATISTICS:
 
 
 
 
 
 
 
Crack spreads (3/2/1) (per barrel):
 
 
 
 
 
 
 
Gulf Coast
$
19.71

 
$
16.42

 
$
18.73

 
$
16.61

Crack spreads (2/1/1) (per barrel):
 
 
 
 
 
 
 
Gulf Coast high sulfur diesel
$
10.21

 
$
12.47

 
$
11.79

 
$
11.62

WTI Cushing crude oil (per barrel)
$
57.86

 
$
103.04

 
$
53.20

 
$
100.86

Crude oil differentials (per barrel):
 
 
 
 
 
 
 
WTI Cushing less WTI Midland
$
0.60

 
$
8.37

 
$
1.27

 
$
5.96

WTI Cushing less WTS
(0.21
)
 
7.88

 
0.76

 
5.79

LLS less WTI Cushing
6.28

 
2.89

 
4.48

 
4.42

Brent less LLS
0.32

 
4.67

 
0.57

 
5.81

Brent less WTI Cushing
3.66

 
7.22

 
4.54

 
8.83

Product price (dollars per gallon):
 
 
 
 
 
 
 
Gulf Coast unleaded gasoline
$
1.86

 
$
2.81

 
$
1.69

 
$
2.73

Gulf Coast ultra-low sulfur diesel
1.83

 
2.92

 
1.76

 
2.93

Gulf Coast high sulfur diesel
1.68

 
2.83

 
1.62

 
2.83

Natural gas (per MMBtu)
2.74

 
4.58

 
2.77

 
4.65


31

THROUGHPUT AND PRODUCTION DATA:
BIG SPRING REFINERY
For the Three Months Ended
 
For the Six Months Ended
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
WTS crude
29,605

 
39.2

 
12,634

 
32.4

 
37,193

 
50.3

 
23,927

 
42.7

WTI crude
43,659

 
57.8

 
23,391

 
60.0

 
33,952

 
45.9

 
29,652

 
52.9

Blendstocks
2,227

 
3.0

 
2,969

 
7.6

 
2,789

 
3.8

 
2,471

 
4.4

Total refinery throughput (4)
75,491

 
100.0

 
38,994

 
100.0

 
73,934

 
100.0

 
56,050

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
37,755

 
49.8

 
17,484

 
45.1

 
36,978

 
49.8

 
26,835

 
48.0

Diesel/jet
28,052

 
37.0

 
12,315

 
31.8

 
27,074

 
36.5

 
18,461

 
33.0

Asphalt
2,479

 
3.3

 
1,660

 
4.3

 
2,876

 
3.9

 
2,529

 
4.5

Petrochemicals
4,915

 
6.5

 
1,825

 
4.7

 
4,863

 
6.5

 
3,111

 
5.5

Other
2,537

 
3.4

 
5,483

 
14.1

 
2,466

 
3.3

 
5,022

 
9.0

Total refinery production (5)
75,738

 
100.0

 
38,767

 
100.0

 
74,257

 
100.0

 
55,958

 
100.0

Refinery utilization (6)
 
 
100.4
%
 
 
 
85.4
%
 
 
 
97.5
%
 
 
 
95.7
%
THROUGHPUT AND PRODUCTION DATA:
KROTZ SPRINGS REFINERY
For the Three Months Ended
 
For the Six Months Ended
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
WTI crude
29,429

 
38.4

 
29,737

 
39.2

 
29,888

 
40.0

 
26,904

 
39.0

Gulf Coast sweet crude
45,069

 
58.8

 
46,138

 
60.8

 
41,076

 
55.0

 
40,953

 
59.3

Blendstocks
2,103

 
2.8

 
—

 
—

 
3,781

 
5.0

 
1,152

 
1.7

Total refinery throughput (4)
76,601

 
100.0

 
75,875

 
100.0

 
74,745

 
100.0

 
69,009

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
35,511

 
45.4

 
33,909

 
43.7

 
35,021

 
45.8

 
32,407

 
46.0

Diesel/jet
32,496

 
41.5

 
33,665

 
43.4

 
31,599

 
41.4

 
29,791

 
42.3

Heavy Oils
1,378

 
1.8

 
1,362

 
1.8

 
1,356

 
1.8

 
980

 
1.4

Other
8,838

 
11.3

 
8,616

 
11.1

 
8,419

 
11.0

 
7,225

 
10.3

Total refinery production (5)
78,223

 
100.0

 
77,552

 
100.0

 
76,395

 
100.0

 
70,403

 
100.0

Refinery utilization (6)
 
 
100.7
%
 
 
 
102.5
%
 
 
 
95.9
%
 
 
 
91.7
%

32

(1)
Net sales include intersegment sales to our asphalt and retail segments at prices which approximate wholesale market prices. These intersegment sales are eliminated through consolidation of our financial statements.
(2)
Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales (exclusive of substantial hedge positions and certain inventory adjustments) attributable to each refinery by the refinery’s throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margins to these crack spreads to assess our operating performance relative to other participants in our industry.
The refinery operating margin for the three and six months ended June 30, 2015 excludes realized and unrealized gains on commodity swaps of $7,512 and $37,355, respectively. For the six months ended June 30, 2015, $8,926 related substantially to inventory adjustments was not included in cost of sales of either the Big Spring refinery or Krotz Springs refinery.
The refinery operating margin for the three and six months ended June 30, 2014 excludes realized and unrealized losses on commodity swaps of $2,389 and $8,627, respectively.
(3)
Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses at our refineries by the applicable refinery’s total throughput volumes.
(4)
Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.
(5)
Total refinery production represents the barrels per day of various products produced from processing crude and other refinery feedstocks through the crude units and other conversion units at the refineries.
(6)
Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.

33

ASPHALT SEGMENT
 
 
 
 
 
 
 
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
 
(dollars in thousands, except per ton data)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
 
 
Net sales (1)
$
69,900

 
$
117,677

 
$
120,552

 
$
213,848

Operating costs and expenses:
 
 
 
 

 

Cost of sales (1)(2)
60,771

 
107,801

 
115,054

 
195,535

Direct operating expenses
6,890

 
10,152

 
14,769

 
20,032

Selling, general and administrative expenses
2,755

 
2,299

 
4,531

 
5,027

Depreciation and amortization
1,207

 
1,162

 
2,352

 
2,362

Total operating costs and expenses
71,623

 
121,414

 
136,706

 
222,956

Gain (loss) on disposition of assets
—


(152
)

—


2,014

Operating loss (5)
$
(1,723
)
 
$
(3,889
)
 
$
(16,154
)
 
$
(7,094
)
KEY OPERATING STATISTICS:
 
 
 
 
 
 
 
Blended asphalt sales volume (tons in thousands) (3)
108

 
142

 
173

 
226

Non-blended asphalt sales volume (tons in thousands) (4)
15

 
4

 
33

 
26

Blended asphalt sales price per ton (3)
$
505.54

 
$
564.75

 
$
498.83

 
$
557.86

Non-blended asphalt sales price per ton (4)
229.20

 
302.75

 
317.36

 
375.85

Asphalt margin per ton (5)
100.92

 
67.64

 
94.41

 
72.67

Capital expenditures
$
238

 
$
1,501

 
$
1,644

 
$
3,219

(1)
Net sales and cost of sales include asphalt purchases sold as part of a supply and offtake arrangement of $11,864 and $36,272 for the three months ended June 30, 2015 and 2014, respectively, and $23,782 and $78,000 for the six months ended June 30, 2015 and 2014, respectively. The volumes associated with these sales are excluded from the Key Operating Statistics.
(2)
Cost of sales includes intersegment purchases of asphalt blends from our refining and marketing segment at prices which approximate wholesale market prices. These intersegment purchases are eliminated through consolidation of our financial statements.
(3)
Blended asphalt represents base material asphalt that has been blended with other materials necessary to sell the asphalt as a finished product.
(4)
Non-blended asphalt represents base material asphalt and other components that require additional blending before being sold as a finished product.
(5)
Asphalt margin is a per ton measurement calculated by dividing the margin between net sales and cost of sales by the total sales volume. Asphalt margins are used in the asphalt industry to measure operating results related to asphalt sales.
Asphalt margin for the three and six months ended June 30, 2015 excludes a loss of $3,284 and $13,950, respectively, resulting from a price adjustment related to asphalt inventory. This loss is included in operating loss above.

34

RETAIL SEGMENT
 
 
 
 
 
 
 
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2015

2014
 
2015
 
2014
 
(dollars in thousands, except per gallon data)
STATEMENTS OF OPERATIONS DATA:
 
 
 
 
 
 
 
Net sales (1)
$
206,634

 
$
252,659

 
$
382,619


$
473,907

Operating costs and expenses:
 
 
 
 



Cost of sales (2)
169,532

 
217,580

 
309,235


407,269

Selling, general and administrative expenses
27,322

 
25,393

 
53,627


51,345

Depreciation and amortization
2,943

 
2,983

 
5,980


5,697

Total operating costs and expenses
199,797

 
245,956

 
368,842

 
464,311

Gain on disposition of assets
—

 
123

 
50


163

Operating income
$
6,837

 
$
6,826

 
$
13,827

 
$
9,759

KEY OPERATING STATISTICS:
 
 
 
 
 
 
 
Number of stores (end of period) (3)
294

 
296

 
294

 
296

Retail fuel sales (thousands of gallons)
49,511

 
48,767

 
95,606

 
94,283

Retail fuel sales (thousands of gallons per site per month)(3)
58

 
57

 
56

 
55

Retail fuel margin (cents per gallon) (4)
20.3

 
19.4

 
21.9

 
18.9

Retail fuel sales price (dollars per gallon) (5)
$
2.46

 
$
3.47

 
$
2.32

 
$
3.36

Merchandise sales
$
84,878

 
$
83,182

 
$
160,980

 
$
156,517

Merchandise sales (per site per month) (3)
$
96

 
$
94

 
$
91

 
$
88

Merchandise margin (6)
31.8
%
 
30.7
%
 
32.5
%
 
31.1
%
Capital expenditures
$
6,202

 
$
2,841

 
$
9,518

 
$
6,222

(1)
Includes excise taxes on sales of $19,369 and $19,101 for the three months ended June 30, 2015 and 2014, respectively, and $37,425 and $36,911 for the six months ended June 30, 2015 and 2014, respectively.
(2)
Cost of sales includes intersegment purchases of motor fuels from our refining and marketing segment at prices which approximate wholesale market prices. These intersegment purchases are eliminated through consolidation of our financial statements.
(3)
At June 30, 2015, we had 294 retail convenience stores of which 283 sold fuel. At June 30, 2014, we had 296 retail convenience stores of which 285 sold fuel.
(4)
Retail fuel margin represents the difference between retail fuel sales revenue and the net cost of purchased retail fuel, including transportation costs and associated excise taxes, expressed on a cents-per-gallon basis. Retail fuel margins are frequently used in the retail industry to measure operating results related to retail fuel sales.
(5)
Retail fuel sales price per gallon represents the average sales price for retail fuels sold through our retail convenience stores.
(6)
Merchandise margin represents the difference between merchandise sales revenues and the delivered cost of merchandise purchases, net of rebates and commissions, expressed as a percentage of merchandise sales revenues. Merchandise margins, also referred to as in-store margins, are commonly used in the retail industry to measure in-store, or non-fuel, operating results.

35

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014
Net Sales
Consolidated. Net sales for the three months ended June 30, 2015 were $1,301.3 million, compared to $1,742.9 million for the three months ended June 30, 2014, a decrease of $441.6 million. This decrease was primarily due to lower refined product prices, partially offset by higher refinery throughput.
Refining and Marketing Segment. Net sales for our refining and marketing segment were $1,126.0 million for the three months ended June 30, 2015, compared to $1,521.3 million for the three months ended June 30, 2014, a decrease of $395.3 million. This decrease was primarily due to lower refined product prices, partially offset by higher refinery throughput.
Refined product prices decreased during the three months ended June 30, 2015, compared to the three months ended June 30, 2014. The average per gallon price of Gulf Coast gasoline for the three months ended June 30, 2015 decreased $0.95, or 33.8%, to $1.86, compared to $2.81 for the three months ended June 30, 2014. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the three months ended June 30, 2015 decreased $1.09, or 37.3%, to $1.83, compared to $2.92 for the three months ended June 30, 2014. The average per gallon price for Gulf Coast high sulfur diesel for the three months ended June 30, 2015 decreased $1.15, or 40.6%, to $1.68, compared to $2.83 for the three months ended June 30, 2014.
Combined refinery average throughput for the three months ended June 30, 2015 was 152,092 bpd, consisting of 75,491 bpd at the Big Spring refinery and 76,601 bpd at the Krotz Springs refinery, compared to a combined refinery average throughput of 114,869 bpd for the three months ended June 30, 2014, consisting of 38,994 bpd at the Big Spring refinery and 75,875 bpd at the Krotz Springs refinery. During the three months ended June 30, 2014, refinery throughput at the Big Spring refinery was reduced as we completed both the planned turnaround and the vacuum tower project.
Asphalt Segment. Net sales for our asphalt segment were $69.9 million for the three months ended June 30, 2015, compared to $117.7 million for the three months ended June 30, 2014, a decrease of $47.8 million, or 40.6%. This decrease was primarily due to lower asphalt sales volumes and lower asphalt sales as part of a supply and offtake arrangement of $24.4 million. The asphalt sales volume decreased 15.8% to 123 thousand tons for the three months ended June 30, 2015 from 146 thousand tons for the three months ended June 30, 2014.
Retail Segment. Net sales for our retail segment were $206.6 million for the three months ended June 30, 2015, compared to $252.7 million for the three months ended June 30, 2014, a decrease of $46.1 million, or 18.2%. This decrease was primarily due to a decrease in retail fuel sales prices, partially offset by an increase in retail fuel sales volumes and merchandise sales. The retail fuel sales price decreased 29.1% to $2.46 per gallon for the three months ended June 30, 2015 from $3.47 per gallon for the three months ended June 30, 2014.
Cost of Sales
Consolidated. Cost of sales for the three months ended June 30, 2015 were $1,069.9 million, compared to $1,580.4 million for the three months ended June 30, 2014, a decrease of $510.5 million. This decrease was primarily due to lower crude oil prices, lower asphalt sales volumes and lower retail fuel costs, partially offset by higher refinery throughput for the three months ended June 30, 2015.
Refining and Marketing Segment. Cost of sales for our refining and marketing segment were $940.9 million for the three months ended June 30, 2015, compared to $1,403.8 million for the three months ended June 30, 2014, a decrease of $462.9 million. This decrease was primarily due to lower crude oil prices, partially offset by higher refinery throughput for the three months ended June 30, 2015. The average price of WTI Cushing decreased 43.8% to $57.86 per barrel for the three months ended June 30, 2015, compared to $103.04 per barrel for the three months ended June 30, 2014.
Asphalt Segment. Cost of sales for our asphalt segment were $60.8 million for the three months ended June 30, 2015, compared to $107.8 million for the three months ended June 30, 2014, a decrease of $47.0 million, or 43.6%. This decrease was primarily due to lower asphalt sales volumes, lower asphalt purchases as part of a supply and offtake arrangement of $24.4 million and lower costs of asphalt purchased during the three months ended June 30, 2015, compared to the three months ended June 30, 2014.
Retail Segment. Cost of sales for our retail segment were $169.5 million for the three months ended June 30, 2015, compared to $217.6 million for the three months ended June 30, 2014, a decrease of $48.1 million, or 22.1%. This decrease was primarily due to lower retail fuel costs.

36

Direct Operating Expenses
Consolidated. Direct operating expenses were $62.9 million for the three months ended June 30, 2015, compared to $67.6 million for the three months ended June 30, 2014, a decrease of $4.7 million, or 7.0%.
Refining and Marketing Segment. Direct operating expenses for our refining and marketing segment for the three months ended June 30, 2015 were $56.0 million, compared to $57.5 million for the three months ended June 30, 2014, a decrease of $1.5 million, or 2.6%. This decrease was primarily due to lower maintenance and utility costs, partially offset by higher throughput during the three months ended June 30, 2015.
Asphalt Segment. Direct operating expenses for our asphalt segment for the three months ended June 30, 2015 were $6.9 million, compared to $10.2 million for the three months ended June 30, 2014, a decrease of $3.3 million, or 32.4%. This decrease was primarily due to lower utility costs and employee related costs during the three months ended June 30, 2015.
Selling, General and Administrative Expenses
Consolidated. SG&A expenses for the three months ended June 30, 2015 were $49.2 million, compared to $46.3 million for the three months ended June 30, 2014, an increase of $2.9 million, or 6.3%. This increase was primarily due to increased employee incentive costs during the three months ended June 30, 2015.
Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the three months ended June 30, 2015 were $18.9 million, compared to $18.5 million for the three months ended June 30, 2014, an increase of $0.4 million, or 2.2%.
Asphalt Segment. SG&A expenses for our asphalt segment for the three months ended June 30, 2015 were $2.8 million, compared to $2.3 million for the three months ended June 30, 2014, an increase of $0.5 million.
Retail Segment. SG&A expenses for our retail segment for the three months ended June 30, 2015 were $27.3 million, compared to $25.4 million for the three months ended June 30, 2014, an increase of $1.9 million.
Depreciation and Amortization
Depreciation and amortization for the three months ended June 30, 2015 was $31.3 million, compared to $29.5 million for the three months ended June 30, 2014, an increase of $1.8 million, or 6.1%. This increase was primarily due to increased amortization of turnaround and catalyst replacement costs during the three months ended June 30, 2015 resulting from the completion of the planned turnaround at the Big Spring refinery during the second quarter of 2014.
Operating Income
Consolidated. Operating income for the three months ended June 30, 2015 was $88.1 million, compared to $18.9 million for the three months ended June 30, 2014, an increase of $69.2 million. This increase was primarily due to higher refinery throughput, increased refinery operating margins and the impacts of commodity swaps.
Refining and Marketing Segment. Operating income for our refining and marketing segment was $83.6 million for the three months ended June 30, 2015, compared to $16.8 million for the three months ended June 30, 2014, an increase of $66.8 million. This increase was primarily due to higher refinery throughput at the Big Spring refinery and the impacts of commodity swaps. We had realized and unrealized gains (losses) on commodity swaps of $7.5 million and $(2.4) million for the three months ended June 30, 2015 and 2014, respectively.
Refinery operating margin at the Big Spring refinery was $17.22 per barrel for the three months ended June 30, 2015, compared to $17.04 per barrel for the three months ended June 30, 2014. This increase in operating margin was primarily due to improved light product yields, partially offset by the industry margin environment. The contraction in the WTI Cushing to WTI Midland and the WTI Cushing to WTS spreads was greater than the improvement in the Gulf Coast 3/2/1 spread and the cost of crude benefit from the market moving from backwardation into contango. The average Gulf Coast 3/2/1 crack spread increased to $19.71 per barrel for the three months ended June 30, 2015, compared to $16.42 per barrel for the three months ended June 30, 2014. The average WTI Cushing to WTS spread narrowed to $(0.21) per barrel for the three months ended June 30, 2015, compared to $7.88 per barrel for the three months ended June 30, 2014. The average WTI Cushing to WTI Midland spread narrowed to $0.60 per barrel for the three months ended June 30, 2015, compared to $8.37 per barrel for the three months ended June 30, 2014. The contango environment in the three months ended June 30, 2015 created a cost of crude benefit of $1.90 per barrel compared to the backwardated environment creating a cost of crude detriment of $0.93 per barrel for the three months ended June 30, 2014 (“second quarter 2015 Contango Benefit”).

37

Refinery operating margin at the Krotz Springs refinery was $7.95 per barrel for the three months ended June 30, 2015, compared to $8.89 per barrel for the three months ended June 30, 2014. This decrease was primarily due to a lower Gulf Coast 2/1/1 high sulfur diesel crack spread and a narrowing of the WTI Cushing to WTI Midland spread, partially offset by a widening LLS to WTI Cushing spread and the second quarter 2015 Contango Benefit during the three months ended June 30, 2015. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the three months ended June 30, 2015 was $10.21 per barrel, compared to $12.47 per barrel for the three months ended June 30, 2014. The average LLS to WTI Cushing spread widened $3.39 per barrel to $6.28 per barrel for the three months ended June 30, 2015, compared to $2.89 per barrel for the three months ended June 30, 2014.
Asphalt Segment. Operating loss for our asphalt segment was $1.7 million for the three months ended June 30, 2015, compared to $3.9 million for the three months ended June 30, 2014, a decrease in loss of $2.2 million. This decrease was primarily due to higher asphalt margins and lower direct operating expenses, partially offset by lower sales volumes during the three months ended June 30, 2015. The asphalt margin was $100.92 per ton for the three months ended June 30, 2015, compared to $67.64 per ton for the three months ended June 30, 2014.
Retail Segment. Operating income for our retail marketing segment was $6.8 million for the three months ended June 30, 2015, compared to $6.8 million for the three months ended June 30, 2014.
Interest Expense
Interest expense was $18.2 million for the three months ended June 30, 2015, compared to $29.3 million for the three months ended June 30, 2014, a decrease of $11.1 million, or 37.9%. 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. The decrease in interest expense for the three months ended June 30, 2015 was due to crude oil prices moving from backwardation in 2014 into contango in 2015.
Income Tax Expense (Benefit)
Income tax expense was $23.9 million for the three months ended June 30, 2015, compared to income tax benefit of $2.0 million for the three months ended June 30, 2014. Income tax expense increased as a result of operating at a pre-tax income during the three months ended June 30, 2015, compared to operating at a pre-tax loss during the three months ended June 30, 2014.
Net Income Attributable to Non-controlling Interest
Net income attributable to non-controlling interest includes the proportional share of the Partnership’s income attributable to the limited partner interests held by the public. Additionally, net income attributable to non-controlling interests includes the proportional share of net income related to non-voting common stock of our subsidiary, Alon Assets, Inc., owned by non-controlling interest shareholders. Net income attributable to non-controlling interest was $11.5 million for the three months ended June 30, 2015, compared to $1.1 million for the three months ended June 30, 2014, an increase of $10.4 million.
Net Income (Loss) Available to Stockholders
Net income available to stockholders was $36.4 million for the three months ended June 30, 2015, compared to net loss of $7.5 million for the three months ended June 30, 2014, an increase of $43.9 million. This increase was attributable to the factors discussed above.
Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014
Net Sales
Consolidated. Net sales for the six months ended June 30, 2015 were $2,404.6 million, compared to $3,426.1 million for the six months ended June 30, 2014, a decrease of $1,021.5 million. This decrease was primarily due to lower refined product prices, partially offset by higher refinery throughput.
Refining and Marketing Segment. Net sales for our refining and marketing segment were $2,085.5 million for the six months ended June 30, 2015, compared to $3,026.2 million for the six months ended June 30, 2014, a decrease of $940.7 million. This decrease was primarily due to lower refined product prices, partially offset by higher refinery throughput.

38

Refined product prices decreased during the six months ended June 30, 2015 compared to the six months ended June 30, 2014. The average per gallon price of Gulf Coast gasoline for the six months ended June 30, 2015 decreased $1.04, or 38.1%, to $1.69, compared to $2.73 for the six months ended June 30, 2014. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the six months ended June 30, 2015 decreased $1.17, or 39.9%, to $1.76, compared to $2.93 for the six months ended June 30, 2014. The average per gallon price of Gulf Coast high sulfur diesel for the six months ended June 30, 2015 decreased $1.21, or 42.8%, to $1.62, compared to $2.83 for the six months ended June 30, 2014.
Combined refinery average throughput for the six months ended June 30, 2015 was 148,679 bpd, consisting of 73,934 bpd at the Big Spring refinery and 74,745 bpd at the Krotz Springs refinery, compared to a combined refinery average throughput of 125,059 bpd for the six months ended June 30, 2014, consisting of 56,050 bpd at the Big Spring refinery and 69,009 bpd at the Krotz Springs refinery. During the six months ended June 30, 2014, refinery throughput at the Big Spring refinery was reduced as we completed both the planned turnaround and the vacuum tower project.
Asphalt Segment. Net sales for our asphalt segment were $120.6 million for the six months ended June 30, 2015, compared to $213.8 million for the six months ended June 30, 2014, a decrease of $93.2 million, or 43.6%. This decrease was primarily due to lower asphalt sales as part of a supply and offtake arrangement of $54.2 million, decreased asphalt sales volumes and lower blended asphalt sales prices. The asphalt sales volume decreased 18.3% to 206 thousand tons for the six months ended June 30, 2015 from 252 thousand tons for the six months ended June 30, 2014. The average blended asphalt sales price decreased 10.6% to $498.83 per ton for the six months ended June 30, 2015 from $557.86 per ton for the six months ended June 30, 2014.
Retail Segment. Net sales for our retail segment were $382.6 million for the six months ended June 30, 2015, compared to $473.9 million for the six months ended June 30, 2014, a decrease of $91.3 million, or 19.3%. This decrease was primarily due to lower retail fuel sales prices, partially offset by retail fuel sales volumes and higher merchandise sales. The retail fuel sales price decreased 31.0% to $2.32 per gallon for the six months ended June 30, 2015 from $3.36 per gallon for the six months ended June 30, 2014.
Cost of Sales
Consolidated. Cost of sales for the six months ended June 30, 2015 were $1,964.4 million, compared to $3,087.0 million for the six months ended June 30, 2014, a decrease of $1,122.6 million, or 36.4%. This decrease was primarily due to lower crude oil prices, lower asphalt sales volumes and lower retail fuel costs, partially offset by higher refinery throughput for the six months ended June 30, 2015.
Refining and Marketing Segment. Cost of sales for our refining and marketing segment were $1,724.3 million for the six months ended June 30, 2015, compared to $2,772.1 million for the six months ended June 30, 2014, a decrease of $1,047.8 million, or 37.8%. This decrease was primarily due to lower crude oil prices, partially offset by higher refinery throughput for the six months ended June 30, 2015. The average price of WTI Cushing decreased 47.3% to $53.20 per barrel for the six months ended June 30, 2015 from $100.86 per barrel for the six months ended June 30, 2014.
Asphalt Segment. Cost of sales for our asphalt segment were $115.1 million for the six months ended June 30, 2015, compared to $195.5 million for the six months ended June 30, 2014, a decrease of $80.4 million, or 41.1%. This decrease was primarily due to decreased asphalt sales volumes, lower asphalt purchases as part of a supply and offtake arrangement of $54.2 million and lower costs of asphalt purchased during the six months ended June 30, 2015, compared to the six months ended June 30, 2014.
Retail Segment. Cost of sales for our retail segment were $309.2 million for the six months ended June 30, 2015, compared to $407.3 million for the six months ended June 30, 2014, a decrease of $98.1 million, or 24.1%. This decrease was primarily due to lower retail fuel costs, partially offset by increased retail fuel sales volumes during the six months ended June 30, 2015, compared to the six months ended June 30, 2014.
Direct Operating Expenses
Consolidated. Direct operating expenses were $127.1 million for the six months ended June 30, 2015, compared to $138.3 million for the six months ended June 30, 2014, a decrease of $11.2 million, or 8.1%.
Refining and Marketing Segment. Direct operating expenses for our refining and marketing segment for the six months ended June 30, 2015 were $112.3 million, compared to $118.3 million for the six months ended June 30, 2014, a decrease of $6.0 million, or 5.1%. This decrease was primarily due to lower maintenance and utility costs during the six months ended June 30, 2015.
Asphalt Segment. Direct operating expenses for our asphalt segment for the six months ended June 30, 2015 were $14.8 million, compared to $20.0 million for the six months ended June 30, 2014, a decrease of $5.2 million, or 26.0%. This decrease was primarily due to lower utility and employee related costs during the six months ended June 30, 2015.

39

Selling, General and Administrative Expenses
Consolidated. SG&A expenses for the six months ended June 30, 2015 were $94.8 million, compared to $85.7 million for the six months ended June 30, 2014, an increase of $9.1 million, or 10.6%. This increase was primarily due to higher employee related costs for the six months ended June 30, 2015.
Refining and Marketing Segment. SG&A expenses for our refining and marketing segment for the six months ended June 30, 2015 were $36.3 million, compared to $29.0 million for the six months ended June 30, 2014, an increase of $7.3 million, or 25.2%. This increase was primarily due to higher employee related costs for the six months ended June 30, 2015.
Asphalt Segment. SG&A expenses for our asphalt segment for the six months ended June 30, 2015 were $4.5 million, compared to $5.0 million for the six months ended June 30, 2014, a decrease of $0.5 million, or 10.0%.
Retail Segment. SG&A expenses for our retail segment for the six months ended June 30, 2015 were $53.6 million, compared to $51.3 million for the six months ended June 30, 2014, an increase of $2.3 million, or 4.5%.
Depreciation and Amortization
Depreciation and amortization for the six months ended June 30, 2015 was $63.2 million, compared to $59.3 million for the six months ended June 30, 2014, an increase of $3.9 million, or 6.6%. This increase was primarily due to increased amortization of turnaround and catalyst replacement costs during the six months ended June 30, 2015 resulting from the completion of the planned turnaround at the Big Spring refinery during the second quarter of 2014.
Operating Income
Consolidated. Operating income for the six months ended June 30, 2015 was $155.7 million, compared to $57.9 million for the six months ended June 30, 2014, an increase of $97.8 million. This increase was primarily due to increased refinery throughput, higher retail fuel and merchandise margins, increased refinery operating margin at the Krotz Springs refinery and the impacts of commodity swaps, partially offset by a loss of $14.0 million resulting from a price adjustment related to asphalt inventory.
Refining and Marketing Segment. Operating income for our refining and marketing segment was $159.2 million for the six months ended June 30, 2015, compared to $56.8 million for the six months ended June 30, 2014, an increase of $102.4 million. This increase was primarily due to increased refinery throughput and increased refinery operating margin at the Krotz Springs refinery and the impact of commodity swaps. We had realized and unrealized gains (losses) on commodity swaps of $37.4 million and $(8.6) million for the six months ended June 30, 2015 and 2014, respectively.
Refinery operating margin at the Big Spring refinery was $15.56 per barrel for the six months ended June 30, 2015, compared to $15.56 per barrel for the six months ended June 30, 2014. The operating margin at the Big Spring refinery was flat relative to the same period last year primarily due to improved light product yields being offset by the industry margin environment. The contraction in the WTI Cushing to WTI Midland and the WTI Cushing to WTS spreads was greater than the improvement in the Gulf Coast 3/2/1 spread and the cost of crude benefit from the market moving from backwardation into contango. The average Gulf Coast 3/2/1 crack spread increased to $18.73 per barrel for the six months ended June 30, 2015, compared to $16.61 per barrel for the six months ended June 30, 2014. The average WTI Cushing to WTS spread narrowed to $0.76 per barrel for the six months ended June 30, 2015, compared to $5.79 per barrel for the six months ended June 30, 2014. The average WTI Cushing to WTI Midland spread narrowed to $1.27 per barrel for the six months ended June 30, 2015, compared to $5.96 per barrel for the six months ended June 30, 2014. The contango environment in the six months ended June 30, 2015 created a cost of crude benefit of $1.28 per barrel compared to the backwardated environment creating a cost of crude detriment of $0.53 per barrel for the six months ended June 30, 2014 (“first half 2015 Contango Benefit”).
Refinery operating margin at the Krotz Springs refinery was $8.71 per barrel for the six months ended June 30, 2015, compared to $8.22 per barrel for the six months ended June 30, 2014. This increase in operating margin was primarily due to a higher Gulf Coast 2/1/1 high sulfur diesel crack spread, a widening of the LLS to WTI Cushing spread and the first half 2015 Contango Benefit, partially offset by a narrowing of the WTI Cushing to WTI Midland spread during the six months ended June 30, 2015. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the six months ended June 30, 2015 was $11.79 per barrel, compared to $11.62 per barrel for the six months ended June 30, 2014. The average LLS to WTI Cushing spread widened to $4.48 per barrel for the six months ended June 30, 2015, compared to $4.42 per barrel for the six months ended June 30, 2014.
Asphalt Segment. Operating loss for our asphalt segment was $16.2 million for the six months ended June 30, 2015, compared to $7.1 million for the six months ended June 30, 2014, an increase in loss of $9.1 million. This increase was primarily due to lower sales volumes and a loss of $14.0 million resulting from a price adjustment related to asphalt inventory, partially offset by higher asphalt margins for the six months ended June 30, 2015. Asphalt margins for the six months ended

40

June 30, 2015 were $94.41 per ton compared to $72.67 per ton for the six months ended June 30, 2014. Operating loss for the six months ended June 30, 2014 included the gain on the sale of our Willbridge, Oregon asphalt terminal of $2.0 million.
Retail Segment. Operating income for our retail segment was $13.8 million for the six months ended June 30, 2015, compared to $9.8 million for the six months ended June 30, 2014, an increase of $4.0 million. This increase was primarily due to higher retail fuel margins and higher merchandise margins.
Interest Expense
Interest expense was $39.3 million for the six months ended June 30, 2015, compared to $57.3 million for the six months ended June 30, 2014, a decrease of $18.0 million, or 31.4%. 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. The decrease in interest expense for the six months ended June 30, 2015 was due to crude oil prices moving from backwardation in 2014 into contango in 2015.
Income Tax Expense
Income tax expense was $35.8 million for the six months ended June 30, 2015, compared to $0.1 million for the six months ended June 30, 2014. Income tax expense increased as a result of our higher pre-tax income for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 and an increase in the effective tax rate. Our effective tax rate was 30.4% for the six months ended June 30, 2015, compared to an effective tax rate of 6.0% for the six months ended June 30, 2014. The higher effective tax rate, as compared to the statutory rate, was due to the impact of the non-controlling interest’s share of Partnership income.
Net Income Attributable to Non-controlling Interest
Net income attributable to non-controlling interest includes the proportional share of the Partnership’s income attributable to the limited partner interests held by the public. Additionally, net income attributable to non-controlling interest includes the proportional share of net income related to non-voting common stock of our subsidiary, Alon Assets, Inc., owned by non-controlling interest shareholders. Net income attributable to non-controlling interest was $18.6 million for the six months ended June 30, 2015, compared to $8.7 million for the six months ended June 30, 2014, an increase of $9.9 million.
Net Income (Loss) Available to Stockholders
Net income available to stockholders was $63.3 million for the six months ended June 30, 2015, compared to net loss available to stockholders of $6.7 million for the six months ended June 30, 2014, an increase of $70.0 million. This increase was attributable to the factors discussed above.
Liquidity and Capital Resources
Our primary sources of liquidity are cash on hand, cash generated from our operating activities, borrowings under our revolving credit facilities, inventory supply and offtake arrangements, other sources of credit and advances from affiliates.
We have agreements with J. Aron for the supply of crude oil that supports the operations of all our refineries as well as most of our asphalt terminals. These agreements substantially reduce our physical inventories and our associated need to issue letters of credit to support crude oil and asphalt purchases. In addition, the structure allows us to acquire crude oil and asphalt without the constraints of a maximum facility size during periods of high crude oil prices.
We believe that the aforementioned sources of funds and other sources of capital available to us will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next twelve months. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive and other factors beyond our control.
Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or equity securities, or other possible capital markets transactions, the proceeds of which could be used to refinance current indebtedness, extend or replace existing revolving credit facilities or for other corporate purposes.

41

Cash Flows
The following table sets forth our consolidated cash flows for the six months ended June 30, 2015 and 2014:
 
For the Six Months Ended
 
June 30,
 
2015
 
2014
 
(dollars in thousands)
Cash provided by (used in):
 
 
 
Operating activities
$
115,891

 
$
31,642

Investing activities
(33,945
)
 
(41,007
)
Financing activities
(33,077
)
 
(17,983
)
Net increase (decrease) in cash and cash equivalents
$
48,869

 
$
(27,348
)
Cash Flows Provided By Operating Activities
Net cash provided by operating activities was $115.9 million during the six months ended June 30, 2015, compared to $31.6 million during the six months ended June 30, 2014. The increase in operating cash flows of $84.3 million was primarily attributable to increased net income after adjusting for non-cash items of $59.1 million, reduced cash used for accounts payable and accrued liabilities of $38.1 million, reduced cash used for inventories of $47.2 million and increased cash provided by prepaid expenses and other current assets of $12.6 million. These changes were partially offset by reduced cash collected on receivables of $57.9 million, increased cash used for other non-current liabilities of $14.4 million and increased cash used for other assets of $0.4 million.
Cash Flows Used In Investing Activities
Net cash used in investing activities was $33.9 million during the six months ended June 30, 2015, compared to $41.0 million during the six months ended June 30, 2014. The change in investing cash flows of $7.1 million was primarily attributable to reduced cash used for capital expenditures and capital expenditures for turnarounds and catalysts of $45.5 million, partially offset by reduced cash proceeds from the disposition of assets of $38.9 million. The decrease in capital expenditures and capital expenditures for turnarounds and catalysts is related to the planned turnaround and the vacuum tower project at our Big Spring refinery during the second quarter of 2014. The decrease in cash proceeds from the disposition of assets is related to the sale of the Willbridge, Oregon asphalt terminal in 2014 for $40.0 million.
Cash Flows Used In Financing Activities
Net cash used in financing activities was $33.1 million during the six months ended June 30, 2015, compared to $18.0 million during the six months ended June 30, 2014. The increase in cash flows used in financing activities of $15.1 million was primarily attributable to reduced proceeds from long term debt of $145.0 million and increased payments to shareholders and non-controlling interests of $15.2 million, partially offset by reduced payments on long-term debt of $89.6 million and increased proceeds from inventory transactions of $55.3 million during the six months ended June 30, 2015.
Indebtedness
Alon USA Energy, Inc. Letter of Credit Facility. We have an unsecured credit facility for the issuance of standby letters of credit in an amount not to exceed $60.0 million. At June 30, 2015 and December 31, 2014, we had letters of credit outstanding under this facility of $44.2 million and $54.2 million, respectively.
Alon USA, LP Revolving Credit Facility. We have a $240.0 million revolving credit facility that can be used both for borrowings and the issuance of letters of credit. We had borrowings of $40.0 million and $60.0 million and letters of credit outstanding of $43.5 million and $23.5 million under this facility at June 30, 2015 and December 31, 2014, respectively.
In May 2015, the $240.0 million revolving credit facility was amended to, among other matters, extend the expiration date to May 2019. Borrowings under this facility now bear interest at the Eurodollar rate plus 3.00% per annum.

42

Convertible Senior Notes. The conversion rate for our 3.00% unsecured convertible senior notes (“Convertible 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 June 30, 2015, the conversion rate was adjusted to 69.482 shares of our common stock per each $1 (in thousands) principal amount of Convertible Notes, equivalent to a conversion price of approximately $14.39 per share, to reflect cash dividend adjustments. The strike price of the options was adjusted to $14.39 per share and the warrants were adjusted to $19.55 per share. Upon a potential change of control, we may have to settle the value of the warrants in accordance with the indenture. 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 governing the Convertible Notes. The Convertible 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 June 30, 2015, there have been no conversions of the Convertible Notes.
Capital Spending
Each year our board of directors approves capital projects, including sustaining maintenance, regulatory and planned turnaround and catalyst projects that our management is authorized to undertake in our annual capital budget. Additionally, our management assesses opportunities for growth and profit improvement projects on an ongoing basis and any related projects require further approval from our board of directors. Our total capital expenditure projection for 2015 is $148.0 million, which includes expenditures for catalysts and turnarounds and approximately $16.7 million of special regulatory projects. Approximately $35.4 million has been spent during the six months ended June 30, 2015.
Contractual Obligations and Commercial Commitments
There have been no material changes outside the ordinary course of business from our contractual obligations and commercial commitments detailed in our Annual Report on Form 10-K for the year ended December 31, 2014.
Off-Balance Sheet Arrangements
We have no material off-balance sheet arrangements.
Critical Accounting Policies
We prepare our consolidated financial statements in conformity with GAAP. In order to apply these principles, we must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events, some of which we may have little or no control over.
Our critical accounting policies are described under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2014. Certain critical accounting policies that materially affect the amounts recorded in our consolidated financial statements are the use of the LIFO method for valuing certain inventories and the deferral and subsequent amortization of costs associated with major turnarounds and catalysts replacements. No significant changes to these accounting policies have occurred subsequent to December 31, 2014.
New Accounting Standards and Disclosures
New accounting standards if any are disclosed in Note (1) Basis of Presentation included in the consolidated financial statements included in Item 1 of this report.

43

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Changes in commodity prices, purchased fuel prices and interest rates are our primary sources of market risk. Our risk management committee oversees all activities associated with the identification, assessment and management of our market risk exposure.
Commodity Price Risk
We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refinery operations. Our financial results can be affected significantly by fluctuations in these prices, which depend on many factors, including demand for crude oil, gasoline and other refined products, changes in the economy, worldwide production levels, worldwide inventory levels and governmental regulatory initiatives. Our risk management strategy identifies circumstances in which we may utilize the commodity futures market to manage risk associated with these price fluctuations.
In order to manage the uncertainty relating to inventory price volatility, we have consistently applied a policy of maintaining inventories at or below a targeted operating level. In the past, circumstances have occurred, such as timing of crude oil cargo deliveries, turnaround schedules or shifts in market demand that have resulted in variances between our actual inventory level and our desired target level. Upon the review and approval of our risk management committee, we may utilize the commodity futures market to manage these anticipated inventory variances.
We maintain inventories of crude oil, refined products, asphalt and blendstocks, the values of which are subject to wide fluctuations in market prices driven by world economic conditions, regional and global inventory levels and seasonal conditions. At June 30, 2015, the market value of refined products, asphalt and blendstock inventories exceeded LIFO costs by $9.5 million. At June 30, 2015, the market value of crude oil inventories exceeded LIFO costs, net of the fair value hedged items, by $25.0 million.
As of June 30, 2015, we held 0.5 million barrels of refined products, asphalt and blendstock and 1.0 million barrels of crude oil inventories valued under the LIFO valuation method. If the market value of refined products, asphalt and blendstock inventories would have been $1.00 per barrel lower, the amount by which market value exceeded LIFO costs would have been lower by $0.5 million. If the market value of crude oil would have been $1.00 per barrel lower, the amount by which market value exceeded LIFO costs, net of the fair value hedged items, would have been lower by $1.0 million.
All commodity derivative contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section or accumulated other comprehensive income of our consolidated financial statements. “Forwards” represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period. “Futures” represent trades which have been executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period. A “long” represents an obligation to purchase product and a “short” represents an obligation to sell product.

44

The following table provides information about our commodity derivative contracts as of June 30, 2015:
Description
 
Contract Volume
 
Wtd Avg Purchase
 
Wtd Avg Sales
 
Contract
 
Market
 
Gain
of Activity
 
(barrels)
 
Price/BBL
 
Price/BBL
 
 Value
 
Value
 
(Loss)
 
 
 
 
 
 
 
 
(in thousands)
Forwards-long (Crude)
 
204,022

 
$
60.85

 
$
—

 
$
12,415

 
$
12,340

 
$
(75
)
Forwards-short (Crude)
 
(26,536
)
 
—

 
64.80

 
(1,720
)
 
(1,735
)
 
(15
)
Forwards-long (Gasoline)
 
195,096

 
84.81

 
—

 
16,545

 
16,411

 
(134
)
Forwards-short (Gasoline)
 
(47,602
)
 
—

 
83.95

 
(3,996
)
 
(3,957
)
 
39

Forwards-long (Distillate)
 
147,956

 
71.06

 
—

 
10,513

 
11,246

 
733

Forwards-short (Distillate)
 
(156,177
)
 
—

 
78.23

 
(12,218
)
 
(12,798
)
 
(580
)
Forwards-long (Jet)
 
35,571

 
73.36

 
—

 
2,609

 
2,619

 
10

Forwards-short (Jet)
 
(90,535
)
 
—

 
72.08

 
(6,525
)
 
(6,630
)
 
(105
)
Forwards-short (Slurry)
 
(12,905
)
 
—

 
46.92

 
(606
)
 
(607
)
 
(1
)
Forwards-long (Catfeed)
 
40,869

 
78.52

 
—

 
3,209

 
3,231

 
22

Forwards-short (Catfeed)
 
(18,424
)
 
—

 
78.52

 
(1,447
)
 
(1,457
)
 
(10
)
Forwards-long (Slop)
 
4,104

 
49.83

 
—

 
204

 
205

 
1

Forwards-short (Slop)
 
(15,359
)
 
—

 
51.52

 
(791
)
 
(791
)
 
—

Forwards-long (Propane)
 
78

 
34.83

 
—

 
3

 
3

 
—

Forwards-short (Propane)
 
(35,000
)
 
—

 
15.42

 
(540
)
 
(591
)
 
(51
)
Forwards-long (Butane)
 
68,724

 
22.02

 
—

 
1,513

 
1,642

 
129

Forwards-short (Asphalt)
 
(104,230
)
 
—

 
55.16

 
(5,749
)
 
(5,749
)
 
—

Futures-long (Crude)
 
95,000

 
59.25

 
—

 
5,629

 
5,650

 
21

Futures-short (Crude)
 
(106,000
)
 
—

 
60.98

 
(6,464
)
 
(6,304
)
 
160

Futures-long (Gasoline)
 
61,000

 
85.35

 
—

 
5,206

 
5,251

 
45

Futures-short (Gasoline)
 
(259,000
)
 
—

 
85.47

 
(22,136
)
 
(22,293
)
 
(157
)
Futures-long (Distillate)
 
166,000

 
79.45

 
—

 
13,188

 
13,176

 
(12
)
Futures-short (Distillate)
 
(22,000
)
 
—

 
77.64

 
(1,708
)
 
(1,746
)
 
(38
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Description
 
Contract Volume
 
Wtd Avg Contract
 
Wtd Avg Market
 
Contract
 
Market
 
Gain
of Activity
 
(barrels)
 
Spread
 
Spread
 
 Value
 
Value
 
(Loss)
 
 
 
 
 
 
 
 
(in thousands)
Futures-swaps (Jet-LLS)
 
(1,800,000
)
 
$
22.58

 
$
32.64

 
$
40,635

 
$
58,746

 
$
18,111

Futures-swaps (WTI-Jet)
 
1,800,000

 
15.25

 
15.30

 
27,450

 
27,543

 
93

Futures-swaps (LLS-WTI)
 
2,880,000

 
4.85

 
2.69

 
13,981

 
7,760

 
(6,221
)
Futures-swaps (Brent-WTI)
 
(4,950,000
)
 
10.52

 
5.79

 
(52,087
)
 
(28,681
)
 
23,406

Futures-swaps (WTI-Brent)
 
4,410,000

 
4.72

 
5.76

 
20,817

 
25,420

 
4,603

Futures-swaps (WTI 2.1.1 crack spread)
 
(550,000
)
 
18.82

 
19.16

 
(10,352
)
 
(10,537
)
 
(185
)
Futures-swaps (Brent 2.1.1 crack spread)
 
(840,000
)
 
14.03

 
15.23

 
(11,781
)
 
(12,791
)
 
(1,010
)
Interest Rate Risk
As of June 30, 2015, $412.1 million, excluding discounts, of our outstanding debt was subject to floating interest rates, of which $243.8 million was charged interest at the Eurodollar rate (with a floor of 1.25%) plus a margin of 8.00%.
As of June 30, 2015, we had three interest rate swap contracts, maturing March 2019, that effectively fix the variable interest component on approximately 75% of the outstanding principal of the term loan within the retail credit agreement. As of June 30, 2015, the outstanding balance of the term loan was $99.0 million and the interest rate swaps had a current fixed interest rate of 0.74%.
An increase of 1% in the variable rate on our indebtedness, after considering the instrument subject to a minimum interest rate and the interest rate swap contracts, would result in an increase to our interest expense of approximately $0.9 million per year.

45

ITEM 4. CONTROLS AND PROCEDURES
Evaluation of disclosure controls and procedures
Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosures.
Changes in internal control over financial reporting
There has been no change in our internal control over financial reporting (as described in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. We are transitioning our assessment of our internal control effectiveness over financial reporting from the criteria outlined by the 1992 framework of the Committee of Sponsoring Organizations of the Treadway Commission to its 2013 framework. We expect to complete this transition during 2015.


46

PART II. OTHER INFORMATION
ITEM 6. EXHIBITS
Exhibit
 
 
Number
 
Description of Exhibit
3.1
 
Amended and Restated Bylaws of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.1 to Form 8-K, filed by the Company on April 17, 2015, SEC File No. 001-32567).
3.2
 
Amended and Restated Bylaws of Alon USA Energy, Inc. (incorporated by reference to Exhibit 3.1 to Form 8-K, filed by the Company on May 15, 2015, SEC File No. 001-32567).
10.1
 
Second Amendment to Shareholder Agreements among Alon USA Energy, Inc., Alon Assets, Inc., Jeff Morris and Jeff Morris/IRA, dated May 12, 2015 (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on May 15, 2015, SEC File No. 001-32567).
10.2
 
Management Employment Agreement between Paul Eisman and Alon USA GP, LLC, dated May 11, 2015 (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on May 15, 2015, SEC File No. 001-32567).
10.3
 
Restricted Stock Award Agreement between Paul Eisman and Alon USA Energy, Inc., dated May 11, 2015 (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by the Company on May 15, 2015, SEC File No. 001-32567).
10.4
 
First Amendment to Employment Agreement between Alan P. Moret and Alon USA GP, LLC, dated May 12, 2015 (incorporated by reference to Exhibit 10.4 to Form 8-K, filed by the Company on May 15, 2015, SEC File No. 001-32567).
31.1
 
Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2
 
Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1
 
Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
101
 
The following financial information from Alon USA Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows and (v) Notes to the Consolidated Financial Statements.


47


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
Alon USA Energy, Inc.
 
Date:
August 4, 2015
By:  
/s/ Paul Eisman
 
 
 
Paul Eisman
 
 
 
President and Chief Executive Officer 
 
 
 
 
 
 
 
 
Date:
August 4, 2015
By:  
/s/ Shai Even
 
 
 
Shai Even 
 
 
 
Senior Vice President and Chief Financial Officer
 
 
 
(Principal Accounting Officer)


48




Exhibit 31.1
CERTIFICATIONS
I, Paul Eisman, certify that:
1.
I have reviewed this Quarterly Report on Form 10-Q of Alon USA Energy, Inc.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:
August 4, 2015
By:  
/s/ Paul Eisman
 
 
 
Paul Eisman
 
 
 
President and Chief Executive Officer 






Exhibit 31.2
CERTIFICATIONS
I, Shai Even, certify that:
1.
I have reviewed this Quarterly Report on Form 10-Q of Alon USA Energy, Inc.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:
August 4, 2015
By:  
/s/ Shai Even
 
 
 
Shai Even 
 
 
 
Senior Vice President and Chief Financial Officer







Exhibit 32.1
CERTIFICATION PURSUANT TO 18 U.S.C. §1350,
AS ADOPTED PURSUANT TO §906
OF THE SARBANES-OXLEY ACT OF 2002

In connection with the filing of the Quarterly Report on Form 10-Q of Alon USA Energy, Inc., a Delaware corporation (the “Company”), for the period ended June 30, 2015, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that, to such officer's knowledge:
1)
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Report.

Date:
August 4, 2015
By:  
/s/ Paul Eisman
 
 
 
Paul Eisman
 
 
 
President and Chief Executive Officer 
 
 
 
 
 
 
 
 
Date:
August 4, 2015
By:  
/s/ Shai Even
 
 
 
Shai Even 
 
 
 
Senior Vice President and Chief Financial Officer


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