UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
___________________________________________________
FORM 10-Q
þ
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2015
OR
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
FOR THE TRANSITION PERIOD FROM __________TO __________ 

Commission file number: 001-35742
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 July 31, 2015, was 62,510,039.

 
 



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,
2015
 
December 31,
2014
 
(unaudited)
 
 
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
149,884

 
$
106,325

Accounts and other receivables, net
81,842

 
68,545

Accounts and other receivables, net - related parties
11,888

 
9,466

Inventories
43,189

 
45,162

Prepaid expenses and other current assets
8,256

 
9,163

Total current assets
295,059

 
238,661

Property, plant and equipment, net
436,407

 
445,706

Other assets, net
76,291

 
85,879

Total assets
$
807,757

 
$
770,246

LIABILITIES AND PARTNERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
252,862

 
$
186,156

Accrued liabilities
39,531

 
54,566

Current portion of long-term debt
2,500

 
2,500

Total current liabilities
294,893

 
243,222

Other non-current liabilities
37,779

 
38,746

Long-term debt
278,920

 
299,876

Total liabilities
611,592

 
581,844

Commitments and contingencies (Note 11)

 

Partners’ equity:
 
 
 
General Partner

 

Common unitholders - 62,510,039 and 62,506,550 units issued and outstanding at June 30, 2015 and December 31, 2014, respectively
196,165

 
188,402

Total partners’ equity
196,165

 
188,402

Total liabilities and partners’ equity
$
807,757

 
$
770,246


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,
 
2015
 
2014
 
2015
 
2014
Net sales (1)
$
625,064

 
$
725,852

 
$
1,167,506

 
$
1,582,312

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales
507,122

 
665,398

 
957,717

 
1,424,444

Direct operating expenses
24,285

 
25,152

 
47,701

 
54,093

Selling, general and administrative expenses
10,215

 
6,784

 
16,118

 
11,152

Depreciation and amortization
13,591

 
9,508

 
27,584

 
19,575

Total operating costs and expenses
555,213

 
706,842

 
1,049,120

 
1,509,264

Operating income
69,851

 
19,010

 
118,386

 
73,048

Interest expense
(10,847
)
 
(11,569
)
 
(22,540
)
 
(22,893
)
Other income (loss), net
27

 
601

 
(14
)
 
613

Income before state income tax expense (benefit)
59,031

 
8,042

 
95,832

 
50,768

State income tax expense (benefit)
(395
)
 
240

 
(45
)
 
725

Net income
$
59,426

 
$
7,802

 
$
95,877

 
$
50,043

Earnings per unit
$
0.95

 
$
0.12

 
$
1.53

 
$
0.80

Weighted average common units outstanding (in thousands)
62,509

 
62,504

 
62,508

 
62,504

Cash distribution per unit
$
0.71

 
$
0.69

 
$
1.41

 
$
0.87

___________
(1)
Includes sales to related parties of $101,233 and $152,170 for the three months and $184,122 and $291,183 for the six months ended June 30, 2015 and 2014, 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,
 
2015
 
2014
Cash flows from operating activities:
 
 
 
Net income
$
95,877

 
$
50,043

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
Depreciation and amortization
27,584

 
19,575

Unit-based compensation
20

 

Deferred income taxes
(736
)
 

Amortization of debt issuance costs
1,098

 
1,018

Amortization of original issuance discount
294

 
272

Changes in operating assets and liabilities:
 
 
 
Accounts and other receivables, net
(13,297
)
 
37,608

Accounts and other receivables, net - related parties
(2,422
)
 
(1,021
)
Inventories
1,973

 
(21,300
)
Prepaid expenses and other current assets
907

 
(11,033
)
Other assets, net
1,500

 
(1,053
)
Accounts payable
36,571

 
(26,977
)
Accrued liabilities
(14,740
)
 
(10,959
)
Other non-current liabilities
(231
)
 
9,059

Net cash provided by operating activities
134,398

 
45,232

Cash flows from investing activities:
 
 
 
Capital expenditures
(7,786
)
 
(11,439
)
Capital expenditures for turnarounds and catalysts
(2,004
)
 
(25,447
)
Net cash used in investing activities
(9,790
)
 
(36,886
)
Cash flows from financing activities:
 
 
 
Distributions paid to unitholders
(16,224
)
 
(10,010
)
Distributions paid to unitholders - Alon Energy
(71,910
)
 
(44,370
)
Inventory agreement transactions
30,135

 
(25,200
)
Deferred debt issuance costs
(1,800
)
 

Revolving credit facility, net
(20,000
)
 

Payments on long-term debt
(1,250
)
 
(1,250
)
Net cash used in financing activities
(81,049
)
 
(80,830
)
Net increase (decrease) in cash and cash equivalents
43,559

 
(72,484
)
Cash and cash equivalents, beginning of period
106,325

 
153,583

Cash and cash equivalents, end of period
$
149,884

 
$
81,099

Supplemental cash flow information:
 
 
 
Cash paid for interest, net of capitalized interest
$
21,775

 
$
23,203

Cash paid for income tax
$
691

 
$
725

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.
We are a Delaware limited partnership formed in August 2012 by Alon Energy and its wholly-owned subsidiary Alon USA Partners GP, LLC (the “General Partner”). In November 2012, we completed our initial public offering of 11,500,000 common units representing limited partner interests. Our General Partner is owned 100% by Alon Energy and holds all of the non-economic general partner interests in the Partnership.
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 three and six months ended June 30, 2015 are not necessarily indicative of the operating results that may be realized for the year ending December 31, 2015.
Our consolidated balance sheet as of December 31, 2014 has been derived from the audited financial statements as of that date. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2014.
New Accounting Standards
In May 2014, the Financial Accounting Standards Board (“FASB”) and the International Accounting Standards Board jointly issued a comprehensive new revenue recognition standard that provides accounting guidance for all revenue arising from contracts to provide goods or services to customers. This standard is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets. The standard allows for either full retrospective adoption or modified retrospective adoption. In July 2015, the FASB voted to approve a one-year deferral of the effective date for the new revenue standard, making the requirements of the standard effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We are evaluating the guidance to determine the method of adoption and the impact this standard will have on our consolidated financial statements.
In February 2015, the FASB issued an accounting standards update making targeted changes to the current consolidation guidance. The new standard changes the way certain decisions are made related to substantive rights, related parties, and decision making fees when applying the variable interest entity consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The requirements from the updated standard are effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. We are evaluating the effect that adopting the updated guidance will have on our consolidated financial statements and related disclosures.
In April 2015, the FASB issued an accounting standards update simplifying the presentation of debt issuance costs. The updated standard requires that certain costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. The requirements from the updated standard are effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. We currently have debt issuance costs included as deferred charges in our consolidated balance sheets, which will be reclassified as a reduction of debt when we adopt the updated guidance.

4

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


In April 2015, the FASB issued an accounting standards update to address the effects of historical earnings per unit of a master limited partnership dropdown transaction. The standard requires a master limited partnership to allocate the earnings or losses of a transferred business for periods before the date of a dropdown of net assets accounted for as a common control transaction entirely to the general partner for purposes of calculating historical earnings per unit. The requirements from the updated standard are effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. We are evaluating the effect that adopting the updated guidance will have on our consolidated financial statements and related disclosures.
In July 2015, the FASB issued an accounting standards update simplifying the measurement of certain inventory. This updated standard simplifies the measurement of inventory by requiring certain inventory to be measured at the lower of cost or net realizable value. The amendments in this accounting standards update are effective for interim and annual periods beginning after December 15, 2016. This accounting standards update does not apply to the subsequent measurement of inventory measured using the last-in, first-out (“LIFO”) or retail inventory method, therefore the adoption of this guidance will not have a material effect on our financial position or results of operations.
(2)
Fair Value
We determine fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We classify financial assets and financial liabilities into the following fair value hierarchy:
Level 1 -     valued based on quoted prices in active markets for identical assets and liabilities;
Level 2 -     valued based on quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability; and
Level 3 -     valued based on unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
As required, we utilize valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy. We generally apply the “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.
The carrying amounts of our cash and cash equivalents, receivables, payables and accrued liabilities approximate fair value due to the short-term maturities of these assets and liabilities. The reported amounts of long-term debt approximate fair value. Derivative instruments are carried at fair value, which are based on quoted market prices. Derivative instruments are our only assets and liabilities measured at fair value on a recurring basis.
The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the consolidated balance sheets at June 30, 2015 and December 31, 2014:
 
Level 1
 
Level 2
 
Level 3
 
Total
As of June 30, 2015
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Fair value hedge
$

 
$
8,728

 
$

 
$
8,728

Liabilities:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
620

 

 

 
620

 
 
 
 
 
 
 
 
As of December 31, 2014
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
1,406

 
$

 
$

 
$
1,406

Fair value hedge

 
10,223

 

 
10,223


5

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


(3)
Derivative Financial Instruments
We selectively utilize crude oil and refined product commodity derivative contracts to reduce the risk associated with potential price changes on committed obligations as well as to reduce earnings volatility. We do not speculate using derivative instruments. Credit risk on our derivative instruments is mitigated by transacting with counterparties meeting established collateral and credit criteria.
Mark to Market
We have certain contracts that serve as economic hedges, which are derivatives used for risk management but not designated as hedges for financial accounting purposes. All economic hedge transactions are recorded at fair value and any changes in fair value between periods are recognized in earnings.
We have contracts that are used to fix prices on forecasted purchases of inventory, which we refer to as futures and forwards. Futures represent trades executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period. Forwards represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period.
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.
We have certain commodity contracts associated with the Supply and Offtake Agreement discussed in Note 5 that have been accounted for as a fair value hedge, which had purchase volumes of 290 thousand barrels of crude oil as of June 30, 2015.
The following tables present the effect of derivative instruments on the consolidated balance sheets:
 
As of June 30, 2015
 
Asset Derivatives
 
Liability Derivatives
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
 
 
$

 
Accrued liabilities
 
$
620

Total derivatives not designated as hedging instruments
 
 

 
 
 
620

 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Fair value hedge
Other assets
 
$
8,728

 
 
 
$

Total derivatives designated as hedging instruments
 
 
8,728

 
 
 

Total derivatives
 
 
$
8,728

 
 
 
$
620

 
As of December 31, 2014
 
Asset Derivatives
 
Liability Derivatives
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
Accounts receivable
 
$
2,629

 
Accrued liabilities
 
$
1,223

Total derivatives not designated as hedging instruments
 
 
2,629

 
 
 
1,223

 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Fair value hedge
Other assets
 
$
10,223

 
 
 
$

Total derivatives designated as hedging instruments
 
 
10,223

 
 
 

Total derivatives
 
 
$
12,852

 
 
 
$
1,223


6

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 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
 
2015
 
2014
 
2015
 
2014
Fair value hedge (1)
Interest expense
 
$
(4,418
)
 
$
(1,569
)
 
$
(1,495
)
 
$
(2,392
)
Total derivatives
 
 
$
(4,418
)
 
$
(1,569
)
 
$
(1,495
)
 
$
(2,392
)
___________
(1)
Changes in the fair value hedge are substantially offset by changes in the hedged item.
Derivatives not designated as hedging instruments:
 
 
 
Gain (Loss) Recognized in Income
 
 
 
For the Three Months Ended
 
For the Six Months Ended
 
 
 
June 30,
 
June 30,
 
Location
 
2015
 
2014
 
2015
 
2014
Commodity contracts (futures and forwards)
Cost of sales
 
$
(1,103
)
 
$
(2,898
)
 
$
(629
)
 
$
(2,275
)
Total derivatives
 
 
$
(1,103
)
 
$
(2,898
)
 
$
(629
)
 
$
(2,275
)
Offsetting Assets and Liabilities
Our derivative instruments are subject to master netting arrangements to manage counterparty credit risk associated with derivatives, and we offset the fair value amounts recorded for derivative instruments to the extent possible under these agreements on our consolidated balance sheets.
The following table presents offsetting information regarding our derivatives by type of transaction as of June 30, 2015 and December 31, 2014:
 
Gross Amounts of Recognized Assets/Liabilities
 
Gross Amounts offset in the Statement of Financial Position
 
Net Amounts Presented in the Statement of Financial Position
 
Gross Amounts Not offset in the Statement of Financial Position
 
Net Amount
 
 
 
Financial Instruments
 
Cash Collateral Pledged
 
As of June 30, 2015
 
 
 
 
 
 
 
 
 
 
Derivative Assets:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
192

 
$
(192
)
 
$

 
$

 
$

 
$

Fair value hedge
8,728

 

 
8,728

 

 

 
8,728

Derivative Liabilities:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
812

 
$
(192
)
 
$
620

 
$

 
$

 
$
620

 
 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2014
 
 
 
 
 
 
 
 
 
 
Derivative Assets:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
3,309

 
$
(680
)
 
$
2,629

 
$
(1,223
)
 
$

 
$
1,406

Fair value hedge
10,223

 

 
10,223

 

 

 
10,223

Derivative Liabilities:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
1,903

 
$
(680
)
 
$
1,223

 
$
(1,223
)
 
$

 
$


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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)


Compliance Program Market Risk
We are obligated by government regulations to blend a certain percentage of biofuels into the products that we produce and are consumed in the U.S. We purchase biofuels from third parties and blend those biofuels into our products, and each gallon of biofuel purchased includes a renewable identification number, or RIN. To the degree we are unable to blend biofuels at the required percentage, a RINs deficit is generated and we must acquire that number of RINs by the annual reporting deadline in order to remain in compliance with applicable regulations. Alternatively, if we have a RINs surplus, some of those RINs could be sold. Any such sales would be subject to our normal credit evaluation process.
We are exposed to market risk related to the volatility in the price of credits needed to comply with these governmental and regulatory programs. We manage this risk by purchasing RINs when prices are deemed favorable utilizing fixed price purchase contracts. Some of these contracts are derivative instruments; however, we elect the normal purchase and sale exception and do not record these contracts at their fair values.
RINs costs were $1,963 for the three months ended June 30, 2015, compared to generating RINs credits of $759 for the three months ended June 30, 2014 as a result of reduced production during the planned turnaround at our refinery. RINs costs were $6,501 and $2,167 for the six months ended June 30, 2015 and 2014, respectively. These amounts are reflected in cost of sales in the consolidated statements of operations.
(4)
Inventories
Carrying value of inventories consisted of the following:
 
June 30,
2015
 
December 31,
2014
Crude oil, refined products and blendstocks
$
25,427

 
$
30,239

Crude oil consignment inventory (Note 5)
7,571

 
5,278

Materials and supplies
10,191

 
9,645

Total inventories
$
43,189

 
$
45,162

The market value of refined products and blendstock inventories was less than inventories on a LIFO cost basis which resulted in recording a lower of cost or market reserve of $3,028 and $4,650 at June 30, 2015 and December 31, 2014, respectively. At June 30, 2015, the market value of crude oil inventories exceeded LIFO costs, net of the fair value hedged item, by $10,749. At December 31, 2014, the market value of crude oil inventories was equal to carrying value.
(5)
Inventory Financing Agreement
We have 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, and J. Aron agreed to buy, 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. As amended in February 2015, the Supply and Offtake Agreement has an initial term that expires in May 2021. J. Aron may elect to terminate the Supply and Offtake Agreement prior to the expiration of the initial term beginning in May 2018 and upon each anniversary thereof, on six months prior notice. We may elect to terminate in May 2020 on six months prior notice.
Following expiration or termination of the Supply and Offtake 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.
Associated with the Supply and Offtake Agreement, we have a fair value hedge of our inventory purchase commitment with J. Aron and crude oil inventory consigned to J. Aron (“crude oil consignment inventory”). Additionally, financing charges related to the Supply and Offtake Agreement are recorded as interest expense in the consolidated statements of operations.
At June 30, 2015 and December 31, 2014, we had net current payables to J. Aron for purchases of $7,434 and $10,544, respectively, and a consignment inventory receivable representing a deposit paid to J. Aron of $6,290 and $6,290, respectively. At June 30, 2015 and December 31, 2014, we had non-current liabilities for the original financing of $18,736 and $17,497, respectively, net of the related fair value hedge.

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


Additionally, we had current payables of $536 and $1,010 at June 30, 2015 and December 31, 2014, respectively, for forward commitments related to month-end consignment inventory target levels differing from projected levels and the associated pricing with these inventory level differences.
(6)
Property, Plant and Equipment, Net
Property, plant and equipment, net consisted of the following:
 
June 30,
2015
 
December 31,
2014
Refining facilities
$
693,441

 
$
685,036

Accumulated depreciation
(257,034
)
 
(239,330
)
Property, plant and equipment, net
$
436,407

 
$
445,706

(7)
Additional Financial Information
The following tables provide additional financial information related to the consolidated financial statements.
(a)
Other Assets, Net
 
June 30,
2015
 
December 31,
2014
Deferred turnaround and catalyst cost
$
46,710

 
$
54,310

Deferred debt issuance costs
6,427

 
5,725

Receivable from supply and offtake agreement (Note 5)
6,290

 
6,290

Fair value hedge (Note 5)
8,728

 
10,223

Other
8,136

 
9,331

Total other assets
$
76,291

 
$
85,879

(b)
Accrued Liabilities and Other Non-Current Liabilities
 
June 30,
2015
 
December 31,
2014
Accrued Liabilities:
 
 
 
Taxes other than income taxes, primarily excise taxes
$
27,918

 
$
41,357

Accrued finance charges
442

 
427

Environmental accrual (Note 11)
1,671

 
1,671

Commodity contracts
620

 
1,223

Other
8,880

 
9,888

Total accrued liabilities
$
39,531

 
$
54,566

 
 
 
 
Other Non-Current Liabilities:
 
 
 
Consignment inventory obligation (Note 5)
$
27,464

 
$
27,720

Environmental accrual (Note 11)
5,471

 
5,486

Asset retirement obligations
2,124

 
2,084

Other
2,720

 
3,456

Total other non-current liabilities
$
37,779

 
$
38,746


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


(8)
Indebtedness
Debt consisted of the following:
 
June 30,
2015
 
December 31,
2014
Term loan credit facility
$
241,420

 
$
242,376

Revolving credit facility
40,000

 
60,000

Total debt
281,420

 
302,376

Less: Current portion
2,500

 
2,500

Total long-term debt
$
278,920

 
$
299,876

Outstanding letters of credit under the revolving credit facility were $43,463 and $23,511 at June 30, 2015 and December 31, 2014, respectively.
The revolving credit facility contains maintenance financial covenants. At June 30, 2015, we were in compliance with these covenants.
In May 2015, the revolving credit facility was amended to, among other matters, extend the expiration date to May 2019. Borrowings under the revolving credit facility now bear interest at the Eurodollar rate plus 3.00% per annum.
(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, subject to the approval of the board of directors of the General Partner. The per unit amount of available cash to be distributed each quarter, if any, will be distributed within 60 days following the end of such quarter.
During the six months ended June 30, 2015, we paid the following cash distributions:
Date Paid
 
Distribution Amount Per Unit
 
Total Distribution Amount
March 2, 2015
 
$
0.70

 
$
43,755

May 26, 2015
 
0.71

 
44,379

Restricted Units
In May 2015, we granted awards to non-employee directors of the General Partner of 3,489 restricted common units at an average grant date price of $21.50 per unit, which vest over a period of 3 years, assuming continued service at vesting.
(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 includes sales of motor fuels and is shown separately on the consolidated balance sheets.

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


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 as selling, general and administrative expenses. Our allocation for selling, general and administrative expenses were $3,347 and $3,225, for the three months ended June 30, 2015 and 2014, respectively, and $5,972 and $5,968 for the six months ended June 30, 2015 and 2014, 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 to us and recorded as payroll expense in direct operating expenses. The allocated portion of Alon Energy’s employee expense costs included in direct operating expenses were $6,692 and $7,091 for the three months ended June 30, 2015 and 2014, respectively, and $13,024 and $13,706 for the six months ended June 30, 2015 and 2014, 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 $1,777 and $1,818 for the three months ended June 30, 2015 and 2014, respectively, and $3,321 and $3,636 for the six months ended June 30, 2015 and 2014, respectively.
Leasing Agreements
In June 2014, we entered into six-year lease agreements with a subsidiary of Alon Energy to lease equipment at the Big Spring refinery. The lease agreements were effective July 1, 2014 and require fixed monthly payments amounting to $4,920 annually. For the three and six months ended June 30, 2015, we recorded selling, general and administrative expense of $1,230 and $2,460, respectively, related to these agreements.
Distributions
During the six months ended June 30, 2015, we paid cash distributions of $88,134, or $1.41 per unit. The total cash distribution paid to Alon Energy was $71,910. During the six months ended June 30, 2014, we paid cash distributions of $54,380, or $0.87 per unit. The total cash distribution paid to Alon Energy was $44,370.
(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.

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


(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 cannot be determined with any degree of reliability.
We have accrued environmental remediation obligations of $7,142 ($1,671 current liability and $5,471 non-current liability) at June 30, 2015, and $7,157 ($1,671 accrued liability and $5,486 non-current liability) at December 31, 2014.
(12)
Subsequent Event
Distribution Declared
On July 31, 2015, the board of directors of the General Partner declared a cash distribution to our common unitholders of approximately $65,010, or $1.04 per common unit. The cash distribution will be paid on August 25, 2015 to unitholders of record at the close of business on August 18, 2015.

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ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
References in this report to the “Partnership,” “Alon,” “we,” “our,” “us” or like terms, refer to Alon USA Partners, LP and its consolidated subsidiaries. Unless the context otherwise requires, references in this report to “Alon Energy” refers to Alon USA Energy, Inc. and any of its consolidated 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, 2014.
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 failures 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 and cost of compliance with the renewable fuel standards program, including the availability, cost and price volatility of renewable identification numbers;
the effects and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;
the effects of seasonality on demand for our products;
the level of competition from other petroleum refiners;
the easing of logistical and infrastructure constraints at Cushing;

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operating hazards, accidents, fires, severe weather, floods and other natural disasters, casualty losses and other matters beyond our control, which could result in unscheduled downtime;
the effect of any national or international financial crisis on our business and financial condition; and
the other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2014 under the caption “Risk Factors.”
Any one of these factors or a combination of these factors could materially affect our future results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.
Company Overview
We are a limited partnership formed in August 2012 and engaged principally in the business of operating a crude oil refinery in Big Spring, Texas with a crude oil throughput capacity of 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 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 2015 was $69.9 million, compared to $19.0 million for the same period last year. Our operational and financial highlights for the second quarter of 2015 include the following:
Big Spring refinery average throughput for the second quarter of 2015 was 75,491 bpd compared to 38,994 bpd for the second quarter of 2014. During the second quarter of 2014, refinery throughput was reduced as we completed both the planned turnaround and the vacuum tower project.
Operating margin at the Big Spring refinery was $17.22 per barrel for the second quarter of 2015 compared to $17.04 per barrel for the same period in 2014. This increase in operating margin was primarily due to improved light product yields, partially offset by the industry margin environment. The contango environment in the second quarter of 2015 created a cost of crude benefit of $1.90 per barrel compared to the backwardated environment creating a cost of crude detriment of $0.93 per barrel for the same period in 2014.
The average Gulf Coast 3/2/1 crack spread was $19.71 per barrel for the second quarter of 2015 compared to $16.42 per barrel for the second quarter of 2014.
The average WTI Cushing to WTS spread for the second quarter of 2015 was $(0.21) per barrel compared to $7.88 per barrel for the same period in 2014. The average WTI Cushing to WTI Midland spread for the second quarter of 2015 was $0.60 per barrel compared to $8.37 per barrel for the same period in 2014.
During the second quarter of 2015, we generated cash available for distribution of $1.04 per unit, compared to $0.13 per unit during the second quarter of 2014.
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, not necessarily fluctuations in those prices, that affect our earnings.
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 (exclusive of certain inventory adjustments).
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.

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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 crudes.
In addition, we have been able to capitalize on the oversupply of West Texas crudes in Midland, the largest origination terminal for West Texas crude oil, resulting from increased production and infrastructure constraints in the Permian Basin. Although West Texas crudes are typically transported to Cushing and to the Gulf Coast for sale, current logistical and infrastructure constraints are limiting the ability of Permian Basin producers to transport their production to Cushing and to the Gulf Coast. The resulting oversupply of West Texas crudes at Midland has depressed Midland crude prices and enabled us to obtain an increased portion of our crude supply at discounted prices to Cushing. Moreover, by sourcing West Texas crudes at Midland, we are able to eliminate the cost of transporting crude to and from Cushing. The WTI Cushing less WTI Midland spread represents the differential between the average per barrel price of WTI Cushing crude oil and the average per barrel price of WTI Midland crude oil. A widening of the WTI Cushing less WTI Midland spread will favorably influence the operating margin for our Big Spring refinery. Alternatively, an easing of the current logistical and infrastructure constraints through new pipeline construction or expansion could reduce this differential, which will have an adverse effect on our margins.
Recently, the additional takeaway capacity moving crude from Midland to the Gulf Coast has caused a contraction of the WTI Cushing less WTI Midland spread. In addition, the relative small growth in WTS production compared to WTI production and the relative high demand for WTS has caused a contraction of the WTI Cushing less WTS spread.
Global product prices are influenced by the price of Brent crude which is a global benchmark crude. Global product prices influence product prices in the U.S. As a result, 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 will 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 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 last-in, first-out (“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, 2015 and 2014 have been influenced by the following factors which are fundamental to understanding comparisons of our period-to-period financial performance.
Maintenance and Reduced Crude Oil Throughput
During the three months ended June 30, 2014, we completed both the planned turnaround and the vacuum tower project at the Big Spring refinery, which increased our distillate yield, improved energy efficiency and allowed us to better optimize our crude slate. Due to these events, refinery throughput was reduced at the Big Spring refinery during the three and six months ended June 30, 2014.

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Table of Contents

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, which include costs associated with our crude oil and product pipelines. 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.
Selling, general and administrative expenses. Selling, general and administrative expenses, or SG&A, primarily include corporate overhead costs and wholesale 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, 2015 and 2014. The following data should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this Form 10-Q. All information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” except for Balance Sheet data as of December 31, 2014 is unaudited.
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
 
(dollars in thousands, except per unit data, per barrel data and pricing statistics)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
 
 
Net sales (1)
$
625,064

 
$
725,852

 
$
1,167,506

 
$
1,582,312

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales
507,122

 
665,398

 
957,717

 
1,424,444

Direct operating expenses
24,285

 
25,152

 
47,701

 
54,093

Selling, general and administrative expenses
10,215

 
6,784

 
16,118

 
11,152

Depreciation and amortization
13,591

 
9,508

 
27,584

 
19,575

Total operating costs and expenses
555,213

 
706,842

 
1,049,120

 
1,509,264

Operating income
69,851

 
19,010

 
118,386

 
73,048

Interest expense
(10,847
)
 
(11,569
)
 
(22,540
)
 
(22,893
)
Other income (loss), net
27

 
601

 
(14
)
 
613

Income before state income tax expense (benefit)
59,031

 
8,042

 
95,832

 
50,768

State income tax expense (benefit)
(395
)
 
240

 
(45
)
 
725

Net income
$
59,426

 
$
7,802

 
$
95,877

 
$
50,043

Earnings per unit
$
0.95

 
$
0.12

 
$
1.53

 
$
0.80

Weighted average common units outstanding (in thousands)
62,509

 
62,504

 
62,508

 
62,504

Cash distribution per unit
$
0.71

 
$
0.69

 
$
1.41

 
$
0.87

CASH FLOW DATA:
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
Operating activities
$
107,311

 
$
(35
)
 
$
134,398

 
$
45,232

Investing activities
(5,985
)
 
(18,259
)
 
(9,790
)
 
(36,886
)
Financing activities
(61,829
)
 
(68,955
)
 
(81,049
)
 
(80,830
)
OTHER DATA:
 
 
 
 
 
 
 
Adjusted EBITDA (2)
$
83,469

 
$
29,119

 
$
145,956

 
$
93,236

Capital expenditures
5,465

 
7,277

 
7,786

 
11,439

Capital expenditures for turnarounds and catalysts
520

 
10,982

 
2,004

 
25,447

KEY OPERATING STATISTICS:
 
 
 
 
 
 
 
Per barrel of throughput:
 
 
 
 
 
 
 
Refinery operating margin (3)
$
17.22

 
$
17.04

 
$
15.56

 
$
15.56

Refinery direct operating expense (4)
3.54

 
7.09

 
3.56

 
5.33

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

 
$
16.42

 
$
18.73

 
$
16.61

WTI Cushing crude oil (per barrel)
$
57.86

 
$
103.04

 
$
53.20

 
$
100.86

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

 
$
8.37

 
$
1.27

 
$
5.96

WTI Cushing less WTS
(0.21
)
 
7.88

 
0.76

 
5.79

Brent less WTI Cushing
3.66

 
7.22

 
4.54

 
8.83

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

 
$
2.81

 
$
1.69

 
$
2.73

Gulf Coast ultra-low sulfur diesel
1.83

 
2.92

 
1.76

 
2.93

Natural gas (per MMBtu)
2.74

 
4.58

 
2.77

 
4.65


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June 30,
2015
 
December 31,
2014
BALANCE SHEET DATA (end of period):
(dollars in thousands)
Cash and cash equivalents
$
149,884

 
$
106,325

Working capital (deficit)
166

 
(4,561
)
Total assets
807,757

 
770,246

Total debt
281,420

 
302,376

Total debt less cash and cash equivalents
131,536

 
196,051

Total partners’ equity
196,165

 
188,402

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

 
39.2

 
12,634

 
32.4

 
37,193

 
50.3

 
23,927

 
42.7

WTI crude
43,659

 
57.8

 
23,391

 
60.0

 
33,952

 
45.9

 
29,652

 
52.9

Blendstocks
2,227

 
3.0

 
2,969

 
7.6

 
2,789

 
3.8

 
2,471

 
4.4

Total refinery throughput (5)
75,491

 
100.0

 
38,994

 
100.0

 
73,934

 
100.0

 
56,050

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
37,755

 
49.8

 
17,484

 
45.1

 
36,978

 
49.8

 
26,835

 
48.0

Diesel/jet
28,052

 
37.0

 
12,315

 
31.8

 
27,074

 
36.5

 
18,461

 
33.0

Asphalt
2,479

 
3.3

 
1,660

 
4.3

 
2,876

 
3.9

 
2,529

 
4.5

Petrochemicals
4,915

 
6.5

 
1,825

 
4.7

 
4,863

 
6.5

 
3,111

 
5.5

Other
2,537

 
3.4

 
5,483

 
14.1

 
2,466

 
3.3

 
5,022

 
9.0

Total refinery production (6)
75,738

 
100.0

 
38,767

 
100.0

 
74,257

 
100.0

 
55,958

 
100.0

Refinery utilization (7)
 
 
100.4
%
 
 
 
85.4
%
 
 
 
97.5
%
 
 
 
95.7
%
(1)
Includes sales to related parties of $101,233 and $152,170 for the three months and $184,122 and $291,183 for the six months ended June 30, 2015 and 2014, respectively.
(2)
Adjusted EBITDA represents earnings before state income tax expense (benefit), 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 (benefit), 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, 2015 and 2014:
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
 
(dollars in thousands)
Net income
$
59,426

 
$
7,802

 
$
95,877

 
$
50,043

State income tax expense (benefit)
(395
)
 
240

 
(45
)
 
725

Interest expense
10,847

 
11,569

 
22,540

 
22,893

Depreciation and amortization
13,591

 
9,508

 
27,584

 
19,575

Adjusted EBITDA
$
83,469

 
$
29,119

 
$
145,956

 
$
93,236

(3)
Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales (exclusive of certain inventory adjustments) 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.
Refinery operating margin for the three and six months ended June 30, 2015 excludes gains (losses) related to inventory adjustments of $(368) and $1,622, respectively.
(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, 2015 Compared to the Three Months Ended June 30, 2014
Net Sales. Net sales for the three months ended June 30, 2015 were $625.1 million, compared to $725.9 million for the three months ended June 30, 2014, a decrease of $100.8 million. This decrease was primarily due to lower refined product prices, partially offset by higher refinery throughput during the three months ended June 30, 2015, compared to the same period last year. The average per gallon price of Gulf Coast gasoline for the three months ended June 30, 2015 decreased $0.95, or 33.8%, to $1.86, compared to $2.81 for the three months ended June 30, 2014. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the three months ended June 30, 2015 decreased $1.09, or 37.3%, to $1.83, compared to $2.92 for the three months ended June 30, 2014. Refinery average throughput for the three months ended June 30, 2015 was 75,491 bpd, compared to 38,994 bpd for the three months ended June 30, 2014, an increase of 93.6%. During the three months ended June 30, 2014, refinery throughput was reduced as we completed both the planned turnaround and the vacuum tower project.
Cost of Sales. Cost of sales for the three months ended June 30, 2015 were $507.1 million, compared to $665.4 million for the three months ended June 30, 2014, a decrease of $158.3 million. This decrease was primarily due to reduced crude oil prices, partially offset by higher refinery throughput. The average price of WTI Cushing decreased 43.8% to $57.86 per barrel for the three months ended June 30, 2015 from $103.04 per barrel for the three months ended June 30, 2014.
Direct Operating Expenses. Direct operating expenses for the three months ended June 30, 2015 were $24.3 million, compared to $25.2 million for the three months ended June 30, 2014, a decrease of $0.9 million, or 3.6%. This decrease was primarily due to lower maintenance and utility costs, partially offset by higher throughput during the three months ended June 30, 2015.
Selling, General and Administrative Expenses. SG&A expenses for the three months ended June 30, 2015 were $10.2 million, compared to $6.8 million for the three months ended June 30, 2014, an increase of $3.4 million, primarily due to higher employee related costs during the three months ended June 30, 2015.
Depreciation and Amortization. Depreciation and amortization for the three months ended June 30, 2015 was $13.6 million, compared to $9.5 million for the three months ended June 30, 2014, an increase of $4.1 million, or 43.1%. This increase was primarily due to increased amortization of turnaround and catalyst replacement costs during the three months ended June 30, 2015 resulting from the completion of the planned turnaround during the second quarter of 2014.
Operating Income. Operating income for the three months ended June 30, 2015 was $69.9 million, compared to $19.0 million for the three months ended June 30, 2014, an increase of $50.9 million. This increase was primarily due to higher refinery throughput and higher refinery operating margin. Refinery operating margin was $17.22 per barrel for the three months ended June 30, 2015, compared to $17.04 per barrel for the three months ended June 30, 2014. This increase in operating margin was primarily due to improved light product yields, partially offset by the industry margin environment. The contraction in the WTI Cushing to WTI Midland and the WTI Cushing to WTS spreads was greater than the improvement in the Gulf Coast 3/2/1 spread and the cost of crude benefit from the market moving from backwardation into contango. The average Gulf Coast 3/2/1 crack spread increased to $19.71 per barrel for the three months ended June 30, 2015, compared to $16.42 per barrel for the three months ended June 30, 2014. The average WTI Cushing to WTS spread narrowed to $(0.21) per barrel for the three months ended June 30, 2015, compared to $7.88 per barrel for the three months ended June 30, 2014. The average WTI Cushing to WTI Midland spread narrowed to $0.60 per barrel for the three months ended June 30, 2015, compared to $8.37 per barrel for the three months ended June 30, 2014. The contango environment in the three months ended June 30, 2015 created a cost of crude benefit of $1.90 per barrel compared to the backwardated environment creating a cost of crude detriment of $0.93 per barrel for the three months ended June 30, 2014.
Interest Expense. Interest expense for the three months ended June 30, 2015 was $10.8 million, compared to $11.6 million for the three months ended June 30, 2014, a decrease of $0.8 million.
State Income Tax Expense (Benefit). State income tax benefit was $0.4 million for the three months ended June 30, 2015, compared to state income tax expense of $0.2 million for the three months ended June 30, 2014. The decrease in state income tax by $0.6 million was primarily due to the State of Texas permanently reducing the Texas Margin Tax from 1.0% to 0.75% during the three months ended June 30, 2015, which generated a deferred tax credit in the current period.
Net Income. Net income for the three months ended June 30, 2015 was $59.4 million, compared to $7.8 million for the three months ended June 30, 2014, an increase of $51.6 million. This increase was attributable to the factors discussed above.
Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014
Net Sales. Net sales for the six months ended June 30, 2015 were $1,167.5 million, compared to $1,582.3 million for the six months ended June 30, 2014, a decrease of $414.8 million. This decrease was primarily due to lower refined product prices, partially offset by higher refinery throughput. The average per gallon price of Gulf Coast gasoline for the six months ended June 30, 2015 decreased $1.04, or 38.1%, to $1.69, compared to $2.73 for the six months ended June 30, 2014. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the six months ended June 30, 2015 decreased $1.17, or 39.9%, to $1.76,

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compared to $2.93 for the six months ended June 30, 2014. Refinery average throughput for the six months ended June 30, 2015 was 73,934 bpd compared to 56,050 bpd for the six months ended June 30, 2014, an increase of 31.9%. During the six months ended June 30, 2014, refinery throughput was reduced as we completed both the planned turnaround and the vacuum tower project.
Cost of Sales. Cost of sales for the six months ended June 30, 2015 were $957.7 million, compared to $1,424.4 million for the six months ended June 30, 2014, a decrease of $466.7 million. This decrease was primarily due to a decrease in crude oil prices, partially offset by higher refinery throughput. The average price of WTI Cushing decreased 47.3% to $53.20 per barrel for the six months ended June 30, 2015 from $100.86 per barrel for the six months ended June 30, 2014.
Direct Operating Expenses. Direct operating expenses for the six months ended June 30, 2015 were $47.7 million, compared to $54.1 million for the six months ended June 30, 2014, a decrease of $6.4 million, or 11.8%. This decrease was primarily due to lower maintenance and utility costs for the six months ended June 30, 2015.
Selling, General and Administrative Expenses. SG&A expenses for the six months ended June 30, 2015 were $16.1 million, compared to $11.2 million for the six months ended June 30, 2014, an increase of $4.9 million. This increase was primarily due to higher allocated costs for the six months ended June 30, 2015.
Depreciation and Amortization. Depreciation and amortization for the six months ended June 30, 2015 was $27.6 million, compared to $19.6 million for the six months ended June 30, 2014, an increase of $8.0 million. This increase was primarily due to increased amortization of turnaround and catalyst replacement costs during the six months ended June 30, 2015 resulting from the completion of the planned turnaround during the second quarter of 2014.
Operating Income. Operating income for the six months ended June 30, 2015 was $118.4 million, compared to $73.0 million for the six months ended June 30, 2014, an increase of $45.4 million. This increase was primarily due to higher refinery throughput and refinery operating margin remaining flat.
Refinery operating margin was $15.56 per barrel for the six months ended June 30, 2015, compared to $15.56 per barrel for the six months ended June 30, 2014. The operating margin was flat relative to the same period last year primarily due to improved light product yields being offset by the industry margin environment. The contraction in the WTI Cushing to WTI Midland and the WTI Cushing to WTS spreads was greater than the improvement in the Gulf Coast 3/2/1 spread and the cost of crude benefit from the market moving from backwardation into contango. The average Gulf Coast 3/2/1 crack spread increased to $18.73 per barrel for the six months ended June 30, 2015, compared to $16.61 per barrel for the six months ended June 30, 2014. The average WTI Cushing to WTS spread narrowed to $0.76 per barrel for the six months ended June 30, 2015, compared to $5.79 per barrel for the six months ended June 30, 2014. The average WTI Cushing to WTI Midland spread narrowed to $1.27 per barrel for the six months ended June 30, 2015, compared to $5.96 per barrel for the six months ended June 30, 2014. The contango environment in the six months ended June 30, 2015 created a cost of crude benefit of $1.28 per barrel compared to the backwardated environment creating a cost of crude detriment of $0.53 per barrel for the six months ended June 30, 2014.
Interest Expense. Interest expense was $22.5 million for the six months ended June 30, 2015, compared to $22.9 million for the six months ended June 30, 2014, a decrease of $0.4 million.
State Income Tax Expense (Benefit). State income tax benefit was $0.0 million for the six months ended June 30, 2015, compared to state income tax expense of $0.7 million for the six months ended June 30, 2014. The decrease in state income tax by $0.7 million was primarily due to the State of Texas permanently reducing the Texas Margin Tax from 1.0% to 0.75% during the six months ended June 30, 2015, which generated a deferred tax credit in the current period.
Net Income. Net income for the six months ended June 30, 2015 was $95.9 million, compared to $50.0 million for the six months ended June 30, 2014, an increase of $45.9 million. This increase was attributable to the factors discussed above.
Liquidity and Capital Resources
Our primary sources of liquidity are cash on hand, cash generated from our operating activities, borrowings under our revolving credit facility, inventory supply and offtake arrangement and other credit lines. Additionally, we have the ability to utilize a $60.0 million letter of credit facility through Alon Energy for our crude and product purchases, which currently expires in November 2015.
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

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capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive, and other factors beyond our control.
Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or equity securities, or other possible capital markets transactions, the proceeds of which could be used to refinance current indebtedness, extend or replace our existing revolving credit facility or for other Partnership purposes.
Cash Flows
The following table sets forth our consolidated cash flows for the six months ended June 30, 2015 and 2014:
 
For the Six Months Ended
 
June 30,
 
2015
 
2014
 
(dollars in thousands)
Cash provided by (used in):
 
 
 
Operating activities
$
134,398

 
$
45,232

Investing activities
(9,790
)
 
(36,886
)
Financing activities
(81,049
)
 
(80,830
)
Net increase (decrease) in cash and cash equivalents
$
43,559

 
$
(72,484
)
Cash Flows Provided by Operating Activities
Net cash provided by operating activities was $134.4 million during the six months ended June 30, 2015 compared to $45.2 million during the six months ended June 30, 2014. The increase in net cash provided by operating activities of $89.2 million was primarily due to increased net income after adjusting for non-cash items of $53.2 million, reduced cash used for accounts payable and accrued liabilities of $59.8 million, reduced cash used for inventories of $23.3 million, reduced cash used for prepaid expenses and other current assets of $11.9 million and increased cash provided by other assets of $2.6 million, partially offset by lower cash collected on accounts receivable of $52.3 million and reduced cash used on other non-current liabilities of $9.3 million.
Cash Flows Used In Investing Activities
Net cash used in investing activities was $9.8 million during the six months ended June 30, 2015 compared to $36.9 million during the six months ended June 30, 2014. The decrease in net cash used in investing activities of $27.1 million was primarily due to the 2014 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 $81.0 million during the six months ended June 30, 2015 compared to $80.8 million during the six months ended June 30, 2014. The increase in net cash used in financing activities of $0.2 million was primarily due to higher distributions to unitholders of $33.8 million and higher payments on our revolving credit facility of $20.0 million, partially offset by increased proceeds from inventory financing arrangements of $55.3 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. We had borrowings of $40.0 million and $60.0 million and letters of credit outstanding of $43.5 million and $23.5 million under this facility at June 30, 2015 and December 31, 2014, respectively.
In May 2015, the revolving credit facility was amended to, among other matters, extend the expiration date to May 2019. Borrowings under the revolving credit facility now bear interest at the Eurodollar rate plus 3.00% per annum.

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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, our management assesses opportunities for growth and profit improvement projects on an ongoing basis and any related projects require further approval from the board of directors of our General Partner. Our total capital expenditure projection for 2015 is $32.0 million, which includes expenditures for catalysts and turnarounds and approximately $10.4 million of special regulatory projects. Approximately $9.8 million has been spent during the six months ended June 30, 2015.
Contractual Obligations and Commercial Commitments
There have been no material changes outside the ordinary course of business from our contractual obligations and commercial commitments detailed in our Annual Report on Form 10-K for the year ended December 31, 2014.

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Off-Balance Sheet Arrangements
We have no material off-balance sheet arrangements.
Critical Accounting Policies
We prepare our consolidated financial statements in conformity with GAAP. In order to apply these principles, we must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events, some of which we may have little or no control over.
Our critical accounting policies are described under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2014. Certain critical accounting policies that materially affect the amounts recorded in our consolidated financial statements are the use of the LIFO method for valuing certain inventories and the deferral and subsequent amortization of costs associated with major turnarounds and catalysts replacements. No significant changes to these accounting policies have occurred subsequent to December 31, 2014.
New Accounting Standards and Disclosures
New accounting standards, if any, are disclosed in Note (1) Basis of Presentation included in the consolidated financial statements included in Item 1 of this report.

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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. At June 30, 2015, the market value of refined products and blendstock inventories was less than inventories on a LIFO cost basis which resulted in recording a lower of cost or market reserve of $3.0 million. At June 30, 2015, the market value of crude oil inventories exceeded LIFO costs, net of the fair value hedged item, by $10.7 million.
As of June 30, 2015, we held 0.3 million barrels of crude oil and 0.3 million barrels of refined product and blendstock inventories valued under the LIFO valuation method. If the market value of refined products and blendstock inventories would have been $1.00 per barrel lower, our lower of cost or market reserve would have increased by $0.3 million. If the market value of crude oil would have been $1.00 per barrel lower, the amount by which market value exceeded LIFO costs, net of the fair value hedged item, would have been lower by $0.3 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, 2015:
Description
 
Contract Volume
 
Wtd Avg Purchase
 
Wtd Avg Sales
 
Contract
 
Market
 
Gain
of Activity
 
(barrels)
 
Price/BBL
 
Price/BBL
 
Value
 
Value
 
(Loss)
 
 
 
 
 
 
 
 
(in thousands)
Forwards-short (Crude)
 
(13,153
)
 
$

 
$
57.65

 
$
(758
)
 
$
(774
)
 
$
(16
)
Forwards-long (Gasoline)
 
156,962

 
85.66

 

 
13,446

 
13,321

 
(125
)
Forwards-short (Distillate)
 
(128,481
)
 

 
78.61

 
(10,099
)
 
(10,576
)
 
(477
)
Forwards-long (Jet)
 
7,907

 
75.32

 

 
596

 
598

 
2

Forwards-short (Slurry)
 
(2,737
)
 

 
50.87

 
(139
)
 
(139
)
 

Forwards-long (Catfeed)
 
7,176

 
78.53

 

 
564

 
567

 
3

Forwards-short (Slop)
 
(10,171
)
 

 
49.83

 
(507
)
 
(507
)
 

Forwards-short (Propane)
 
(35,000
)
 

 
15.42

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

 
22.02

 

 
1,513

 
1,642

 
129

Futures-short (Crude)
 
(37,000
)
 

 
61.03

 
(2,258
)
 
(2,200
)
 
58

Futures-short (Gasoline)
 
(217,000
)
 

 
85.43

 
(18,538
)
 
(18,678
)
 
(140
)
Futures-long (Distillate)
 
124,000

 
79.40

 

 
9,846

 
9,843

 
(3
)

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Interest Rate Risk
As of June 30, 2015, our outstanding debt balance of $283.8 million, excluding discounts, was subject to floating interest rates, of which $40.0 million was charged interest at the Eurodollar rate plus 3.00% and $243.8 million was charged interest at the Eurodollar rate (with a floor of 1.25%) plus a margin of 8.00%.
An increase of 1% in the Eurodollar rate on our indebtedness would result in an increase in our interest expense of approximately $0.4 million per year.

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

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PART II. OTHER INFORMATION
ITEM 6. EXHIBITS
Exhibit
 
 
Number
 
Description of Exhibit
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, 2015, 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 4, 2015
By:  
/s/ David Wiessman
 
 
 
David Wiessman 
 
 
 
Executive Chairman of the Board
 
 
 
 
 
 
 
 
Date:
August 4, 2015
By:  
/s/ Paul Eisman
 
 
 
Paul Eisman
 
 
 
President, Chief Executive Officer and Director
 
 
 
 
 
 
 
 
Date:
August 4, 2015
By:  
/s/ Shai Even
 
 
 
Shai Even 
 
 
 
Senior Vice President and Chief Financial Officer 
 
 
 
(Principal Accounting Officer)

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