UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
___________________________________________________
FORM 10-Q
þ
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2014
OR
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
FOR THE TRANSITION PERIOD FROM __________TO __________ 

Commission file number: 001-35742
ALON USA PARTNERS, LP
(Exact name of Registrant as specified in its charter)
___________________________________________________

Delaware
 
46-0810241
(State of organization)
 
(I.R.S. Employer
 
 
Identification No.)
12700 Park Central Dr., Suite 1600, Dallas, Texas 75251
(Address of principal executive offices) (Zip Code)

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes  þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:
Large accelerated filer o
Accelerated filer þ
Non-accelerated filer o
Smaller reporting company o
 
 
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 the Registrant’s common limited partner units outstanding as of August 1, 2014, was 62,506,550.

 
 



TABLE OF CONTENTS

 
Page
 
 


Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1.
FINANCIAL STATEMENTS

ALON USA PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
 
June 30,
2014
 
December 31,
2013
 
(unaudited)
 
 
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
81,099

 
$
153,583

Accounts and other receivables, net
86,173

 
123,781

Accounts and other receivables, net - related parties
15,642

 
14,621

Inventories
70,446

 
49,146

Prepaid expenses and other current assets
15,675

 
4,642

Total current assets
269,035

 
345,773

Property, plant and equipment, net
460,097

 
472,885

Other assets, net
83,191

 
31,266

Total assets
$
812,323

 
$
849,924

LIABILITIES AND PARTNERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
236,857

 
$
280,774

Accrued liabilities
47,024

 
44,492

Current portion of long-term debt
2,500

 
2,500

Total current liabilities
286,381

 
327,766

Other non-current liabilities
43,953

 
34,894

Long-term debt
340,844

 
341,822

Total liabilities
671,178

 
704,482

Commitments and contingencies (Note 11)

 

Partners’ equity:
 
 
 
General Partner

 

Common unitholders - 62,506,550 and 62,502,467 units issued and outstanding at June 30, 2014 and December 31, 2013, respectively
141,145

 
145,442

Total partners’ equity
141,145

 
145,442

Total liabilities and partners’ equity
$
812,323

 
$
849,924


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

Table of Contents

ALON USA PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands except per unit data)

 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
Net sales (1)
$
725,852

 
$
865,694

 
$
1,582,312

 
$
1,669,861

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales
665,398

 
767,322

 
1,424,444

 
1,417,525

Direct operating expenses
25,152

 
27,314

 
54,093

 
57,736

Selling, general and administrative expenses
6,784

 
5,065

 
11,152

 
12,730

Depreciation and amortization
9,508

 
11,243

 
19,575

 
23,307

Total operating costs and expenses
706,842

 
810,944

 
1,509,264

 
1,511,298

Operating income
19,010

 
54,750

 
73,048

 
158,563

Interest expense
(11,569
)
 
(8,970
)
 
(22,893
)
 
(18,362
)
Other income, net
601

 
14

 
613

 
18

Income before state income tax expense
8,042

 
45,794

 
50,768

 
140,219

State income tax expense
240

 
473

 
725

 
1,373

Net income
$
7,802

 
$
45,321

 
$
50,043

 
$
138,846

Earnings per unit
$
0.12

 
$
0.73

 
$
0.80

 
$
2.22

Weighted average common units outstanding (in thousands)
62,504

 
62,502

 
62,504

 
62,502

Cash distribution per unit
$
0.69

 
$
1.48

 
$
0.87

 
$
2.05

___________
(1)
Includes sales to related parties of $152,170 and $156,043 for the three months and $291,183 and $297,942 for the six months ended June 30, 2014 and 2013, respectively.




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

Table of Contents

ALON USA PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, dollars in thousands)
 
For the Six Months Ended
 
June 30,
 
2014
 
2013
Cash flows from operating activities:
 
 
 
Net income
$
50,043

 
$
138,846

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
Depreciation and amortization
19,575

 
23,307

Amortization of debt issuance costs
1,018

 
990

Amortization of original issuance discount
272

 
251

Changes in operating assets and liabilities:
 
 
 
Accounts and other receivables, net
37,608

 
(25,211
)
Accounts and other receivables, net - related parties
(1,021
)
 
1,586

Inventories
(21,300
)
 
3,028

Prepaid expenses and other current assets
(11,033
)
 
4,219

Other assets, net
(1,053
)
 
553

Accounts payable
(26,977
)
 
2,335

Accrued liabilities
(10,959
)
 
1,401

Other non-current liabilities
9,059

 
1,938

Net cash provided by operating activities
45,232

 
153,243

Cash flows from investing activities:
 
 
 
Capital expenditures
(11,439
)
 
(9,157
)
Capital expenditures for turnarounds and catalysts
(25,447
)
 
(4,819
)
Net cash used in investing activities
(36,886
)
 
(13,976
)
Cash flows from financing activities:
 
 
 
Distributions paid to unitholders
(10,010
)
 
(23,579
)
Distributions paid to unitholders - Alon Energy
(44,370
)
 
(104,550
)
Inventory agreement transactions
(25,200
)
 

Deferred debt issuance costs

 
(205
)
Revolving credit facility, net

 
(49,000
)
Payments on long-term debt
(1,250
)
 
(1,250
)
Net cash used in financing activities
(80,830
)
 
(178,584
)
Net decrease in cash and cash equivalents
(72,484
)
 
(39,317
)
Cash and cash equivalents, beginning of period
153,583

 
66,001

Cash and cash equivalents, end of period
$
81,099

 
$
26,684

Supplemental cash flow information:
 
 
 
Cash paid for interest, net of capitalized interest
$
23,203

 
$
17,601

Cash paid for income tax
$
725

 
$
1,373

Supplemental disclosure of non-cash activity:
 
 
 
Capital expenditures included in accounts payable and accrued liabilities
$
28,741

 
$


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

Table of Contents

ALON USA PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
(1)
Basis of Presentation
As used in this report, the terms “Alon,” the “Partnership,” “we,” “us” or “our” refer to Alon USA Partners, LP, one or more of its consolidated subsidiaries or all of them taken as a whole. References in this report to “Alon Energy” refer collectively to Alon USA Energy, Inc. and its consolidated subsidiaries, other than Alon USA Partners, LP, its subsidiaries and its general partner.
Alon is a Delaware limited partnership formed in August 2012 by Alon Energy and its wholly-owned subsidiary Alon USA Partners GP, LLC (the “General Partner”). On November 26, 2012, we completed our initial public offering of 11,500,000 common units representing limited partner interests.
These consolidated financial statements and notes are unaudited and have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements.
In the opinion of the General Partner’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 our consolidated financial position and results of operations for the interim periods presented. All significant intercompany balances and transactions have been eliminated in consolidation. Certain prior year balances may have been aggregated or disaggregated in order to conform to the current year presentation. Our results of operations for the six months ended June 30, 2014 are not necessarily indicative of the operating results that may be realized for the year ending December 31, 2014.
Our consolidated balance sheet as of December 31, 2013 has been derived from the audited financial statements as of that date. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2013.
New Accounting Standards
In May 2014, the Financial Accounting Standards Board and the International Accounting Standards Board jointly issued a comprehensive new revenue recognition standard that provides accounting guidance for all revenue arising from contracts to provide goods or services to customers. This standard is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets. The requirements from the new standard are effective for interim and annual periods beginning after December 15, 2016, and early adoption is not permitted. The standard allows for either full retrospective adoption or modified retrospective adoption. We are evaluating the guidance to determine the method of adoption and the impact of this standard on our consolidated financial statements.
(2)
Fair Value
We determine fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We classify financial assets and financial liabilities into the following fair value hierarchy:
Level 1 -     valued based on quoted prices in active markets for identical assets and liabilities;
Level 2 -     valued based on quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability; and
Level 3 -     valued based on unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
As required, we utilize valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy. We generally apply the “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.

4

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


The carrying amounts of our cash and cash equivalents, receivables, payables and accrued liabilities approximate fair value due to the short-term maturities of these assets and liabilities. The reported amounts of long-term debt approximate fair value. Derivative instruments are carried at fair value, which are based on quoted market prices. Derivative instruments and the Renewable Identification Numbers (“RINs”) obligation are our only assets and liabilities measured at fair value on a recurring basis.
The RINs obligation represents the period-end deficit, if any, after considering any RINs acquired or under contract, necessary to meet our requirements to blend biofuels into the products we have produced. The RINs obligation is categorized as level 2 of the fair value hierarchy and is measured at fair value using the market approach based on quoted prices from an independent pricing service.
The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the consolidated balance sheets at June 30, 2014 and December 31, 2013:
 
Level 1
 
Level 2
 
Level 3
 
Total
As of June 30, 2014
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
329

 
$

 
$

 
$
329

Fair value hedge

 
4,696

 

 
4,696

 
 
 
 
 
 
 
 
As of December 31, 2013
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
22

 
$

 
$

 
$
22

Liabilities:
 
 
 
 
 
 
 
Fair value hedge

 
2,304

 

 
2,304

RINs obligation

 
334

 

 
334

(3)
Derivative Financial Instruments
Mark to Market
Commodity Derivatives. We selectively utilize crude oil and refined product commodity derivative contracts to reduce the risk associated with potential price changes on committed obligations. We do not speculate using derivative instruments. Credit risk on our derivative instruments is mitigated by transacting with counterparties meeting established collateral and credit criteria.
Fair Value Hedge
Fair value hedges are used to hedge price volatility of certain refining inventories and firm commitments to purchase inventories. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk, is recognized in earnings in the same period.
As of June 30, 2014, we have accounted for certain commodity contracts as fair value hedges with contract purchase volumes of 304 thousand barrels of crude oil with remaining contract terms through May 2019.

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


The following tables present the effect of derivative instruments on the consolidated statements of financial position:
 
As of June 30, 2014
 
Asset Derivatives
 
Liability Derivatives
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
Accounts receivable
 
$
520

 
Accrued liabilities
 
$
849

Total derivatives not designated as hedging instruments
 
 
$
520

 
 
 
$
849

 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Fair value hedge
 
 
$

 
Other non-current liabilities
 
$
4,696

Total derivatives designated as hedging instruments
 
 

 
 
 
4,696

Total derivatives
 
 
$
520

 
 
 
$
5,545

 
As of December 31, 2013
 
Asset Derivatives
 
Liability Derivatives
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
Accounts receivable
 
$
303

 
Accrued liabilities
 
$
281

Total derivatives not designated as hedging instruments
 
 
$
303

 
 
 
$
281

 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Fair value hedge
 
 
$

 
Other non-current liabilities
 
$
2,304

Total derivatives designated as hedging instruments
 
 

 
 
 
2,304

Total derivatives
 
 
$
303

 
 
 
$
2,585

The following tables present the effect of derivative instruments on the consolidated statements of operations:
Derivatives in fair value hedging relationships:
 
 
 
Gain (Loss) Recognized in Income
 
 
 
For the Three Months Ended
 
For the Six Months Ended
 
 
 
June 30,
 
June 30,
 
Location
 
2014
 
2013
 
2014
 
2013
Fair value hedge
Cost of sales
 
$
(1,569
)
 
$
(4
)
 
$
(2,392
)
 
$
(1,598
)
Total derivatives
 
 
$
(1,569
)
 
$
(4
)
 
$
(2,392
)
 
$
(1,598
)
Derivatives not designated as hedging instruments:
 
 
 
Gain (Loss) Recognized in Income
 
 
 
For the Three Months Ended
 
For the Six Months Ended
 
 
 
June 30,
 
June 30,
 
Location
 
2014
 
2013
 
2014
 
2013
Commodity contracts (futures & forwards)
Cost of sales
 
$
(2,898
)
 
$
(1,001
)
 
$
(2,275
)
 
$
6,650

Total derivatives
 
 
$
(2,898
)
 
$
(1,001
)
 
$
(2,275
)
 
$
6,650


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


Offsetting Assets and Liabilities
Our derivative financial instruments are subject to master netting arrangements to manage counterparty credit risk associated with derivatives and we offset the fair value amounts recorded for derivative instruments to the extent possible under these agreements on our consolidated balance sheets.
The following table presents offsetting information regarding our derivatives by type of transaction as of June 30, 2014 and December 31, 2013:
 
Gross Amounts of Recognized Assets/Liabilities
 
Gross Amounts offset in the Statement of Financial Position
 
Net Amounts Presented in the Statement of Financial Position
 
Gross Amounts Not offset in the Statement of Financial Position
 
Net Amount
 
 
 
Financial Instruments
 
Cash Collateral Pledged
 
As of June 30, 2014
 
 
 
 
 
 
 
 
 
 
Derivative Assets:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures & forwards)
$
566

 
$
(46
)
 
$
520

 
$
(520
)
 
$

 
$

Derivative Liabilities:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures & forwards)
$
895

 
$
(46
)
 
$
849

 
$
(520
)
 
$

 
$
329

Fair value hedge
4,696

 

 
4,696

 

 

 
4,696

 
 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2013
 
 
 
 
 
 
 
 
 
 
Derivative Assets:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures & forwards)
$
514

 
$
(211
)
 
$
303

 
$
(281
)
 
$

 
$
22

Derivative Liabilities:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures & forwards)
$
492

 
$
(211
)
 
$
281

 
$
(281
)
 
$

 
$

Fair value hedge
2,304

 

 
2,304

 

 

 
2,304

Compliance Program Market Risk
We are obligated by government regulations to blend a certain percentage of biofuels into the products we produce that are consumed in the U.S. We purchase biofuels from third parties and blend those biofuels into our products, and each gallon of biofuel purchased includes a RIN. To the degree we are unable to blend biofuels at the required percentage, a RINs deficit is generated and we must acquire that number of RINs by the annual reporting deadline in order to remain in compliance with applicable regulations.
We are exposed to market risk related to the volatility in the price of credits needed to comply with these government regulations. We manage this risk by purchasing RINs when prices are deemed favorable utilizing fixed price purchase contracts. Some of these contracts are derivative instruments; however, we elect the normal purchase and sale exception and do not record these contracts at their fair values.
During the three months ended June 30, 2014, we generated RINs credits of $759, as a result of reduced production during the planned turnaround at our refinery, compared to RINs costs of $8,016 for three months ended June 30, 2013. RINs costs were $2,167 and $8,016 for the six months ended June 30, 2014 and 2013, respectively. These amounts are reflected in cost of sales. We utilized carryover RINs from 2012 to completely offset our first quarter 2013 RINs deficit.
(4)
Inventories
Our inventories (including inventory consigned to others) are stated at the lower of cost or market. Cost is determined under the last-in, first-out (LIFO) method for crude oil, refined products and blendstock inventories. Materials and supplies are stated at average cost.

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


Carrying value of inventories consisted of the following:
 
June 30,
2014
 
December 31,
2013
Crude oil, refined products and blendstocks
$
39,665

 
$
25,246

Crude oil inventory consigned to others
21,388

 
14,214

Materials and supplies
9,393

 
9,686

Total inventories
$
70,446

 
$
49,146

Market values of crude oil, refined products and blendstock inventories exceeded LIFO costs by $24,735 and $21,216 at June 30, 2014 and December 31, 2013, respectively.
(5)
Inventory Financing Agreement
The Partnership has entered into a Supply and Offtake Agreement and other associated agreements (together 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 us, and we agreed to buy from J. Aron, at market prices, crude oil for processing at the Big Spring refinery and (ii) we agreed to sell to J. Aron, and J. Aron agreed to buy from us, at market prices, certain refined products produced at the Big Spring refinery.
The Supply and Offtake Agreement also provided for the sale, at market prices, of our crude oil and certain refined product inventories to J. Aron, the lease to J. Aron of crude oil and refined product storage facilities, and to identify prospective purchasers of refined products on J. Aron’s behalf. The Supply and Offtake Agreement has an initial term that expires in May 2019. J. Aron may elect to terminate the Supply and Offtake Agreement prior to the expiration of the initial term beginning in May 2016 and upon each anniversary thereof, on six months prior notice. We may elect to terminate in May 2018 on six months prior notice.
Following expiration or termination of the Supply and Offtake Agreement, we are obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the Big Spring refinery at then current market prices.
At June 30, 2014 and December 31, 2013, we had net current receivables of $19,914 and $11,640, respectively, from J. Aron for sales and purchases, non-current liabilities related to the original financing of $33,499 and $24,482, respectively, and a consignment inventory receivable representing a deposit paid to J. Aron of $6,290 and $6,290, respectively.
Additionally, we had current receivables of $520 and current payables of $263 at June 30, 2014 and December 31, 2013, respectively, for forward commitments related to month-end consignment inventory target levels differing from projected levels and the associated pricing with these inventory level differences.
(6)
Property, Plant and Equipment, Net
Property, plant and equipment, net consisted of the following:
 
June 30,
2014
 
December 31,
2013
Refining facilities
$
681,594

 
$
677,085

Accumulated depreciation
(221,497
)
 
(204,200
)
Property, plant and equipment, net
$
460,097

 
$
472,885

(7)
Additional Financial Information
The following tables provide additional financial information related to the consolidated financial statements.
(a)
Other Assets, Net
 
June 30,
2014
 
December 31,
2013
Deferred debt issuance costs
$
6,764

 
$
7,782

Receivable from supply agreement
6,290

 
6,290

Deferred turnaround and catalyst cost
60,783

 
7,774

Other
9,354

 
9,420

Total other assets
$
83,191

 
$
31,266


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


(b)
Accrued Liabilities and Other Non-Current Liabilities
 
June 30,
2014
 
December 31,
2013
Accrued Liabilities:
 
 
 
Taxes other than income taxes, primarily excise taxes
$
16,341

 
$
30,354

Accrued finance charges
647

 
1,365

Environmental accrual (Note 11)
1,307

 
1,307

Commodity contracts
849

 
281

Other
27,880

 
11,185

Total accrued liabilities
$
47,024

 
$
44,492

 
 
 
 
Other Non-Current Liabilities:
 
 
 
Consignment inventory obligation
$
33,499

 
$
24,482

Environmental accrual (Note 11)
5,640

 
5,640

Asset retirement obligations
2,015

 
1,973

Other
2,799

 
2,799

Total other non-current liabilities
$
43,953

 
$
34,894

(8)
Indebtedness
Debt consisted of the following:
 
June 30,
2014
 
December 31,
2013
Term loan credit facility
$
243,344

 
$
244,322

Revolving credit facility
100,000

 
100,000

Total debt
343,344

 
344,322

Less: Current portion
2,500

 
2,500

Total long-term debt
$
340,844

 
$
341,822

Outstanding letters of credit under the revolving credit facility were $58,963 and $109,772 at June 30, 2014 and December 31, 2013, respectively.
Our revolving credit facility contains maintenance financial covenants. At June 30, 2014, we were in compliance with these covenants.
(9)
Partners' Equity (unit values in dollars)
Cash Distributions
We have adopted a policy pursuant to which we will distribute all of the available cash generated each quarter, as defined in the partnership agreement and subject to the approval of the board of directors of the General Partner. The per unit amount of available cash to be distributed each quarter, if any, will be distributed within 60 days following the end of such quarter.
During the six months ended June 30, 2014, we paid the following cash distributions:
Date Paid
 
Distribution Amount Per Unit
 
Total Distribution Amount
May 21, 2014
 
$
0.69

 
$
43,130

March 3, 2014
 
0.18

 
11,250

Restricted Units
In May 2014, we granted awards to non-employee directors of the General Partner of 4,083 restricted common units at an average grant date price of $18.38 per unit, which vest over a period of three years, assuming continued service at vesting.

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


(10)
Related-Party Transactions
Sales and Receivables
Sales to related parties include motor fuels and asphalt sold to other Alon Energy subsidiaries at prices substantially determined by reference to market commodity pricing information. These sales are included in net sales in the consolidated statements of operations. Accounts receivable from related parties include sales of motor fuels and are shown separately on the consolidated balance sheets.
Costs Allocated from Alon Energy
The Partnership is a subsidiary of Alon Energy and is operated as a component of the integrated operations of Alon Energy. As such, the executive officers of Alon Energy, who are employed by another subsidiary of Alon Energy, also serve as executive officers of the General Partner and Alon Energy’s other subsidiaries.
(a)
Corporate Overhead Allocations
Alon Energy performs general corporate and administrative services and functions for us and their other subsidiaries, which include accounting, treasury, cash management, tax, information technology, insurance administration and claims processing, legal, environmental, risk management, audit, payroll and employee benefit processing and internal audit services. Alon Energy allocates the expenses actually incurred in performing these services to the Partnership based primarily on the estimated amount of time the individuals performing such services devote to our business and affairs relative to the amount of time they devote to the business and affairs of Alon Energy’s other subsidiaries. The management of Alon Energy and the General Partner consider these allocations to be reasonable. We record the amount of such allocations to our consolidated financial statements as selling, general and administrative expenses. Our allocation for selling, general and administrative expenses were $3,225 and $3,529, for the three months ended June 30, 2014 and 2013, respectively, and $5,968 and $6,444 for the six months ended June 30, 2014 and 2013, respectively.
(b)
Labor Costs
As we are operated as a component of Alon Energy’s integrated operations, we have no employees. As a result, employee expense costs for Alon Energy employees working in our operations have been allocated and recorded as payroll expense and included in direct operating expenses within the consolidated statements of operations. The allocated portion of Alon Energy’s employee expense costs included in direct operating expenses were $7,091 and $5,650 for the three months ended June 30, 2014 and 2013, respectively, and $13,706 and $11,958 for the six months ended June 30, 2014 and 2013, respectively.
(c)
Insurance Costs
Insurance costs related to the Big Spring refinery and wholesale marketing operations are allocated to us by Alon Energy based on estimated insurance premiums on a stand-alone basis relative to Alon Energy’s total insurance premium. Our allocation for insurance costs included in direct operating expenses were $1,818 and $2,658 for the three months ended June 30, 2014 and 2013, respectively, and $3,636 and $5,262 for the six months ended June 30, 2014 and 2013, respectively.
Leasing Agreements
In June 2014, we entered into six year lease agreements with a subsidiary of Alon Energy to lease equipment used at the Big Spring refinery. The lease agreements are effective July 1, 2014 and require fixed monthly payments amounting to $4,920 annually.
The transaction was reviewed and approved by the Conflicts Committee of our General Partner, in consultation with independent consultants.
Distributions
During the six months ended June 30, 2014, we paid cash distributions of $54,380, or $0.87 per unit. Total cash distributions paid to Alon Energy were $44,370. During the six months ended June 30, 2013, we paid cash distributions of $128,129, or $2.05 per unit. Total cash distributions paid to Alon Energy were $104,550.

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


(11)
Commitments and Contingencies
(a)
Commitments
In the normal course of business, we have long-term commitments to purchase, at market prices, utilities such as natural gas, electricity and water for use by our refinery, terminals and pipelines. We are also party to various refined product and crude oil supply and exchange agreements, which are typically short-term in nature or provide terms for cancellation.
(b)
Contingencies
We are involved in various legal actions arising in the ordinary course of business. We believe the ultimate disposition of these matters will not have a material effect on our financial position, results of operations or liquidity.
(c)
Environmental
We are subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These laws and regulations govern the discharge of materials into the environment and may require us to incur future obligations to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites; to remediate or restore these sites and to compensate others for damage to property and natural resources. These contingent obligations relate to sites owned by the Partnership and are associated with past or present operations. We are currently participating in environmental investigations, assessments and cleanups pertaining to the refinery, pipelines and terminals. We may be involved in additional future environmental investigations, assessments and cleanups. The magnitude of future costs are unknown and will depend on factors such as the nature and contamination at many sites, the timing, extent and method of the remedial actions which may be required, and the determination of our liability in proportion to other responsible parties.
Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Substantially all amounts accrued are expected to be paid out over the next 15 years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.
We have accrued environmental remediation obligations of $6,947 ($1,307 accrued liability and $5,640 non-current liability) at June 30, 2014 and December 31, 2013.
(12)
Subsequent Event
Distribution Declared
In August 2014, the board of directors of the General Partner declared a cash distribution to our common unitholders of approximately $8,130, or $0.13 per common unit. The cash distribution will be paid on August 25, 2014 to unitholders of record at the close of business on August 18, 2014.

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ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
References in this report to “we,” “our,” “us” or like terms, refer to Alon USA Partners, LP and its subsidiaries, also referred to as the “Partnership” or “Alon.” Unless the context otherwise requires, references in this report to “Alon Energy” refers to Alon USA Energy, Inc. and any of its subsidiaries other than the Partnership, its subsidiaries and its general partner.
The following discussion of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2013.
Forward-Looking Statements
Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.
Forward-looking statements reflect our current expectations of future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations and cash flows.
Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:
changes in general economic conditions and capital markets;
changes in the underlying demand for our products;
the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;
changes in the spread between West Texas Intermediate (“WTI”) Cushing crude oil and West Texas Sour (“WTS”) crude oil or WTI Midland crude oil;
changes in the spread between Brent crude oil and WTI Cushing crude oil;
the effects of transactions involving forward contracts and derivative instruments;
actions of customers and competitors;
termination of our Supply and Offtake Agreement with J. Aron & Company (“J. Aron”), under which J. Aron is our largest supplier of crude oil and our largest customer of refined products. Additionally upon termination of the Supply and Offtake Agreement, we are obligated to purchase the crude oil and refined product inventories then owned by J. Aron at then current market prices;
changes in fuel and utility costs incurred by our refinery;
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 the Renewable Fuel Standards 2 (“RFS2”) requirements, including the availability, cost and price volatility of Renewable Identification Numbers (“RINs”);
the effects and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;
operating hazards, natural disasters, casualty losses and other matters beyond our control;
the effect of any national or international financial crisis on our business and financial condition; and
the other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2013 under the caption “Risk Factors.”

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Any one of these factors or a combination of these factors could materially affect our future results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.
Company Overview
We are a Delaware limited partnership formed in August 2012 by Alon USA Energy, Inc. (NYSE: ALJ) (“Alon Energy”) to own, operate and grow our strategically located refining and petroleum products marketing business. Our integrated downstream business operates primarily in the South Central and Southwestern regions of the United States. We own and operate a crude oil refinery in Big Spring, Texas with total crude oil throughput capacity of approximately 73,000 barrels per day (“bpd”), which we refer to as our Big Spring refinery. We refine crude oil into finished products, which we market primarily in West and Central Texas, Oklahoma, New Mexico and Arizona through our wholesale distribution network to both Alon Energy’s retail convenience stores and other third-party distributors.
We sell refined products in both the wholesale rack and bulk markets. We focus our marketing of transportation fuels on West and Central Texas, Oklahoma, New Mexico and Arizona through our physically-integrated refining and distribution system. We distribute fuel products through a product pipeline and terminal network of seven pipelines and five terminals that we own or access through leases or long-term throughput agreements.
Second Quarter Operational and Financial Highlights
Operating income for the second quarter of 2014 was $19.0 million, compared to $54.8 million for the same period last year. Our operational and financial highlights for the second quarter of 2014 include the following:
During the second quarter of 2014, we completed the planned turnaround and the vacuum tower project at the Big Spring refinery, which has allowed us to increase the refinery’s crude oil throughput by 3,000 bpd to 73,000 bpd.
Big Spring refinery average throughput for the second quarter of 2014 was 38,994 bpd compared to 72,124 bpd for the second quarter of 2013. The lower throughput was primarily due to the planned turnaround during the second quarter of 2014.
Operating margin at the Big Spring refinery was $17.04 per barrel for the second quarter of 2014 compared to $14.99 per barrel for the same period in 2013. This increase in operating margin was primarily due to a widening of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread, partially offset by a lower Gulf Coast 3/2/1 crack spread. During the second quarter of 2014, we generated RINs credits of $0.8 million, as a result of reduced production during the planned turnaround, compared to RINs costs of $8.0 million for the second quarter of 2013.
The average WTI Cushing to WTS spread for the second quarter of 2014 was $7.88 per barrel compared to $0.36 per barrel for the same period in 2013. The average WTI Cushing to WTI Midland spread for the second quarter of 2014 was $8.37 per barrel compared to $0.14 per barrel for the same period in 2013.
The average Gulf Coast 3/2/1 crack spread was $16.42 per barrel for the second quarter of 2014 compared to $21.17 per barrel for the second quarter of 2013, which was primarily influenced by a reduction in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for the second quarter of 2014 was $7.56 per barrel compared to $12.51 per barrel for the same period in 2013.
During the second quarter of 2014, we paid cash distributions of $43.1 million, or $0.69 per unit, compared to $92.5 million, or $1.48 per unit during the second quarter of 2013.
Major Influences on Results of Operations
Earnings and cash flow are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. These prices depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation. While our sales and operating revenues fluctuate significantly with movements in crude oil and refined product prices, it is the spread between crude oil and refined product prices, and not necessarily fluctuations in those prices, that affect our earnings.

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In order to measure our operating performance, we compare our per barrel refinery operating margin to certain industry benchmarks. We calculate this margin for the Big Spring refinery by dividing the refinery’s gross margin by its throughput volumes. Gross margin is the difference between net sales and cost of sales.
We compare our Big Spring refinery operating margin to the Gulf Coast 3/2/1 crack spread, which is intended to approximate the refinery’s crude slate and product yield. A Gulf Coast 3/2/1 crack spread is calculated assuming that three barrels of WTI Cushing crude oil are converted, or cracked, into two barrels of Gulf Coast conventional gasoline and one barrel of Gulf Coast ultra-low sulfur diesel.
Our Big Spring refinery is capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate and sweet crude oils. We measure the cost advantage of refining sour crude oil by calculating the difference between the price of WTI Cushing crude oil and the price of WTS, a medium, sour crude oil. We refer to this differential as the WTI Cushing/WTS, or sweet/sour, spread. A widening of the sweet/sour spread can favorably influence the operating margin for our Big Spring refinery. The Big Spring refinery’s crude oil input is primarily comprised of WTS and WTI Midland priced crude oil.
In addition, we have been able to capitalize on the oversupply of West Texas crudes in Midland, the largest origination terminal for West Texas crude oil, resulting from increased production in the Permian Basin coupled with infrastructure constraints. Although West Texas crudes are typically transported to Cushing and to the Gulf Coast for sale, current logistical and infrastructure constraints are limiting the ability of Permian Basin producers to transport their production to Cushing and to the Gulf Coast. The resulting oversupply of West Texas crudes at Midland has depressed Midland crude prices and enabled us to obtain an increased portion of our crude supply at discounted prices to Cushing. Moreover, by sourcing West Texas crude oils at Midland, we are able to eliminate the cost of transporting crude to and from Cushing. The WTI Cushing less WTI Midland spread represents the differential between the average per barrel price of WTI Cushing crude oil and the average per barrel price of WTI Midland crude oil. A widening of the WTI Cushing less WTI Midland spread can favorably influence the operating margin for our Big Spring refinery.
Global product prices are influenced by the price of Brent crude which is a global benchmark crude. Global product prices set product prices in the U.S. As a result, the Big Spring refinery is influenced by the spread between Brent crude and WTI Cushing. The Brent less WTI Cushing spread represents the differential between the average per barrel price of Brent crude oil and the average per barrel price of WTI Cushing crude oil. A widening of the spread between Brent and WTI Cushing can favorably influence the operating margins for our Big Spring refinery.
Our results of operations are also significantly affected by our refinery’s 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, our operating results 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 refinery is 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 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.
Factors Affecting Comparability
Our financial condition and operating results over the three and six months ended June 30, 2014 and 2013 have been influenced by the following factors which are fundamental to understanding comparisons of our period-to-period financial performance.
Maintenance and Turnaround Impact on Crude Oil Throughput
During the three months ended June 30, 2014, we completed both the planned turnaround and the vacuum tower project at the refinery, which will increase our distillate yield, improve energy efficiency and allow us to better optimize our crude slate. Due to these events, refinery throughput was reduced during the three and six months ended June 30, 2014.

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Renewable Fuel Standard
During the three months ended June 30, 2014, we generated RINs credits of $0.8 million, as a result of reduced production during the planned turnaround, compared to RINs costs of $8.0 million for the three months ended June 30, 2013. RINs costs were $2.2 million and $8.0 million for the six months ended June 30, 2014 and 2013, respectively. We utilized carryover RINs from 2012 to completely offset our first quarter 2013 RINs deficit.
Results of Operations
The period-to-period comparisons of our results of operations have been prepared using the historical periods included in our consolidated financial statements. We refer to our financial statement line items in the explanation of our period-to-period changes in results of operations. Below are general definitions of what those line items include and represent.
Net sales. Net sales consist principally of sales of refined petroleum products and are mainly affected by refined product prices, changes to the product mix and volume changes caused by operations. Product mix refers to the percentage of production represented by higher value motor fuels, such as gasoline, rather than lower value finished products.
Cost of sales. Cost of sales includes principally crude oil, blending materials, other raw materials and transportation costs. Cost of sales excludes depreciation and amortization, which is presented separately in the consolidated statements of operations.
Direct operating expenses. Direct operating expenses include costs associated with the actual operations of the refinery, such as energy and utility costs, routine maintenance, labor, insurance and environmental compliance costs. All operating costs associated with our crude oil and product pipelines are considered to be transportation costs and are reflected in cost of sales in the consolidated statements of operations.
Selling, general and administrative expenses. Selling, general and administrative expenses, or SG&A, primarily include corporate overhead costs and marketing expenses. These costs also include actual costs incurred by Alon Energy and allocated to us.
Depreciation and amortization. Depreciation and amortization represents an allocation to expense within the consolidated statements of operations of the carrying value of capital assets. The value is allocated based on the straight-line method over the estimated useful life of the related asset. Depreciation and amortization also includes deferred turnaround and catalyst replacement costs. Turnaround and catalyst replacement costs are currently deferred and amortized on a straight-line basis beginning the month after the completion of the turnaround and ending immediately prior to the next scheduled turnaround.
Operating income. Operating income represents our net sales less our total operating costs and expenses.
Interest expense. Interest expense includes interest expense, letters of credit, financing costs associated with crude oil purchases, financing fees, and amortization of both original issuance discount and deferred debt issuance costs but excludes capitalized interest.

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ALON USA PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED
Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for the three and six months ended June 30, 2014 and 2013. The following data should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this Form 10-Q. All information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” except for Balance Sheet data as of December 31, 2013 is unaudited.
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
 
(dollars in thousands, except per unit data, per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
 
 
 
 
 
 
 
Net sales (1)
$
725,852

 
$
865,694

 
$
1,582,312

 
$
1,669,861

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales
665,398

 
767,322

 
1,424,444

 
1,417,525

Direct operating expenses
25,152

 
27,314

 
54,093

 
57,736

Selling, general and administrative expenses
6,784

 
5,065

 
11,152

 
12,730

Depreciation and amortization
9,508

 
11,243

 
19,575

 
23,307

Total operating costs and expenses
706,842

 
810,944

 
1,509,264

 
1,511,298

Operating income
19,010

 
54,750

 
73,048

 
158,563

Interest expense
(11,569
)
 
(8,970
)
 
(22,893
)
 
(18,362
)
Other income, net
601

 
14

 
613

 
18

Income before state income tax expense
8,042

 
45,794

 
50,768

 
140,219

State income tax expense
240

 
473

 
725

 
1,373

Net income
$
7,802

 
$
45,321

 
$
50,043

 
$
138,846

Earnings per unit
$
0.12

 
$
0.73

 
$
0.80

 
$
2.22

Weighted average common units outstanding (in thousands)
62,504

 
62,502

 
62,504

 
62,502

Cash distribution per unit
$
0.69

 
$
1.48

 
$
0.87

 
$
2.05

CASH FLOW DATA:
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
Operating activities
$
(35
)
 
$
(13,403
)
 
$
45,232

 
$
153,243

Investing activities
(18,259
)
 
(7,257
)
 
(36,886
)
 
(13,976
)
Financing activities
(68,955
)
 
(143,128
)
 
(80,830
)
 
(178,584
)
OTHER DATA:
 
 
 
 
 
 
 
Adjusted EBITDA (2)
$
29,119

 
$
66,007

 
$
93,236

 
$
181,888

Capital expenditures
7,277

 
6,216

 
11,439

 
9,157

Capital expenditures for turnarounds and catalysts
10,982

 
1,041

 
25,447

 
4,819

KEY OPERATING STATISTICS:
 
 
 
 
 
 
 
Per barrel of throughput:
 
 
 
 
 
 
 
Refinery operating margin (3)
$
17.04

 
$
14.99

 
$
15.56

 
$
21.18

Refinery direct operating expense (4)
7.09

 
4.16

 
5.33

 
4.85

PRICING STATISTICS:
 
 
 
 
 
 
 
Crack spreads (per barrel):
 
 
 
 
 
 
 
Gulf Coast 3/2/1
$
16.42

 
$
21.17

 
$
16.61

 
$
24.76

WTI Cushing crude oil (per barrel)
$
103.04

 
$
94.20

 
$
100.86

 
$
94.23

Crude oil differentials (per barrel):
 
 
 
 
 
 
 
WTI Cushing less WTI Midland
$
8.37

 
$
0.14

 
$
5.96

 
$
3.91

WTI Cushing less WTS
7.88

 
0.36

 
5.79

 
5.86

Brent less WTI Cushing
7.56

 
12.51

 
10.25

 
16.98

Product price (dollars per gallon):
 
 
 
 
 
 
 
Gulf Coast unleaded gasoline
$
2.81

 
$
2.69

 
$
2.73

 
$
2.77

Gulf Coast ultra-low sulfur diesel
2.92

 
2.86

 
2.93

 
2.97

Natural gas (per MMBtu)
4.58

 
4.02

 
4.65

 
3.76


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June 30,
2014
 
December 31,
2013
BALANCE SHEET DATA (end of period):
(dollars in thousands)
Cash and cash equivalents
$
81,099

 
$
153,583

Working capital
(17,346
)
 
18,007

Total assets
812,323

 
849,924

Total debt
343,344

 
344,322

Total debt less cash and cash equivalents
262,245

 
190,739

Total partners’ equity
141,145

 
145,442

THROUGHPUT AND PRODUCTION DATA:
For the Three Months Ended
 
For the Six Months Ended
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
WTS crude
12,634

 
32.4

 
53,627

 
74.4

 
23,927

 
42.7

 
49,446

 
75.1

WTI crude
23,391

 
60.0

 
17,180

 
23.8

 
29,652

 
52.9

 
14,380

 
21.8

Blendstocks
2,969

 
7.6

 
1,317

 
1.8

 
2,471

 
4.4

 
2,009

 
3.1

Total refinery throughput (5)
38,994

 
100.0

 
72,124

 
100.0

 
56,050

 
100.0

 
65,835

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
17,484

 
45.1

 
35,057

 
48.7

 
26,835

 
48.0

 
32,436

 
49.4

Diesel/jet
12,315

 
31.8

 
24,748

 
34.4

 
18,461

 
33.0

 
22,038

 
33.6

Asphalt
1,660

 
4.3

 
4,453

 
6.2

 
2,529

 
4.5

 
3,909

 
6.0

Petrochemicals
1,825

 
4.7

 
4,628

 
6.4

 
3,111

 
5.5

 
4,179

 
6.4

Other
5,483

 
14.1

 
3,088

 
4.3

 
5,022

 
9.0

 
3,029

 
4.6

Total refinery production (6)
38,767

 
100.0

 
71,974

 
100.0

 
55,958

 
100.0

 
65,591

 
100.0

Refinery utilization (7)
 
 
85.4
%
 
 
 
101.2
%
 
 
 
95.7
%
 
 
 
97.1
%
(1)
Includes sales to related parties of $152,170 and $156,043 for the three months and $291,183 and $297,942 for the six months ended June 30, 2014 and 2013, respectively.
(2)
Adjusted EBITDA represents earnings before state income tax expense, interest expense and depreciation and amortization. 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 state income tax expense, interest expense 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 changes in or cash requirements for our working capital needs; and
Our calculation of Adjusted EBITDA may differ from EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.
Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.

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The following table reconciles net income to Adjusted EBITDA for the three and six months ended June 30, 2014 and 2013:
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
 
(dollars in thousands)
Net income
$
7,802

 
$
45,321

 
$
50,043

 
$
138,846

State income tax expense
240

 
473

 
725

 
1,373

Interest expense
11,569

 
8,970

 
22,893

 
18,362

Depreciation and amortization
9,508

 
11,243

 
19,575

 
23,307

Adjusted EBITDA
$
29,119

 
$
66,007

 
$
93,236

 
$
181,888

(3)
Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales by the refinery’s throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margin to these crack spreads to assess our operating performance relative to other participants in our industry.
(4)
Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses by total throughput volumes.
(5)
Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.
(6)
Total refinery production represents the barrels per day of various refined products produced from processing crude and other refinery feedstocks through the crude units and other conversion units.
(7)
Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.

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Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013
Net Sales. Net sales for the three months ended June 30, 2014 were $725.9 million, compared to $865.7 million for the three months ended June 30, 2013, a decrease of $139.8 million. This decrease was due to lower refinery throughput, partially offset by increased sales of purchased products and higher refined product prices during the three months ended June 30, 2014 compared to the same period last year. Refinery average throughput for the three months ended June 30, 2014 was 38,994 bpd compared to 72,124 bpd for the three months ended June 30, 2013, a decrease of 45.9%. During the three months ended June 30, 2014, we completed both the planned turnaround and the vacuum tower project at the refinery, which will increase our distillate yield, improve energy efficiency and allow us to better optimize our crude slate. Due to these events, refinery throughput was reduced during the three months ended June 30, 2014. The average per gallon price of Gulf Coast gasoline for the three months ended June 30, 2014 increased $0.12, or 4.5%, to $2.81, compared to $2.69 for the three months ended June 30, 2013. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the three months ended June 30, 2014 increased $0.06, or 2.1%, to $2.92, compared to $2.86 for the three months ended June 30, 2013.
Cost of Sales. Cost of sales for the three months ended June 30, 2014 were $665.4 million, compared to $767.3 million for the three months ended June 30, 2013, a decrease of $101.9 million. This decrease was primarily due to lower refinery throughput, partially offset by increased products purchased to meet contractual obligations during the planned turnaround.
Direct Operating Expenses. Direct operating expenses for the three months ended June 30, 2014 were $25.2 million, compared to $27.3 million for the three months ended June 30, 2013, a decrease of $2.1 million, or 7.7%. This decrease was primarily due to lower overall direct operating expenses as a result of the shut down for the turnaround as well as lower insurance costs.
Selling, General and Administrative Expenses. SG&A expenses for the three months ended June 30, 2014 were $6.8 million, compared to $5.1 million for the three months ended June 30, 2013, an increase of $1.7 million, or 33.3%, primarily due to higher employee related costs.
Depreciation and Amortization. Depreciation and amortization for the three months ended June 30, 2014 was $9.5 million, compared to $11.2 million for the three months ended June 30, 2013, a decrease of $1.7 million, or 15.2%. This decrease was primarily due to reduced amortization of turnaround and catalyst replacement costs during the three months ended June 30, 2014.
Operating Income. Operating income for the three months ended June 30, 2014 was $19.0 million, compared to $54.8 million for the three months ended June 30, 2013, a decrease of $35.8 million. This decrease was primarily due to the planned turnaround, partially offset by higher refinery operating margin. Refinery operating margin was $17.04 per barrel for the three months ended June 30, 2014, compared to $14.99 per barrel for the three months ended June 30, 2013. This increase in operating margin was primarily due to a widening of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread, partially offset by a lower Gulf Coast 3/2/1 crack spread. The average Gulf Coast 3/2/1 crack spread decreased to $16.42 per barrel for the three months ended June 30, 2014, compared to $21.17 per barrel for the three months ended June 30, 2013, which was primarily influenced by a reduction in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for the three months ended June 30, 2014 was $7.56 per barrel compared to $12.51 per barrel for the three months ended June 30, 2013. The WTI Cushing to WTS spread widened for the three months ended June 30, 2014 to $7.88 per barrel compared to $0.36 per barrel for the three months ended June 30, 2013. The WTI Cushing to WTI Midland spread widened to $8.37 per barrel for the three months ended June 30, 2014, compared to $0.14 per barrel for the three months ended June 30, 2013. Also impacting operating income and refinery operating margin during the three months ended June 30, 2014, were RINs credits of $0.8 million, generated as a result of reduced production during the planned turnaround, compared to RINs costs of $8.0 million for the three months ended June 30, 2013.
Interest Expense. Interest expense for the three months ended June 30, 2014 was $11.6 million, compared to $9.0 million for the three months ended June 30, 2013, an increase of $2.6 million. This increase was primarily due to higher financing costs associated with crude oil purchases as a result of a backwardated crude oil market.
Net Income. Net income for the three months ended June 30, 2014 was $7.8 million, compared to $45.3 million for the three months ended June 30, 2013, a decrease of $37.5 million. This decrease was attributable to the factors discussed above.
Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013
Net Sales. Net sales for the six months ended June 30, 2014 were $1,582.3 million, compared to $1,669.9 million for the six months ended June 30, 2013, a decrease of $87.6 million. This decrease was primarily due to lower refinery throughput and lower refined product prices, partially offset by increased sales of purchased products. Refinery average throughput for the six months ended June 30, 2014 was 56,050 bpd compared to 65,835 bpd for the six months ended June 30, 2013, a decrease of 14.9%. During the six months ended June 30, 2014, we completed both the planned turnaround and the vacuum tower project at our refinery, which will increase our distillate yield, improve energy efficiency and allow us to better optimize our crude

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slate. Due to these events, refinery throughput was reduced during the six months ended June 30, 2014. The average per gallon price of Gulf Coast gasoline for the six months ended June 30, 2014 decreased $0.04, or 1.4%, to $2.73, compared to $2.77 for the six months ended June 30, 2013. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the six months ended June 30, 2014 decreased $0.04, or 1.3%, to $2.93, compared to $2.97 for the six months ended June 30, 2013.
Cost of Sales. Cost of sales for the six months ended June 30, 2014 were $1,424.4 million, compared to $1,417.5 million for the six months ended June 30, 2013, an increase of $6.9 million. This increase was primarily due to an increase in crude oil prices and increased products purchased to meet contractual obligations during the planned turnaround, partially offset by reduced refinery throughput. The average price of WTI Cushing increased 7.0% to $100.86 per barrel for the six months ended June 30, 2014 from $94.23 per barrel for the six months ended June 30, 2013. The WTI Cushing to WTI Midland spread widened 52.4%, to $5.96 per barrel for the six months ended June 30, 2014, compared to $3.91 per barrel for the six months ended June 30, 2013. Additionally, cost of sales for the six months ended June 30, 2014 and 2013 includes RINs costs of $2.2 million and $8.0 million, respectively, for the purchase of RINs needed to satisfy our obligation to blend biofuels into the products we produce.
Direct Operating Expenses. Direct operating expenses for the six months ended June 30, 2014 were $54.1 million, compared to $57.7 million for the six months ended June 30, 2013, a decrease of $3.6 million, or 6.2%. This decrease was primarily due to lower major maintenance and insurance costs, partially offset by higher utility costs for the six months ended June 30, 2014.
Selling, General and Administrative Expenses. SG&A expenses for the six months ended June 30, 2014 were $11.2 million, compared to $12.7 million for the six months ended June 30, 2013, a decrease of $1.5 million, or 11.8%. This decrease was primarily due to lower marketing expenses for the six months ended June 30, 2014.
Depreciation and Amortization. Depreciation and amortization for the six months ended June 30, 2014 was $19.6 million, compared to $23.3 million for the six months ended June 30, 2013, a decrease of $3.7 million due to reduced amortization of turnaround and catalyst replacement costs.
Operating Income. Operating income for the six months ended June 30, 2014 was $73.0 million, compared to $158.6 million for the six months ended June 30, 2013, a decrease of $85.6 million. This decrease was primarily due to lower refinery operating margins and lower refinery throughput. Refinery operating margin was $15.56 per barrel for the six months ended June 30, 2014, compared to $21.18 per barrel for the six months ended June 30, 2013. This decrease in operating margin was primarily due to a lower Gulf Coast 3/2/1 crack spread, partially offset by a widening WTI Cushing to WTI Midland spread. The average Gulf Coast 3/2/1 crack spread decreased 32.9% to $16.61 per barrel for the six months ended June 30, 2014, compared to $24.76 per barrel for the six months ended June 30, 2013, which was primarily influenced by a reduction in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for the six months ended June 30, 2014 was $10.25 per barrel compared to $16.98 per barrel for the six months ended June 30, 2013. Also impacting operating income and refinery operating margin for the six months ended June 30, 2014 and 2013 were RINs costs of $2.2 million and $8.0 million, respectively.
Interest Expense. Interest expense was $22.9 million for the six months ended June 30, 2014, compared to interest expense of $18.4 million for the six months ended June 30, 2013, an increase of $4.5 million. This increase was primarily due to higher financing costs associated with crude oil purchases as a result of a backwardated crude oil market.
Net Income. Net income for the six months ended June 30, 2014 was $50.0 million, compared to $138.8 million for the six months ended June 30, 2013, a decrease of $88.8 million. This decrease was attributable to the factors discussed above.
Liquidity and Capital Resources
Our primary sources of liquidity are cash on hand, cash generated from our operating activities, borrowings under our revolving credit facility, inventory supply and offtake arrangement and other credit lines.
We have an agreement with J. Aron for the supply of crude oil that supports the operations of the Big Spring refinery. This arrangement substantially reduces our physical inventories and the associated need to issue letters of credit to support crude oil purchases. In addition, the structure allows us to acquire crude oil without the constraints of a maximum facility size during periods of high crude oil prices.
We believe that the aforementioned sources of funds and other sources of capital available to us will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next twelve months. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive, and other factors beyond our control.

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Cash Flows
The following table sets forth our consolidated cash flows for the six months ended June 30, 2014 and 2013:
 
For the Six Months Ended
 
June 30,
 
2014
 
2013
 
(dollars in thousands)
Cash provided by (used in):
 
 
 
Operating activities
$
45,232

 
$
153,243

Investing activities
(36,886
)
 
(13,976
)
Financing activities
(80,830
)
 
(178,584
)
Net decrease in cash and cash equivalents
$
(72,484
)
 
$
(39,317
)
Cash Flows Provided by Operating Activities
Net cash provided by operating activities was $45.2 million during the six months ended June 30, 2014 compared to $153.2 million during the six months ended June 30, 2013. The reduction in net cash provided by operating activities of $108.0 million was primarily attributable to lower net income after adjusting for non-cash items of $92.5 million, decreased cash provided by accounts payable and accrued liabilities of $41.7 million and higher cash used on increases of inventories of $24.3 million, partially offset by increased cash collected on accounts receivable of $60.2 million.
Cash Flows Used In Investing Activities
Net cash used in investing activities was $36.9 million during the six months ended June 30, 2014 compared to $14.0 million during the six months ended June 30, 2013. The increase in net cash used in investing activities of $22.9 million was primarily due to an increase in capital expenditures and capital expenditures for turnarounds and catalysts associated with the planned turnaround completed during the second quarter of 2014.
Cash Flows Used In Financing Activities
Net cash used in financing activities was $80.8 million during the six months ended June 30, 2014 compared to $178.6 million during the six months ended June 30, 2013. The reduction in net cash used in financing activities of $97.8 million was primarily attributable to lower distributions to unitholders of $73.7 million and reduced payments on financing arrangements of $23.8 million.
Indebtedness
Revolving Credit Facility. We have a $240.0 million revolving credit facility that can be used both for borrowings and the issuance of letters of credit. Borrowings of $100.0 million and $100.0 million and letters of credit of $59.0 million and $109.8 million were outstanding under this facility at June 30, 2014 and December 31, 2013, respectively.
Capital Spending
Each year the Board of Directors of our General Partner approves capital projects, including sustaining maintenance, regulatory and planned turnaround projects that our management is authorized to undertake in our annual capital budget. Additionally, at times when conditions warrant or as new opportunities arise, growth and profit improvement projects may be approved. Our total capital expenditure plan, including expenditures for catalysts and turnarounds, for 2014 is $67.0 million. Approximately $36.9 million has been spent during the six months ended June 30, 2014.
Contractual Obligations and Commercial Commitments
There have been no material changes outside the ordinary course of business from our contractual obligations and commercial commitments detailed in our Annual Report on Form 10-K for the year ended December 31, 2013.
Off-Balance Sheet Arrangements
We have no material off-balance sheet arrangements.
Critical Accounting Policies
We prepare our consolidated financial statements in conformity with GAAP. In order to apply these principles, we must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events, some of which we may have little or no control over.

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Our critical accounting policies are described under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2013. Certain critical accounting policies that materially affect the amounts recorded in our consolidated financial statements are the use of the LIFO method for valuing certain inventories and the deferral and subsequent amortization of costs associated with major turnarounds and catalysts replacements. No significant changes to these accounting policies have occurred subsequent to December 31, 2013.
New Accounting Standards and Disclosures
New accounting standards, if any, are disclosed in Note (1) Basis of Presentation included in the consolidated financial statements included in Item 1 of this report.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Changes in commodity prices, purchased fuel prices and interest rates are our primary sources of market risk. Alon Energy’s risk management committee oversees all activities associated with the identification, assessment and management of our market risk exposure.
Commodity Price Risk
We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refinery operations. Our financial results can be affected significantly by fluctuations in these prices, which depend on many factors, including demand for crude oil, gasoline and other refined products, changes in the economy, worldwide production levels, worldwide inventory levels and governmental regulatory initiatives. Alon Energy’s risk management strategy identifies circumstances in which we may utilize the commodity futures market to manage risk associated with these price fluctuations.
In order to manage the uncertainty relating to inventory price volatility, we have consistently applied a policy of maintaining inventories at or below a targeted operating level. In the past, circumstances have occurred, such as timing of crude oil cargo deliveries, turnaround schedules or shifts in market demand that have resulted in variances between our actual inventory level and our desired target level. Upon the review and approval of Alon Energy’s risk management committee, we may utilize the commodity futures market to manage these anticipated inventory variances.
We maintain inventories of crude oil, refined products and blendstocks, the values of which are subject to wide fluctuations in market prices driven by world economic conditions, regional and global inventory levels and seasonal conditions. As of June 30, 2014, we held 0.7 million barrels of crude oil and refined product inventories valued under the LIFO valuation method. Market value exceeded carrying value of LIFO costs by $24.7 million. We refer to this excess as our LIFO reserve. If the market value of these inventories had been $1.00 per barrel lower, our LIFO reserve would have been reduced by $0.7 million.
All commodity derivative contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section of our consolidated financial statements. “Forwards” represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period. “Futures” represent trades which have been executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period. A “long” represents an obligation to purchase product and a “short” represents an obligation to sell product.
The following table provides information about our commodity derivative contracts as of June 30, 2014:
Description
 
Contract Volume
 
Wtd Avg Purchase
 
Wtd Avg Sales
 
Contract
 
Market
 
Gain
of Activity
 
(barrels)
 
Price/BBL
 
Price/BBL
 
 Value
 
Value
 
(Loss)
 
 
 
 
 
 
 
 
(in thousands)
Forwards-long (Crude)
 
2,410

 
$
96.24

 
$

 
$
232

 
$
236

 
$
4

Forwards-long (Gasoline)
 
338,986

 
126.60

 

 
42,917

 
43,382

 
465

Forwards-long (Distillate)
 
142,600

 
125.57

 

 
17,906

 
17,893

 
(13
)
Forwards-short (Jet)
 
(26,766
)
 

 
123.56

 
(3,307
)
 
(3,287
)
 
20

Forwards-long (Slurry)
 
1,179

 
92.10

 

 
109

 
109

 

Forwards-long (Catfeed)
 
65,326

 
121.29

 

 
7,924

 
7,985

 
61

Forwards-long (Slop)
 
10,438

 
95.15

 

 
993

 
995

 
2

Forwards-short (Propane)
 
(29,981
)
 

 
41.73

 
(1,251
)
 
(1,270
)
 
(19
)
Futures-short (Crude)
 
(145,000
)
 

 
105.47

 
(15,293
)
 
(15,279
)
 
14

Futures-short (Gasoline)
 
(460,000
)
 

 
126.50

 
(58,189
)
 
(58,796
)
 
(607
)
Futures-short (Distillate)
 
(150,000
)
 

 
123.25

 
(18,488
)
 
(18,744
)
 
(256
)
Interest Rate Risk
As of June 30, 2014, our outstanding debt balance of $346.3 million, excluding discounts, was subject to floating interest rates, of which $246.3 million was charged interest at the Eurodollar rate (with a floor of 1.25%) plus a margin of 8.00% and $100.0 million was charged interest at the Eurodollar rate plus 3.5%, subject to a minimum interest rate of 4.0%.
An increase of 1% in the Eurodollar rate on indebtedness would result in an increase in our interest expense of approximately $0.7 million per year.

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ITEM 4. CONTROLS AND PROCEDURES
(1)
Disclosure controls and procedures.
Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as amended (the “Exchange Act”)) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosures.
(2)
Changes in internal control over financial reporting.
There has been no change in our internal control over financial reporting (as described in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. We are transitioning our assessment of our internal control effectiveness over financial reporting from the criteria outlined by the 1992 framework of the Committee of Sponsoring Organizations of the Treadway Commission to its 2013 framework. We expect to complete this transition during 2014.

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PART II. OTHER INFORMATION
ITEM 6. EXHIBITS
Exhibit
 
 
Number
 
Description of Exhibit
10.1
 
Amendment to Supply and Offtake Agreement dated as of February 1, 2013 between J. Aron & Company and Alon USA, LP (incorporated by reference to Exhibit 10.5 to Alon USA Energy, Inc.’s Quarterly Report on Form 10-Q filed on August 8, 2014, SEC File No. 001-32567).
31.1
 
Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2
 
Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1
 
Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
101
 
The following financial information from Alon USA Partners, LP’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows and (iv) Notes to the Consolidated Financial Statements.


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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
Alon USA Partners, LP
 
 
By:  
Alon USA Partners GP, LLC
 
 
 
its general partner
 
 
 
Date:
August 8, 2014
By:  
/s/ David Wiessman
 
 
 
David Wiessman 
 
 
 
Executive Chairman of the Board
 
 
 
 
 
 
 
 
Date:
August 8, 2014
By:  
/s/ Paul Eisman
 
 
 
Paul Eisman
 
 
 
President, Chief Executive Officer and Director
 
 
 
 
 
 
 
 
Date:
August 8, 2014
By:  
/s/ Shai Even
 
 
 
Shai Even 
 
 
 
Senior Vice President and Chief Financial Officer 
 
 
 
(Principal Accounting Officer)

26