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, 2017
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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o
 
Accelerated filer þ
Non-accelerated filer o (Do not check if a smaller reporting company)
 
Smaller reporting company o
Emerging growth company o
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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, 2017, was 62,529,328.
 
 



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,
2017
 
December 31,
2016
 
(unaudited)
 
 
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
167,239

 
$
73,524

Accounts and other receivables, net
109,827

 
82,292

Accounts and other receivables, net - related parties
10,307

 
11,425

Inventories
37,067

 
49,682

Prepaid expenses and other current assets
4,248

 
4,949

Total current assets
328,688

 
221,872

Property, plant and equipment, net
413,033

 
420,554

Other assets, net
45,721

 
53,211

Total assets
$
787,442

 
$
695,637

LIABILITIES AND PARTNERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
326,693

 
$
249,835

Accrued liabilities
37,477

 
43,100

Current portion of long-term debt
2,500

 
2,500

Total current liabilities
366,670

 
295,435

Other non-current liabilities
22,572

 
62,880

Long-term debt
283,496

 
233,819

Total liabilities
672,738

 
592,134

Commitments and contingencies (Note 11)

 

Partners’ equity:
 
 
 
General Partner

 

Common unitholders - 62,529,328 and 62,520,220 units issued and outstanding at June 30, 2017 and December 31, 2016, respectively
114,704

 
103,503

Total partners’ equity
114,704

 
103,503

Total liabilities and partners’ equity
$
787,442

 
$
695,637


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,
 
2017
 
2016
 
2017
 
2016
Net sales (1)
$
521,751

 
$
468,457

 
$
1,066,283

 
$
836,466

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales
440,895

 
410,735

 
911,366

 
730,068

Direct operating expenses
27,878

 
23,255

 
52,638

 
48,299

Selling, general and administrative expenses
7,392

 
8,802

 
14,156

 
16,111

Depreciation and amortization
14,462

 
14,667

 
28,691

 
28,873

Total operating costs and expenses
490,627

 
457,459

 
1,006,851

 
823,351

Loss on disposition of assets
(23
)
 

 
(23
)
 

Operating income
31,101

 
10,998

 
59,409

 
13,115

Interest expense
(8,652
)
 
(9,920
)
 
(16,497
)
 
(20,507
)
Other income (loss), net
(459
)
 
113

 
(554
)
 
197

Income (loss) before state income tax expense
21,990

 
1,191

 
42,358

 
(7,195
)
State income tax expense
310

 

 
566

 
176

Net income (loss)
$
21,680

 
$
1,191

 
$
41,792

 
$
(7,371
)
Earnings (loss) per unit
$
0.35

 
$
0.02

 
$
0.67

 
$
(0.12
)
Weighted average common units outstanding (in thousands)
62,525

 
62,515

 
62,523

 
62,512

Cash distribution per unit
$
0.38

 
$

 
$
0.49

 
$
0.08

___________
(1)
Includes sales to related parties of $94,323 and $76,884 for the three months ended and $185,760 and $139,994 for the six months ended June 30, 2017 and 2016, 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,
 
2017
 
2016
Cash flows from operating activities:
 
 
 
Net income (loss)
$
41,792

 
$
(7,371
)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
 
 
 
Depreciation and amortization
28,691

 
28,873

Unit-based compensation
47

 
28

Loss on disposition of assets
23

 

Amortization of debt issuance costs
811

 
951

Amortization of original issuance discount
345

 
318

Changes in operating assets and liabilities:
 
 
 
Accounts and other receivables, net
(27,535
)
 
(18,965
)
Accounts and other receivables, net - related parties
1,118

 
(2,354
)
Inventories
12,592

 
(8,939
)
Prepaid expenses and other current assets
701

 
2,023

Other assets, net
(900
)
 
3,719

Accounts payable
25,731

 
36,926

Accrued liabilities
(5,441
)
 
(1,453
)
Other non-current liabilities
(830
)
 
12,831

Net cash provided by operating activities
77,145

 
46,587

Cash flows from investing activities:
 
 
 
Capital expenditures
(12,175
)
 
(12,700
)
Capital expenditures for turnarounds and catalysts
(1,016
)
 
(8,224
)
Net cash used in investing activities
(13,191
)
 
(20,924
)
Cash flows from financing activities:
 
 
 
Distributions paid to unitholders
(5,648
)
 
(921
)
Distributions paid to unitholders - Alon Energy
(24,990
)
 
(4,080
)
RINs financing transactions
11,649

 
9,455

Revolving credit facility, net
50,000

 

Payments on long-term debt
(1,250
)
 
(1,250
)
Net cash provided by financing activities
29,761

 
3,204

Net increase in cash and cash equivalents
93,715

 
28,867

Cash and cash equivalents, beginning of period
73,524

 
132,953

Cash and cash equivalents, end of period
$
167,239

 
$
161,820

Supplemental cash flow information:
 
 
 
Cash paid for interest, net of capitalized interest
$
16,155

 
$
19,882

Cash paid for income tax
$
566

 
$
176


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,” “our” and “us” or like terms refer to Alon USA Partners, LP, and its consolidated subsidiaries or to Alon USA Partners, LP or an individual subsidiary. References in this report to “Alon Energy” refer collectively to Alon USA Energy, Inc. and any of 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 Alon USA Partners GP, LLC (the “General Partner”). The General Partner, a wholly-owned subsidiary of Alon Energy, owns 100% of our general partner interest, which is a non-economic interest.
Effective July 1, 2017, with the completion of the merger between Delek US Holdings, Inc. (“Delek”) and Alon Energy, Delek indirectly owns 100% of our General Partner and 81.6% of our limited partner interest. Our General Partner manages our operations and activities subject to the terms and conditions specified in our partnership agreement. The operations of our General Partner in its capacity as general partner are managed by its board of directors.
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, 2017 are not necessarily indicative of the operating results that may be realized for the year ending December 31, 2017.
Our consolidated balance sheet as of December 31, 2016 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, 2016.
New Accounting Pronouncements
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 August 2015, the FASB updated the guidance to include 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 and related disclosures. Based on our initial evaluation, though not currently quantified, the adoption of the standard is not expected to have a material impact on the timing of revenue recognized, results of operations or cash flows.
In February 2016, the FASB issued new guidance on the accounting for leases, which requires lessees to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The standard will also require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The requirements from this guidance are effective for interim and annual periods beginning after December 31, 2018. We are evaluating the guidance to determine the impact this standard will have on our consolidated financial statements.
In June 2016, the FASB issued an accounting standards update requiring the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. Financial institutions and other organizations will now use forward-looking information to better inform their credit loss estimates. The requirements from the updated standard are effective for interim and annual periods beginning after

4

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


December 15, 2019. We are evaluating the guidance to determine the impact this standard will have on our consolidated financial statements.
In August 2016, the FASB issued an accounting standards update addressing eight specific cash flow issues with the objective of eliminating the existing diversity in practice. The amendments from this update are effective for interim and annual periods beginning after December 15, 2017. We do not expect application of this standard to have a material effect 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.
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, 2017 and December 31, 2016:
 
Level 1
 
Level 2
 
Level 3
 
Total
As of June 30, 2017
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Fair value hedge of consigned inventory
$

 
$
5,130

 
$

 
$
5,130

Liabilities:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
662

 

 

 
662

 
 
 
 
 
 
 
 
As of December 31, 2016
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Fair value hedge of consigned inventory
$

 
$
4,389

 
$

 
$
4,389

Liabilities:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
689

 

 

 
689

(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.

5

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


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 116 thousand barrels of crude oil as of June 30, 2017.
The following tables present the effect of derivative instruments on the consolidated balance sheets:
 
As of June 30, 2017
 
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
 
$
662

Total derivatives not designated as hedging instruments
 
 

 
 
 
662

 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Fair value hedge of consigned inventory
Other assets
 
$
5,130

 
 
 
$

Total derivatives designated as hedging instruments
 
 
5,130

 
 
 

Total derivatives
 
 
$
5,130

 
 
 
$
662

 
As of December 31, 2016
 
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
 
$
30

 
Accrued liabilities
 
$
719

Total derivatives not designated as hedging instruments
 
 
30

 
 
 
719

 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Fair value hedge of consigned inventory
Other assets
 
$
4,389

 
 
 
$

Total derivatives designated as hedging instruments
 
 
4,389

 
 
 

Total derivatives
 
 
$
4,419

 
 
 
$
719


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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 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
 
2017
 
2016
 
2017
 
2016
Fair value hedge of consigned inventory (1)
Interest expense
 
$
(325
)
 
$
(5,249
)
 
$
741

 
$
(4,223
)
Total derivatives
 
 
$
(325
)
 
$
(5,249
)
 
$
741

 
$
(4,223
)
_______________________
(1)
Changes in the fair value hedge are substantially offset in earnings by changes in the hedged item.
Derivatives not designated as hedging instruments:
 
 
 
Gain Recognized in Income
 
 
 
For the Three Months Ended
 
For the Six Months Ended
 
 
 
June 30,
 
June 30,
 
Location
 
2017
 
2016
 
2017
 
2016
Commodity contracts (futures and forwards)
Cost of sales
 
$
1,323

 
$
823

 
$
3,479

 
$
6,197

Total derivatives
 
 
$
1,323

 
$
823

 
$
3,479

 
$
6,197

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, 2017 and December 31, 2016:
 
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, 2017
 
 
 
 
 
 
 
 
 
 
Derivative Assets:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
719

 
$
(719
)
 
$

 
$

 
$

 
$

Fair value hedge of consigned inventory
5,130

 

 
5,130

 

 

 
5,130

Derivative Liabilities:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
1,381

 
$
(719
)
 
$
662

 
$

 
$

 
$
662

 
 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2016
 
 
 
 
 
 
 
 
 
 
Derivative Assets:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
980

 
$
(950
)
 
$
30

 
$
(30
)
 
$

 
$

Fair value hedge of consigned inventory
4,389

 

 
4,389

 

 

 
4,389

Derivative Liabilities:
 
 
 
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
1,669

 
$
(950
)
 
$
719

 
$
(30
)
 
$

 
$
689


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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. We may also sell the RINs with an agreement to repurchase in the future at a fixed price. Some of these contracts are derivative instruments; however, we elect the normal purchase and sale exception and do not record these contracts at their fair values.
The cost of meeting our obligations under these compliance programs was $2,280 and $2,089 for the three months ended and $6,438 and $2,908 for the six months ended June 30, 2017 and 2016, 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,
2017
 
December 31,
2016
Crude oil, refined products and blendstocks
$
25,083

 
$
36,259

Crude oil consignment inventory (Note 5)
779

 
1,850

Materials and supplies
11,205

 
11,573

Total inventories
$
37,067

 
$
49,682

At June 30, 2017 and December 31, 2016, the market value of our refined products and blendstock inventories was less than inventories valued on a LIFO cost basis which resulted in a lower of cost or market reserve of $7,477 and $6,213, respectively. At June 30, 2017 and December 31, 2016, the market value of our crude oil inventories exceeded LIFO costs, net of the fair value hedged item, by $2,930 and $5,236, respectively.
(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 our refinery and (ii) we agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced at our 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 the identification of prospective purchasers of refined products on J. Aron’s behalf.
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, 2017 and December 31, 2016, we had net current receivables of $24,534 and $10,569, respectively, with J. Aron for purchases and sales, and a consignment inventory receivable representing a deposit paid to J. Aron of $6,290 and $6,290, respectively. At June 30, 2017 and December 31, 2016, we had non-current liabilities for the original financing of $5,888 and $7,550, respectively, net of the related fair value hedge.
Additionally, we had net current payables of $351 and $719 at June 30, 2017 and December 31, 2016, 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,
2017
 
December 31,
2016
Refining facilities
$
744,690

 
$
732,697

Accumulated depreciation
(331,657
)
 
(312,143
)
Property, plant and equipment, net
$
413,033

 
$
420,554


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


(7)
Additional Financial Information
The following tables provide additional financial information related to the consolidated financial statements.
(a)
Other Assets, Net
 
June 30,
2017
 
December 31,
2016
Deferred turnaround and catalyst cost
$
27,218

 
$
34,252

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

 
6,290

Fair value hedge of consigned inventory (Note 3)
5,130

 
4,389

Other
7,083

 
8,280

Total other assets
$
45,721

 
$
53,211

(b)
Accounts Payable
Included in accounts payable was $130,364 and $78,565 related to RINs financing transactions as of June 30, 2017 and December 31, 2016, respectively.
(c)
Accrued Liabilities and Other Non-Current Liabilities
 
June 30,
2017
 
December 31,
2016
Accrued Liabilities:
 
 
 
Taxes other than income taxes, primarily excise taxes
$
27,740

 
$
31,882

Accrued finance charges
364

 
372

Environmental accrual (Note 11)
796

 
796

Commodity contracts
662

 
719

Other
7,915

 
9,331

Total accrued liabilities
$
37,477

 
$
43,100

 
 
 
 
Other Non-Current Liabilities:
 
 
 
Consignment inventory obligation (Note 5)
$
11,018

 
$
11,939

Environmental accrual (Note 11)
5,796

 
5,796

Asset retirement obligations
3,222

 
3,131

RINs financing transactions

 
39,478

Other
2,536

 
2,536

Total other non-current liabilities
$
22,572

 
$
62,880

(8)
Indebtedness
Debt consisted of the following:
 
June 30,
2017
 
December 31,
2016
Term loan credit facility
$
235,996

 
$
236,319

Revolving credit facility
50,000

 

Total debt
285,996

 
236,319

Less: Current portion
2,500

 
2,500

Total long-term debt
$
283,496

 
$
233,819

Outstanding letters of credit under the revolving credit facility were $48,730 and $100,613 at June 30, 2017 and December 31, 2016, respectively.
The revolving credit facility contains maintenance financial covenants. At June 30, 2017, we were in compliance with these covenants.

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


(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.
The following table summarizes the Partnership’s cash distribution activity during the period:
 
 
Cash Available for Distribution per Unit (1)
 
Distribution Paid Per Unit
 
Total Distribution Paid
First Quarter 2017
 
$
0.38

 
$
0.11

 
$
6,877

Second Quarter 2017
 
0.35

 
0.38
 
23,761

_______________________
(1)
Represents the aggregate cash available for distribution per unit attributable to the period indicated. This represents the difference between cash available for distribution and distributions paid in the table above.
Restricted Units
Non-employee directors of the General Partner are awarded an annual grant of $25 in restricted units, which vest over a period of three years, assuming continued service at vesting. In May 2017, we granted awards of 9,108 restricted common units at a grant date price of $10.98 per unit.
(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.
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.
Effective July 1, 2017, with the completion of the merger between Delek and Alon Energy, Delek indirectly owns 100% of our General Partner and 81.6% of our limited partner interest. As the owner of the General Partner, Delek is responsible for appointing all members of the board of directors of our General Partner, including all of our General Partner’s independent directors.
(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 $3,116 and $4,245, for the three months ended June 30, 2017 and 2016, respectively, and $5,766 and $7,665 for the six months ended June 30, 2017 and 2016, respectively.

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


(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 and selling, general and administrative expenses. The allocated portion of Alon Energy’s employee expense costs included in direct operating expenses were $7,451 and $7,070 for the three months ended June 30, 2017 and 2016, respectively, and $14,474 and $14,332 for the six months ended June 30, 2017 and 2016, respectively. The allocated portion of Alon Energy’s employee expense costs included in selling, general and administrative expenses were $947 and $1,280 for the three months ended June 30, 2017 and 2016, respectively, and $1,967 and $2,235 for the six months ended June 30, 2017 and 2016, 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 $1,118 and $1,512 for the three months ended June 30, 2017 and 2016, respectively, and $2,246 and $2,372 for the six months ended June 30, 2017 and 2016, 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. Related to these agreements, we recorded selling, general and administrative expense of $1,230 for the three months ended June 30, 2017 and 2016 and $2,460 for the six months ended June 30, 2017 and 2016.
Transactions with Delek US Holdings, Inc.
We have transactions with Delek that occur in the ordinary course of business. We had purchases, net of sales, of crude oil, products and RINs from Delek of $19,458 and $371 for the three months ended June 30, 2017 and 2016, respectively, and $22,239 and $785 for the six months ended June 30, 2017 and 2016, respectively. Accounts payable includes a balance outstanding to Delek of $1,824 at June 30, 2017.
Distributions
During the six months ended June 30, 2017, we paid cash distributions of $30,638, or $0.49 per unit, of which $24,990 was paid to Alon Energy. During the six months ended June 30, 2016, we paid cash distributions of $5,001, or $0.08 per unit, of which $4,080 was paid to Alon Energy.
(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 cannot be determined with any degree of reliability.
We have accrued environmental remediation obligations of $6,592 ($796 current liability and $5,796 non-current liability) at June 30, 2017, and $6,592 ($796 accrued liability and $5,796 non-current liability) at December 31, 2016.

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


(12)
Subsequent Event
Distribution Declared
On July 27, 2017, the board of directors of the General Partner declared a cash distribution to our common unitholders of approximately $21,885, or $0.35 per common unit. The cash distribution will be paid on August 24, 2017 to unitholders of record at the close of business on August 17, 2017.

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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” and “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” refer collectively to Alon USA Energy, Inc. and any of its consolidated subsidiaries other than Alon USA Partners, LP, its subsidiaries and its general partner. Effective July 1, 2017, with the completion of the merger between Delek US Holdings, Inc. and Alon Energy, references in this report to “Delek” refer to Delek US Holdings, Inc. and any of its consolidated subsidiaries. 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, 2016.
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 as a result of the completed merger between Delek and Alon Energy;
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 one of our largest suppliers of crude oil and one of our largest customers 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;

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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, 2016 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 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”). We refine crude oil into finished products, which we market primarily in Central and West Texas, Oklahoma, New Mexico and Arizona through our integrated wholesale distribution network to both Alon Energy’s retail convenience stores and other third-party distributors. We distribute fuel products through a network of pipelines and terminals that we own or access through leases or long-term throughput agreements.
Effective July 1, 2017, with the completion of the merger between Delek and Alon Energy, Delek indirectly owns 100% of our General Partner and 81.6% of our limited partner interest. Our General Partner manages our operations and activities subject to the terms and conditions specified in our partnership agreement. The operations of our General Partner in its capacity as general partner are managed by its board of directors.
For additional information on our business, see Items 1. and 2. “Business and Properties” included in our Annual Report on Form 10-K for the year ended December 31, 2016.
Second Quarter Operational and Financial Highlights
Our operational and financial highlights for the second quarter of 2017 include the following:
Operating income for the second quarter of 2017 was $31.1 million, compared to $11.0 million for the second quarter of 2016.
Big Spring refinery average throughput for the second quarter of 2017 was 72,763 bpd compared to 71,153 bpd for the second quarter of 2016. Refinery throughput for the second quarter of 2017 was affected by maintenance on the FCCU and refinery throughput for the second quarter of 2016 was affected by unplanned downtime due to a power outage caused by inclement weather, which affected multiple units.
Refinery operating margin was $12.68 per barrel for the second quarter of 2017 compared to $8.53 per barrel for the same period in 2016. This increase in operating margin was primarily due to a higher Gulf Coast 3/2/1 crack spread, a widening of both the WTI Cushing to WTI Midland and WTI Cushing to WTS spreads and a stronger wholesale marketing environment, partially offset by a reduced benefit from the contango market environment which increased the cost of crude.
The average Gulf Coast 3/2/1 crack spread was $15.07 per barrel for the second quarter of 2017 compared to $13.16 per barrel for the second quarter of 2016.
The average WTI Cushing to WTI Midland spread for the second quarter of 2017 was $0.84 per barrel compared to $0.17 per barrel for the same period in 2016. The average WTI Cushing to WTS spread for the second quarter of 2017 was $1.24 per barrel compared to $0.75 per barrel for the same period in 2016. The average Brent to WTI Cushing spread for the second quarter of 2017 was $1.21 per barrel compared to $(0.18) per barrel for the same period in 2016.
The average RINs cost effect on refinery operating margin was $0.34 per barrel for the second quarter of 2017, compared to $0.32 per barrel for the same period in 2016.
The contango environment in the second quarter of 2017 created an average cost of crude benefit of $0.55 per barrel compared to an average cost of crude benefit of $1.49 per barrel for the same period in 2016.
During the second quarter of 2017, we generated cash available for distribution of $0.35 per unit, compared to$0.14 per unit during the second quarter of 2016.

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Major Influences on Results of Operations
Earnings and cash flows are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. These prices depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation. While our sales and operating revenues fluctuate significantly with movements in crude oil and refined product prices, it is the spread between crude oil and refined product prices, not necessarily fluctuations in those prices, that affects our earnings.
In order to measure our operating performance, we compare our per barrel refinery operating 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 and inclusive of RINs costs).
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.
In addition, the location of the Big Spring refinery near Midland, the largest origination terminal for West Texas crude oil, provides reliable crude sourcing with a relatively low transportation cost. Additionally, we have the ability to source locally produced crude at Big Spring by truck, which enables us to better control quality and eliminate the cost of transporting our crude supply from Midland. 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, a narrowing of this differential will have an adverse effect on our operating margin.
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 margin 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.

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Factors Affecting Comparability
Our financial condition and operating results over the three and six months ended June 30, 2017 and 2016 have been influenced by the following factor which is fundamental to understanding comparisons of our period-to-period financial performance.
Maintenance and Turnaround Impact on Crude Oil Throughput
During the six months ended June 30, 2017, throughput at the refinery was affected by maintenance on the FCCU. During the six months ended June 30, 2016, throughput at the refinery was reduced as a result of planned downtime to complete a reformer regeneration and catalyst replacement for our diesel hydrotreater unit in the beginning of the first quarter of 2016, as well as unplanned downtime during the second quarter of 2016 due to a power outage caused by inclement weather, which affected multiple units.


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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 and RINs, 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 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 of the cost of capital assets to expense within the consolidated statements of operations. The cost is expensed 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, 2017 and 2016. 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, 2016 is unaudited.
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2017
 
2016
 
2017
 
2016
 
(dollars in thousands, except per unit data, per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
 
 
 
 
 
 
 
Net sales (1)
$
521,751

 
$
468,457

 
$
1,066,283

 
$
836,466

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales
440,895

 
410,735

 
911,366

 
730,068

Direct operating expenses
27,878

 
23,255

 
52,638

 
48,299

Selling, general and administrative expenses
7,392

 
8,802

 
14,156

 
16,111

Depreciation and amortization
14,462

 
14,667

 
28,691

 
28,873

Total operating costs and expenses
490,627

 
457,459

 
1,006,851

 
823,351

Loss on disposition of assets
(23
)
 

 
(23
)
 

Operating income
31,101

 
10,998

 
59,409

 
13,115

Interest expense
(8,652
)
 
(9,920
)
 
(16,497
)
 
(20,507
)
Other income (loss), net
(459
)
 
113

 
(554
)
 
197

Income (loss) before state income tax expense
21,990

 
1,191

 
42,358

 
(7,195
)
State income tax expense
310

 

 
566

 
176

Net income (loss)
$
21,680

 
$
1,191

 
$
41,792

 
$
(7,371
)
Earnings (loss) per unit
$
0.35

 
$
0.02

 
$
0.67

 
$
(0.12
)
Weighted average common units outstanding (in thousands)
62,525

 
62,515

 
62,523

 
62,512

Cash distribution per unit
$
0.38

 
$

 
$
0.49

 
$
0.08

CASH FLOW DATA:
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
Operating activities
$
35,373

 
$
39,925

 
$
77,145

 
$
46,587

Investing activities
(7,316
)
 
(10,131
)
 
(13,191
)
 
(20,924
)
Financing activities
30,148

 
8,830

 
29,761

 
3,204

OTHER DATA:
 
 
 
 
 
 
 
Adjusted EBITDA (2)
$
45,127

 
$
25,778

 
$
87,569

 
$
42,185

Capital expenditures
7,149

 
4,588

 
12,175

 
12,700

Capital expenditures for turnarounds and catalysts
167

 
5,543

 
1,016

 
8,224

KEY OPERATING STATISTICS:
 
 
 
 
 
 
 
Per barrel of throughput:
 
 
 
 
 
 
 
Refinery operating margin (3)
$
12.68

 
$
8.53

 
$
11.47

 
$
8.16

Refinery direct operating expense (4)
4.21

 
3.59

 
3.86

 
3.83

PRICING STATISTICS:
 
 
 
 
 
 
 
Crack spreads (per barrel):
 
 
 
 
 
 
 
Gulf Coast 3/2/1
$
15.07

 
$
13.16

 
$
14.41

 
$
12.20

WTI Cushing crude oil (per barrel)
$
48.25

 
$
45.48

 
$
50.00

 
$
39.39

Crude oil differentials (per barrel):
 
 
 
 
 
 
 
WTI Cushing less WTI Midland
$
0.84

 
$
0.17

 
$
0.11

 
$
0.02

WTI Cushing less WTS
1.24

 
0.75

 
1.26

 
0.32

Brent less WTI Cushing
1.21

 
(0.18
)
 
1.44

 
0.15

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

 
$
1.42

 
$
1.54

 
$
1.25

Gulf Coast ultra-low sulfur diesel
1.48

 
1.34

 
1.52

 
1.19

Natural gas (per MMBtu)
3.14

 
2.25

 
3.10

 
2.12


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June 30,
2017
 
December 31,
2016
 
(dollars in thousands)
BALANCE SHEET DATA (end of period):
 
 
 
Cash and cash equivalents
$
167,239

 
$
73,524

Working capital
(37,982
)
 
(73,563
)
Total assets
787,442

 
695,637

Total debt
285,996

 
236,319

Total debt less cash and cash equivalents
118,757

 
162,795

Total partners’ equity
114,704

 
103,503

THROUGHPUT AND PRODUCTION DATA:
For the Three Months Ended
 
For the Six Months Ended
June 30,
 
June 30,
 
2017
 
2016
 
2017
 
2016
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
WTS crude
17,680

 
24.3

 
25,698

 
36.1

 
23,955

 
31.8

 
31,126

 
44.9

WTI crude
52,207

 
71.7

 
43,040

 
60.5

 
47,568

 
63.2

 
35,400

 
51.0

Blendstocks
2,876

 
4.0

 
2,415

 
3.4

 
3,722

 
5.0

 
2,819

 
4.1

Total refinery throughput (5)
72,763

 
100.0

 
71,153

 
100.0

 
75,245

 
100.0

 
69,345

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
33,506

 
46.5

 
33,744

 
47.6

 
36,084

 
48.2

 
33,922

 
49.0

Diesel/jet
27,885

 
38.7

 
26,627

 
37.6

 
28,375

 
37.9

 
24,655

 
35.6

Asphalt
2,020

 
2.8

 
2,572

 
3.6

 
2,454

 
3.3

 
2,860

 
4.2

Petrochemicals
3,827

 
5.3

 
3,354

 
4.7

 
4,176

 
5.6

 
3,485

 
5.0

Other
4,755

 
6.7

 
4,569

 
6.5

 
3,700

 
5.0

 
4,298

 
6.2

Total refinery production (6)
71,993

 
100.0

 
70,866

 
100.0

 
74,789

 
100.0

 
69,220

 
100.0

Refinery utilization (7)
 
 
99.0
%
 
 
 
94.2
%
 
 
 
99.6
%
 
 
 
93.7
%
(1)
Includes sales to related parties of $94,323 and $76,884 for the three months ended and $185,760 and $139,994 for the six months ended June 30, 2017 and 2016, 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 (loss) to Adjusted EBITDA for the three and six months ended June 30, 2017 and 2016:
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2017
 
2016
 
2017
 
2016
 
(dollars in thousands)
Net income (loss)
$
21,680

 
$
1,191

 
$
41,792

 
$
(7,371
)
State income tax expense
310

 

 
566

 
176

Interest expense
8,652

 
9,920

 
16,497

 
20,507

Depreciation and amortization
14,462

 
14,667

 
28,691

 
28,873

Adjusted EBITDA
$
45,127

 
$
25,778

 
$
87,569

 
$
42,185

(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, 2017 excludes losses related to inventory adjustments of $(3,106) and $(1,264), respectively. Refinery operating margin for the three and six months ended June 30, 2016 excludes gains related to inventory adjustments of $2,519 and $3,465, 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 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 blendstocks through the crude units and other conversion units.
(7)
Refinery utilization represents average daily crude throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.

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Three Months Ended June 30, 2017 Compared to the Three Months Ended June 30, 2016
Net Sales. Net sales for the three months ended June 30, 2017 were $521.8 million, compared to $468.5 million for the three months ended June 30, 2016, an increase of $53.3 million, or 11.4%. This increase was primarily due to higher refined product prices and higher refinery throughput. The average per gallon price of Gulf Coast gasoline for the three months ended June 30, 2017 increased $0.10, or 7.0%, to $1.52, compared to $1.42 for the three months ended June 30, 2016. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the three months ended June 30, 2017 increased $0.14, or 10.4%, to $1.48, compared to $1.34 for the three months ended June 30, 2016. Refinery average throughput for the three months ended June 30, 2017 was 72,763 bpd, compared to 71,153 bpd for the three months ended June 30, 2016, an increase of 2.3%.
Cost of Sales. Cost of sales for the three months ended June 30, 2017 were $440.9 million, compared to $410.7 million for the three months ended June 30, 2016, an increase of $30.2 million, or 7.4%. This increase was primarily due to increased crude oil prices and higher refinery throughput. The average price of WTI Cushing increased 6.1% to $48.25 per barrel for the three months ended June 30, 2017 from $45.48 per barrel for the three months ended June 30, 2016.
Direct Operating Expenses. Direct operating expenses for the three months ended June 30, 2017 were $27.9 million, compared to $23.3 million for the three months ended June 30, 2016, an increase of $4.6 million, or 19.7%. This increase was primarily due to higher maintenance expenses and increased natural gas costs.
Selling, General and Administrative Expenses. SG&A expenses for the three months ended June 30, 2017 were $7.4 million, compared to $8.8 million for the three months ended June 30, 2016, a decrease of $1.4 million, or 15.9%. This decrease was primarily due to lower corporate allocations.
Depreciation and Amortization. Depreciation and amortization for the three months ended June 30, 2017 was $14.5 million, compared to $14.7 million for the three months ended June 30, 2016, a decrease of $0.2 million, or 1.4%.
Operating Income. Operating income for the three months ended June 30, 2017 was $31.1 million, compared to $11.0 million for the three months ended June 30, 2016, an increase of $20.1 million. This increase was primarily due to higher refinery operating margin and higher refinery throughput. Refinery operating margin was $12.68 per barrel for the three months ended June 30, 2017, compared to $8.53 per barrel for the three months ended June 30, 2016. This increase in operating margin was primarily due to a higher Gulf Coast 3/2/1 crack spread, a widening of both the WTI Cushing to WTI Midland and WTI Cushing to WTS spreads and a stronger wholesale marketing environment, partially offset by a reduced benefit from the contango market environment which increased the cost of crude.
The average Gulf Coast 3/2/1 crack spread was $15.07 per barrel for the three months ended June 30, 2017, compared to $13.16 per barrel for the three months ended June 30, 2016. The average WTI Cushing to WTI Midland spread was $0.84 per barrel for the three months ended June 30, 2017, compared to $0.17 per barrel for the three months ended June 30, 2016. The average WTI Cushing to WTS spread was $1.24 per barrel for the three months ended June 30, 2017, compared to $0.75 per barrel for the three months ended June 30, 2016. The average Brent to WTI Cushing spread was $1.21 per barrel for the three months ended June 30, 2017, compared to $(0.18) per barrel for the three months ended June 30, 2016. The contango environment for the three months ended June 30, 2017 created an average cost of crude benefit of $0.55 per barrel, compared to an average cost of crude benefit of $1.49 per barrel for the three months ended June 30, 2016. The average RINs cost effect on refinery operating margin was $0.34 per barrel for the three months ended June 30, 2017, compared to $0.32 per barrel for the three months ended June 30, 2016.
Interest Expense. Interest expense for the three months ended June 30, 2017 was $8.7 million, compared to $9.9 million for the three months ended June 30, 2016, a decrease of $1.2 million, or 12.1%. This decrease was primarily due to lower finance fees associated with our supply and offtake agreements.
State Income Tax Expense. State income tax expense was $0.3 million for the three months ended June 30, 2017, compared to $0.0 million for the three months ended June 30, 2016, an increase of $0.3 million.
Net Income. Net income for the three months ended June 30, 2017 was $21.7 million, compared to $1.2 million for the three months ended June 30, 2016, an increase of $20.5 million. This increase was attributable to the factors discussed above.

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Six Months Ended June 30, 2017 Compared to the Six Months Ended June 30, 2016
Net Sales. Net sales for the six months ended June 30, 2017 were $1,066.3 million, compared to $836.5 million for the six months ended June 30, 2016, an increase of $229.8 million, or 27.5%. This increase was primarily due to higher refined product prices and higher refinery throughput. The average per gallon price of Gulf Coast gasoline for the six months ended June 30, 2017 increased $0.29, or 23.2%, to $1.54, compared to $1.25 for the six months ended June 30, 2016. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the six months ended June 30, 2017 increased $0.33, or 27.7%, to $1.52, compared to $1.19 for the six months ended June 30, 2016. Refinery average throughput for the six months ended June 30, 2017 was 75,245 bpd compared to 69,345 bpd for the six months ended June 30, 2016, an increase of 8.5%. Refinery throughput for the first half of 2017 was affected by maintenance on the FCCU. The reduced throughput during the six months ended June 30, 2016 was primarily the result of planned downtime to complete a reformer regeneration and catalyst replacement for our diesel hydrotreater unit in the first quarter of 2016, as well as unplanned downtime during the second quarter of 2016 due to a power outage caused by inclement weather, which affected multiple units.
Cost of Sales. Cost of sales for the six months ended June 30, 2017 were $911.4 million, compared to $730.1 million for the six months ended June 30, 2016, an increase of $181.3 million, or 24.8%. This increase was primarily due to increased crude oil prices and higher refinery throughput. The average price of WTI Cushing increased 26.9% to $50.00 per barrel for the six months ended June 30, 2017 from $39.39 per barrel for the six months ended June 30, 2016.
Direct Operating Expenses. Direct operating expenses for the six months ended June 30, 2017 were $52.6 million, compared to $48.3 million for the six months ended June 30, 2016, an increase of $4.3 million, or 8.9%. This increase was primarily due to higher natural gas costs.
Selling, General and Administrative Expenses. SG&A expenses for the six months ended June 30, 2017 were $14.2 million, compared to $16.1 million for the six months ended June 30, 2016, a decrease of $1.9 million, or 11.8%. This decrease was primarily due to lower corporate allocations.
Depreciation and Amortization. Depreciation and amortization for the six months ended June 30, 2017 was $28.7 million, compared to $28.9 million for the six months ended June 30, 2016, a decrease of $0.2 million, or 0.7%.
Operating Income. Operating income for the six months ended June 30, 2017 was $59.4 million, compared to $13.1 million for the six months ended June 30, 2016, an increase of $46.3 million. This increase was primarily due to higher refinery throughput and higher refinery operating margin. Refinery operating margin for the six months ended June 30, 2017 was $11.47 per barrel, compared to $8.16 per barrel for the six months ended June 30, 2016. This increase in operating margin was primarily due to a higher Gulf Coast 3/2/1 crack spread and a widening of both the WTI Cushing to WTI Midland and WTI Cushing to WTS spreads, partially offset by increased RINs costs and a reduced benefit from the contango market environment which increased the cost of crude.
The average Gulf Coast 3/2/1 crack spread was $14.41 per barrel for the six months ended June 30, 2017, compared to $12.20 per barrel for the six months ended June 30, 2016. The average WTI Cushing to WTI Midland spread was $0.11 per barrel for the six months ended June 30, 2017, compared to $0.02 per barrel for the six months ended June 30, 2016. The average WTI Cushing to WTS spread was $1.26 per barrel for the six months ended June 30, 2017, compared to $0.32 per barrel for the six months ended June 30, 2016. The average Brent to WTI Cushing spread was $1.44 per barrel for the six months ended June 30, 2017 compared to $0.15 per barrel for the six months ended June 30, 2016. The contango environment for the six months ended June 30, 2017 created an average cost of crude benefit of $0.77 per barrel, compared to an average cost of crude benefit of $1.66 per barrel for the six months ended June 30, 2016. The average RINs cost effect on refinery operating margin was $0.47 per barrel for the six months ended June 30, 2017, compared to $0.23 per barrel for the six months ended June 30, 2016.
Interest Expense. Interest expense for the six months ended June 30, 2017 was $16.5 million, compared to $20.5 million for the six months ended June 30, 2016, a decrease of $4.0 million, or 19.5%. This decrease was primarily due to lower finance fees associated with our supply and offtake agreements.
State Income Tax Expense. State income tax expense for the six months ended June 30, 2017 was $0.6 million, compared to $0.2 million for the six months ended June 30, 2016.
Net Income (Loss). Net income for the six months ended June 30, 2017 was $41.8 million, compared to net loss of $(7.4) million for the six months ended June 30, 2016, an increase of $49.2 million. This increase was attributable to the factors discussed above.

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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.
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.
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, 2017 and 2016:
 
For the Six Months Ended
 
June 30,
 
2017
 
2016
 
(dollars in thousands)
Cash provided by (used in):
 
 
 
Operating activities
$
77,145

 
$
46,587

Investing activities
(13,191
)
 
(20,924
)
Financing activities
29,761

 
3,204

Net increase in cash and cash equivalents
$
93,715

 
$
28,867

Cash Flows Provided by Operating Activities
Net cash provided by operating activities was $77.1 million during the six months ended June 30, 2017 compared to $46.6 million during the six months ended June 30, 2016. The increase in net cash provided by operating activities of $30.5 million was primarily due to increased net income after adjusting for non-cash items of $48.9 million and increased cash provided by inventories of $21.5 million, partially offset by reduced cash collected on accounts receivable of $5.1 million, increased cash used for other assets of $4.6 million, increased cash used for accounts payable and accrued liabilities of $15.2 million, reduced cash provided by other non-current liabilities of $13.7 million and increased cash used for prepaid expenses and other current assets of $1.3 million.
Cash Flows Used in Investing Activities
Net cash used in investing activities was $13.2 million during the six months ended June 30, 2017 compared to $20.9 million during the six months ended June 30, 2016. The decrease in net cash used in investing activities of $7.7 million was primarily due to completing a reformer regeneration and catalyst replacement for our diesel hydrotreater unit during 2016.
Cash Flows Provided by Financing Activities
Net cash provided by financing activities was $29.8 million during the six months ended June 30, 2017 compared to $3.2 million during the six months ended June 30, 2016. The change in net cash provided by financing activities of $26.6 million was primarily due to increased cash from borrowings on our credit facility of $50.0 million and increased cash received from RINs financing transactions of $2.2 million, partially offset by increased distributions to unitholders of $25.6 million.

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Table of Contents

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. At June 30, 2017 there were $50.0 million outstanding borrowings under this facility, compared to no borrowings at December 31, 2016. At June 30, 2017 and December 31, 2016, we had letters of credit outstanding of $48.7 million and $100.6 million, respectively.
Capital Spending
Each year the board of directors of our General Partner approves capital projects, including sustaining maintenance, regulatory and planned turnaround and catalyst projects that our management is authorized to undertake in our annual capital budget. Additionally, our management assesses opportunities for growth and profit improvement projects on an ongoing basis and any related projects require further approval from the board of directors of our General Partner. Our total capital expenditure plan for 2017 is $64.3 million, which includes expenditures for catalysts and turnarounds of $11.1 million, growth and profit improvement projects of $10.0 million and sustaining and regulatory projects of $42.9 million. Approximately $13.2 million has been spent during the six months ended June 30, 2017.
The Partnership is finalizing a consent decree with the U.S. Environmental Protection Agency (“EPA”) that will reduce air emissions from the Big Spring, Texas refinery. The agreement was part of the EPA’s industry-wide Refinery Enforcement Initiative and addresses what the EPA deems to be the most significant Clean Air Act compliance concerns affecting the petroleum industry. In addition to the payment of a civil penalty, the refinery has agreed to reduce emissions from certain units, which will require significant capital expenditures over coming years to cover the increase in the expected costs of complying with the consent decree. 
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, 2016.
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, 2016. 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, 2016.
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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Table of Contents

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, 2017, 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 $7.5 million. At June 30, 2017, the market value of crude oil inventories exceeded LIFO costs, net of the fair value hedged item, by $2.9 million.
As of June 30, 2017, we held 0.3 million barrels of refined products and blendstock and 0.2 million barrels of crude oil 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, the lower of cost or market adjustment recorded for the six months ended June 30, 2017 would have been $0.3 million higher. If the market value of crude oil would have been $1.00 per barrel lower, the market value of crude oil inventories would have exceeded LIFO costs, net of the fair value hedged item, by $2.7 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, 2017:
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)
 
(186,716
)
 
$

 
$
45.20

 
$
(8,439
)
 
$
(8,675
)
 
$
(236
)
Forwards-long (Gasoline)
 
63,926

 
60.98

 

 
3,898

 
3,984

 
86

Forwards-short (Distillate)
 
(156,892
)
 

 
61.11

 
(9,588
)
 
(10,234
)
 
(646
)
Forwards-long (Jet)
 
8,101

 
56.98

 

 
462

 
485

 
23

Forwards-long (Slurry)
 
1,039

 
39.11

 

 
41

 
45

 
4

Forwards-long (Catfeed)
 
198,036

 
56.02

 

 
11,094

 
11,524

 
430

Forwards-long (Slop)
 
6,615

 
35.20

 

 
233

 
240

 
7

Forwards-short (Propane)
 
(35,000
)
 

 
23.66

 
(828
)
 
(873
)
 
(45
)
Forwards-long (Butane)
 
22,755

 
29.67

 

 
675

 
701

 
26

Futures-long (Crude)
 
150,000

 
45.72

 

 
6,858

 
6,906

 
48

Futures-short (Gasoline)
 
(230,000
)
 

 
61.60

 
(14,169
)
 
(14,623
)
 
(454
)
Futures-long (Distillate)
 
94,000

 
61.27

 

 
5,760

 
5,855

 
95


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Table of Contents

Interest Rate Risk
As of June 30, 2017, our outstanding debt balance of $288.8 million, excluding discounts and debt issuance costs, was subject to floating interest rates, of which $50.0 million was charged interest at the Eurodollar rate plus 3.00% and $238.8 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 $2.7 million per year.

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Table of Contents

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 the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-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 were effective as of June 30, 2017 to provide reasonable assurance that information required to be disclosed by us in the reports that we file or furnish 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 provide reasonable assurance that information required to be disclosed by us in the reports that we file or furnish 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 and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission.
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) during the quarter ended June 30, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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Table of Contents

PART II. OTHER INFORMATION
ITEM 6. EXHIBITS
Exhibit
 
 
Number
 
Description of Exhibit
31.1
 
Certification of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2
 
Certification 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, 2017, 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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Table of Contents

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 1, 2017
By:  
/s/ David Wiessman
 
 
 
David Wiessman 
 
 
 
Executive Chairman of the Board
 
 
 
 
 
 
 
 
Date:
August 1, 2017
By:  
/s/ Alan Moret
 
 
 
Alan Moret
 
 
 
Chief Executive Officer
 
 
 
(Principal Executive Officer)
 
 
 
 
 
 
 
 
Date:
August 1, 2017
By:  
/s/ Shai Even
 
 
 
Shai Even
 
 
 
President and Chief Financial Officer
 
 
 
(Principal Accounting Officer)

29