UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
___________________________________________________
Form 10-Q
þ
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011
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.)
7616 LBJ Freeway, Suite 300, 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 November 1, 2011, was 56,017,382.

 
 

TABLE OF CONTENTS

 
 
 
 
EX-10.1 SUPPLEMENTAL AGREEMENT TO SUPPLY AND OFFTAKE AGREEMENT BETWEEN ALON REFINING KROTZ SPRINGS, INC. AND J. ARON & COMPANY
EX-10.2 SUPPLEMENTAL AGREEMENT TO SUPPLY AND OFFTAKE AGREEMENT BETWEEN ALON USA, LP AND J. ARON & COMPANY
EX-31.1 CERTIFICATION OF CEO PURSUANT TO SECTION 302
EX-31.2 CERTIFICATION OF CFO PURSUANT TO SECTION 302
EX-32.1 CERTIFICATION OF CEO AND CFO PURSUANT TO SECTION 906

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1.
FINANCIAL STATEMENTS

ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in thousands except per share data)
 
September 30,
2011
 
December 31,
2010
 
(unaudited)
 
 
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
175,601

 
$
71,687

Accounts and other receivables, net
210,850

 
115,541

Income tax receivable
8,642

 
8,642

Inventories
254,164

 
141,050

Deferred income tax asset
36,699

 
49,052

Prepaid expenses and other current assets
8,555

 
7,875

Total current assets
694,511

 
393,847

Equity method investments
20,189

 
18,664

Property, plant, and equipment, net
1,510,063

 
1,488,532

Goodwill
105,943

 
105,943

Other assets, net
89,191

 
81,535

Total assets
$
2,419,897

 
$
2,088,521

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
330,965

 
$
292,991

Accrued liabilities
139,281

 
88,354

Current portion of long-term debt
124,707

 
11,512

Total current liabilities
594,953

 
392,857

Other non-current liabilities
179,714

 
160,976

Long-term debt
929,301

 
904,793

Deferred income tax liability
298,013

 
288,128

Total liabilities
2,001,981

 
1,746,754

Commitments and contingencies (Note 14)

 

Stockholders’ equity:
 
 
 
Preferred stock, par value $0.01, 10,000,000 shares authorized; 4,000,000 issued and outstanding at September 30, 2011 and December 31, 2010, respectively
40,000

 
40,000

Common stock, par value $0.01, 100,000,000 shares authorized; 55,933,446 and 54,281,636 shares issued and outstanding at September 30, 2011 and December 31, 2010, respectively
558

 
543

Additional paid-in capital
316,953

 
290,809

Accumulated other comprehensive loss, net of income tax
(20,433
)
 
(21,917
)
Retained earnings
79,270

 
33,052

Total stockholders’ equity
416,348

 
342,487

Non-controlling interest in subsidiaries
1,568

 
(720
)
Total equity
417,916

 
341,767

Total liabilities and equity
$
2,419,897

 
$
2,088,521


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

Table of Contents

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

 
For the Three Months Ended
 
For the Nine Months Ended
 
September 30,
 
September 30,
 
2011
 
2010
 
2011
 
2010
Net sales (1)
$
2,056,653

 
$
1,248,569

 
$
5,303,388

 
$
2,668,243

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales
1,827,098

 
1,153,743

 
4,717,673

 
2,443,533

Direct operating expenses
83,338

 
68,448

 
202,476

 
192,816

Selling, general and administrative expenses
34,680

 
35,012

 
107,595

 
96,001

Depreciation and amortization
29,812

 
26,781

 
80,046

 
78,471

Total operating costs and expenses
1,974,928

 
1,283,984

 
5,107,790

 
2,810,821

Gain on disposition of assets
229

 

 
161

 
474

Operating income (loss)
81,954

 
(35,415
)
 
195,759

 
(142,104
)
Interest expense
(22,582
)
 
(24,091
)
 
(63,780
)
 
(72,411
)
Equity earnings of investees
2,005

 
3,864

 
3,775

 
4,970

Gain on bargain purchase

 
17,480

 

 
17,480

Other income (loss), net
(14,272
)
 
(494
)
 
(51,065
)
 
13,345

Income (loss) before income tax expense (benefit) and non-controlling interest in income (loss) of subsidiaries
47,105

 
(38,656
)
 
84,689

 
(178,720
)
Income tax expense (benefit)
17,004

 
(21,905
)
 
26,952

 
(73,711
)
Income (loss) before non-controlling interest in income (loss) of subsidiaries
30,101

 
(16,751
)
 
57,737

 
(105,009
)
Non-controlling interest in income (loss) of subsidiaries
1,480

 
(1,167
)
 
2,317

 
(7,224
)
Net income (loss) available to common stockholders
$
28,621

 
$
(15,584
)
 
$
55,420

 
$
(97,785
)
Income (loss) per share, basic
$
0.51

 
$
(0.29
)
 
$
1.00

 
$
(1.80
)
Weighted average shares outstanding, basic (in thousands)
55,755

 
54,181

 
55,290

 
54,177

Income (loss) per share, diluted
$
0.46

 
$
(0.29
)
 
$
0.91

 
$
(1.80
)
Weighted average shares outstanding, diluted (in thousands)
61,690

 
54,181

 
61,231

 
54,177

Cash dividends per share
$
0.04

 
$
0.04

 
$
0.12

 
$
0.12

___________________________________
(1)
Includes excise taxes on sales by the retail segment of $15,476 and $14,204 for the three months and $44,887 and $40,521 for the nine months ended September 30, 2011, and 2010, respectively.


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

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, dollars in thousands)
 
For the Nine Months Ended
 
September 30,
 
2011
 
2010
Cash flows from operating activities:
 
 
 
Net income (loss) available to common stockholders
$
55,420

 
$
(97,785
)
Adjustments to reconcile net income (loss) available to common stockholders to cash provided by (used in) operating activities:
 
 
 
Depreciation and amortization
80,046

 
78,471

Stock compensation
2,135

 
446

Deferred income tax expense
21,438

 
(73,715
)
Non-controlling interest in income (loss) of subsidiaries
2,317

 
(7,224
)
Equity earnings of investees (net of dividends)
(1,525
)
 
(2,614
)
Amortization of debt issuance costs
4,370

 
4,475

Amortization of original issuance discount
2,146

 
1,235

Write-off of unamortized debt issuance costs

 
6,659

Gain on bargain purchase

 
(17,480
)
Gain on disposition of assets
(161
)
 
(474
)
Changes in operating assets and liabilities, net of acquisition effects:
 
 
 
Accounts and other receivables, net
(95,309
)
 
(22,001
)
Income tax receivable

 
47,290

Inventories
(114,279
)
 
34,644

Prepaid expenses and other current assets
(680
)
 
(3,943
)
Other assets, net
(13,705
)
 
(30,461
)
Accounts payable
37,974

 
36,480

Accrued liabilities
57,153

 
12,989

Other non-current liabilities
21,022

 
(4,267
)
Net cash provided by (used in) operating activities
58,362

 
(37,275
)
Cash flows from investing activities:
 
 
 
Capital expenditures
(91,120
)
 
(20,526
)
Capital expenditures for turnarounds and catalysts
(6,995
)
 
(12,668
)
Proceeds from disposition of assets
547

 
20,095

Proceeds from sale of securities

 
36,852

Acquisition of Bakersfield refinery

 
(32,409
)
Earnout payment related to Krotz Springs refinery acquisition
(6,562
)
 
(6,562
)
Net cash used in investing activities
(104,130
)
 
(15,218
)
Cash flows from financing activities:
 
 
 
Dividends paid to stockholders
(6,652
)
 
(6,501
)
Dividends paid to non-controlling interest
(570
)
 
(429
)
Proceeds from issuance of common stock
11,900

 

Stock issuance costs
(537
)
 

Inventory supply agreement
1,165

 
45,807

Deferred debt issuance costs
(2,169
)
 
(2,450
)
Revolving credit facilities, net
125,053

 
(6,527
)
Additions to long-term debt
30,136

 

Payments on long-term debt
(8,644
)
 
(8,209
)
Additions to short-term debt

 
76,500

Payments on short-term debt

 
(46,500
)
Net cash provided by financing activities
149,682

 
51,691

Net increase (decrease) in cash and cash equivalents
103,914

 
(802
)
Cash and cash equivalents, beginning of period
71,687

 
40,437

Cash and cash equivalents, end of period
$
175,601

 
$
39,635

Supplemental cash flow information:
 
 
 
Cash paid for interest
$
49,784

 
$
53,717

Cash paid (received) for income tax, net of refunds
$
3,203

 
$
(46,748
)

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

Table of Contents

ALON USA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
(1)
Basis of Presentation
(a)
Basis of Presentation
The consolidated financial statements include the accounts of Alon USA Energy, Inc. and its subsidiaries (collectively, “Alon”). All significant intercompany balances and transactions have been eliminated. These consolidated financial statements of Alon 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 Alon’s 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 Alon’s consolidated financial position and results of operations for the interim periods presented. The results of operations for the interim periods are not necessarily indicative of the operating results that may be obtained for the year ending December 31, 2011.
The consolidated balance sheet as of December 31, 2010, 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 Alon’s Annual Report on Form 10-K for the year ended December 31, 2010.
(b)
New Accounting Standards
In September 2011, the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 350, Intangibles - Goodwill and Other, were amended to permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If the existence of events or circumstances leads an entity to believe that the fair value of the entity is not below its carrying amount, then performing the two-step impairment test is unnecessary. The adoption of this guidance will not affect Alon's financial position or results of operations.
In June 2011, the provisions of FASB ASC 220, Comprehensive Income, were amended to allow an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. Under either option, the entity is required to present reclassification adjustments on the face of the financial statements for items that are reclassified from other comprehensive income to net income in the statement where those components are presented. These provisions are effective for the first interim or annual period beginning after December 15, 2011, and are to be applied retrospectively, with early adoption permitted. The adoption of this guidance will not affect Alon's financial position or results of operations because these requirements only affect disclosures.
(2)
Segment Data
Alon’s revenues are derived from three operating segments: (i) refining and unbranded marketing, (ii) asphalt and (iii) retail and branded marketing. 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 Unbranded Marketing Segment
Alon’s refining and unbranded marketing segment includes sour and heavy crude oil refineries located in Big Spring, Texas; and Paramount, Bakersfield and Long Beach, California (the “California refineries”); and a light sweet crude oil refinery located in Krotz Springs, Louisiana. At these refineries, Alon refines crude oil into products including gasoline, diesel, jet fuel, petrochemicals, feedstocks, asphalts and other petroleum products, which are marketed primarily in the South Central, Southwestern and Western regions of the United States. In Bakersfield, Alon is converting intermediate products into finished products and is not refining crude oil. Finished products and blendstocks are also marketed through sales and exchanges with other major oil companies, state and federal governmental entities, unbranded wholesale distributors and various other third parties. Alon also acquires finished products through exchange agreements and third-party suppliers.
(b)
Asphalt Segment
Alon’s asphalt segment includes the Willbridge, Oregon refinery and 12 refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Oregon (Willbridge), Washington

4

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


(Richmond Beach), Arizona (Phoenix, Flagstaff and Fredonia), and Nevada (Fernley) (50% interest) as well as a 50% interest in Wright Asphalt Products Company, LLC (“Wright”) which specializes in marketing patented tire rubber modified asphalt products. Alon produces both paving and roofing grades of asphalt and, depending on the terminal, can manufacture performance-graded asphalts, emulsions and cutbacks. The operations in which Alon has a 50% interest (Fernley and Wright), are recorded under the equity method of accounting and the investments are included as part of total assets in the asphalt segment data.
(c)
Retail and Branded Marketing Segment
Alon’s retail and branded marketing segment operates 303 convenience stores located primarily in Central and West Texas and New Mexico. These convenience stores typically offer various grades of gasoline, diesel fuel, general merchandise and food and beverage products to the general public, primarily under the 7-Eleven and FINA brand names. Alon’s branded marketing business markets gasoline and diesel under the FINA brand name, primarily in the Southwestern and South Central United States, through a network of approximately 640 locations, including Alon’s convenience stores. Historically, substantially all of the motor fuel sold through Alon’s convenience stores and the majority of the motor fuels marketed in Alon’s branded business have been supplied by Alon’s 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 nine month periods ended September 30, 2011 and 2010, are presented below:
 
Refining and
Unbranded Marketing
 
Asphalt
 
Retail and Branded
Marketing
 
Corporate
 
Consolidated
Total
Three Months Ended September 30, 2011
 
 
 
 
 
 
 
 
 
Net sales to external customers
$
1,471,936

 
$
201,081

 
$
383,636

 
$

 
$
2,056,653

Intersegment sales/purchases
390,245

 
(114,492
)
 
(275,753
)
 

 

Depreciation and amortization
25,179

 
1,522

 
2,707

 
404

 
29,812

Operating income (loss)
77,380

 
(4,114
)
 
9,280

 
(592
)
 
81,954

Total assets
2,047,354

 
145,788

 
212,253

 
14,502

 
2,419,897

Turnaround, chemical catalyst and capital expenditures
17,664

 
125

 
7,777

 
329

 
25,895

 
Refining and
Unbranded Marketing
 
Asphalt
 
Retail and Branded
Marketing
 
Corporate
 
Consolidated
Total
Three Months Ended September 30, 2010
 
 
 
 
 
 
 
 
 
Net sales to external customers
$
830,478

 
$
144,610

 
$
273,481

 
$

 
$
1,248,569

Intersegment sales/purchases
226,000

 
(55,052
)
 
(170,948
)
 

 

Depreciation and amortization
21,315

 
1,716

 
3,353

 
397

 
26,781

Operating income (loss)
(52,601
)
 
8,962

 
8,809

 
(585
)
 
(35,415
)
Total assets
1,818,774

 
153,104

 
184,694

 
18,992

 
2,175,564

Turnaround, chemical catalyst and capital expenditures
5,844

 
465

 
1,322

 
1,344

 
8,975


5

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


 
Refining and
Unbranded Marketing
 
Asphalt
 
Retail and Branded
Marketing
 
Corporate
 
Consolidated
Total
Nine Months Ended September 30, 2011
 
 
 
 
 
 
 
 
 
Net sales to external customers
$
3,784,798

 
$
435,135

 
$
1,083,455

 
$

 
$
5,303,388

Intersegment sales/purchases
1,012,327

 
(232,971
)
 
(779,356
)
 

 

Depreciation and amortization
64,799

 
4,999

 
9,037

 
1,211

 
80,046

Operating income (loss)
200,523

 
(27,439
)
 
24,450

 
(1,775
)
 
195,759

Total assets
2,047,354

 
145,788

 
212,253

 
14,502

 
2,419,897

Turnaround, chemical catalyst and capital expenditures
83,114

 
1,458

 
12,271

 
1,272

 
98,115

 
Refining and
Unbranded Marketing
 
Asphalt
 
Retail and Branded
Marketing
 
Corporate
 
Consolidated
Total
Nine Months Ended September 30, 2010
 
 
 
 
 
 
 
 
 
Net sales to external customers
$
1,598,064

 
$
316,715

 
$
753,464

 
$

 
$
2,668,243

Intersegment sales/purchases
632,785

 
(158,754
)
 
(474,031
)
 

 

Depreciation and amortization
62,150

 
5,148

 
10,209

 
964

 
78,471

Operating income (loss)
(146,506
)
 
(8,754
)
 
14,684

 
(1,528
)
 
(142,104
)
Total assets
1,818,774

 
153,104

 
184,694

 
18,992

 
2,175,564

Turnaround, chemical catalyst and capital expenditures
27,902

 
991

 
2,149

 
2,152

 
33,194

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 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.
(3)
Fair Value
The carrying amounts of Alon’s 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 financial instruments are carried at fair value, which is based on quoted market prices.
Alon must 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. As required, Alon utilizes 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. Alon generally applies 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.

6

Table of Contents
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 September 30, 2011, and December 31, 2010, respectively:
 
Quoted Prices in
Active Markets
For Identical
Assets or
Liabilities
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Consolidated
Total
As of September 30, 2011
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
3,618

 
$

 
$

 
$
3,618

Liabilities:
 
 
 
 
 
 
 
Commodity contracts (swaps)

 
2,540

 

 
2,540

Commodity contracts (call options)

 
33,429

 

 
33,429

Interest rate swap

 
5,217

 

 
5,217

As of December 31, 2010
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
1,214

 
$

 
$

 
$
1,214

Liabilities:
 
 
 
 
 
 
 
Commodity contracts (swaps)

 
681

 

 
681

Commodity contracts (call options)

 
8,876

 

 
8,876

Interest rate swap

 
7,501

 

 
7,501

(4)
Derivative Financial Instruments
Commodity Derivatives — Mark to Market
Alon selectively utilizes commodity derivatives to manage its exposure to commodity price fluctuations and uses crude oil, refined product and precious metal (catalyst) commodity derivative contracts to reduce risk associated with potential price changes on committed obligations. Alon does not speculate using derivative instruments. Credit risk on Alon’s derivative instruments is mitigated by transacting with counterparties meeting established collateral and credit criteria.
Cash Flow Hedges
To designate a derivative as a cash flow hedge, Alon documents at the inception of the hedge the assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. If, during the term of the derivative, the hedge is determined to be no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings when the underlying transaction occurs.
Interest Rate Derivatives. Alon selectively utilizes interest rate related derivative instruments to manage its exposure to floating-rate debt instruments. Alon periodically uses interest rate swap agreements to manage its floating to fixed rate position by converting certain floating-rate debt to fixed-rate debt. As of September 30, 2011, Alon had an interest rate swap agreement with a notional amount of $100,000, a remaining period of 15 months and a fixed interest rate of 4.25%. This swap was accounted for as a cash flow hedge.
For cash flow hedges, gains and losses reported in equity are reclassified into interest expense when the forecasted transaction affects income. During the nine months ended September 30, 2011 and 2010, Alon recognized in equity unrealized after-tax gains of $1,484 and $3,973, respectively, for the fair value measurement of the interest rate swap agreements. There were no amounts reclassified from equity into interest expense as a result of the discontinuance of cash flow hedge accounting.
For the nine months ended September 30, 2011 and 2010, there was no hedge ineffectiveness recognized in income. No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.
Commodity Derivatives. In May 2008, as part of financing the acquisition of the Krotz Springs refinery, Alon entered into futures contracts for the forward purchase of crude oil and the forward sale of heating oil of 14,849,750 barrels. These futures contracts were designated as cash flow hedges for accounting purposes. In the fourth quarter of 2008, Alon determined during its retrospective assessment of hedge effectiveness that the hedge was no longer highly effective. Cash flow hedge

7

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


accounting was discontinued in the fourth quarter of 2008 and all changes in value subsequent to the discontinuance were recognized into earnings. An after-tax loss of $4,003 for the nine months ended September 30, 2010 was reclassified from equity to earnings due to the discontinuance of cash flow hedge accounting. No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.
The following table presents the effect of derivative instruments on the consolidated statements of financial position.
 
As of September 30, 2011
 
Asset Derivatives
 
Liability Derivatives
 
Balance Sheet
 
 
 
Balance Sheet
 
 
 
Location
 
Fair Value
 
Location
 
Fair Value
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (swaps)
 
 
$

 
Accrued liabilities
 
$
(2,540
)
Commodity contracts (call options)
 
 

 
Accrued liabilities
 
(33,429
)
Commodity contracts (futures and forwards)
Accounts receivable
 
7,090

 
Accrued liabilities
 
(3,472
)
Total derivatives not designated as hedging instruments
 
 
$
7,090

 
 
 
$
(39,441
)
 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Interest rate swap
 
 
$

 
Other non-current liabilities
 
$
(5,217
)
Total derivatives designated as hedging instruments
 
 

 
 
 
(5,217
)
Total derivatives
 
 
$
7,090

 
 
 
$
(44,658
)
 
As of December 31, 2010
 
Asset Derivatives
 
Liability Derivatives
 
Balance Sheet
 
 
 
Balance Sheet
 
 
 
Location
 
Fair Value
 
Location
 
Fair Value
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (swaps)
 
 
$

 
Accounts Payable
 
$
(681
)
Commodity contracts (call options)
 
 

 
Accrued liabilities
 
(5,748
)
Commodity contracts (futures and forwards)
Accounts receivable
1,364

 
Accrued liabilities
 
(150
)
Commodity contracts (call options)
 
 

 
Other non-current liabilities
 
(3,128
)
Total derivatives not designated as hedging instruments
 
 
$
1,364

 
 
 
$
(9,707
)
 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Interest rate swap
 
 
$

 
Other non-current liabilities
 
$
(7,501
)
Total derivatives designated as hedging instruments
 
 

 
 
 
(7,501
)
Total derivatives
 
 
$
1,364

 
 
 
$
(17,208
)

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


The following tables present the effect of derivative instruments on Alon’s consolidated statements of operations and accumulated other comprehensive income (“OCI”).
Cash Flow Hedging Relationships
 
Gain (Loss) Recognized
in OCI
 
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
 
Gain (Loss) Reclassified
from Accumulated OCI into
Income (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)
 
 
 
 
Location
 
Amount
 
Location
 
Amount
For the Three Months Ended September 30, 2011
 
 
 
 
 
 
 
 
Interest rate swap
 
$
918

 
Interest expense
 
$
(1,058
)
 
 
 
$

Total derivatives
 
$
918

 
 
 
$
(1,058
)
 
 
 
$

 
 
 
 
 
 
 
 
 
 
 
For the Three Months Ended September 30, 2010
 
 
 
 
 
 
 
 
Commodity contracts (swaps)
 
$

 
Cost of sales
 
$
(2,825
)
 
 
 
$

Interest rate swaps
 
2,494

 
Interest expense
 
(3,693
)
 
 
 

Total derivatives
 
$
2,494

 
 
 
$
(6,518
)
 
 
 
$


Cash Flow Hedging Relationships
 
Gain (Loss) Recognized
in OCI
 
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
 
Gain (Loss) Reclassified
from Accumulated OCI into
Income (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)
 
 
 
 
Location
 
Amount
 
Location
 
Amount
For the Nine Months Ended September 30, 2011
 
 
 
 
 
 
 
 
Interest rate swap
 
$
2,284

 
Interest expense
 
$
(3,053
)
 
 
 
$

Total derivatives
 
$
2,284

 
 
 
$
(3,053
)
 
 
 
$

 
 
 
 
 
 
 
 
 
 
 
For the Nine Months Ended September 30, 2010
 
 
 
 
 
 
 
 
Commodity contracts (swaps)
 
$

 
Cost of sales
 
$
(6,354
)
 
 
 
$

Interest rate swaps
 
6,112

 
Interest expense
 
(10,917
)
 
 
 

Total derivatives
 
$
6,112

 
 
 
$
(17,271
)
 
 
 
$

Derivatives not designated as hedging instruments:
 
Gain (Loss) Recognized in Income
 
Location
 
Amount
For the Three Months Ended September 30, 2011
 
 
 
Commodity contracts (futures & forwards)
Cost of sales
 
$
(469
)
Commodity contracts (swaps)
Cost of sales
 
(1,038
)
Commodity contracts (call options)
Other income (loss), net
 
(14,269
)
Total derivatives
 
 
$
(15,776
)
 
 
 
 
For the Three Months Ended September 30, 2010
 
 
 
Commodity contracts (futures & forwards)
Cost of sales
 
$
1,796

Commodity contracts (swaps)
Cost of sales
 
$
(126
)
Commodity contracts (swaps)
Other income (loss), net
 
(671
)
Total derivatives
 
 
$
999


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


 
Gain (Loss) Recognized in Income
 
Location
 
Amount
For the Nine Months Ended September 30, 2011
 
 
 
Commodity contracts (futures & forwards)
Cost of sales
 
$
10,290

Commodity contracts (swaps)
Cost of sales
 
(3,716
)
Commodity contracts (call options)
Other income (loss), net
 
(51,093
)
Total derivatives
 
 
$
(44,519
)
 
 
 
 
For the Nine Months Ended September 30, 2010
 
 
 
Commodity contracts (futures & forwards)
Cost of sales
 
$
3,536

Commodity contracts (swaps)
Cost of sales
 
$
(501
)
Commodity contracts (swaps)
Other income (loss), net
 
(873
)
Total derivatives
 
 
$
2,162

(5)
Inventories
Alon’s inventories are stated at the lower of cost or market. Cost is determined under the last-in, first-out (LIFO) method for crude oil, refined products, asphalt, and blendstock inventories. Materials and supplies are stated at average cost. Cost for convenience store merchandise inventories is determined under the retail inventory method and cost for convenience store fuel inventories is determined under the first-in, first-out (FIFO) method.
Carrying value of inventories consisted of the following:

 
September 30,
2011
 
December 31,
2010
Crude oil, refined products, asphalt and blendstocks
$
146,377

 
$
60,588

Crude oil inventory consigned to others
59,301

 
38,445

Materials and supplies
21,675

 
19,059

Store merchandise
19,451

 
17,237

Store fuel
7,360

 
5,721

Total inventories
$
254,164

 
$
141,050

Crude oil, refined products, asphalt and blendstock inventories totaled 2,733 thousand barrels and 2,441 thousand barrels as of September 30, 2011 and December 31, 2010, respectively. A reduction of inventory volumes resulted in a liquidation of LIFO inventory layers associated with refined products and asphalt carried at lower costs which prevailed in previous years. The liquidation decreased cost of sales by approximately $44,570 for the nine months ended September 30, 2011. An increase in LIFO inventory associated with crude oil resulted in an increase to cost of sales of $21,074 for the nine months ended September 30, 2011.
Market values of crude oil, refined products, asphalt and blendstock inventories exceeded LIFO costs by $100,522 and $115,072 at September 30, 2011 and December 31, 2010, respectively.
Crude oil inventory consigned to others represents inventory that was sold to third parties with an obligation by Alon to repurchase the inventory at the end of the respective agreements. As a result of this requirement to repurchase inventory, no revenue was recorded on these transactions and the inventory volumes remain valued under the LIFO method.
Alon had 929 thousand barrels and 674 thousand barrels of crude oil consigned to others at September 30, 2011 and December 31, 2010, respectively. Alon recorded liabilities associated with this consigned inventory of $26,916 in accounts payable and $56,994 in other non-current liabilities and $27,034 in accounts payable and $32,433 in other non-current liabilities at September 30, 2011 and December 31, 2010, respectively.
Additionally, Alon recorded accrued liabilities of $3,131 and accounts receivable of $1,073 at September 30, 2011 and December 31, 2010, respectively, for forward commitments related to month-end consignment inventory target levels differing

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


from projected levels and the associated pricing with these inventory level differences.
Normal Purchase Normal Sale
Effective January 1, 2011, Alon elected to account for all inventory financing agreements it has under the "Normal Purchase Normal Sales" exemption of FASB ASC 815, Derivatives and Hedging. This exemption applies to situations where commodities are physically delivered. In previous periods Alon recorded changes in the fair value of the estimated settlement liability of these contracts through the statement of operations. Beginning January 1, 2011 and forward, changes in fair value of the estimated settlement liability will no longer be recorded due to the Normal Purchase Normal Sale exemption. If the contracts were settled September 30, 2011, the payment would be in excess of the liabilities recorded by $8,946.
(6)
Property, Plant and Equipment, Net
Property, plant and equipment, net consisted of the following:

 
September 30,
2011
 
December 31,
2010
Refining facilities
$
1,704,182

 
$
1,628,039

Pipelines and terminals
41,708

 
40,686

Retail
144,326

 
137,771

Other
18,418

 
16,773

Property, plant and equipment, gross
1,908,634

 
1,823,269

Less accumulated depreciation
(398,571
)
 
(334,737
)
Property, plant and equipment, net
$
1,510,063

 
$
1,488,532

The increase in refining facilities at September 30, 2011 is mainly due to the investment in the integration of the hydrocracker unit in Bakersfield, California.
(7)
Additional Financial Information
The tables that follow provide additional financial information related to the consolidated financial statements.
(a)
Other Assets, Net
 
September 30,
2011
 
December 31,
2010
Deferred turnaround and chemical catalyst cost
$
24,202

 
$
23,047

Environmental receivables
16,338

 
17,426

Deferred debt issuance costs
14,083

 
16,284

Intangible assets, net
7,539

 
7,901

Receivable from supply agreements
12,095

 
5,805

Other, net
14,934

 
11,072

Total other assets
$
89,191

 
$
81,535


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


(b)
Accrued Liabilities and Other Non-Current Liabilities
 
September 30,
2011
 
December 31,
2010
Accrued Liabilities:
 
 
 
Taxes other than income taxes, primarily excise taxes
$
32,943

 
$
23,584

Employee costs
10,804

 
11,571

Commodity contracts
39,441

 
5,898

Accrued finance charges
19,023

 
12,246

Environmental accrual
7,349

 
7,349

Valero earnout liability

 
6,562

Other
29,721

 
21,144

Total accrued liabilities
$
139,281

 
$
88,354

 
 
 
 
Other Non-Current Liabilities:
 
 
 
Pension and other postemployment benefit liabilities, net
$
33,481

 
$
33,157

Environmental accrual (Note 14)
59,387

 
61,657

Asset retirement obligations
11,314

 
10,932

Interest rate swap valuations
5,217

 
7,501

Consignment inventory
56,994

 
32,433

Commodity contracts

 
3,128

Other
13,321

 
12,168

Total other non-current liabilities
$
179,714

 
$
160,976

(c)
Comprehensive Income (Loss)
The following table displays the computation of total comprehensive income (loss):
 
For the Three Months Ended
 
For the Nine Months Ended
 
September 30,
 
September 30,
 
2011
 
2010
 
2011
 
2010
Income (loss) before non-controlling interest in income (loss) of subsidiaries
$
30,101

 
$
(16,751
)
 
$
57,737

 
$
(105,009
)
Other comprehensive gain, net of tax:
 
 
 
 
 
 
 
Unrealized gain on cash flow hedges, net of tax
597

 
3,401

 
1,484

 
7,976

Total other comprehensive income, net of tax
597

 
3,401

 
1,484

 
7,976

Comprehensive gain (loss)
30,698

 
(13,350
)
 
59,221

 
(97,033
)
Comprehensive income (loss) attributable to non-controlling interest
1,463

 
(956
)
 
2,300

 
(6,834
)
Comprehensive income (loss) attributable to common stockholders
$
29,235

 
$
(12,394
)
 
$
56,921

 
$
(90,199
)
The following table displays the components of accumulated other comprehensive loss, net of tax.
 
September 30,
2011
 
December 31,
2010
Unrealized losses on cash flow hedges, net of tax
$
(3,857
)
 
$
(5,341
)
Pension and post-employment benefits, net of tax
(16,576
)
 
(16,576
)
Accumulated other comprehensive loss, net of tax
$
(20,433
)
 
$
(21,917
)
(8)
Postretirement Benefits
Alon has three defined benefit pension plans covering substantially all of its refining and unbranded marketing segment employees. The benefits are based on years of service and the employee’s final average monthly compensation. Alon’s funding policy is to contribute annually not less than the minimum required nor more than the maximum amount that can be deducted for federal income tax purposes. Contributions are intended to provide not only for benefits attributed to service to date but also for those benefits expected to be earned in the future. Alon’s estimated contributions during 2011 to its pension plans has not

12

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


changed significantly from amounts previously disclosed in Alon’s consolidated financial statements for the year ended December 31, 2010. For the nine months ended September 30, 2011 and 2010, Alon contributed $4,410 and $5,000, respectively, to its qualified pension plans.
The components of net periodic benefit cost related to Alon’s benefit plans were as follows for the three and nine months ended September 30, 2011 and 2010:
 
For the Three Months Ended
 
For the Nine Months Ended
 
September 30,
 
September 30,
 
2011
 
2010
 
2011
 
2010
Components of net periodic benefit cost:
 
 
 
 
 
 
 
Service cost
$
914

 
$
1,018

 
$
2,743

 
$
3,055

Interest cost
1,035

 
946

 
3,105

 
2,837

Expected return on plan assets
(932
)
 
(904
)
 
(2,798
)
 
(2,715
)
Amortization of net loss
447

 
385

 
1,343

 
1,157

Net periodic benefit cost
$
1,464

 
$
1,445

 
$
4,393

 
$
4,334

(9)
Indebtedness
Debt consisted of the following:
 
September 30,
2011
 
December 31,
2010
Term loan credit facility
$
426,375

 
$
429,750

Revolving credit facilities
310,172

 
185,120

Senior secured notes
208,804

 
207,378

Retail credit facilities
108,657

 
94,057

Total debt
1,054,008

 
916,305

Less current portion
(124,707
)
 
(11,512
)
Total long-term debt
$
929,301

 
$
904,793

Alon Brands Term Loans. In March 2011, Alon Brands issued $30,000 five-year unsecured notes (the "Alon Brands Term Loans") to a group of investors including certain shareholders of Alon Israel and their affiliates. The notes will mature in March 2016. The group of investors have the right to request that principal payments of the loan will be paid in four equal, consecutive annual payments, starting in March 2013. Otherwise, the principal amount will be paid at the maturity date in March 2016. During the third quarter of 2011, certain shareholders of Alon Israel assigned $6,000 of the Alon Brands Term Loans to Alon Israel.
Borrowings under the Alon Brands Term Loans bear interest at a rate of 7% per annum, payable on a semi-annual basis, provided that the interest rate will increase to 9% per annum solely with respect to the portion of the loan equal to the unexercised portion of the warrants described below.
The Alon Brands Term Loans contain certain restrictive covenants, including maintenance financial covenants.
In conjunction with the issuance of the Alon Brands Term Loans, Alon issued 3,092,783 warrants to purchase shares of Alon USA Energy, Inc. common stock at an initial exercise price per share of $9.70. The warrants are exercisable in whole or in part until March 2016, five years from the date of issuance. The allocated fair value of the warrants was $10,988 and was recorded as additional paid-in capital at the time of issuance.
At September 30, 2011, the Alon Brands Term Loans had an outstanding balance of $19,731 (net of unamortized discount of $10,269). Alon is utilizing the effective interest method to amortize the discount over the five-year life of the Alon Brands Term Loans and has amortized $362 and $719 to interest expense for the three and nine months ended September 30, 2011, respectively.
Paramount Petroleum Revolving Credit Facility. Paramount Petroleum Corporation has a $300,000 revolving credit facility (the “Paramount Credit Facility”) that will mature on February 28, 2012. The Paramount Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility or the amount of the borrowing base under the facility.

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


Borrowings under the Paramount Credit Facility bear interest at the Eurodollar rate plus a margin based on excess availability. Based on the excess availability at September 30, 2011, the margin was 1.75%.
Borrowings of $113,172, which are included in current portion of long-term debt, and $63,120, which are included in long-term debt, were outstanding under the Paramount Credit Facility at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011 and December 31, 2010, outstanding letters of credit under the Paramount Credit Facility were $130,272 and $1,250, respectively.
Financial Covenants. Alon has certain credit facilities that contain restrictive covenants, including maintenance financial covenants. At September 30, 2011, Alon was in compliance with these covenants.
(10)
Stock-Based Compensation
Alon has two employee incentive compensation plans, (i) the Amended and Restated 2005 Incentive Compensation Plan and (ii) the 2000 Incentive Stock Compensation Plan.
(a)
Amended and Restated 2005 Incentive Compensation Plan (share value in dollars)
Alon’s original incentive compensation plan, the Alon USA Energy, Inc. 2005 Incentive Compensation Plan, was approved by its stockholders in 2006. In May 2010, Alon’s stockholders approved an amended and restated incentive compensation plan, the Alon USA Energy, Inc. Amended and Restated 2005 Incentive Compensation Plan, which is a component of Alon’s overall executive incentive compensation program. The Amended and Restated 2005 Incentive Compensation Plan permits the granting of awards in the form of options to purchase common stock, Stock Appreciation Rights (“SARs”), restricted shares of common stock, restricted common stock units, performance shares, performance units and senior executive plan bonuses to Alon’s directors, officers and key employees.
Restricted Stock. Non-employee directors are awarded an annual grant of shares of restricted stock valued at $25. The restricted shares granted to the non-employee directors vest over a period of three years, assuming continued service at vesting.
In May 2011, Alon granted awards of 180,000 restricted shares to certain executive officers at a grant date price of $13.53. These May 2011 restricted shares will vest as follows: 50% on May 10, 2012 and 50% on May 10, 2016, assuming continued service at vesting.
Compensation expense for the restricted stock grants amounted to $389 and $22 for the three months ended September 30, 2011 and 2010, respectively, and $665 and $53 for the nine months ended September 30, 2011 and 2010, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations. There is no material difference between intrinsic value and fair value under FASB ASC Topic 718-10 for pro forma disclosure purposes.
The following table summarizes the restricted share activity from January 1, 2010:
 
 
 
Weighted
Average
Grant Date
Fair Values
Nonvested Shares
Shares
 
(per share)
Nonvested at January 1, 2010
10,226

 
$
14.67

Granted
10,416

 
7.20

Vested
(4,473
)
 
16.77

Forfeited

 

Nonvested at December 31, 2010
16,169

 
$
9.28

Granted
186,015

 
13.50

Vested
(7,278
)
 
10.31

Forfeited

 

Nonvested at September 30, 2011
194,906

 
$
13.26

As of September 30, 2011, there was $1,908 of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the Amended and Restated 2005 Incentive Compensation Plan. That cost is expected to be recognized over a weighted-average period of 2.5 years. The fair value of shares vested in 2011 was $88.
Restricted Stock Units. In May 2011, Alon granted 500,000 restricted stock units to the CEO and President of Alon at a

14

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


grant date fair value of $11.47. Each restricted unit represents the right to receive one share of Alon common stock upon the vesting of the restricted stock unit. All 500,000 restricted stock units vest on March 1, 2015, assuming continued service at vesting. Compensation expense for the restricted stock units amounted to $374 and $623 for the three and nine months ended September 30, 2011, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.
Stock Appreciation Rights. Through December 31, 2010, Alon has granted awards of 580,915 SARs to certain officers and key employees of Alon of which 62% of these SARs have a grant price of $28.46 and the remaining SARs have grant prices ranging from $10.00 to $16.00.
In January 2011, Alon granted awards of 18,250 SARs to certain officers and key employees at a grant price equal to $16.00. The January 2011 SARs vest as follows: 50% on January 5, 2013, 25% on January 5, 2014, and 25% on January 5, 2015, and are exercisable during the 365-day period following the date of vesting.
When exercised, all SARs are convertible into shares of Alon common stock, the number of which will be determined at the time of exercise by calculating the difference between the closing price of Alon common stock on the exercise date and the grant price of the SARs (the “Spread”), multiplying the Spread by the number of SARs being exercised and then dividing the product by the closing price of Alon common stock on the exercise date.
Compensation expense for the SARs grants amounted to $31 and $97 for the three months ended September 30, 2011 and 2010, respectively, and $305 and $403 for the nine months ended September 30, 2011 and 2010, respectively, and is included in selling, general and administrative expenses in the consolidated statements of operations.
(b)
2000 Incentive Stock Compensation Plan
On August 1, 2000, Alon Assets, Inc. (“Alon Assets”) and Alon USA Operating, Inc. (“Alon Operating”), majority owned, consolidated subsidiaries of Alon, adopted the 2000 Incentive Stock Compensation Plan pursuant to which Alon’s board of directors may grant stock options to certain officers and members of executive management. The 2000 Incentive Stock Compensation Plan authorized grants of options to purchase up to 16,154 shares of common stock of Alon Assets and 6,066 shares of common stock of Alon Operating. This plan was closed to new participants subsequent to August 1, 2000, the initial grant date. All remaining stock options outstanding were exercised during the three months ended March 31, 2011. Total compensation expense recognized under this plan was $(11) for the nine months ended September 30, 2010 and is included in selling, general and administrative expenses in the consolidated statements of operations.
During the three months ended September 30, 2011, an agreement was reached with one of the participants whereby the participant would exchange 2,019 shares of common stock of Alon Assets and 758 shares of Alon Operating for 377,710 shares of common stock of Alon USA Energy, Inc. One-third of the shares were exchanged in October 2011 and the remaining two-thirds will be exchanged equally in October 2012 and October 2013. Compensation expense of $542 associated with the difference in value between the participants ownership of Alon Assets and Alon Operating stock compared to Alon USA Energy, Inc. stock was recognized for the three and nine months ended September 30, 2011 and is included in selling, general and administrative expenses in the consolidated statements of operations.
The following table summarizes the stock option activity for Alon Assets and Alon Operating for the nine months ended September 30, 2011, and for the year ended December 31, 2010:
 
Alon Assets
 
Alon Operating
 
Number of
Options
Outstanding
 
Weighted
Average
Exercise
Price
 
Number of
Options
Outstanding
 
Weighted
Average
Exercise
Price
Outstanding at January 1, 2010
2,793

 
$
100.00

 
1,049

 
$
100.00

Granted

 

 

 

Exercised
(2,187
)
 
100.00

 
(822
)
 
100.00

Forfeited and expired

 

 

 

Outstanding at December 31, 2010
606

 
$
100.00

 
227

 
$
100.00

Granted

 

 

 

Exercised
(606
)
 
100.00

 
(227
)
 
100.00

Forfeited and expired

 

 

 

Outstanding at September 30, 2011

 
$

 

 
$

The intrinsic value of total options exercised in 2011 was $471.

15

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


(11)
Stockholders’ Equity (per share in dollars)
Common Stock Dividends. On September 15, 2011, Alon paid a regular quarterly cash dividend of $0.04 per share on Alon’s common stock to stockholders of record at the close of business on September 1, 2011.
Preferred Stock Dividends. On September 30, 2011, shares of Alon common stock were issued for payment of the quarterly 8.5% preferred stock dividend to preferred stockholders of record at the close of business on September 20, 2011.
Warrants. In conjunction with the issuance of the Alon Brands Term Loans, Alon issued 3,092,783 warrants to purchase shares of Alon USA Energy, Inc. common stock at an initial exercise price per share of $9.70. The warrants are exercisable in whole or in part until March 2016, five years from the date of issuance.
Standby Equity Distribution Agreement. In January 2011, Alon entered into a Standby Equity Distribution Agreement (the "SEDA”) with YA Global Master SPV Ltd. ("YA Global”) to purchase up to $25,000 of Alon USA Energy, Inc. common stock ("Common Stock"). At any time during the effective period of the agreement, Alon may require YA Global to purchase shares of Common Stock by delivering an advance notice (as provided for in the SEDA) to YA Global. The purchase price of the Common Stock is 98.5% of the market price during the five consecutive trading days after the receipt of the advance notice is provided to YA Global. In no event shall the number of shares of Common Stock owned by YA Global and its affiliates exceed 4.99% of the outstanding Common Stock at that time. The SEDA automatically terminates in January 2013. During the first nine months of 2011, Alon sold Common Stock with total proceeds of $11,900.
(12)
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 per share include the dilutive effect of SARs using the treasury stock method and the dilutive effect of convertible preferred shares, warrants and granted restricted stock units using the if-converted method.
The calculation of earnings (loss) per share, basic and diluted, for the three and nine months ended September 30, 2011 and 2010, is as follows:
 
For the Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2011
 
2010
 
2011
 
2010
Net income (loss) available to common stockholders
$
28,621

 
$
(15,584
)
 
$
55,420

 
$
(97,785
)
Average number of shares of common stock outstanding
55,755

 
54,181

 
55,290

 
54,177

Dilutive SARs, RSUs, convertible preferred stock and warrants
5,935

 

 
5,941

 

Average number of shares of common stock outstanding assuming dilution
61,690

 
54,181

 
61,231

 
54,177

Income (loss) per share – basic
$
0.51

 
$
(0.29
)
 
$
1.00

 
$
(1.80
)
Income (loss) per share – diluted
$
0.46

 
$
(0.29
)
 
$
0.91

 
$
(1.80
)
(13)
Related-Party Transactions
Alon Brands Term Loans    
In March 2011, Alon Brands issued $12,000 five-year unsecured notes to certain shareholders of Alon Israel and their affiliates as part of the Alon Brands Term Loans. The Alon Brands Term Loans will mature in March 2016. The shareholders have the right to request that principal payments of the loan will be paid in four equal, consecutive annual payments, starting in March 2013. Otherwise, the principal amount will be paid at the maturity date in March 2016. During the third quarter of 2011, these shareholders assigned the Alon Brands Term Loans to Alon Israel.
Borrowings under the Alon Brands Term Loans bear interest at a rate of 7% per annum, payable on a semi-annual basis, provided that the interest rate will increase to 9% per annum solely with respect to the portion of the loan equal to the unexercised portion of the warrants described below.
In conjunction with the issuance of the Alon Brands Term Loans, Alon issued to certain shareholders of Alon Israel 1,237,113 warrants to purchase shares of Alon USA Energy, Inc. common stock at an initial exercise price per share of $9.70.

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


The warrants are exercisable in whole or in part until March 2016, five years from the date of issuance.
(14)
Commitments and Contingencies
(a)
Commitments
In the normal course of business, Alon has long-term commitments to purchase utilities such as natural gas, electricity and water for use by its refineries, terminals, pipelines and retail locations. Alon is also party to various refined product and crude oil supply and exchange agreements. These agreements are typically short-term in nature or provide terms for cancellation.
Supply and Offtake Agreement with J. Aron & Company
In February 2011, Alon entered into a Supply and Offtake Agreement (the “Supply and Offtake Agreement”), with J. Aron & Company (“J. Aron”). Pursuant to the Supply and Offtake Agreement (i) J. Aron agreed to sell to Alon, and Alon agreed to buy from J. Aron, at market prices, crude oil for processing at the Big Spring refinery and (ii) Alon agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced at the Big Spring refinery.
In connection with the execution of the Supply and Offtake Agreement, Alon also entered into agreements that provided for the sale, at market prices, of Alon's crude oil and certain refined product inventories to J. Aron, the lease to J. Aron of crude oil and refined product storage tanks located at the Big Spring refinery, and an agreement to identify prospective purchasers of refined products on J. Aron’s behalf. The Supply and Offtake Agreement has an initial term that expires in May 2016. J. Aron may elect to terminate the agreement prior to the initial term beginning in May 2013, provided Alon receives notice of termination at least six months prior to that date. Following expiration or termination of the Supply and Offtake Agreement, Alon is obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the Big Spring refinery.
(b)
Contingencies
Alon is involved in various other claims and legal actions arising in the ordinary course of business. In August 2011, Alon received from the Federal Trade Commission a civil investigative demand to provide documents as part of an industry-wide investigation related to petroleum industry practices and pricing. Alon believes the ultimate disposition of this and all other matters will not have a material effect on Alon’s financial position, results of operations or liquidity.
(c)
Environmental
Alon is subject to federal, state, and local environmental laws and regulations. These rules regulate the discharge of materials into the environment and may require Alon 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; to compensate others for damage to property and natural resources and for remediation and restoration costs. These possible obligations relate to sites owned by Alon and associated with past or present operations. Alon is currently participating in environmental investigations, assessments and cleanups under these regulations at refineries, service stations, pipelines and terminals. Alon may in the future be involved in additional environmental investigations, assessments and cleanups. The magnitude of future costs will depend on factors such as the unknown nature and contamination at many sites, the timing, extent and method of the remedial actions which may be required, and the determination of Alon’s 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.
Alon has accrued environmental remediation obligations of $66,736 ($7,349 current payable and $59,387 non-current liability) at September 30, 2011, and $69,006 ($7,349 current payable and $61,657 non-current liability) at December 31, 2010.
In connection with the acquisition of the Bakersfield refinery on June 1, 2010, a subsidiary of Alon entered into an indemnification agreement with a prior owner for remediation expenses of conditions that existed at the refinery on the acquisition date. Alon is required to make indemnification claims to the prior owner by March 15, 2015. Alon has recorded a current receivable of $2,675 and a non-current receivable of $13,840, and a current receivable of $2,675 and a non-current receivable of $14,386 at September 30, 2011 and December 31, 2010, respectively.
Paramount Petroleum Corporation has indemnification agreements with a prior owner for part of the remediation

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


expenses at its refineries and offsite tank farm and, as a result, has recorded a current receivable of $1,323 and a non-current receivable of $2,498, and a current receivable of $1,323 and a non-current receivable of $3,039 at September 30, 2011 and December 31, 2010, respectively.
(15)
Subsequent Event
Dividend Declared
On November 2, 2011, Alon declared its regular quarterly cash dividend of $0.04 per share on Alon’s common stock, payable on December 15, 2011, to stockholders of record at the close of business on December 1, 2011.
Crude Oil Supply Arrangements
In October 2011, Alon entered into arrangements that will allow the Krotz Springs refinery to process on average 20,000 to 25,000 barrels per day of West Texas Intermediate priced crude oil during 2012.

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ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2010. In this document, the words “Alon,” “the Company,” “we” and “our” refer to Alon USA Energy, Inc. and its subsidiaries.
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 regarding 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 sweet/sour spread;
changes in the spread between West Texas Intermediate ("WTI") crude oil and Light Louisiana Sweet and Heavy Louisiana Sweet crude oils, as well as the spread between California crudes such as Buena Vista and WTI;
the effects of transactions involving forward contracts and derivative instruments;
actions of customers and competitors;
changes in fuel and utility costs incurred by our facilities;
disruptions due to equipment interruption, pipeline disruptions or failure at our or third-party facilities;
the execution of planned capital projects;
adverse changes in the credit ratings assigned to our trade credit and debt instruments;
the effects of and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;
operating hazards, natural disasters such as flooding, casualty losses and other matters beyond our control;
the global financial crisis’ impact 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, 2010 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.

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Company Overview
We are an independent refiner and marketer of petroleum products operating primarily in the South Central, Southwestern and Western regions of the United States. Our crude oil refineries are located in Texas, California, Oregon and Louisiana and have a combined throughput capacity of approximately 250,000 barrels per day (“bpd”). Our refineries produce petroleum products including various grades of gasoline, diesel fuel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt, and other petroleum-based products.
Refining and Unbranded Marketing Segment. Our refining and unbranded marketing segment includes sour and heavy crude oil refineries located in Big Spring, Texas; and Paramount, Bakersfield and Long Beach, California; and a light sweet crude oil refinery located in Krotz Springs, Louisiana. We refer to the Long Beach, Bakersfield and Paramount refineries together as our “California refineries.” The refineries in our refining and unbranded marketing segment have a combined throughput capacity of approximately 240,000 bpd. At these refineries we refine crude oil into petroleum products, including gasoline, diesel fuel, jet fuel, petrochemicals, feedstocks and asphalts, which are marketed primarily in the South Central, Southwestern, and Western United States. In Bakersfield, we are converting intermediate products into finished products and are not refining crude oil.
We market transportation fuels produced at our Big Spring refinery in West and Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in these regions as our “physically integrated system” because we supply our retail convenience stores, branded and unbranded distributors in this region 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 market refined products produced from our California refineries to wholesale distributors, other refiners and third parties primarily on the West Coast. We started up the hydrocracker unit in Bakersfield in late June 2011 and began processing vacuum gas oil produced at our other California refineries.
The Krotz Springs refinery's processing units are structured to yield approximately 101.5% of total feedstock input, meaning that for each 100 barrels of crude oil and feedstocks input into the refinery, it produces 101.5 barrels of refined products. Of the 101.5%, on average 99.0% is light finished products such as gasoline and distillates, including diesel and jet fuel, petrochemical feedstocks and liquefied petroleum gas, and the remaining 2.5% is primarily heavy oils. We market refined products from Krotz Springs to wholesale distributors, other refiners, and third parties. The refinery’s location provides access to upriver markets on the Mississippi and Ohio Rivers and its docking facilities along the Atchafalaya River allow barge access. The refinery also uses its direct access to the Colonial Pipeline to transport products to markets in the Southern and Eastern United States.
Asphalt Segment. Our asphalt segment markets asphalt produced at our Big Spring and California refineries included in the refining and marketing segment and at our Willbridge, Oregon refinery. Asphalt produced by the refineries in our refining and marketing segment 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. Our asphalt segment markets asphalt through 12 refinery/terminal locations in Texas (Big Spring), California (Paramount, Long Beach, Elk Grove, Bakersfield and Mojave), Oregon (Willbridge), Washington (Richmond Beach), Arizona (Phoenix, Flagstaff and Fredonia) and Nevada (Fernley) (50% interest) as well as a 50% interest in Wright Asphalt Products Company, LLC (“Wright”). We produce both paving and roofing grades of asphalt, including performance-graded asphalts, emulsions and cutbacks.
Retail and Branded Marketing Segment. Our retail and branded marketing segment operates 303 convenience stores located primarily in Central and West Texas and New Mexico. These convenience stores typically offer various grades of gasoline, diesel fuel, general merchandise and food and beverage products to the general public, primarily under the 7-Eleven and FINA brand names. Substantially all of the motor fuel sold through our retail operations and the majority of the motor fuel marketed in our branded business is supplied by our Big Spring refinery. In 2011, approximately 90% of the motor fuel requirements of our branded marketing operations, including retail operations, were supplied by our Big Spring refinery. Branded distributors that are not part of our integrated supply system, primarily in Central Texas, are supplied with motor fuels we obtain from third-party suppliers.
We market gasoline and diesel under the FINA brand name through a network of approximately 640 locations, including our convenience stores. Approximately 58% of the gasoline and 21% of the diesel motor fuel produced at our Big Spring refinery was transferred to our retail and branded marketing segment at prices substantially determined by reference to commodity pricing information published by Platts. Additionally, our retail and branded marketing segment licenses the use of the FINA brand name and provides credit card processing services to approximately 240 licensed locations that are not under fuel supply agreements with us.


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Third Quarter Operational and Financial Highlights
Operating income for the third quarter of 2011 was $82.0 million, compared to an operating loss of $(35.4) in the same period last year. Our operational and financial highlights for the third quarter of 2011 include the following:
Combined refinery throughput for the third quarter of 2011 averaged 162,214 bpd, consisting of 56,828 bpd at the Big Spring refinery, 39,056 bpd at the California refineries and 66,330 bpd at the Krotz Springs refinery, compared to a combined average throughput of 138,253 bpd for third quarter of 2010, consisting of 53,060 bpd at the Big Spring refinery, 21,035 bpd at the California refineries and 64,158 bpd at the Krotz Springs refinery.
Operating margin at the Big Spring refinery was $23.05 per barrel for the third quarter of 2011, compared to $5.04 per barrel for the same period in 2010. This increase is due to higher Gulf Coast 3/2/1 crack spreads and improved operating efficiencies at higher throughputs.
Operating margin at the California refineries was $3.64 per barrel for the third quarter of 2011, compared to $0.12 per barrel for the same period in 2010. This increase reflects higher margin received on greater yield of light products due to the integration of the Bakersfield hydrocracker and a slight increase in the West Coast 3/1/1/1 crack spread.
Operating margin at the Krotz Springs refinery was $7.77 per barrel for the third quarter of 2011, compared to $0.97 per barrel for the same period in 2010. This increase is due to higher Gulf Coast 2/1/1 crack spreads.
The average sweet/sour spread for the third quarter of 2011 was $0.82 per barrel compared to $2.16 per barrel for the same period in 2010. The average LLS to WTI spread for the third quarter of 2011 was $18.87 per barrel compared to $3.11 per barrel for the same period in 2010. The average WTI to Buena Vista spread for the third quarter of 2011 was $(17.52) per barrel compared to $0.87 per barrel for the same period in 2010.
The average Gulf Coast 3/2/1 crack spread was $31.28 per barrel for the third quarter of 2011 compared to $7.76 per barrel for the third quarter of 2010. The average West Coast 3/1/1/1 crack spread for the third quarter of 2011 was $11.22 per barrel compared to $9.09 per barrel for the third quarter of 2010. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the third quarter of 2011 was $12.44 per barrel compared to $3.91 per barrel for the third quarter of 2010.
Asphalt margins in the third quarter of 2011 were $25.68 per ton compared to $77.59 per ton in the third quarter of 2010. This decrease was due primarily to higher crude oil costs without having the ability to increase asphalt sales prices accordingly. The average blended asphalt sales price increased 12.8% from $478.65 per ton in the third quarter of 2010 to $540.07 per ton in the third quarter of 2011 and the average non-blended asphalt sales price increased 10.0% from $348.89 per ton in the third quarter of 2010 to $383.87 per ton in the third quarter of 2011. The average price of Buena Vista crude increased 42.7% from $75.18 per barrel in the third quarter of 2010 to $107.27 per barrel in the third quarter of 2011.
Retail fuel sales volume increased by 10.9% from 36.8 million gallons in the third quarter of 2010 to 40.8 million gallons in the third quarter of 2011. Our branded fuel sales volume increased by 12.4% from 84.7 million gallons in the third quarter of 2010 to 95.2 million gallons in the third quarter of 2011.
On September 15, 2011, we paid a regular quarterly cash dividend of $0.04 per share on our common stock to stockholders of record at the close of business on September 1, 2011.
On September 30, 2011, shares of our common stock were issued for payment of the quarterly 8.5% preferred stock dividend to preferred stockholders of record at the close of business on September 20, 2011.
Major Influences on Results of Operations
Refining and Unbranded Marketing. Earnings and cash flow from our refining and unbranded marketing segment are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire crude oil and other feedstocks and the price of the refined products we ultimately sell depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation. While our sales and operating revenues fluctuate significantly with movements in crude oil and refined product prices, it is the spread between crude oil and refined product prices, and not necessarily fluctuations in those prices, that affect our earnings.
In order to measure our operating performance, we compare our per barrel refinery operating margins to certain industry benchmarks. We compare our Big Spring refinery’s per barrel operating margin to the Gulf Coast 3/2/1 crack spreads. A 3/2/1

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crack spread is calculated assuming that three barrels of a benchmark crude oil are converted, or cracked, into two barrels of gasoline and one barrel of diesel. We calculate the Gulf Coast 3/2/1 crack spread using the market values of Gulf Coast conventional gasoline and ultra-low sulfur diesel and the market value of West Texas Intermediate, or WTI, a light, sweet crude oil. We calculate the per barrel operating margin for our Big Spring refinery by dividing the Big Spring refinery’s gross margin by its throughput volumes. Gross margin is the difference between net sales and cost of sales (exclusive of substantial unrealized hedge positions and inventories adjustments related to acquisitions).
We compare our California refineries’ per barrel operating margin to the West Coast 3/1/1/1 crack spread. A 3/1/1/1 crack spread is calculated assuming that three barrels of a benchmark crude oil are converted into one barrel of gasoline, one barrel of diesel and one barrel of fuel oil. This is calculated using the market values of West Coast LA CARBOB pipeline gasoline, LA ultra-low sulfur pipeline diesel, LA 380 pipeline CST (fuel oil) and the market value of Buena Vista crude oil.
We compare our Krotz Springs refinery’s per barrel margin to the Gulf Coast 2/1/1 crack spread. The 2/1/1 crack spread is calculated assuming that two barrels of a benchmark crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate the Gulf Coast 2/1/1 crack spread using the market values of Gulf Coast conventional gasoline and Gulf Coast high sulfur diesel and the market value of Light Louisiana Sweet, or LLS, crude oil.
Our Big Spring refinery and California refineries are 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 value of WTI crude oil less the value of West Texas Sour, or WTS, a medium, sour crude oil. We refer to this differential as the sweet/sour spread. A widening of the sweet/sour spread can favorably influence the operating margin for our Big Spring and California refineries. In addition, our California refineries are capable of processing significant volumes of heavy crude oils which historically have cost less than light crude oils. We measure the cost advantage of refining heavy crude oils by calculating the difference between the value of WTI crude oil less the value of Buena Vista crude oil. A widening of this spread can favorably influence the refinery operating margins for our California refineries.
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 was primarily comprised of Heavy Louisiana Sweet, or HLS crude oil, and LLS crude oil. We measure the cost of refining these lighter sweet crude oils by calculating the difference between the average value of LLS crude oil (which also approximates the value of HLS crude oil) to the average value of WTI crude oil. A narrowing of this spread can favorably influence the refinery operating margins of our Krotz Springs refinery.
The results of operations from our refining and unbranded marketing segment are also significantly affected by our refineries’ operating costs, particularly the cost of natural gas used for fuel and the cost of electricity. Natural gas prices have historically been volatile. Typically, electricity prices fluctuate with natural gas prices.
Demand for gasoline products is generally higher during summer months than during winter months due to seasonal increases in highway traffic. As a result, the operating results for our refining and unbranded marketing segment for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters. The effects of seasonal demand for gasoline are partially offset by seasonality in demand for diesel, which in our region is generally higher in winter months as east-west trucking traffic moves south to avoid winter conditions on northern routes.
Safety, reliability and the environmental performance of our refineries are critical to our financial performance. The financial impact of planned downtime, such as a turnaround or major maintenance project, is mitigated through a diligent planning process that considers expectations for product availability, margin environment and the availability of resources to perform the required maintenance.
The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Crude oil and refined products are essentially commodities, and we have no control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market value under the LIFO inventory valuation methodology, price fluctuations generally have little effect on our financial results.
Asphalt. Earnings from our asphalt segment depend primarily upon the margin between the price at which we sell our asphalt and the transfer prices for asphalt produced at our refineries in the refining and unbranded marketing segment. Asphalt is transferred to our asphalt segment at prices substantially determined by reference to the cost of crude oil, which is intended to approximate wholesale market prices. The asphalt segment also conducts operations at and markets asphalt produced by our refinery located in Willbridge, Oregon. In addition to producing asphalt at our refineries, at times when refining margins are unfavorable we opportunistically purchase asphalt from other producers for resale. A portion of our asphalt sales are made using fixed price contracts for delivery at future dates. Because these contracts are priced at the 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,

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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 and Branded Marketing. Earnings and cash flows from our retail and branded marketing segment are primarily affected by merchandise and motor fuel sales volumes and margins at our convenience stores and the motor fuel sales volumes and margins from sales to our FINA-branded distributors, together with licensing and credit card related fees generated from our FINA-branded distributors and licensees. 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. Motor fuel margin is equal to motor fuel sales less the delivered cost of fuel and motor fuel taxes, measured on a cents per gallon (“cpg”) basis. Our motor fuel margins are driven by local supply, demand and competitor pricing. Our convenience store 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 nine months ended September 30, 2011 and 2010, have been influenced by the following factors which are fundamental to understanding comparisons of our period-to-period financial performance.
Throughput at the Big Spring refinery was higher over the nine months ended September 30, 2011, after we implemented new operating procedures. The California refineries were shut down for most of the first quarter of 2011 to redeploy resources for the integration of the Bakersfield hydrocracker unit acquired in June 2010. Crude throughput was reduced at the Krotz Springs refinery during the second quarter of 2011 due to the flooding in Louisiana and its impact on crude oil supply to the refinery. Additionally, the Krotz Springs refinery was shut down during November 2009 for a scheduled turnaround and remained down until its restart in June 2010.
Results of Operations
Net Sales. Net sales consist primarily of sales of refined petroleum products through our refining and unbranded marketing segment and asphalt segment and sales of merchandise, including food products, and motor fuels, through our retail and branded marketing segment.
For the refining and unbranded marketing segment, net sales consist of gross sales, net of customer rebates, discounts and excise taxes and includes inter-segment sales to our asphalt and retail and branded marketing segments, which are eliminated through consolidation of our financial statements. Asphalt sales consist of gross sales, net of any discounts and applicable taxes. Retail net sales consist of gross merchandise sales, less rebates, commissions and discounts, and gross fuel sales, including motor fuel taxes. For our petroleum and asphalt products, net sales are mainly affected by crude oil and refined product prices and volume changes caused by operations. Our retail merchandise sales are affected primarily by competition and seasonal influences.
Cost of Sales. Refining and unbranded marketing cost of sales includes crude oil and other raw materials, inclusive of transportation costs. Asphalt cost of sales includes costs of purchased asphalt, blending materials and transportation costs. Retail cost of sales includes cost of sales for motor fuels and for merchandise. Motor fuel cost of sales represents the net cost of purchased fuel, including transportation costs and associated motor fuel 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.
Direct Operating Expenses. Direct operating expenses, which relate to our refining and unbranded 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. Environmental compliance costs, including monitoring and routine maintenance, are expensed as incurred. All operating costs associated with our crude oil and product pipelines are considered to be transportation costs and are reflected as cost of sales.
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. Refining and marketing and asphalt segment corporate overhead and marketing expenses are also included in SG&A expenses.

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ALON USA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED
Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for Alon and our three operating segments for the three and nine months ended September 30, 2011 and 2010. 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, 2010 is unaudited.
 
For the Three Months Ended
 
For the Nine Months Ended
 
September 30,
 
September 30,
 
2011
 
2010
 
2011
 
2010
 
(dollars in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
 
 
Net sales (1)
$
2,056,653

 
$
1,248,569

 
$
5,303,388

 
$
2,668,243

Operating costs and expenses:
 
 

 
 
 
 
Cost of sales
1,827,098

 
1,153,743

 
4,717,673

 
2,443,533

Direct operating expenses
83,338

 
68,448

 
202,476

 
192,816

Selling, general and administrative expenses (2)
34,680

 
35,012

 
107,595

 
96,001

Depreciation and amortization (3)
29,812

 
26,781

 
80,046

 
78,471

Total operating costs and expenses
1,974,928

 
1,283,984

 
5,107,790

 
2,810,821

Gain on disposition of assets
229

 

 
161

 
474

Operating income (loss)
81,954

 
(35,415
)
 
195,759

 
(142,104
)
Interest expense (4)
(22,582
)
 
(24,091
)
 
(63,780
)
 
(72,411
)
Equity earnings of investees
2,005

 
3,864

 
3,775

 
4,970

Gain on bargain purchase (5)

 
17,480

 

 
17,480

Other income (loss), net (6)
(14,272
)
 
(494
)
 
(51,065
)
 
13,345

Income (loss) before income tax expense (benefit) and non-controlling interest in income (loss) of subsidiaries
47,105

 
(38,656
)
 
84,689

 
(178,720
)
Income tax expense (benefit)
17,004

 
(21,905
)
 
26,952

 
(73,711
)
Income (loss) before non-controlling interest in income (loss) of subsidiaries
30,101

 
(16,751
)
 
57,737

 
(105,009
)
Non-controlling interest in income (loss) of subsidiaries
1,480

 
(1,167
)
 
2,317

 
(7,224
)
Net income (loss) available to common stockholders
$
28,621

 
$
(15,584
)
 
$
55,420

 
$
(97,785
)
Income (loss) per share, basic
$
0.51

 
$
(0.29
)
 
$
1.00

 
$
(1.80
)
Weighted average shares outstanding, basic (in thousands)
55,755

 
54,181

 
55,290

 
54,177

Income (loss) per share, diluted
$
0.46

 
$
(0.29
)
 
$
0.91

 
$
(1.80
)
Weighted average shares outstanding, diluted (in thousands)
61,690

 
54,181

 
61,231

 
54,177

Cash dividends per share
$
0.04

 
$
0.04

 
$
0.12

 
$
0.12

CASH FLOW DATA:
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
Operating activities
$
109,478

 
$
24,285

 
$
58,362

 
$
(37,275
)
Investing activities
(28,055
)
 
(11,162
)
 
(104,130
)
 
(15,218
)
Financing activities
(22,964
)
 
18,799

 
149,682

 
51,691

OTHER DATA:
 
 
 
 
 
 
 
Adjusted EBITDA (7)
99,270

 
(5,264
)
 
228,354

 
(45,792
)
Capital expenditures (8)
23,162

 
7,838

 
91,120

 
20,526

Capital expenditures for turnaround and chemical catalyst
2,733

 
1,137

 
6,995

 
12,668


24

Table of Contents

 
September 30,
2011
 
December 31,
2010
BALANCE SHEET DATA (end of period):
 
 
 
Cash and cash equivalents
175,601

 
71,687

Working capital
99,558

 
990

Total assets
2,419,897

 
2,088,521

Total debt
1,054,008

 
916,305

Total equity
417,916

 
341,767

(1)
Includes excise taxes on sales by the retail and branded marketing segment of $15,476 and $14,204 for the three months ended September 30, 2011 and 2010, respectively, and $44,887 and $40,521 for the nine months ended September 30, 2011 and 2010, respectively.
(2)
Includes corporate headquarters selling, general and administrative expenses of $188 and $188 for the three months ended September 30, 2011 and 2010, respectively, and $564 and $564 for the nine months ended September 30, 2011 and 2010, respectively, which are not allocated to our three operating segments.
(3)
Includes corporate depreciation and amortization of $404 and $397 for the three months ended September 30, 2011 and 2010, respectively, and $1,211 and $964 for the nine months ended September 30, 2011 and 2010, respectively, which are not allocated to our three operating segments.
(4)
Interest expense of $72,411 for the nine months ended September 30, 2010, includes a charge of $6,659 for the write-off of debt issuance costs associated with our prepayment of the Alon Refining Krotz Springs, Inc. revolving credit facility.
(5)
In connection with the Bakersfield refinery acquisition in 2010, the acquisition date fair value of the identifiable net assets acquired exceeded the fair value of the consideration transferred, resulting in a $17,480 bargain purchase gain.
(6)
Other income (loss), net for the three and nine months ended September 30, 2011 is substantially the loss on heating oil crack spread contracts. Other income (loss), net for the nine months ended September 30, 2010 substantially represents the gain from the sale of our investment in Holly Energy Partners.
(7)
Adjusted EBITDA represents earnings before non-controlling interest in income of subsidiaries, income tax expense, interest expense, depreciation and amortization, gain on bargain purchase and gain on disposition of assets. Adjusted EBITDA is not a recognized measurement under GAAP; however, the amounts included in Adjusted EBITDA are derived from amounts included in our consolidated financial statements. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors, and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of non-controlling interest in income of subsidiaries, income tax expense, interest expense, gain on disposition of assets and the accounting effects of capital expenditures and acquisitions, items that may vary for different companies for reasons unrelated to overall operating performance.
Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:
Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;
Adjusted EBITDA does not reflect the prior claim that non-controlling interest have on the income generated by non-wholly-owned subsidiaries;
Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and
Our calculation of Adjusted EBITDA may differ from EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.
Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.

25

Table of Contents

The following table reconciles net income (loss) available to common stockholders to Adjusted EBITDA for the three and nine months ended September 30, 2011 and 2010, respectively:
 
For the Three Months Ended
 
For the Nine Months Ended
 
September 30,
 
September 30,
 
2011
 
2010