UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

___________________________________________________

FORM 10-Q



þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2017



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.)

7102 Commerce Way, Brentwood, Tennessee 37027

(Address of principal executive offices) (Zip Code)

(615) 771-6701

(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 November 7, 2017, was 62,529,328.

TABLE OF CONTENTS



PART I. FINANCIAL INFORMATION
	Page
Item 1. Financial Statements	1

Condensed Consolidated Balance Sheets: Successor as of September 30, 2017 and Predecessor as of December 31, 2016 (Unaudited)	1

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss): Successor period for the three months ended September 30, 2017, and Predecessor periods for the six months ended June 30, 2017 and the three and nine months ended September 30, 2016 (Unaudited)	2

Condensed Consolidated Statements of Cash Flows: Successor period for the three months ended September 30, 2017, and Predecessor periods for the six months ended June 30, 2017 and the nine months ended September 30, 2016 (Unaudited)	3

Notes to Condensed Consolidated Financial Statements (Unaudited)	4

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	18

Forward-Looking Statements	18

Item 3. Quantitative and Qualitative Disclosures about Market Risk	35

Item 4. Controls and Procedures	37

PART II. OTHER INFORMATION	38

Item 6. Exhibits	38

Signatures	39

Table of Contents

PART I. FINANCIAL INFORMATION


ITEM 1.	FINANCIAL STATEMENTS

ALON USA PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(In thousands, except unit and per unit data)



	Successor		Predecessor
	September 30, 2017		December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	268,572	$	73,524
Accounts receivable	83,781		82,292
Accounts receivable from related parties, net of related party payables	—		11,425
Inventories, net of lower of cost or net realizable value	99,802		49,682
Prepaid expenses and other current assets	4,877		4,949
Total current assets	457,032		221,872
Property, plant and equipment, net	418,106		420,554
Goodwill	568,541		—
Other non-current assets	54,031		53,211
Total assets	$	1,497,710	$	695,637
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	101,588	$	249,835
Accounts payable to related parties, net of related party receivables	84,631		—
Accrued expenses and other current liabilities	181,820		43,100
Current portion of long-term debt	2,500		2,500
Obligation under Supply and Offtake Agreement	99,108		—
Total current liabilities	469,647		295,435
Non-current liabilities:
Long-term debt, net of current portion	335,625		233,819
Deferred income tax liability	2,374		—
Other non-current liabilities	27,381		62,880
Total non-current liabilities	365,380		296,699
Commitments and contingencies (see Note 15)
Partners’ equity:
General partner interest	—		—
Common unit interest - 62,529,328 and 62,520,220 units issued and outstanding at September 30, 2017 and December 31, 2016, respectively	662,683		103,503
Total partners’ equity	662,683		103,503
Total liabilities and partners’ equity	$	1,497,710	$	695,637

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

Table of Contents

ALON USA PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

(In thousands except per unit data)



	Successor		Predecessor
	Period from July 1, 2017 to September 30, 2017		Period from January 1, 2017 to June 30, 2017		Three Months Ended September 30, 2016			Nine Months Ended September 30, 2016
Net sales:
Affiliate	$	94,536	$	185,760	$	82,717		$	222,711
Third party	400,942		880,523		379,540			1,076,012
Net sales	495,478		1,066,283		462,257			1,298,723
Operating costs and expenses:
Cost of goods sold	415,386		911,366		404,207			1,134,275
Operating expenses	26,548		52,638		25,125			73,424
Selling, general and administrative expenses	7,741		14,156		8,153			24,264
Depreciation and amortization	7,620		28,691		14,581			43,454
Loss on disposition of assets	—		23		—			—
Total operating costs and expenses	457,295		1,006,874		452,066			1,275,417
Operating income	38,183		59,409		10,191			23,306
Interest expense, net	8,817		16,497		8,144			28,651
Other expense (income), net	5		554		(353		)	(550		)
Total non-operating expense	8,822		17,051		7,791			28,101
Income (loss) before income tax expense	29,361		42,358		2,400			(4,795		)
Income tax expense	125		566		317			493
Net income (loss) attributable to partners	$	29,236	$	41,792	$	2,083		$	(5,288	)
Comprehensive income (loss) attributable to partners	$	29,236	$	41,792	$	2,083		$	(5,288	)

Net income (loss) per unit - (basic and diluted)	$	0.47	$	0.67	$	0.03		$	(0.08	)

Weighted average common units outstanding (in thousands) - (basic and diluted)	62,529		62,523		62,520			62,515

Cash distribution per unit	$	0.35	$	0.49	0.14			$	0.22

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

Table of Contents

ALON USA PARTNERS, LP AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (In thousands)

	Successor			Predecessor
	Period from July 1, 2017 to September 30, 2017			Period from January 1, 2017 to June 30, 2017			Nine Months Ended September 30, 2016
Cash flows from operating activities:
Net income (loss)	$	29,236		$	41,792		$	(5,288	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation and amortization	7,620			28,691			43,454
Unit-based compensation	25			47			53
Deferred income taxes	9			—			—
Loss on disposition of assets	—			23			—
Amortization of debt issuance costs	—			811			1,335
Amortization of original issuance discount	—			345			480
Accretion of environmental liabilities and asset retirement obligations	187			—			—
Changes in operating assets and liabilities:
Accounts receivables, net	34,795			(27,535		)	(7,064		)
Accounts receivables/payables from related parties	73,721			1,118			(2,186		)
Inventories	(8,220		)	12,592			(16,446		)
Prepaid expenses and other current assets	1,018			701			1,012
Other non-current assets, net	203			(900		)	4,573
Accounts payable	(70,411		)	25,731			22,268
Accrued liabilities	528			(5,441		)	(2,134		)
Obligations under supply and offtake agreement	25,863			—			—
Other non-current liabilities	—			(830		)	18,400
Net cash provided by operating activities	94,574			77,145			58,457
Cash flows from investing activities:
Capital expenditures	(17,738		)	(12,175		)	(17,199		)
Capital expenditures for turnarounds and catalysts	—			(1,016		)	(9,679		)
Net cash used in investing activities	(17,738		)	(13,191		)	(26,878		)
Cash flows from financing activities:
Distributions paid to unitholders	(4,035		)	(5,648		)	(2,534		)
Distributions paid to unitholders - Alon Energy	(17,850		)	(24,990		)	(11,220		)
Proceeds from product financing agreements	—			11,649			54,860
Repayments of product financing agreements	(2,993		)	—			—
Proceeds from revolving credit facility	100,000			50,000			—
Payments of revolving credit facility	(50,000		)	—			—
Payments on long-term debt	(625		)	(1,250		)	(1,875		)
Net cash provided by financing activities	24,497			29,761			39,231
Net increase in cash and cash equivalents	101,333			93,715			70,810
Cash and cash equivalents, beginning of period	167,239			73,524			132,953
Cash and cash equivalents, end of period	$	268,572		$	167,239		$	203,763
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$	8,314		$	16,155		$	27,219
Cash paid for income tax	$	—		$	566		$	493
Capital expenditures in accounts payable	$	4,143		$	—		$	—

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

Table of Contents

ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited, dollars in thousands except as noted)

1. Organization and Basis of Presentation

As used in this report, the terms 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.

In January 2017, it was announced that Delek US Holdings, Inc. (and various related entities) had entered into an Agreement and Plan of Merger with Alon Energy (previously traded under NYSE: ALJ), as subsequently amended on February 27 and April 21, 2017 (as so amended, the "Merger Agreement"). The related mergers (the “Merger” or the “Delek/Alon Merger”) were effective July 1, 2017 (the “Effective Time”), resulting in a new post-combination consolidated registrant renamed as Delek US Holdings, Inc. (“New Delek”) (NYSE: DK), with Alon Energy and the previous Delek US Holdings, Inc. (“Old Delek”) surviving as wholly-owned subsidiaries. New Delek is the successor issuer to Old Delek and Alon Energy pursuant to Rule 12g-3(c) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). In addition, as a result of the Delek/Alon Merger, the shares of common stock of Old Delek and Alon Energy were delisted from the New York Stock Exchange in July 2017, and their respective reporting obligations under the Exchange Act were terminated. Effective July 1, 2017, with the completion of the Delek/Alon Merger, references in this report to “Delek” refer to Old Delek and its consolidated subsidiaries for the periods prior to July 1, 2017, and New Delek and its consolidated subsidiaries for the periods on or after July 1, 2017, other than the Partnership and its subsidiaries.

Effective July 1, 2017, with the completion of the Delek/Alon Merger, Delek indirectly owns 100% of our General Partner and 81.6% of our limited partner interests. 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.

As a result of the Delek/Alon Merger, the Partnership became a consolidated subsidiary of Delek and elected to apply “push-down” accounting, which required its assets and liabilities to be adjusted to fair value on the effective date of the Merger. Due to the application of push-down accounting, the Partnership’s consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented. Our consolidated financial statements and related footnotes are presented with a black-line division, which delineates the lack of comparability between amounts presented on or after July 1, 2017, and dates prior. The periods prior to the Merger date, July 1, 2017, are identified as “Predecessor” and the period from July 1, 2017, forward is identified as “Successor”. Additionally, the Partnership’s accounting policies were conformed to those of Delek at the start of the Successor Period, in connection with the Delek/Alon Merger, effective July 1, 2017. Because of the application of push-down accounting and the conforming of accounting policies, our Successor consolidated balance sheet and consolidated statements of operations and comprehensive income (loss) subsequent to the Merger are not comparable to the Predecessor’s consolidated balance sheet and consolidated statements of operations and comprehensive income (loss) prior to the Merger, and differences could be material.

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 Exchange Act. 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 nine months ended September 30, 2017, are not necessarily indicative of the operating results that may be realized for the year ending December 31, 2017.

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. Our consolidated balance sheet as of December 31, 2016, has been derived from the audited financial statements as of that date.

Accounting Policies Update

The following condensed accounting policies represent updates in the Successor period to those policies disclosed in our annual report on Form 10-K, and primarily relate to changes resulting from the conforming of accounting policies in connection with the Merger.

Inventory

Crude oil, refined products and blendstocks (including crude oil consignment inventory) are stated at the lower of cost or net realizable value. Effective July 1, 2017, inventories were recorded at fair value in connection with the push-down of the acquisition method of accounting and subsequently, in the Successor period, cost is determined under the first-in, first-out (“FIFO”) inventory valuation method. Prior to July 1, 2017, cost was determined under the last-in, first-out (“LIFO”) valuation method. Under the LIFO valuation method, the most recently incurred costs are charged to cost of goods sold and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. An inventory write-down to market value results in a non-cash accounting adjustment, decreasing the value of our inventory and increasing our cost of goods sold. Such charges are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of goods sold in years when inventory volumes decline and result in charging cost of goods sold with LIFO inventory costs generated in prior periods.

Supply and Inventory Purchase Agreements

We have a Supply and Offtake Agreement (as defined in Note 6) with J. Aron & Company (“J. Aron”) whereby we agree to buy from J. Aron, at market prices, crude oil for processing at our refinery, and whereby we agree to sell to J. Aron certain refined products produced at our refinery. Such refined product will ultimately be marketed for sale to third parties, facilitated by the Partnership’s marketing function, as required by the Supply and Offtake Agreement. Following expiration or termination of the Supply and Offtake Agreement, we are obligated to purchase the crude oil and refined product inventories owned by J. Aron at then current market rates. (See further discussion in Note 6).

During the Successor period, such crude oil and refined product inventory is treated as financed inventory and reflected on the balance sheet, initially at fair value (in connection with the push-down of the acquisition method of accounting as of July 1, 2017) and then subsequently at the lower of FIFO cost or net realizable value, and the liability to repurchase the inventory (the “step-out liability”, further discussed in Note 6), is reflected on the balance sheet at fair value on a recurring basis. Effective July 1, 2017, such refined product inventory purchased by J. Aron is recognized in revenue when the inventory is sold to third parties.

During the Predecessor period, the crude oil inventory was treated as financed inventory and reflected on the balance sheet and the refined product inventory was relieved and excluded from the balance sheet when purchased by J. Aron at the inception of the Supply and Offtake Agreement. The repurchase requirement for the crude oil was considered to contain an embedded derivative, which was bifurcated and designated as a fair value hedge against changes to the fair value of the crude oil inventory. As such, the carrying value of inventory was adjusted for changes in fair value, with those changes recognized in earnings. The changes in fair value of the bifurcated derivative were also reflected in earnings. Additionally, sales of refined product inventory were recognized when purchased by J. Aron. See Note 6 for further discussion.

Property, Plant and Equipment

Depreciation for depreciable assets is computed using the straight-line method over management’s estimated useful lives of the related assets, which was 3 - 20 years during the Predecessor periods, and 7 - 40 years in the Successor period.

Renewable Identification Numbers

The U.S. Environmental Protection Agency (“EPA”) requires certain refiners to blend biofuels into the fuel products they produce pursuant to the EPA’s Renewable Fuel Standard - 2 ("RFS-2"). Alternatively, credits, called Renewable Identification Numbers ("RINs"), which may be generated and/or purchased, can be used to satisfy this obligation instead of physically blending biofuels ("RINs Obligation"). See Note 3 for further information.

From time to time, we enter into future commitments to purchase or sell RINs at fixed prices and quantities, which are used to manage the costs associated with our RINs Obligation. These future RIN commitment contracts meet the definition of derivative instruments under ASC 815 and are recorded at estimated fair value in accordance with the provisions of ASC 815. During the Successor period, changes in the fair value of these future RIN commitment contracts are recorded in cost of goods sold on the consolidated statements of income. During the Predecessor period, we elected the normal purchase and sale exception and did not record these contracts at their fair values. See Note 4 for further information.

Income Taxes

Following the Delek/Alon Merger, operations of the Partnership are included in the consolidated Texas franchise tax return of Delek. Prior to the Delek/Alon Merger, Texas franchise tax was reported in the financial statements for the Partnership as if a separate return was filed.

Beginning July 1, 2017, Texas franchise tax is allocated to the Partnership based on its relative share of the consolidated gross margin of Delek.

Change in Classification

In connection with conforming the accounting policies to that of Delek in connection with the Merger, the presentation and classification of certain financial statement amounts has changed in the Successor period as compared to the Predecessor period. The most significant of these changes is the change in classification of catalysts and turnaround costs. During the Predecessor period, such costs were included in other non-current assets on the balance sheet. In the Successor period, such costs are included in property, plant and equipment. Other changes in classification have been made to the Successor period as compared to the Predecessor period, as appropriate, to conform to the presentation of the Delek consolidated financial statements.

New Accounting Pronouncements

In August 2017, the Financial Accounting Standards Board (the “FASB”) issued guidance to refine and expand hedge accounting for both financial and commodity risks. Its provisions create more transparency around how economic results are presented, both on the face of the financial statements and in the footnotes and align the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. It also makes certain targeted improvements to simplify the application of hedge accounting guidance. This guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, and can be early adopted for any interim or annal financial statements that have not yet been issued. We expect to adopt this guidance on or before the effective date and are currently evaluating the impact that adopting this new guidance will have on our business, financial condition and results of operations.

In May 2017, the FASB issued guidance that clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. The modification accounting guidance applies if the value, vesting conditions or classification of the award changes. This guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, and can be early adopted for any interim or annual financial statements that have not yet been issued. We expect to adopt this guidance on or before the effective date and are currently evaluating the impact that adopting this new guidance will have on our business, financial condition and results of operations.

In January 2017, the FASB issued guidance that eliminates Step 2 of the goodwill impairment test, which required a comparison of the implied fair value of goodwill of the reporting unit with the carrying amount of that goodwill for that reporting unit. It also eliminates the requirements for any reporting unit with a zero or negative carrying amount to perform a qualitative assessment and, if it fails that qualitative assessment, to perform Step 2 of the goodwill impairment test. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. This guidance is effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We expect to adopt this guidance on or before the effective date and we do not anticipate that the adoption will have a material impact on our business, financial condition or results of operations.

In January 2017, the FASB issued guidance clarifying the definition of a business in order to assist entities with evaluating when a set of transferred assets and activities is considered a business. In general, we expect that the revised definition will result in fewer acquisitions being accounted for as business combinations than under the current guidance. This guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted under certain circumstances. We early adopted this guidance as of July 1, 2017, with no material impact to our consolidated financial statements.

In March 2016, the FASB issued guidance that simplifies several aspects of the accounting for share-based payment award transactions, including the accounting for excess tax benefits and deficiencies, classification of awards as either equity or liabilities and classification of excess tax benefits on the statement of cash flows. This guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years and can be early adopted for any interim or annual financial statements that have not yet been issued. We have adopted the updated guidance, effective January 1, 2017, with no material impact to our consolidated financial statements.

In January 2016, the FASB issued guidance that affects the accounting for equity investments, financial liabilities accounted for under the fair value option and the presentation and disclosure requirements for financial instruments. Under the new guidance, all equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) will generally be measured at fair value through earnings. There will no longer be an available-for-sale classification for equity securities with readily determinable fair values. For financial liabilities when the fair value option has been elected, changes in fair value due to instrument-specific credit risk will be recognized separately in other comprehensive income. It will require public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes and separate presentation of financial assets and financial liabilities by measurement category and form

of financial asset, and will eliminate the requirement for public business entities to disclose the method and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost.The new guidance is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We expect to adopt this guidance on or before the effective date and currently do not expect this new guidance to have a material impact on our business, financial condition or results of operations.

In July 2015, the FASB issued guidance requiring entities to measure FIFO or average cost inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This guidance does not change the measurement of inventory measured using LIFO or the retail inventory method. This guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. We adopted this guidance on July 1, 2017 in connection with the Merger, and the adoption did not have a material impact on our business, financial condition or results of operations.

In May 2014, the FASB issued guidance regarding “Revenue from Contracts with Customers,” to clarify the principles for recognizing revenue. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires improved interim and annual disclosures that enable the users of financial statements to better understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. The new guidance is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period, and can be adopted retrospectively. We will adopt this guidance on January 1, 2018.

As part of our efforts to prepare for adoption, in connection with the Delek/Alon Merger, we reviewed and gained an understanding of the new revenue recognition accounting guidance as applicable to the Partnership, performed scoping to identify and evaluate revenue streams under the new standard, and continue to review industry specific implementation guidance. We also developed internal controls over the implementation and transition process. We will perform testing to confirm our overall assessment during the fourth quarter of 2017 and determine any transition adjustments that may be required. We preliminarily expect to use the modified retrospective adoption method to apply this standard, under which the cumulative effect of initially applying the new guidance will be recognized as an adjustment to the opening balance of retained earnings in the first quarter of 2018.

2. Delek/Alon Merger

The Delek/Alon Merger was accounted for using the acquisition method. The Partnership estimated the enterprise value of the Partnership on July 1, 2017 based on fair value as of the effective date. The estimated fair value of the partners’ capital balances as of July 1, 2017 was $655,307.

As a result of the Partnership’s election to apply push-down accounting in connection with the Delek/Alon Merger, our assets and liabilities were adjusted to fair value on July 1, 2017. The Partnership has recorded goodwill as the excess of the estimated enterprise value over the sum of the fair value amounts allocated to the Partnership’s assets and liabilities. The allocation was based upon a preliminary valuation. Our estimates and assumptions are subject to change during the purchase price allocation period. The preliminary purchase price allocation as of September 30, 2017 is summarized as follows:

Table of Contents

ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)



Cash	$	167,239
Receivables	119,495
Inventories	91,582
Prepaids and other current assets	5,895
Property, plant and equipment ⁽¹⁾	402,273
Acquired intangibles ^{(1) (2)}	43,924
Goodwill	568,541
Other non-current assets	11,882
Accounts payable	(179,815		)
Obligation under Supply and Offtake Agreement	(73,245		)
Other current liabilities	(184,155		)
Deferred income taxes	(2,365		)
Long term debt, net of current portion	(288,750		)
Other non-current liabilities	(27,194		)
	$	655,307

_______________________


⁽¹⁾	The primary areas of the purchase price allocation that are not yet finalized relate to property, plant and equipment valuation and allocation, evaluation of certain contracts and certain evaluations of legal and environmental matters.

⁽²⁾The acquired intangibles amount includes the following identified intangibles:


•	third-party fuel supply agreement intangible that is subject to amortization with a preliminary fair value of $43,000, which will be amortized over a 10-year useful life. We recognized amortization expense for the three months ended September 30, 2017 of $1,075. The estimated amortization is $1,075 for the fourth quarter of 2017 and $4,300 for each of the five succeeding fiscal years.


•	Refinery permits preliminarily valued at $924, which have an indefinite life.

3. Fair Value Measurements

The fair values of financial instruments are estimated based upon current market conditions and quoted market prices for the same or similar instruments. Management estimates that the carrying value approximates fair value for all of our assets and liabilities that fall under the scope of Accounting Standards Codification (“ASC”) 825, Financial Instruments ("ASC 825").

We apply the provisions of ASC 820, Fair Value Measurements ("ASC 820"), which defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. ASC 820 applies to our commodity derivatives that are measured at fair value on a recurring basis. The standard also requires that we assess the impact of nonperformance risk on our derivatives. Nonperformance risk is not considered material to our financial statements at this time.

Our RINs Obligation surplus or deficit is based on the amount of RINs we must purchase, net of amounts internally generated and purchased and the price of those RINs as of the balance sheet date. The RINs Obligation surplus or deficit is categorized as Level 2 and is measured at fair value based on quoted prices from an independent pricing service.

Our RIN commitment contracts are future commitments to purchase or sell RINs at fixed prices and quantities, which are used to manage the costs associated with our RINs Obligation. In the Successor period, they are categorized as Level 2, and are measured at fair value based on quoted prices from an independent pricing service. Changes in the fair value of these future RIN commitment contracts are recorded in cost of goods sold on the consolidated statements of income. In the Predecessor period, we elected the normal purchase and sale exception and did not record these contracts at their fair values.

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.

Beginning July 1, 2017, we account for the liability to repurchase inventory previously sold to J. Aron under the Supply and Offtake Agreement, defined in Note 6 (the “step-out liability”), at fair value in accordance with ASC 825, as it pertains to the fair value option. This standard permits the election to carry financial instruments and certain other items similar to financial instruments at fair value on the balance sheet, with all changes in fair value reported in earnings. By electing the fair value option, we can achieve an accounting result similar to a fair value hedge without having to follow the complex hedge accounting rules. Our J. Aron step-out liability is categorized as Level 2, and is measured at fair value using market prices for the consigned crude oil and refined products we are required to repurchase from J. Aron at the end of the term of the Supply and Offtake Agreement. The J. Aron step-out liability is presented in the Obligation under Supply and Offtake Agreement line item of our condensed consolidated balance sheet as of September 30, 2017. Such inventory was previously considered consigned, and we previously recorded an associated embedded derivative at fair value, and designated such as a fair value hedge on the change in fair value of the inventory in the Predecessor periods. See Note 6 for further discussion.

The fair value hierarchy for our financial assets and liabilities accounted for at fair value on a recurring basis at September 30, 2017 and December 31, 2016 was as follows:



	Level 1			Level 2			Level 3		Total
Successor
As of September 30, 2017
Assets
Commodity contracts (futures)	$	—		$	311		$	—	$	311
Total assets	—			311			—		311
Liabilities
Commodity contracts (futures)	—			(199		)	—		(199		)
RINs obligation deficit	—			(29,593		)	—		(29,593		)
RIN commitment contracts	—			(6,614		)	—		(6,614		)
J. Aron step-out liability	—			(99,108		)	—		(99,108		)
Total liabilities	—			(135,514		)	—		(135,514		)
Net Liabilities	$	—		$	(135,203	)	$	—	$	(135,203	)

Predecessor
As of December 31, 2016
Assets
Commodity contracts (futures and forwards)	$	1,930		$	—		$	—	$	1,930
Fair value hedge of consigned inventory	—			4,389			—		4,389
Total assets	1,930			4,389			—		6,319

Liabilities
Commodity contracts (futures and forwards)	(2,619		)	—			—		(2,619		)
Total liabilities	(2,619		)	—			—		(2,619		)
Net (liabilities) assets	$	(689	)	$	4,389		$	—	$	3,700

4. Derivative Instruments

We selectively utilize crude oil and refined product commodity derivative contracts to reduce the risk associated with potential price changes on committed obligations as well as to reduce earnings volatility. We do not speculate using derivative instruments. Credit risk on our derivative instruments is mitigated by transacting with counterparties meeting established collateral and credit criteria.

Mark to Market

We have certain contracts that serve as economic hedges, which are derivatives used for risk management but not designated as hedges for financial accounting purposes. All economic hedge transactions are recorded at fair value and any changes in fair value between periods are recognized in earnings.

We have contracts that are used to fix prices on forecasted purchases of inventory, which we refer to as futures. Futures represent trades executed which have not been closed or settled at the end of the reporting period.

The following table presents the fair value of our derivative instruments as of September 30, 2017. The fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under our master netting arrangements, including cash collateral on deposit with our counterparties. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements. As a result, the asset and liability amounts below differ from the amounts presented in our condensed consolidated balance sheets. See Note 3 for further information regarding the fair value of derivative instruments (in thousands):



Successor
		September 30, 2017
Derivative Type	Balance Sheet Location	Assets			Liabilities
Derivatives not designated as hedging instruments:
Commodity contracts (futures) ⁽¹⁾	Other current assets	$	311		$	(199	)
RIN commitment contracts ⁽²⁾	Other current liabilities	—			(6,614		)
Total gross fair value of derivatives		311			(6,813		)
Less: Counterparty netting and cash collateral⁽³⁾		(1,558		)	(199		)
Total net fair value of derivatives		$	1,869		$	(6,614	)


⁽¹⁾	As of September 30, 2017, we had open derivative positions representing 432 thousand barrels of crude oil and refined petroleum products.


⁽²⁾	As of September 30, 2017, we had open RIN contracts representing 320,217 thousand RINs.


⁽³⁾	As of September 30, 2017, $1,757 of cash collateral held by a counterparty has been netted with the derivatives with that counterparty.

Fair Value Hedge

Prior to July 1, 2017, we had forwards that 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. These were designated as fair value hedges and were 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, was recognized in earnings in the same period.

We had certain embedded commodity derivatives associated with the Supply and Offtake Agreement discussed in Note 6 that were accounted for as a fair value hedge, which had purchase volumes of 126 thousand barrels of crude oil as of December 31, 2016.

The following table presents the effect of derivative instruments on the consolidated balance sheets as of December 31, 2016:



Predecessor
		December 31, 2016
Derivative Type	Balance Sheet Location	Assets		Liabilities
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	980	$	(950	)
Commodity contracts (futures and forwards)	Accrued liabilities	950		(1,669		)

Derivatives designated as hedging instruments:
Fair value hedge of consigned inventory	Other assets	4,389		—
Total gross fair value of derivatives		6,319		(2,619		)
Less: Counterparty netting and cash collateral⁽¹⁾		1,900		(1,900		)
Total net fair value of derivatives		$	4,419	$	(719	)


⁽¹⁾	As of December 31, 2016, there was no cash collateral held by a counterparty to net.

The following tables present the effect of derivative instruments on the consolidated statements of operations:

Derivatives in fair value hedging relationships:




		Predecessor
	Location	Period from January 1, 2017 to June 30, 2017		Three Months Ended September 30, 2016			Nine Months Ended September 30, 2016
Fair value hedge of consigned inventory ⁽¹⁾	Interest expense	741		(1,772		)	(5,995		)
Total derivatives		$	741	$	(1,772	)	$	(5,995	)

_______________________


⁽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 (Loss) Recognized in Income
		Successor			Predecessor
	Location	Period from July 1, 2017 to September 30, 2017			Period from January 1, 2017 to June 30, 2017		Three Months Ended September 30, 2016			Nine Months Ended September 30, 2016
Commodity contracts (futures)	Cost of goods sold	(2,393		)	3,479		(1,199		)	4,998
Total derivatives		$	(2,393	)	$	3,479	$	(1,199	)	$	4,998

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 meet the definition of derivative instruments under ASC 815. In the Successor period, these contracts are recorded at estimated fair value in accordance with the provisions of ASC 815. Changes in the fair value of these future RIN commitment contracts are recorded in cost of goods sold on the consolidated statements of income. In the Predecessor period, we elected the normal purchase and sale exception and recorded purchases and sales as a component of cost of goods sold in the consolidated statements of income.

The cost of meeting our obligations under these compliance programs for the Successor three-month period ended September 30, 2017 and the Predecessor three-month period ended September 30, 2016 was $7,314 and $3,712, respectively, and $6,438 and $6,620 for the Predecessor six-month period ended June 30, 2017 and the Predecessor nine-month period ended September 30, 2016, respectively. These amounts are reflected in cost of goods sold in the consolidated statements of operations.

5. Inventory

Carrying value of inventories consisted of the following:



	Successor		Predecessor
	September 30, 2017		December 31, 2016
Crude oil, refined products and blendstocks	$	99,802	$	38,109
Materials and supplies	—		11,573
Total inventories	$	99,802	$	49,682

Effective July 1, 2017, in connection with the Delek/Alon Merger, inventory was recorded at fair value under the acquisition method. Going forward, cost of inventory is accounted for using the FIFO method, pursuant to which inventories are valued at the lower of FIFO cost or net realizable value.

Prior to July 1, 2017, our Predecessor determined the cost of inventory using the LIFO valuation method and costs in excess of market value were charged to cost of goods sold. At 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 $6,213. At December 31, 2016, the market value of our crude oil inventories exceeded LIFO costs, net of the fair value hedged item, by $5,236.

6. Crude Oil Supply and Inventory Purchase Agreements

We have entered into a Supply and Offtake Agreement and other associated agreements (together “Supply and Offtake Agreement”) with 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 provides 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. These daily purchases and sales are trued-up on a monthly basis in order to reflect actual average monthly prices. We have recorded a receivable related to this monthly settlement of $7,052 as of September 30, 2017. 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.

Effective July 1, 2017, in connection with the Delek/Alon Merger, the Supply and Offtake Agreement is accounted for as a product financing arrangement. We incurred fees payable to J. Aron of $1,455 during the three months ended September 30, 2017. These amounts are included as a component of interest expense in the condensed consolidated statements of income.

Upon any termination of the Supply and Offtake Agreement, including in connection with a force majeure event, the parties are required to negotiate with third parties for the assignment to us of certain contracts, commitments and arrangements, including procurement contracts, commitments for the sale of product, and pipeline, terminalling, storage and shipping arrangements. Upon the expiration or termination of the Supply and Offtake Agreement, we will be required to repurchase the consigned crude oil and refined products from J. Aron at then-prevailing market prices. At September 30, 2017, we had 1.6 million barrels of inventory consigned from J. Aron, and we have recorded liabilities associated with this consigned inventory of $99,108 in the condensed consolidated balance sheet.

Prior to July 1, 2017, associated with the Supply and Offtake Agreement, our Predecessor had 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 were recorded as interest expense in the consolidated statements of operations.

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ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

At December 31, 2016, we had net current receivables of $10,569 with J. Aron for purchases and sales, and a consignment inventory receivable representing a deposit paid to J. Aron of $6,290. At December 31, 2016, we had non-current liabilities for the original financing of $7,550, net of the related fair value hedge. Additionally, we had net current payables of $719 at December 31, 2016, for forward commitments related to month-end consignment inventory target levels differing from projected levels and the associated pricing with these inventory level differences.

7. Property, Plant and Equipment

Property, plant and equipment, net and depreciation expense are as follows:



	Successor			Predecessor
	September 30, 2017			December 31, 2016
Refining facilities	$	424,154		$	732,697
Less: Accumulated depreciation	(6,048		)	(312,143		)
Property, plant and equipment, net	$	418,106		$	420,554

Depreciation expense for the Successor three-month period ended September 30, 2017 and the Predecessor three-month period ended September 30, 2016 was $6,048 and $9,316, respectively. Depreciation expense for the Predecessor six-month period ended June 30, 2017 and the Predecessor nine-month period ended September 30, 2016 was $19,514 and $27,558, respectively.

8. Other Assets and Liabilities

The detail of other non-current assets is as follows:

Other Non-Current Assets, Net



	Successor		Predecessor
	September 30, 2017		December 31, 2016
Deferred turnaround and catalyst cost	$	—	$	34,252
Contract and other intangibles	42,849		—
Receivable from Supply and Offtake Agreement (Note 6)	6,290		6,290
Fair value hedge of consigned inventory (Note 4)	—		4,389
Other	4,892		8,280
Total other assets	$	54,031	$	53,211

Accounts Payable

Included in accounts payable were $78,565 related to RINs financing transactions as of December 31, 2016 that are accounted for as product financing arrangements. RINs financing transactions were included in accrued expenses and other current liabilities as of September 30, 2017.

The detail of accrued expenses and other non-current liabilities is as follows:

Accrued Liabilities and Other Non-Current Liabilities



	Successor		Predecessor
	September 30, 2017		December 31, 2016
Accrued Liabilities:
Taxes other than income taxes, primarily excise taxes	$	21,196	$	31,882
Accrued finance charges	493		372
Environmental accrual (Note 15)	4,214		796
Commodity contracts (Note 4)	6,614		719
RINs Obligation deficit (Note 3)	29,593		—
RINs financing transactions	109,276		—
Other	10,434		9,331
Total accrued liabilities	$	181,820	$	43,100

Other Non-Current Liabilities:
Obligation under Supply and Offtake Agreement (Note 6)	$	—	$	11,939
Environmental accrual (Note 15)	25,171		5,796
Asset retirement obligations	2,010		3,131
RINs financing transactions	—		39,478
Other	200		2,536
Total other non-current liabilities	$	27,381	$	62,880

9. Long-Term Obligations

Debt consisted of the following:



	Successor		Predecessor
	September 30, 2017		December 31, 2016
Term loan credit facility	$	238,125	$	236,319
Revolving credit facility	100,000		—
Total debt	338,125		236,319
Less: Current portion	2,500		2,500
Total long-term debt	$	335,625	$	233,819

At July 1, 2017, all outstanding debt was adjusted to fair value pursuant to the push-down of the acquisition method of accounting.

Term Loan Credit Facility

In November 2012, we entered into a $250,000 term loan with Credit Suisse (the “Term Loan”). The Term Loan requires principal payments of $2,500 per annum paid in equal quarterly installments until maturity in November 2018. The Term Loan bears interest at a rate equal to the sum of (i) the Eurodollar rate (with a floor of 1.25% per annum) plus (ii) a margin of 8.00% per annum. At September 30, 2017, the weighted average interest rate was approximately 9.25% per annum under the Term Loan.

The Term Loan is secured by a first priority lien on all of our fixed assets and other specified property, as well as on our general partner interest held by the General Partner, and a second priority lien on our cash, accounts receivables, inventories and related assets. The Term Loan contains restrictive covenants, such as restrictions on liens, mergers, consolidation, sales of assets, additional indebtedness, different businesses, certain lease obligations and certain restricted payments. The Term Loan does not contain any maintenance financial covenants.

At September 30, 2017, and December 31, 2016, the Term Loan had an outstanding principal balance of $238,125 and $240,000, respectively. Outstanding borrowings are net of deferred financing costs and debt discount of $2,307 and $1,374, respectively, at December 31, 2016.

Revolving Credit Facility

We have a $240,000 revolving credit facility (the “Revolving Credit Facility”) that will mature on May 6, 2019 or an earlier date linked to our Term Loan maturity date, in accordance with the terms of the Revolving Credit Facility. The Revolving Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility amount or the borrowing base amount under the facility. Borrowings under the Revolving Credit Facility allow us to choose between base rate loans or LIBOR loans, plus respective margins.

The Revolving Credit Facility is secured by a first priority lien on our cash, accounts receivables, inventories and related assets and a second priority lien on our fixed assets and other specified property. The Revolving Credit Facility contains maintenance financial covenants. At September 30, 2017, we were in compliance with these covenants.

At September 30, 2017, the weighted average borrowing rate was approximately 5.3%. Additionally, the Revolving Credit Facility requires the payment of a quarterly fee on the average unused revolving commitment. As of September 30, 2017, this fee was 0.65% per year. As of September 30, 2017, we had $100,000 of outstanding borrowings under the credit facility. There were no borrowings outstanding at December 31, 2016. At September 30, 2017 and December 31, 2016, we had letters of credit outstanding of $14,398 and $100,613, respectively. Unused credit commitments under the Revolving Credit Facility as of September 30, 2017 were $125,602.

As of September 30, 2017, the Partnership has a letter of commitment from Delek to refinance the Revolving Credit Facility as long-term debt prior to its maturity. As such, the borrowings outstanding under this facility as of September 30, 2017 have been classified as non-current.

10. Income Taxes

For tax purposes, each partner of the Partnership is required to take into account its share of income, gain, loss and deduction in computing its federal and state income tax liabilities, regardless of whether cash distributions are made to such partner by the Partnership. The taxable income reportable to each partner takes into account differences between the tax basis and fair market value of our assets, the acquisition price of such partner's units and the taxable income allocation requirements under our Partnership Agreement.

11. Net Income per Common Unit

The Partnership’s net income (loss) is allocated wholly to the common units as the general partner does not have an economic interest. Basic and diluted net income (loss) per common unit is calculated by dividing net income (loss) by the weighted-average number of common units outstanding during the period.

The following table illustrates the Partnership’s calculation of net income (loss) per common unit for the three and nine months ended September 30, 2017 and 2016:



	Successor		Predecessor
	Period from July 1, 2017 to September 30, 2017		Period from January 1, 2017 to June 30, 2017		Three Months Ended September 30, 2016		Nine Months Ended September 30, 2016
Net income (loss)	$	29,236	$	41,792	$	2,083	$	(5,288	)
Net income (loss) per common unit, basic and diluted	0.47		0.67		0.03		(0.08		)
Weighted-average common units outstanding, basic and diluted	62,529		62,523		62,520		62,515

12. Equity

We had 11,492,800 common limited partner units held by the public outstanding as of September 30, 2017. Additionally, as of September 30, 2017, Delek owned an 81.6% limited partner interest in us, consisting of 51,036,528 common limited partner units. The Delek/Alon Merger had no impact on the number of units outstanding.

Equity Activity

The table below summarizes the changes to equity during the nine months ended September 30, 2017:



	Common Unitholders			General Partner		Total Partners' Equity
Predecessor
Balance at December 31, 2016	$	103,503		$	—	$	103,503
Unit-based compensation	47			—		47
Distributions paid to unitholders	(30,638		)	—		(30,638		)
Net income	41,792			—		41,792
Balance at June 30, 2017	$	114,704		$	—	$	114,704

Successor
Balance at July 1, 2017	$	655,307		$	—	$	655,307
Unit-based compensation	25			—		25
Distributions paid to unitholders	(21,885		)	—		(21,885		)
Net income	29,236			—		29,236
Balance at September 30, 2017	$	662,683		$	—	$	662,683

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 in accordance with the terms and conditions of our Partnership Agreement. 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 nine months ended September 30, 2017:



	Cash Available for Distribution per Unit ⁽¹⁾		Distribution Paid Per Unit		Total Distribution Paid
Predecessor
First Quarter 2017	$	0.38	$	0.11	$	6,877
Second Quarter 2017	$	0.35	$	0.38	$	23,761

Successor
Third Quarter 2017	$	0.43	$	0.35	$	21,885


⁽¹⁾	Represents the aggregate cash available for distribution per unit attributable to the period indicated.

13. Equity Based Compensation

Restricted Units

We, through our General Partner, have adopted the Alon USA Partners, LP 2012 Long-Term Incentive Plan (the “LTIP”) for the employees, consultants and the directors of the Partnership, the General Partner and its affiliates who perform services for us. The LTIP provides grants of options, unit appreciation rights, restricted units, phantom units, unit awards, substitute awards, other unit-based awards, cash awards, performance awards and distribution equivalent rights. The maximum aggregate number of common units that may be issued under the LTIP shall not exceed 3,125,000 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.

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ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

14. Related Party Transactions

Acquisition of Alon Energy

The general and limited partner interests that were previously owned by Alon Energy were contributed to Delek in connection with the Delek/Alon Merger, as described in Note 1. As a result of the Delek/Alon Merger, both the Partnership and Alon Energy became subsidiaries of Delek, and Delek thereafter 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. The Partnership has various operating and administrative agreements with Alon Energy (now Delek), including the agreements described below. Delek performs the administrative functions defined in such agreements on the Partnership’s behalf.

Sales and Receivables

Sales to related parties include feedstock, refined and blended product and asphalt sold to other Delek 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.

Purchases and Payables

We had purchases of crude oil, products and RINs from Delek of $770 and $175 for the Successor three-month period ended September 30, 2017 and the Predecessor three-month period ended September 30, 2016, respectively, and $22,239 and $960 for the Predecessor six months ended June 30, 2017 and and the Predecessor nine-month period ended September 30, 2016, respectively. Accounts payable includes a balance outstanding to Delek of $84,631 at September 30, 2017.

Costs Allocated from Delek

The Partnership is a subsidiary of Delek and is operated as a component of the integrated operations of Delek. As such, the executive officers of Delek, who are employed by another subsidiary of Delek, also serve as executive officers of the General Partner and Delek’s other subsidiaries.

Corporate Overhead Allocations

Delek performs general corporate and administrative services and functions for us and Delek’s 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. Delek 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 Delek’s other subsidiaries. The management of Delek 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 was $3,215 and $3,301, for the Successor three-month period ended September 30, 2017 and the Predecessor three-month period ended September 30, 2016, respectively, and $5,766 and $10,966 for the Predecessor six-month period ended June 30, 2017 and the Predecessor nine-month period ended September 30, 2016, respectively.

Labor Costs

As we are operated as a component of Delek’s integrated operations, we have no employees. As a result, employee expense costs for Delek 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 Delek’s employee expense costs included in direct operating expenses were $6,400 and $7,391 for the Successor three-month period ended September 30, 2017 and the Predecessor three-month period ended September 30, 2016, respectively, and $14,474 and $21,723 for the Predecessor six-month period ended June 30, 2017 and the Predecessor nine-month period ended September 30, 2016, respectively. The allocated portion of Delek’s employee expense costs included in selling, general and administrative expenses were $3,805 and $1,178 for the Successor three-month period ended September 30, 2017 and the Predecessor three-month period ended September 30, 2016, respectively, and $1,967 and $3,413 for the Predecessor six-month period ended June 30, 2017 and the Predecessor nine-month period ended September 30, 2016, respectively.

Insurance Costs

Insurance costs related to the Big Spring refinery and wholesale marketing operations are allocated to us by Delek based on estimated insurance premiums on a stand-alone basis relative to Delek’s total insurance premium. Our allocation for insurance costs included in direct operating expenses were $971 and $1,507 for the Successor three-month period ended September 30, 2017 and the Predecessor three-month period ended September 30, 2016, respectively, and $2,246 and $3,879 for the Predecessor six-month period ended June 30, 2017 and the Predecessor nine-month period ended September 30, 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)

Leasing Agreements

Included as a component of selling, general and administrative expenses are payments to a subsidiary of Alon Energy for use of certain equipment at the Big Spring refinery totaling $1,230 for the both Successor three-month period ended September 30, 2017 and the Predecessor three-month period ended September 30, 2016, $2,460 for the Predecessor six-month period ended June 30, 2017 and $3,690 for the the Predecessor nine-month period ended September 30, 2016.

Cash Distributions

Our common unitholders are entitled to receive distributions of available cash as it is determined by the board of directors of the General Partner in accordance with the terms and provisions of our Partnership Agreement. During the Successor three-month period ended September 30, 2017 we paid cash distributions of $21,885, or $0.35 per unit, of which $17,850 was paid to Delek. During the Predecessor six-month period ended June 30, 2017 and the Predecessor nine-month period ended September 30, 2016, we paid cash distributions of $30,638 or $0.49 per unit, and $13,754, or $0.22 per unit, of which $24,990 and $11,220 was paid to Alon Energy, respectively.


15.	Commitments and Contingencies

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.

Litigation

In the ordinary conduct of our business, we are from time to time subject to lawsuits, investigations and claims, including environmental claims and employee-related matters.

Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, including civil penalties or other enforcement actions, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, financial condition or results of operations.

Environmental, Health and Safety

We are subject to extensive federal, state and local environmental and safety laws and regulations enforced by various agencies, including the EPA, the United States Department of Transportation, the Occupational Safety and Health Administration, the Texas Commission on Environmental Quality, and the Railroad Commission of Texas, as well as other state and federal agencies.

These laws and regulations govern the discharge of materials into the environment, waste management practices, pollution prevention measures and the composition of the fuels we produce, as well as the safe operation of our plants and pipelines and the safety of our workers and the public. Numerous permits or other authorizations are required under these laws and regulations for the operation of our refineries, terminals, pipelines and related operations, and may be subject to revocation, modification and renewal.

These laws and permits raise potential exposure to future claims and lawsuits involving environmental and safety matters which could include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of, transported, or that relate to pre-existing conditions for which we have assumed responsibility. We believe that our current operations are in substantial compliance with existing environmental and safety requirements. However, there have been and will continue to be ongoing discussions about environmental and safety matters between us and federal and state authorities, including notices of violations, citations and other enforcement actions, some of which have resulted or may result in changes to operating procedures and in capital expenditures. While it is often difficult to quantify future environmental or safety related expenditures, we anticipate that continuing capital investments and changes in operating procedures will be required for the foreseeable future to comply with existing and new requirements, as well as evolving interpretations and more strict enforcement of existing laws and regulations.

We have been negotiating an agreement with EPA for over 10 years under EPA’s National Petroleum Refinery Initiative regarding alleged historical violations of the federal Clean Air Act. A Consent Decree resolving these alleged historical violations for our refinery was lodged with the United States District Court for the Northern District of Texas on June 6, 2017, and we expect that Consent Decree to become final later this year. If finalized, the Consent Decree will require payment of a $456 civil penalty and capital expenditures for pollution control equipment that may be significant over the next 5 years.

As of September 30, 2017, we have recorded an environmental liability of approximately $29,385, primarily related to remediating or otherwise addressing certain environmental issues of a non-capital nature at the Big Spring Refinery. This liability includes estimated costs for ongoing investigation and remediation efforts, which were already being performed by the former operators of the refineries and terminals prior to our acquisition of those facilities, for known contamination of soil and groundwater, as well as estimated costs for additional issues which have been identified subsequent to the acquisitions.

Approximately $4,214 of the total liability is expected to be expended over the next 12 months with most of the balance expended by 2046. In the future, we could be required to extend the expected remediation period or undertake additional investigations of our refineries, pipelines and terminal facilities, which could result in additional remediation liabilities.

16. Subsequent Event

Planned Acquisition of Non-controlling Interest in the Partnership

On November 8, 2017, Delek and the Partnership announced a definitive merger agreement under which Delek will acquire all of the outstanding limited partner units which Delek does not already own in an all-equity transaction. Delek currently owns approximately 51,000 limited partner units of the Partnership, or approximately 81.6% of the outstanding units. Under terms of the merger agreement, the owners of the remaining outstanding units in the Partnership that Delek does not currently own will receive a fixed exchange ratio of 0.49 Delek shares for each limited partner unit of the Partnership. This transaction was approved by all voting members of the board of directors of the general partner of the Partnership upon the recommendation from its conflicts committee and by the board of directors of Delek. This transaction is expected to close in the first quarter of 2018.

Dividend Declaration

On November 2, 2017, our General Partner’s board of directors voted to declare a quarterly cash distribution of $0.43 per share of our common units, payable on November 22, 2017 to unitholders of record on November 13, 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,” “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. In January 2017, it was announced that Delek US Holdings, Inc. (and various related entities) had entered into an Agreement and Plan of Merger with Alon Energy (NYSE: ALJ), as subsequently amended on February 27 and April 21, 2017 (as so amended, the "Merger Agreement"). The related mergers (the “Merger” of the “Delek/Alon Merger”) were effective July 1, 2017 (the “Effective Time”), resulting in a new post-combination consolidated registrant renamed as Delek US Holdings, Inc. (“New Delek”), with Alon Energy and the previous Delek US Holdings, Inc. (“Old Delek”) surviving as wholly-owned subsidiaries. New Delek is the successor issuer to Old Delek and Alon Energy pursuant to Rule 12g-3(c) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). In addition, as a result of the Delek/Alon Merger, the shares of common stock of Old Delek and Alon Energy were delisted from the New York Stock Exchange in July 2017, and their respective reporting obligations under the Exchange Act were terminated. Effective July 1, 2017, with the completion of the Delek/Alon Merger, references in this report to “Delek” refer to New Delek and any of its consolidated subsidiaries other than the Partnership and its subsidiaries.

Effective July 1, 2017, with the completion of the Delek/Alon Merger, 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.

As a result of the Delek/Alon Merger, the Partnership became a consolidated subsidiary of Delek and elected to apply “push-down” accounting, which required its assets and liabilities to be adjusted to fair value on the effective date of the Merger. Due to the application of push-down accounting, the Partnership’s consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented. Our consolidated financial statements and related footnotes are presented with a black-line division which delineates the lack of comparability between amounts presented on or after July 1, 2017 and dates prior. The periods prior to the Merger date, July 1, 2017, are identified as “Predecessor” and the period from July 1, 2017 forward is identified as “Successor”. Additionally, the Partnership’s accounting policies were conformed to those of Delek at the start of the Successor Period in connection with the Delek/Alon Merger, effective July 1, 2017. Because of the application of push-down accounting and the conforming of accounting policies, our Successor consolidated balance sheet and consolidated statements of operations and comprehensive income (loss) subsequent to the Merger are not comparable to the Predecessor’s consolidated balance sheet and consolidated statements of operations and comprehensive income (loss) prior to the Merger, and differences could be material.

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. All amounts discussed are in thousands unless otherwise specified.

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 Delek/Alon Merger;


•	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;

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•	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;


•	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.

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.

Recent Developments

Planned Acquisition of Non-controlling Interest in the Partnership

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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 sales volumes. Gross margin is the difference between net sales and cost of goods sold (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 pipeline and 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.

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Factors Affecting Comparability

Our financial condition and operating results over the three and nine months ended September 30, 2017 and 2016 have been influenced by the following factors which is fundamental to understanding comparisons of our period-to-period financial performance.

Delek/Alon Merger

Effective July 1, 2017, as a result of the Delek/Alon Merger, the Partnership became a consolidated subsidiary of Delek and elected to apply push-down accounting. See “ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information pertaining to push-down accounting and financial statement presentation, including the significance of the delineation between Predecessor and Successor periods.

Maintenance and Turnaround Impact on Crude Oil Throughput

During the nine months ended September 30, 2017 , throughput at the refinery was affected by maintenance on the FCCU. During the nine months ended September 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 goods sold. Cost of goods sold 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 goods sold 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 Delek 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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A discussion and analysis of the factors contributing to our results of operations is presented below. The financial statements, together with the following information, are intended to provide investors with a reasonable basis for assessing our historical operations, but should not serve as the only criteria for predicting our future performance.

The following tables and discussion present a summary of our consolidated results of operations for the three and nine months ended September 30, 2017 and 2016, including a reconciliation of Earnings Before Interest, Taxes, Depreciation and Amortization (“EBITDA”) and Adjusted EBITDA to net income and distributable cash flow (in thousands, except unit and per unit amounts).



	Successor			Predecessor
	Three Months Ended September 30, 2017			Three Months Ended September 30, 2016
Net sales:
Affiliate	$	94,536		$	82,717
Third party	400,942			379,540
Net sales	495,478			462,257
Operating costs and expenses:
Cost of goods sold	415,386			404,207
Operating expenses	26,548			25,125
Selling, general and administrative expenses	7,741			8,153
Depreciation and amortization	7,620			14,581
Loss on disposition of assets	—			—
Total operating costs and expenses	457,295			452,066
Operating income	38,183			10,191
Interest expense, net	8,817			8,144
Other expense (income), net	5			(353		)
Total non-operating expense	8,822			7,791
Income before income tax expense	29,361			2,400
Income tax expense	125			317
Net income attributable to partners	$	29,236		$	2,083
Comprehensive income attributable to partners	$	29,236		$	2,083
Net income per unit - (basic and diluted)	$	0.47		$	0.03
Weighted average common units outstanding (in thousands) - (basic and diluted)	62,529			62,520
Cash distribution per unit	$	0.35		$	0.14
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	94,574		$	11,870
Investing activities	(17,738		)	(5,954		)
Financing activities	24,497			36,027
Other Data:
Adjusted EBITDA	$	67,798		$	25,125
Capital expenditures	12,681			4,499
Capital expenditures for operating lease purchase	9,200			—
Capital expenditures for turnaround and catalysts	—			1,455
Key Operating Statistics:
Per barrel of throughput:
Refinery operating margin ⁽¹⁾	$	12.49		$	9.22
Refinery direct operating expense ⁽²⁾	4.14			3.90

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	Successor			Predecessor			Predecessor
	Period from July 1, 2017 to September 30, 2017			Period from January 1, 2017 to June 30, 2017			Nine Months Ended September 30, 2016
Net sales:
Affiliate	$	94,536		$	185,760		$	222,711
Third party	400,942			880,523			1,076,012
Net sales	495,478			1,066,283			1,298,723
Operating costs and expenses:
Cost of goods sold	415,386			911,366			1,134,275
Operating expenses	26,548			52,638			73,424
Selling, general and administrative expenses	7,741			14,156			24,264
Depreciation and amortization	7,620			28,691			43,454
Loss on disposition of assets	—			23			—
Total operating costs and expenses	457,295			1,006,874			1,275,417
Operating income	38,183			59,409			23,306
Interest expense, net	8,817			16,497			28,651
Other expense (income), net	5			554			(550		)
Total non-operating expense	8,822			17,051			28,101
Income (loss) before income tax expense	29,361			42,358			(4,795		)
Income tax expense	125			566			493
Net income (loss) attributable to partners	$	29,236		$	41,792		$	(5,288	)
Comprehensive income (loss) attributable to partners	$	29,236		$	41,792		$	(5,288	)
Net income (loss) per unit - (basic and diluted)	$	0.47		$	0.67		$	(0.08	)
Weighted average common units outstanding (in thousands) - (basic and diluted)	62,529			62,523			62,515
Cash distribution per unit	$	0.35		$	0.49		$	0.22
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	94,574		77,145			$	58,457
Investing activities	(17,738		)	(13,191		)	(26,878		)
Financing activities	24,497			29,761			39,231
Other Data:
Adjusted EBITDA	$	67,798		$	87,546		$	67,310
Capital expenditures	12,681			12,175			17,199
Capital expenditures for operating lease purchase	9,200			—			—
Capital expenditures for turnaround and catalysts	—			1,016			9,679
Key Operating Statistics:
Per barrel of throughput:
Refinery operating margin ⁽¹⁾	$	12.49		$	11.47		$	8.52
Refinery direct operating expense ⁽²⁾	4.14			3.86			3.85

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Because the following information is not impacted by push-down accounting and other differences related to the Delek/Alon Merger affecting comparability, the following information does not reflect Predecessor/Successor delineation.



PRICING STATISTICS:	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016
Crack spreads (per barrel):
Gulf Coast 3/2/1	$	20.16	$	13.31	16.20		$	12.25
WTI Cushing crude oil (per barrel)	$	48.16	$	44.88	49.31		$	41.40
Crude oil differentials (per barrel):
WTI Cushing less WTI Midland	$	0.79	$	0.31	0.53		$	0.18
WTI Cushing less WTS	0.97		1.47		1.15		0.82
Brent less WTI Cushing	4.04		2.05		3.18		1.81
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	1.63	$	1.39	$	1.57	$	1.29
Gulf Coast ultra-low sulfur diesel	1.62		1.37		1.55		1.25
Natural gas (per MMBtu)	2.95		2.79		3.05		2.35



THROUGHPUT AND PRODUCTION DATA:	For the Three Months Ended						For the Nine Months Ended
THROUGHPUT AND PRODUCTION DATA:	September 30,						September 30,
	2017			2016			2017			2016
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
WTS crude	17,016	24.4		34,292	48.9		21,617	29.5		32,189	46.3
WTI crude	52,101	74.7		32,503	46.4		49,095	66.9		34,428	49.4
Blendstocks	606	0.9		3,268	4.7		2,672	3.6		2,969	4.3
Total refinery throughput ⁽³⁾	69,722	100.0		70,063	100.0		73,384	100.0		69,586	100.0
Refinery production:
Gasoline	35,990	51.9		33,637	48.1		36,052	49.4		33,826	48.7
Diesel/jet	27,001	38.9		26,004	37.2		27,912	38.3		25,108	36.1
Asphalt	1,213	1.7		2,818	4.0		2,036	2.8		2,846	4.1
Petrochemicals	2,956	4.3		3,861	5.5		3,765	5.2		3,611	5.2
Other	2,196	3.2		3,661	5.2		3,193	4.4		4,084	5.9
Total refinery production ⁽⁴⁾	69,356	100.0		69,981	100.0		72,958	100.0		69,475	100.0
Refinery utilization ⁽⁵⁾		94.7	%		99.1	%		96.9	%		95.5	%

⁽¹⁾

Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of goods sold (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 Successor three-month period ended September 30, 2017 and Predecessor six-month period ended June 30, 2017 excludes gains (losses) related to inventory adjustments of $0 and $1,264, respectively. Refinery operating margin for the Predecessor three- and nine-month periods ended September 30, 2016 excludes gains (losses) related to inventory adjustments of $1,419 and $2,046, respectively.


⁽²⁾	Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses by total throughput volumes.


⁽³⁾	Total refinery throughput represents the total barrels per day of crude and blendstock inputs in the refinery production process.

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⁽⁴⁾	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.


⁽⁵⁾	Refinery utilization represents average daily crude throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.

EBITDA, Adjusted EBITDA and Cash Available for Distribution

To supplement our financial information presented in accordance with United States generally accepted accounting principles (“GAAP”), management uses additional measures that are known as “non-GAAP financial measures” in its evaluation of past performance and prospectus for the future. The primary measures used by management are EBITDA, Adjusted EBITDA and cash available for distribution.

EBITDA and Adjusted EBITDA represent earnings before income tax expense, interest expense, depreciation and amortization and in the case of Adjusted EBITDA, the inventory fair value adjustment. Neither EBITDA nor Adjusted EBITDA is a recognized measurement under GAAP; however, the amounts included in EBITDA and Adjusted EBITDA are derived from amounts included in our consolidated financial statements. Our management believes that the presentation of EBITDA and 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 EBITDA and Adjusted EBITDA are useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of EBITDA and Adjusted EBITDA generally eliminates the effects of 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.

Cash available for distribution is derived from net income plus or minus all adjustments to arrive at Adjusted EBITDA, less cash needed for maintenance capital expenditures, debt service and other contractual obligations, and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, including reserves for our expenses in the quarters in which our planned turnarounds and catalyst replacement occur and special reserves for cost increase in capital expenditures associated with the consent decree.

Our management believes that the presentation of cash available for distribution 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 cash available for distribution is useful in evaluating our ability to generate sufficient cash flow to make distributions to our unitholders.

We believe that the presentation of EBITDA, Adjusted EBITDA and cash available for distribution provides useful information to investors in assessing our financial condition and results of operations. EBITDA, Adjusted EBITDA and cash available for distribution should not be considered alternatives to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. EBITDA, Adjusted EBITDA and cash available for distribution have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. Additionally, because EBITDA, Adjusted EBITDA and cash available for distribution may be defined differently by other companies in our industry, our definition of EBITDA, Adjusted EBITDA and cash available for distribution may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. Because of these limitations, EBITDA, Adjusted EBITDA and cash available for distribution 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 EBITDA, Adjusted EBITDA and cash available for distribution only supplementally.

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The following table reconciles net income (loss), as determined under GAAP, to Adjusted EBITDA and cash available for distribution:



	Successor		Predecessor
	Three Months Ended September 30, 2017		Three Months Ended September 30, 2016
Reconciliation of net income to EBITDA, Adjusted EBITDA and cash available for distribution ⁽¹⁾:
Net income	$	29,236	$	2,083
Add:
Interest Expense	8,817		8,144
Income tax expense	125		317
Depreciation and amortization	7,620		14,581
EBITDA	$	45,798	$	25,125
Inventory fair value adjustment ⁽²⁾	22,000		—
Adjusted EBITDA	$	67,798	$	25,125
Less:
Maintenance/growth capital expenditures	21,881		4,499
Turnaround and catalyst replacement capital expenditures	—		1,455
Major turnaround reserve for future years	3,500		1,500
Principal payments	625		625
Income tax payments	310		317
Interest paid in cash	8,314		7,337
Cash available for distribution before special expenses	$	33,168	$	9,392
Special reserve for cost increase in capital expenditures associated with the consent decree	6,300		—
Cash available for distribution	$	26,868	$	9,392

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	Successor		Predecessor		Predecessor
	Period from July 1, 2017 to September 30, 2017		Period from January 1, 2017 to June 30, 2017		Nine Months Ended September 30, 2016
Reconciliation of net income to EBITDA, Adjusted EBITDA and cash available for distribution ⁽¹⁾:
Net income	$	29,236	41,792		$	(5,288	)
Add:
Interest Expense	8,817		16,497		28,651
Income tax expense	125		566		493
Depreciation and amortization	7,620		28,691		43,454
EBITDA	45,798		87,546		67,310
Inventory fair value adjustment ⁽²⁾	22,000		—		—
Adjusted EBITDA	$	67,798	$	87,546	$	67,310
Less:
Maintenance/growth capital expenditures	21,881		12,175		17,199
Turnaround and catalyst replacement capital expenditures	—		1,016		4,616
Major turnaround reserve for future years	3,500		7,000		4,500
Principal payments	625		1,250		1,875
Income tax payments	310		566		493
Gain (loss) on asset disposals	—		23		—
Interest paid in cash	8,314		16,155		27,219
Cash available for distribution before special expenses	33,168		49,361		11,408
Special reserve for cost increase in capital expenditures associated with the consent decree	6,300		4,000		—
Cash available for distribution	$	26,868	$	45,361	$	11,408


⁽¹⁾	For definitions of EBITDA, Adjusted EBITDA and cash available for distribution, see “EBITDA, Adjusted EBITDA and Cash Available for Distribution” above.


⁽²⁾	The fair value adjustment to inventory recorded in connection with push-down purchase accounting resulted in a reduction to normal margins in the quarter ended September 30, 2017, when that inventory was sold.

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Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016

All of the following operational and financial discussion reflect the Successor basis and accounting policies for the third quarter 2017, and the Predecessor basis and accounting policies for the third quarter of 2016.

Net Sales.

Net sales for the three months ended September 30, 2017 were $495,478, compared to $462,257 for the three months ended September 30, 2016, an increase of $33,221, or 7.2%. This increase was primarily due to higher refined product prices and higher refined product sales. The average per gallon price of Gulf Coast gasoline for the three months ended September 30, 2017 increased $0.23, or 17.0%, to $1.63, compared to $1.39 for the three months ended September 30, 2016. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the three months ended September 30, 2017 increased $0.25, or 18.2%, to $1.62, compared to $1.37 for the three months ended September 30, 2016. Refinery barrels sold for the three months ended September 30, 2017 was 7,253 compared to 6,913 for the three months ended September 30, 2016, an increase of 4.9%. Refinery average throughput for the three months ended September 30, 2017 was 69,723 bpd, compared to 70,063 bpd for the three months ended September 30, 2016, a decrease of 0.5%.

Cost of Goods Sold.

Cost of goods sold for the three months ended September 30, 2017 were $415,386, compared to $404,207 for the three months ended September 30, 2016, an increase of $11,179, or 2.8%. This increase was primarily due to increased crude oil prices. The average price of WTI Cushing increased 7.3% to $48.16 per barrel for the three months ended September 30, 2017 from $44.88 per barrel for the three months ended September 30, 2016.

Direct Operating Expenses.

Direct operating expenses for the three months ended September 30, 2017 were $26,548, compared to $25,125 for the three months ended September 30, 2016, an increase of $1,423, or 5.7%. This increase was largely due to the change of classification of certain expenses from selling, general and administrative to operating in the Successor period in connection with the Merger and higher maintenance costs.

Selling, General and Administrative Expenses.

SG&A expenses for the three months ended September 30, 2017 were $7,741, compared to $8,153 for the three months ended September 30, 2016, a decrease of $412, or 5.1%. This decrease was primarily due the change of classification of certain expenses from selling, general and administrative to operating in the Successor period in connection with the Merger.

Depreciation and Amortization.

Depreciation and amortization for the three months ended September 30, 2017 was $7,620, compared to $14,581 for the three months ended September 30, 2016, a decrease of $6,961, or 47.7%. The decrease in depreciation expense is primarily related to the preliminary purchase accounting fair value allocation of property, plant and equipment at July 1, 2017.

Operating Income.

Operating income for the three months ended September 30, 2017 was $38,183, compared to $10,191 for the three months ended September 30, 2016, an increase of $27,992. This increase was primarily due to higher refinery operating margin and higher refinery throughput. Refinery operating margin was $12.49 per barrel for the three months ended September 30, 2017, compared to $11.47 per barrel for the three months ended September 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 spread and a stronger wholesale marketing environment, partially offset by a reduction in the WTI Cushing to WTS spread 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 $20.16 per barrel for the three months ended September 30, 2017, compared to $13.31 per barrel for the three months ended September 30, 2016. The average WTI Cushing to WTI Midland spread was $0.79 per barrel for the three months ended September 30, 2017, compared to $0.31 per barrel for the three months ended September 30, 2016. The average WTI Cushing to WTS spread was $0.97 per barrel for the three months ended September 30, 2017, compared to $1.47 per barrel for the three months ended September 30, 2016. The average Brent to WTI Cushing spread was $4.04 per barrel for the three months ended September 30, 2017, compared to $2.05 per barrel for the three months ended September 30, 2016. The contango environment for the three months ended September 30, 2017 created an average cost of crude benefit of $0.24 per barrel, compared to an average cost of crude benefit of $0.84 per barrel for the three months ended September 30, 2016. The average RINs cost effect on refinery operating margin was $1.14 per barrel for the three months ended September 30, 2017, compared to $0.58 per barrel for the three months ended September 30, 2016.

Interest Expense.

Interest expense, net for the three months ended September 30, 2017 was $8,817, compared to $8,144 for the three months ended September 30, 2016, an increase of $673, or 8.3%. This increase was primarily due to fluctuations in finance fees associated with our Supply and Offtake Agreement, as well as an increase in borrowings outstanding under our revolving line of credit facility.

Income Tax Expense.

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Income tax expense was $125 for the three months ended September 30, 2017, compared to $317 for the three months ended September 30, 2016, a decrease of $192. The decrease in income tax expense is attributable to the effect of conforming our income tax accrual policy to that of Delek’s effective July 1, 2017.

Net Income.

Net income for the three months ended September 30, 2017 was $29,236, compared to $2,083 for the three months ended September 30, 2016, an increase of $27,153. This increase was attributable to the factors discussed above.

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Three Months Ended September 30, 2017 and Six Months Ended June 30, 2017 Compared to the Nine Months Ended September 30, 2016

Net Sales

Net sales increased from $1,298,723 for the nine months ended September 30, 2016 to $495,478 for the three months ended September 30, 2017 and $1,066,283 for the six months ended June 30, 2017. This increase was primarily due to higher refined product prices and higher refined product sales volumes. The average per gallon price of Gulf Coast gasoline for the nine months ended September 30, 2017 increased $0.26, or 20.6%, to $1.57, compared to $1.29 for the nine months ended September 30, 2016. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the nine months ended September 30, 2017 increased $0.30, or 24.0%, to $1.55, compared to $1.25 for the nine months ended September 30, 2016. Refinery barrels sold for the nine months ended September 30, 2017 was 21,378 as compared to 20,536 for the nine month ended September 30, 2016, an increase of 842. Refinery average throughput for the nine months ended September 30, 2017 was 73,384 bpd compared to 69,586 bpd for the nine months ended September 30, 2016, a decrease of 5.5%.

Cost of Goods Sold.

Cost of goods sold increased from $1,134,275 for the nine months ended September 30, 2016, to $415,386 for the three months ended September 30, 2017 and $911,366 for the six months ended June 30, 2017. This increase was primarily due to increased crude oil prices and higher refined product sales volumes. The average price of WTI Cushing increased 19.1% to $49.31 per barrel for the nine months ended September 30, 2017 from $41.40 per barrel for the nine months ended September 30, 2016.

Direct Operating Expenses.

Direct operating expenses increased from $73,424 for the nine months ended September 30, 2016 to $26,548 for the three months ended September 30, 2017 and $52,638 for the six months ended June 30, 2017. This increase was primarily due to the change of classification of certain expenses from selling, general and administrative to operating in the Successor three-month period ended September 30, 2017 in connection with the Merger.

Selling, General and Administrative Expenses.

SG&A expenses decreased from $24,264 for the nine months ended September 30, 2016 to $7,741 for the three months ended September 30, 2017 and $14,156 for the six months ended June 30, 2017. This decrease was primarily due to lower corporate allocations as well as the change of classification of certain expenses from selling, general and administrative to operating in the Successor three-month period ended September 30, 2017 in connection with the Merger.

Depreciation and Amortization.

Depreciation and amortization decreased from $43,454 for the nine months ended September 30, 2016 to $7,620 for the three months ended September 30, 2017 and $28,691 for the six months ended June 30, 2017. The decrease in depreciation expense is primarily related to the preliminary purchase accounting fair value allocation of property, plant and equipment at July 1, 2017.

Operating Income.

Operating income increased from $23,306 for the nine months ended September 30, 2016 to $38,183 for the three months ended September 30, 2017 and $59,409 for the six months ended June 30, 2017. This increase was primarily due to higher refinery sales volumes and higher refinery operating margin. This increase 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.

Interest Expense.

Interest expense decreased from $28,651 for the nine months ended September 30, 2016 to $8,817 for the three months ended September 30, 2017 and $16,497 for the six months ended June 30, 2017. This decrease was primarily due to lower finance fees associated with our Supply and Offtake Agreement.

Income Tax Expense.

Income tax expense increased from $493 for the nine months ended September 30, 2016 to $125 for the three months ended September 30, 2017 and $566 for the six months ended June 30, 2017. The increase in income tax expense is attributable to the increase in pre-tax income compared to 2016, offset by the effect of conforming the income tax accrual policy to that of Delek’s effective July 1, 2017.

Net Income (Loss).

Net loss increased from $5,288 for the nine months ended September 30, 2016 to net income of $29,236 for the three months ended September 30, 2017 and $41,792 for the six months ended June 30, 2017. 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 letter of credit facilities through Delek 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. In Predecessor periods, this arrangement substantially reduced 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 nature of cash flows is not impacted by the differences in Successor and Predecessor basis and accounting policies. Therefore, we have not delineated between Successor and Predecessor periods in the following discussion. The following table sets forth our consolidated cash flows for the nine months ended September 30, 2017 and 2016:



	For the Nine Months Ended
	September 30,
	2017			2016
	(dollars in thousands)
Cash provided by (used in):
Operating activities	171,719			58,457
Investing activities	(30,929		)	(26,878		)
Financing activities	54,258			39,231
Net increase in cash and cash equivalents	$	195,048		$	70,810

Cash Flows Provided by Operating Activities

Net cash provided by operating activities was $171,719 during the nine months ended September 30, 2017 compared to $58,457 during the nine months ended September 30, 2016. The increase in net cash provided by operating activities of $113,262 was primarily due to the following: increased net income (adjusted for certain non-cash items) of $68,752 combined with increased cash provided by inventories of $20,818, increased cash collected on accounts receivable of $14,324, increased cash provided by accounts receivable/payables with related parties of $77,025, and partially offset by an increase in cash used to pay accounts payable and settle accrued liabilities of $69,727.

Cash Flows Used in Investing Activities

Net cash used in investing activities was $30,929 during the nine months ended September 30, 2017 compared to $26,878 during the nine months ended September 30, 2016. The increase in net cash used in investing activities of $4,051 was primarily due to the buy-out of certain leased assets subsequent to the Merger, partially offset by the completion of 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 $54,258 during the nine months ended September 30, 2017 compared to $39,231 during the nine months ended September 30, 2016. The increase in net cash provided by financing activities of $15,027 was primarily due to increased cash from net borrowings on our credit facility of $100,000 and decreased cash received from RINs financing transactions of $43,211, partially offset by increased distributions to unitholders of $38,769.

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Cash Position and Indebtedness

As of September 30, 2017, our cash and cash equivalents were $268,572 and we had total indebtedness of approximately $338,125. Total unused credit commitments or borrowing base availability, as applicable, under our credit facilities was approximately $125,602 and we had letters of credit issued of approximately $14,398. We believe we were in compliance with our covenants in all debt facilities as of September 30, 2017.

Capital Spending

The nature of capital expenditures is not impacted by the differences in the Successor and Predecessor basis and accounting policies. Therefore, we have not delineated between Successor and Predecessor periods in the following discussion. The following table summarizes our actual capital expenditures for the three and nine months ended September 30, 2017 (in thousands):



	Three Months Ended				Nine months Ended
	September 30,				September 30,
	2017		2016		2017		2016
Capital Expenditures	$	21,881	$	4,499	$	29,913	$	17,199
Capital Expenditures for turnaround and catalysts	—		1,455		1,016		9,679

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 $33,075, which includes expenditures for regulatory projects of $11,349, maintenance projects of $11,177, and discretionary projects of $10,549. Approximately $29,913 has been spent during the nine months ended September 30, 2017 (inclusive of the Successor three-month period ended September 30, 2017, the remainder comprising the Predecessor period).

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 during the Predecessor periods. See Note 1 for additional information on our critical accounting policies, including conforming changes between the Predecessor periods and the Successor period.

LIFO Inventory Valuation. Prior to July 1, 2017, our Predecessor determined the cost of inventory using the last-in, first-out (“LIFO”) valuation method and costs in excess of market value were charged to cost of goods sold. Crude oil, refined products and blendstocks (including crude oil consignment inventory) are priced at the lower of cost or market. Cost is determined using the LIFO valuation method. Under the LIFO valuation method, we charge the most recent acquisition costs to cost of goods sold, and we valued inventories at the earliest acquisition costs.

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If the market value of inventory is less than the inventory cost on a LIFO basis, then the inventory is written down to market value. An inventory write-down to market value results in a non-cash accounting adjustment, decreasing the value of our inventory and increasing our cost of goods sold. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of goods sold in years when inventory volumes decline and result in charging cost of goods sold with LIFO inventory costs generated in prior periods. Effective July 1, 2017, in connection with the Delek/Alon Merger, cost of inventory is determined using the first-in, first-out (“FIFO”) valuation method, pursuant to which inventories are valued at the lower of FIFO cost or net realizable value.

Turnarounds and Catalysts Costs. Our refinery units require regular major maintenance and repairs that are commonly referred to as “turnarounds.” Catalysts used in certain refinery process units are typically replaced in conjunction with planned turnarounds. The required frequency of the maintenance varies by unit and by catalyst but generally is every three to five years. In order to minimize downtime during turnarounds, we often utilize contract labor as well as our maintenance personnel on a continuous 24 hour basis. Whenever possible, turnarounds are scheduled so that some units continue to operate while others are down for maintenance. We record the turnaround and catalysts costs as deferred charges and amortize the deferred costs on a straight-line basis over the period of time estimated until the next turnaround occurs (generally 3 to 5 years). Effective July 1, 2017, turnaround and catalysts costs are recorded to property, plant and equipment as opposed to deferred charges. Additionally, all property, plant and equipment was adjusted to fair value in connection with the push-down of purchase accounting, which resulted in the elimination of separate deferred turnaround costs on the balance sheet as of June 30, 2016, previously recorded during the Predecessor periods.

New Accounting Standards and Disclosures

New accounting standards, are disclosed in Note 1 Organization and Basis of Presentation included in the condensed consolidated financial statements included in Item 1 of this report.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

These disclosures should be read in conjunction with the condensed consolidated financial statements, "Management's Discussion and Analysis of Financial Condition and Results of Operations," and other information presented herein as well as in the "Quantitative and Qualitative Disclosures About Market Risk" section contained in our Annual Report on Form 10-K.

Changes in commodity prices, purchased fuel prices and interest rates are our primary sources of market risk. Delek’s risk management oversees all activities associated with the identification, assessment and management of our market risk exposure.

Price Risk Management Activities

At times, we enter into commodity derivative contracts to manage our price exposure to our inventory positions, future purchases of crude oil, blendstock, future sales of refined products or to fix margins on future production. We also enter into future commitments to purchase or sell RINs at fixed prices and quantities, which are used to manage the costs associated with our RINs obligations. These future RIN commitments meet the definition of derivative instruments under ASC 815, Derivatives and Hedging ("ASC 815"). In accordance with ASC 815, all of these commodity contracts and future purchase commitments are recorded at fair value, and any change in fair value between periods has historically been recorded in the profit and loss section of our condensed consolidated financial statements. Occasionally, at inception, the company will elect to designate the commodity derivative contracts as cash flow hedges under ASC 815. Gains or losses on commodity derivative contracts accounted for as cash flow hedges are recognized in other comprehensive income on the condensed consolidated balance sheets and ultimately, when the forecasted transactions are completed in net sales or cost of goods sold in the condensed consolidated statements of income.

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. Delek’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 by management, we may utilize the commodity futures market to manage these anticipated inventory variances.

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 sets forth information relating to our open commodity derivative contracts as of September 30, 2017:



	Total Outstanding				Notional Contract Volume by Year of Maturity
Contract Description	Fair Value			Notional Contract Volume	2017	2018	2019
Contracts not designated as hedging instruments:
Commodity contracts (futures) - long⁽¹⁾	$	(8	)	11	11	—	—
Commodity contracts (futures) - short⁽¹⁾	121			421	421	—	—
RIN commitment contracts - long⁽²⁾	(34,771		)	185,716	185,716	—	—
RIN commitment contracts - short⁽²⁾	28,157			134,500	134,500	—	—
Total	$	(6,501	)	320,648	320,648	—	—

(1)Volume in thousands of barrels

(2)Volume in thousands of RINs

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Interest Risk Management Activities

We have market exposure to changes in interest rates relating to our outstanding floating rate borrowings. As of September 30, 2017 our outstanding debt balance of $338,125, excluding discounts and issuance costs, was subject to floating interest rates.

The annualized impact of a hypothetical one percent change in interest rates on our floating rate debt outstanding as of September 30, 2017 would be to change interest expense by approximately $3,400.

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of 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 September 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

In connection with the Delek/Alon Merger, our internal controls over financial reporting are being integrated to incorporate the internal controls and internal control over financial reporting framework of Delek. Such integration has resulted in changes in our internal control over financial reporting (as described in Rule 13a-15(f) under the Exchange Act) that have materially affected our internal control over financial reporting. Other than the changes that have and may continue to result from such integration, 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 September 30, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We have been negotiating an agreement with EPA for over 10 years under EPA’s National Petroleum Refinery Initiative regarding alleged historical violations of the Clean Air Act ("CAA"). According to the EPA, approximately 95% of the nation’s refining capacity has entered into “global” settlements under this EPA enforcement initiative. A Consent Decree resolving these alleged historical violations for our refinery was lodged with the United States District Court for the Northern District of Texas on June 6, 2017, and we expect that Consent Decree to become final later this year. If finalized, the Consent Decree will require payment of a $456,250 civil penalty and capital expenditures for pollution control equipment that may be significant over the next 5 years.

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 September 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.

* Filed herewith.

** Furnished herewith.

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:	November 9, 2017	By:	/s/ Frederec Green
			Frederec Green
			Executive Vice President and Chief Executive Officer of Alon USA Partners GP, LLC
			(Principal Executive Officer)


Date:	November 9, 2017	By:	/s/ Kevin Kremke
			Kevin Kremke
			Executive Vice President, Chief Financial Officer and Secretary of Alon USA Partners GP, LLC
			(Principal Accounting Officer)

Alon USA Partners, LP 10-Q