UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

___________________________________________________

FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED ~~JUNE~~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.)

~~12700~~7102 ~~Park~~Commerce ~~Central Dr.~~Way, ~~Suite 1600~~Brentwood, ~~Dallas,~~Tennessee ~~Texas 75251~~37027

(Address of principal executive offices) (Zip Code)

(~~972~~615) ~~367~~771-~~3600~~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 ~~July~~November 317, 2017, was 62,529,328.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
	Page
PART I. FINANCIAL INFORMATION	1
Item 1. Financial Statements	1
ITEM 1. FINANCIAL STATEMENTS	1
Condensed Consolidated Balance Sheets: Successor as of September 30, 2017 and Predecessor as of December 31, 2016 (Unaudited)	1
CONSOLIDATED BALANCE SHEETS	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
CONSOLIDATED STATEMENTS OF OPERATIONS	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
CONSOLIDATED STATEMENTS OF CASH FLOWS	3
Notes to Condensed Consolidated Financial Statements (Unaudited)	4
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	4
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	13
Forward-Looking Statements	18
FORWARD-LOOKING STATEMENTS	13
Item 3. Quantitative and Qualitative Disclosures about Market Risk	35
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	25
Item 4. Controls and Procedures	37
ITEM 4. CONTROLS AND PROCEDURES	27
PART II. OTHER INFORMATION	38
PART II. OTHER INFORMATION	28
Item 6. Exhibits	38
ITEM 6. EXHIBITS	28
Signatures	39
SIGNATURES	29

Table of Contents

PART I. FINANCIAL INFORMATION


ITEM 1.	FINANCIAL STATEMENTS

ALON USA PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(~~dollars~~In in thousands, except unit and per unit data)

	June 30, 2017		December 31, 2016
	Successor			Predecessor
	(unaudited)
	September 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	~~167~~268,~~239~~572	$	~~73,524~~$	73,524
Accounts and other receivables, net	109,827		82,292
Accounts receivable	83,781			82,292
Accounts and other receivables, net - related parties	10,307		11,425
Accounts receivable from related parties, net of related party payables	—			11,425
Inventories	37,067		49,682
Inventories, net of lower of cost or net realizable value	99,802			49,682
Prepaid expenses and other current assets	4,~~248~~877		~~4,949~~	4,949
Total current assets	~~328~~457,~~688~~032		~~221,872~~	221,872
Property, plant and equipment, net	~~413~~418,~~033~~106		~~420,554~~	420,554
Other assets, net	45,721		53,211
Goodwill	568,541			—
Total assets	$	787,442	$	695,637
Other non-current assets	54,031			53,211
LIABILITIES AND PARTNERS’ EQUITY
Total assets	$	1,497,710		$	695,637
Current liabilities:
LIABILITIES AND PARTNERS’ EQUITY
Accounts payable	$	326,693	$	249,835
Current liabilities:
Accrued liabilities	37,477		43,100
Accounts payable	$	101,588		$	249,835
Current portion of long-term debt	2,500		2,500
Accounts payable to related parties, net of related party receivables	84,631			—
Total current liabilities	366,670		295,435
Accrued expenses and other current liabilities	181,820			43,100
Other non-current liabilities	22,572		62,880
Current portion of long-term debt	2,500			2,500
Long-term debt	283,496		233,819
Obligation under Supply and Offtake Agreement	99,108			—
Total liabilities	672,738		592,134
Total current liabilities	469,647			295,435
Commitments and contingencies (Note 11)
Non-current liabilities:
Partners’ equity:
Long-term debt, net of current portion	335,625			233,819
General Partner	—		—
Deferred income tax liability	2,374			—
Common unitholders - 62,529,328 and 62,520,220 units issued and outstanding at June 30, 2017 and December 31, 2016, respectively	114,704		103,503
Other non-current liabilities	27,381			62,880
Total partners’ equity	114,704		103,503
Total non-current liabilities	365,380			296,699
Total liabilities and partners’ equity	$	787,442	$	695,637
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)

(~~unaudited,~~In ~~dollars in~~ thousands except per unit data)

	For the Three Months Ended						For the Six Months Ended
	Successor				Predecessor
	June 30,						June 30,
	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
	2017			2016			2017				2016
Net sales:
Net sales (1)	$	521,751		$	468,457		$	1,066,283			$	836,466
Affiliate	$	94,536			$	185,760		$	82,717			$	222,711
Operating costs and expenses:
Third party	400,942				880,523			379,540				1,076,012
Cost of sales	440,895			410,735			911,366				730,068
Net sales	495,478				1,066,283			462,257				1,298,723
Direct operating expenses	27,878			23,255			52,638				48,299
Operating costs and expenses:
Selling, general and administrative expenses	7,392			8,802			14,156				16,111
Cost of goods sold	415,386				911,366			404,207				1,134,275
Depreciation and amortization	14,462			14,667			28,691				28,873
Operating expenses	26,548				52,638			25,125				73,424
Total operating costs and expenses	490,627			457,459			1,006,851				823,351
Selling, general and administrative expenses	7,741				14,156			8,153				24,264
Loss on disposition of assets	(23		)	—			(23		)		—
Depreciation and amortization	7,620				28,691			14,581				43,454
Operating income	31,101			10,998			59,409				13,115
Loss on disposition of assets	—				23			—				—
Interest expense	(8,652		)	(9,920		)	(16,497		)		(20,507		)
Total operating costs and expenses	457,295				1,006,874			452,066				1,275,417
Other income (loss), net	(459		)	113			(554		)		197
Operating income	38,183				59,409			10,191				23,306
Income (loss) before state income tax expense	21,990			1,191			42,358				(7,195		)
Interest expense, net	8,817				16,497			8,144				28,651
State income tax expense	310			—			566				176
Other expense (income), net	5				554			(353		)		(550		)
Net income (loss)	$	21,680		$	1,191		$	41,792			$	(7,371	)
Total non-operating expense	8,822				17,051			7,791				28,101
Earnings (loss) per unit	$	0.35		$	0.02		$	0.67			$	(0.12	)
Income (loss) before income tax expense	29,361				42,358			2,400				(4,795		)
Weighted average common units outstanding (in thousands)	62,525			62,515			62,523				62,512
Income tax expense	125				566			317				493
Cash distribution per unit	$	0.38		$	—		$	0.49			$	0.08
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

___________

(1) Includes sales to related parties of $94,323 and $76,884 for the three months ended and $185,760 and $139,994 for the six months ended June 30, 2017 and 2016, respectively.

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

Table of Contents

ALON USA PARTNERS, LP AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS(unaudited, dollars in thousands)
ALON USA PARTNERS, LP AND SUBSIDIARIESCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)(In thousands)
	For the Six Months Ended
		Successor					Predecessor
	June 30,
		Period from July 1, 2017 to September 30, 2017					Period from January 1, 2017 to June 30, 2017			Nine Months Ended September 30, 2016
	2017				2016
Cash flows from operating activities:
Cash flows from operating activities:
Net income (loss)		$	29,236				$	41,792		$	(5,288	)
Net income (loss)	$	41,792			$	(7,371	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation and amortization		7,620					28,691			43,454
Depreciation and amortization	28,691				28,873
Unit-based compensation		25					47			53
Unit-based compensation	47				28
Deferred income taxes		9					—			—
Loss on disposition of assets	23	—			—		23			—
Amortization of debt issuance costs	~~811~~	—			~~951~~		811			1,335
Amortization of original issuance discount	~~345~~	—			~~318~~		345			480
Changes in operating assets and liabilities:
Accretion of environmental liabilities and asset retirement obligations		187					—			—
Accounts and other receivables, net	(27,535		)		(18,965		)
Changes in operating assets and liabilities:
Accounts and other receivables, net - related parties	1,118				(2,354		)
Accounts receivables, net		34,795					(27,535		)	(7,064		)
Inventories	12,592				(8,939		)
Accounts receivables/payables from related parties		73,721					1,118			(2,186		)
Prepaid expenses and other current assets	701				2,023
Inventories		(8,220		)			12,592			(16,446		)
Other assets, net	(900		)		3,719
Prepaid expenses and other current assets		1,018					701			1,012
Accounts payable	25,731				36,926
Other non-current assets, net		203					(900		)	4,573
Accrued liabilities	(5,441		)		(1,453		)
Accounts payable		(70,411		)			25,731			22,268
Other non-current liabilities	(830		)		12,831
Accrued liabilities		528					(5,441		)	(2,134		)
Net cash provided by operating activities	77,145				46,587
Obligations under supply and offtake agreement		25,863					—			—
Cash flows from investing activities:
Other non-current liabilities		—					(830		)	18,400
Capital expenditures	(12,175		)		(12,700		)
Net cash provided by operating activities		94,574					77,145			58,457
Capital expenditures for turnarounds and catalysts	(1,016		)		(8,224		)
Cash flows from investing activities:
Net cash used in investing activities	(13,191		)		(20,924		)
Capital expenditures		(17,738		)			(12,175		)	(17,199		)
Cash flows from financing activities:
Capital expenditures for turnarounds and catalysts		—					(1,016		)	(9,679		)
Distributions paid to unitholders	(5,648		)		(921		)
Net cash used in investing activities		(17,738		)			(13,191		)	(26,878		)
Distributions paid to unitholders - Alon Energy	(24,990		)		(4,080		)
Cash flows from financing activities:
RINs financing transactions	11,649				9,455
Distributions paid to unitholders		(4,035		)			(5,648		)	(2,534		)
Revolving credit facility, net	50,000				—
Distributions paid to unitholders - Alon Energy		(17,850		)			(24,990		)	(11,220		)
Payments on long-term debt	(1,250		)		(1,250		)
Proceeds from product financing agreements		—					11,649			54,860
Net cash provided by financing activities	29,761				3,204
Repayments of product financing agreements		(2,993		)			—			—
Net increase in cash and cash equivalents	93,715				28,867
Proceeds from revolving credit facility		100,000					50,000			—
Cash and cash equivalents, beginning of period	73,524				132,953
Payments of revolving credit facility		(50,000		)			—			—
Cash and cash equivalents, end of period	$	167,239			$	161,820
Payments on long-term debt		(625		)			(1,250		)	(1,875		)
Supplemental cash flow information:
Net cash provided by financing activities		24,497					29,761			39,231
Cash paid for interest, net of capitalized interest	$	16,155			$	19,882
Net increase in cash and cash equivalents		101,333					93,715			70,810
Cash paid for income tax	$	566			$	176
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 ~~“Alon,”~~ the “Partnership,” “we,” “our” and “us” or like terms refer to Alon USA Partners, LP, and its consolidated subsidiaries or to Alon USA Partners, LP or an individual subsidiary. References in this report to “Alon Energy” refer collectively to Alon USA Energy, Inc. and any of its consolidated subsidiaries, other than Alon USA Partners, LP, its subsidiaries and its general partner.

We are a Delaware limited partnership formed in August 2012 by Alon Energy and Alon USA Partners GP, LLC (the “General Partner”). The General Partner, a wholly-owned subsidiary of Alon Energy, owns 100% of our general partner interest, which is a non-economic interest.

~~Effective~~In ~~July~~January 12017, ~~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 ~~completion~~"Merger ofAgreement"). The related mergers (the ~~merger~~“Merger” ~~between~~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”) ~~and~~(NYSE: DK), with Alon Energy and the previous Delek US Holdings, Inc. (“Old Delek”) ~~indirectly~~surviving ~~owns~~as ~~100%~~wholly-owned ofsubsidiaries. ~~our~~New ~~General~~Delek ~~Partner~~is the successor issuer to Old Delek and ~~81.6%~~Alon Energy pursuant to Rule 12g-3(c) under the Securities Exchange Act of ~~our~~1934, ~~limited~~as ~~partner~~amended ~~interest~~(the "Exchange Act"). ~~Our~~In ~~General~~addition, ~~Partner~~as ~~manages~~a ~~our~~result ~~operations~~of the Delek/Alon Merger, the shares of common stock of Old Delek and ~~activities~~Alon ~~subject~~Energy towere delisted from the ~~terms~~New ~~and~~York ~~conditions~~Stock ~~specified~~Exchange in ~~our~~July ~~partnership~~2017, ~~agreement~~and their respective reporting obligations under the Exchange Act were terminated. ~~The~~Effective ~~operations~~July 1, 2017, with the completion of ~~our~~the ~~General~~Delek/Alon ~~Partner~~Merger, references in this report to “Delek” refer to Old Delek and its ~~capacity~~consolidated assubsidiaries ~~general~~for ~~partner~~the ~~are~~periods ~~managed~~prior byto July 1, 2017, and New Delek and its ~~board~~consolidated ofsubsidiaries ~~directors~~for the periods on or after July 1, 2017, other than the Partnership and its subsidiaries.

~~These~~Effective ~~consolidated~~July ~~financial~~1, ~~statements~~2017, ~~and~~with ~~notes~~the ~~are~~completion ~~unaudited~~of ~~and~~the ~~have~~Delek/Alon ~~been~~Merger, ~~prepared~~Delek inindirectly ~~accordance~~owns ~~with~~100% ~~United~~of ~~States~~our ~~generally~~General ~~accepted~~Partner ~~accounting~~and ~~principles~~81.6% ~~(“GAAP”)~~of ~~for~~our ~~interim~~limited ~~financial~~partner ~~information~~interests. ~~and~~Our ~~with~~General ~~the~~Partner ~~instructions~~manages toour ~~Form~~operations ~~10-Q~~ and ~~Article 10~~activities ofsubject ~~Regulation~~to ~~S-X~~the ofterms ~~the~~and ~~Securities~~conditions ~~Exchange~~specified ~~Act~~in ofour ~~1934~~partnership agreement. ~~Accordingly,~~The ~~they~~operations doof ~~not~~our ~~include~~General ~~all~~Partner ofin ~~the~~its ~~information~~capacity ~~and~~as ~~notes~~general ~~required~~partner byare ~~GAAP~~managed ~~for~~by ~~complete~~its ~~consolidated~~board ~~financial~~of ~~statements~~directors.

InAs ~~the~~a ~~opinion~~result of the ~~General~~Delek/Alon ~~Partner’s management~~Merger, the ~~information~~Partnership ~~included~~became ina ~~these~~ consolidated ~~financial~~subsidiary ~~statements~~of ~~reflects~~Delek ~~all~~and ~~adjustments~~elected to apply “push-down” accounting, ~~consisting~~which ofrequired ~~normal~~its assets and ~~recurring~~liabilities ~~adjustments,~~to ~~which~~be ~~are~~adjusted ~~necessary~~to ~~for~~fair avalue ~~fair~~on ~~presentation~~the effective date of ~~our~~the Merger. Due to the application of push-down accounting, the Partnership’s consolidated financial ~~position~~statements and ~~results~~certain offootnote ~~operations~~disclosures ~~for~~are presented in two distinct periods to indicate the ~~interim~~application of two different bases of accounting between the periods presented. Our ~~All~~consolidated ~~significant~~financial ~~intercompany~~statements ~~balances~~ and ~~transactions~~related ~~have~~footnotes ~~been~~are ~~eliminated~~presented inwith ~~consolidation.~~a ~~Certain~~black-line ~~prior~~division, ~~year~~which ~~balances~~delineates ~~may~~the ~~have~~lack ~~been~~of ~~aggregated~~comparability between amounts presented on or ~~disaggregated~~after inJuly ~~order~~1, to2017, ~~conform~~and dates prior. The periods prior to the ~~current~~Merger ~~year~~date, ~~presentation~~July 1, 2017, are identified as “Predecessor” and the period from July 1, 2017, forward is identified as “Successor”. Additionally, ~~Our~~the ~~results~~Partnership’s accounting policies were conformed to those of ~~operations~~Delek ~~for~~at the start ~~three~~of ~~and~~the ~~six~~Successor ~~months~~Period, ~~ended~~in ~~June 30~~connection with the Delek/Alon Merger, ~~2017~~effective ~~are~~July ~~not~~1, ~~necessarily~~2017. Because ~~indicative~~of the application of push-down accounting and the ~~operating~~conforming ~~results~~of ~~that~~accounting ~~may~~policies, beour ~~realized~~Successor ~~for~~consolidated balance sheet and consolidated statements of operations and comprehensive income (loss) subsequent to the ~~year~~Merger ~~ending~~are ~~December 31~~not comparable to the Predecessor’s consolidated balance sheet and consolidated statements of operations and comprehensive income (loss) prior to the Merger, ~~2017~~and differences could be material.

~~Our~~These consolidated ~~balance~~financial ~~sheet~~statements asand ofnotes ~~December 31,~~are ~~2016~~unaudited ~~has~~and have been ~~derived~~prepared ~~from~~in ~~the~~accordance ~~audited~~with ~~financial~~United ~~statements~~States asgenerally ofaccepted ~~that~~accounting ~~date.~~principles ~~These~~(“GAAP”) ~~unaudited~~for ~~consolidated~~interim financial ~~statements~~information ~~should~~and bewith ~~read~~the ininstructions ~~conjunction~~to ~~with~~Form 10-Q and Article 10 of Regulation S-X of the ~~audited~~Exchange ~~consolidated~~Act. Accordingly, ~~financial~~they ~~statements~~do ~~and~~not ~~notes~~include ~~thereto~~all ~~included~~of inthe ~~our~~information ~~Annual~~and ~~Report~~notes onrequired ~~Form~~by ~~10-K~~GAAP for ~~the~~complete ~~year~~consolidated ~~ended~~financial ~~December 31, 2016~~statements.

~~New~~In ~~Accounting~~the ~~Pronouncements~~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.

InThese ~~May~~unaudited ~~2014,~~consolidated ~~the~~financial ~~Financial~~statements ~~Accounting~~should ~~Standards~~be ~~Board~~read ~~(“FASB”)~~in ~~and~~conjunction with the ~~International~~audited ~~Accounting~~consolidated ~~Standards~~financial ~~Board~~statements jointly issued a comprehensive new revenue recognition standard that provides accounting guidance for all revenue arising from contracts to provide goods or services to customers. This standard is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and ~~capital~~notes ~~markets.~~thereto ~~The~~included ~~standard~~in ~~allows~~our ~~for~~Annual ~~either~~Report ~~full~~on ~~retrospective~~Form ~~adoption or modified retrospective adoption. In August 2015, the FASB updated the guidance to include a one~~10-~~year~~K ~~deferral of the effective date~~ for the ~~new~~year ~~revenue~~ended ~~standard, making the requirements of the standard effective for interim and annual periods beginning after~~ December 15 31, ~~2017,~~2016. ~~with~~Our ~~early~~consolidated ~~adoption~~balance ~~permitted~~sheet ~~for~~as ~~interim~~of ~~and annual periods beginning after~~ December 15 31, 2016., Wehas ~~are~~been ~~evaluating~~derived ~~the~~from ~~guidance to determine~~ the ~~method~~audited ~~of adoption and the impact this standard will have on our consolidated~~ financial statements ~~and~~as ~~related disclosures. Based on our initial evaluation, though not currently quantified, the adoption~~ of ~~the~~that ~~standard is not expected to have a material impact on the timing of revenue recognized, results of operations or cash flows~~date.

InAccounting ~~February~~Policies 2016, the FASB issued new guidance on the accounting for leases, which requires lessees to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The standard will also require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The requirements from this guidance are effective for interim and annual periods beginning after December 31, 2018. We are evaluating the guidance to determine the impact this standard will have on our consolidated financial statements.Update

InThe ~~June~~following ~~2016,~~condensed ~~the FASB issued an~~ accounting ~~standards~~policies ~~update~~represent ~~requiring~~updates in the ~~measurement~~Successor ofperiod ~~all~~to ~~expected~~those ~~credit~~policies ~~losses~~disclosed ~~for~~in ~~financial~~our ~~assets~~annual ~~held~~report ~~at the reporting date based~~ on ~~historical~~Form ~~experience~~10-K, ~~current conditions,~~ and ~~reasonable~~primarily ~~and~~relate ~~supportable forecasts. Financial institutions and other organizations will now use forward-looking information~~ to ~~better~~changes ~~inform~~resulting ~~their credit loss estimates. The requirements~~ from the ~~updated~~conforming ~~standard~~of ~~are~~accounting ~~effective~~policies ~~for~~in ~~interim~~connection ~~and~~with ~~annual~~the ~~periods beginning after~~ 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:

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ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

December 15, 2019. We are evaluating the guidance to determine the impact this standard will have on our consolidated financial statements.



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

In August 2016, the FASB issued an accounting standards update addressing eight specific cash flow issues with the objective of eliminating the existing diversity in practice. The amendments from this update are effective for interim and annual periods beginning after December 15, 2017. We do not expect application of this standard to have a material effect on our consolidated financial statements._______________________

(21) ~~Fair~~The ~~Value~~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.

AsBeginning ~~required~~July 1, 2017, we ~~utilize~~account ~~valuation~~for ~~techniques~~the ~~that~~liability ~~maximize~~to ~~the~~repurchase ~~use~~inventory ofpreviously ~~observable~~sold ~~inputs~~to ~~(levels~~J. 1Aron ~~and~~under 2)the Supply and ~~minimize~~Offtake ~~the~~Agreement, ~~use~~defined ofin ~~unobservable~~Note ~~inputs~~6 (~~level~~the 3“step-out liability”), ~~within~~at fair value in accordance with ASC 825, as it pertains to the fair value ~~hierarchy~~option. WeThis ~~generally~~standard ~~apply~~permits the ~~“market~~election ~~approach”~~to carry financial instruments and certain other items similar to ~~determine~~financial instruments at fair value on the balance sheet, with all changes in fair value reported in earnings. By ~~This~~electing ~~method~~the ~~uses~~fair ~~pricing~~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 ~~other~~is ~~information~~measured ~~generated~~at byfair value using market ~~transactions~~prices for ~~identical~~the orconsigned ~~comparable~~crude ~~assets~~oil and ~~liabilities~~refined products we are required to repurchase from J. ~~Assets~~Aron at the end of the term of the Supply and ~~liabilities~~Offtake ~~are~~Agreement. The ~~classified~~J. ~~within~~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, ~~hierarchy~~and ~~based~~designated onsuch ~~the~~as ~~lowest~~a ~~level~~fair ~~(least~~value ~~observable)~~hedge ~~input~~on ~~that~~the ischange ~~significant~~in tofair value of the ~~measurement~~inventory in ~~its~~the ~~entirety~~Predecessor periods. See Note 6 for further discussion.

The ~~carrying amounts of our cash and cash equivalents, receivables, payables and accrued liabilities approximate~~ fair value ~~due~~hierarchy tofor ~~the~~our ~~short-term~~financial ~~maturities of these~~ assets and liabilities. ~~The~~accounted ~~reported~~for ~~amounts~~at ~~of long-term debt approximate~~ fair value. ~~Derivative~~on ~~instruments~~a ~~are~~recurring ~~carried~~basis at ~~fair value~~September 30, ~~which~~2017 ~~are based on quoted market prices. Derivative instruments are our only assets~~ and ~~liabilities~~December 31, ~~measured~~2016 atwas ~~fair~~as ~~value on a recurring basis.~~follows:

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the consolidated balance sheets at June 30, 2017 and December 31, 2016:



	Level 1			Level 2			Level 3		Total
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

	Level 1		Level 2		Level 3		Total
As of June 30, 2017
Assets:
Fair value hedge of consigned inventory	$	—	$	5,130	$	—	$	5,130
Liabilities:
Commodity contracts (futures and forwards)	662		—		—		662
As of December 31, 2016
Assets:
Fair value hedge of consigned inventory	$	—	$	4,389	$	—	$	4,389
Liabilities:
Commodity contracts (futures and forwards)	689		—		—		689

4. Derivative Instruments

(3) Derivative Financial Instruments

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

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ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

Mark to Market

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

We have contracts that are used to fix prices on forecasted purchases of inventory, which we refer to as futures and forwards. Futures represent trades executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period. Forwards represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period.9

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

~~Fair~~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 ~~are~~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, iswas recognized in earnings in the same period.

We ~~have~~had certain embedded commodity ~~contracts~~derivatives associated with the Supply and Offtake Agreement discussed in Note 56 that ~~have~~were ~~been~~ accounted for as a fair value hedge, which had purchase volumes of ~~116~~126 thousand barrels of crude oil as of ~~June~~December 3031, ~~2017~~2016.

~~The~~ ~~following tables present the effect of derivative instruments on the consolidated balance sheets:~~10

	As of June 30, 2017
	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)		$	—	Accrued liabilities	$	662
Total derivatives not designated as hedging instruments		—			662
Derivatives designated as hedging instruments:
Fair value hedge of consigned inventory	Other assets	$	5,130		$	—
Total derivatives designated as hedging instruments		5,130			—
Total derivatives		$	5,130		$	662

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

	As of December 31, 2016
Predecessor
	Asset Derivatives			Liability Derivatives
		December 31, 2016
	Balance Sheet Location	Fair Value		Balance Sheet Location		Fair Value
Derivative Type	Balance Sheet Location	Assets		Liabilities
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	30980	~~Accrued liabilities~~$	(950	$)	~~719~~
Total derivatives not designated as hedging instruments		30				719
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	~~4,389~~	—		$	—
Total derivatives designated as hedging instruments		4,389				—
Total gross fair value of derivatives		6,319		(2,619		)
Total derivatives		$	4,419			$	719
Less: Counterparty netting and cash collateral(1)		1,900		(1,900		)
Total net fair value of derivatives		$	4,419	$	(719	)

(1) 6As of December 31, 2016, there was no cash collateral held by a counterparty to net.

Table of Contents

ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

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

Derivatives in fair value hedging relationships:

		Gain (Loss) Recognized in Income
		Predecessor
		For the Three Months Ended						For the Six Months Ended
	Location	Period from January 1, 2017 to June 30, 2017			Three Months Ended September 30, 2016			Nine Months Ended September 30, 2016
		June 30,						June 30,
Fair value hedge of consigned inventory (1)	Interest expense	741			(1,772		)	(5,995		)
	Location	2017			2016			2017			2016
Total derivatives		$	741		$	(1,772	)	$	(5,995	)
Fair value hedge of consigned inventory (1)	Interest expense	$	(325	)	$	(5,249	)	$	741		$	(4,223	)
Total derivatives		$	(325	)	$	(5,249	)	$	741		$	(4,223	)

_______________________


⁽¹⁾	Changes in the fair value hedge are substantially offset in earnings by changes in the hedged item.

Derivatives not designated as hedging instruments:

		Gain Recognized in Income
		Gain (Loss) Recognized in Income
		For the Three Months Ended						For the Six Months Ended
		Successor				Predecessor
		June 30,						June 30,
	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
	Location	2017			2016			2017				2016
Commodity contracts (futures)	Cost of goods sold	(2,393		)		3,479			(1,199		)		4,998
Commodity contracts (futures and forwards)	Cost of sales	$	1,323		$	823		$	3,479			$	6,197
Total derivatives		$	(2,393	)		$	3,479		$	(1,199	)		$	4,998
Total derivatives		$	1,323		$	823		$	3,479			$	6,197

Offsetting Assets and Liabilities

Our derivative instruments are subject to master netting arrangements to manage counterparty credit risk associated with derivatives, and we offset the fair value amounts recorded for derivative instruments to the extent possible under these agreements on our consolidated balance sheets.

The following table presents offsetting information regarding our derivatives by type of transaction as of June 30, 2017 and December 31, 2016:

	Gross Amounts of Recognized Assets/Liabilities		Gross Amounts offset in the Statement of Financial Position			Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not offset in the Statement of Financial Position					Net Amount
								Financial Instruments			Cash Collateral Pledged
As of June 30, 2017
Derivative Assets:
Commodity contracts (futures and forwards)	$	719	$	(719	)	$	—	$	—		$	—	$	—
Fair value hedge of consigned inventory	5,130		—			5,130		—			—		5,130
Derivative Liabilities:
Commodity contracts (futures and forwards)	$	1,381	$	(719	)	$	662	$	—		$	—	$	662
As of December 31, 2016
Derivative Assets:
Commodity contracts (futures and forwards)	$	980	$	(950	)	$	30	$	(30	)	$	—	$	—
Fair value hedge of consigned inventory	4,389		—			4,389		—			—		4,389
Derivative Liabilities:
Commodity contracts (futures and forwards)	$	1,669	$	(950	)	$	719	$	(30	)	$	—	$	689

Table of Contents

ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

Compliance Program Market Risk

We are obligated by government regulations to blend a certain percentage of biofuels into the products that we produce and are consumed in the U.S. We purchase biofuels from third parties and blend those biofuels into our products, and each gallon of biofuel purchased includes a renewable identification number, or RIN. To the degree we are unable to blend biofuels at the required percentage, a RINs deficit is generated and we must acquire that number of RINs by the annual reporting deadline in order to remain in compliance with applicable regulations. Alternatively, if we have a RINs surplus, some of those RINs could be sold. Any such sales would be subject to our normal credit evaluation process.

We are exposed to market risk related to the volatility in the price of credits needed to comply with these governmental and regulatory programs. We manage this risk by purchasing RINs when prices are deemed favorable utilizing fixed price purchase contracts. We may also sell the RINs with an agreement to repurchase in the future at a fixed price. Some of these contracts are derivative instruments; however, we elect the normal purchase and sale exception and do not record these contracts at their fair values.11

~~The~~We ~~cost~~are exposed to market risk related to the volatility in the price of ~~meeting~~credits ~~our~~needed ~~obligations~~to ~~under~~comply with these ~~compliance~~governmental and regulatory programs. ~~was~~We ~~$2,280~~manage ~~and~~this ~~$2,089~~risk ~~for~~by purchasing RINs when prices are deemed favorable utilizing fixed price purchase contracts. We may also sell the ~~three~~RINs ~~months~~with ~~ended~~an ~~and~~agreement ~~$6,438~~to ~~and~~repurchase ~~$2,908~~in ~~for~~the future at a fixed price. Some of these contracts meet the ~~six~~definition ~~months~~of ~~ended~~derivative ~~June 30,~~instruments ~~2017~~under ~~and~~ASC ~~2016~~815. In the Successor period, ~~respectively~~these contracts are recorded at estimated fair value in accordance with the provisions of ASC 815. ~~These~~Changes ~~amounts~~in the fair value of these future RIN commitment contracts are ~~reflected~~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 ~~operations~~income.

~~(4)~~The ~~Inventories~~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:

	June 30, 2017		December 31, 2016
	Successor			Predecessor
Crude oil, refined products and blendstocks	$	25,083	$	36,259
	September 30, 2017			December 31, 2016
Crude oil consignment inventory (Note 5)	779		1,850
Crude oil, refined products and blendstocks	$	99,802		$	38,109
Materials and supplies	~~11,205~~—		~~11,573~~	11,573
Total inventories	$	3799,~~067~~802	$	~~49,682~~$	49,682

AtEffective ~~June 30~~July 1, 2017, ~~and~~in ~~December 31,~~connection ~~2016,~~with the ~~market~~Delek/Alon ~~value~~Merger, ofinventory ~~our~~was ~~refined~~recorded ~~products~~at ~~and~~fair ~~blendstock~~value ~~inventories~~under ~~was~~the ~~less~~acquisition ~~than~~method. ~~inventories~~Going ~~valued~~forward, ~~on a LIFO~~ cost ~~basis which resulted in a lower~~ of ~~cost~~inventory oris ~~market~~accounted ~~reserve~~for ofusing ~~$7,477~~the ~~and~~FIFO $6method,~~213,~~ ~~respectively.~~pursuant Atto ~~June 30,~~which ~~2017~~inventories ~~and~~are ~~December 31,~~valued ~~2016,~~at the ~~market~~lower ~~value~~ of ~~our~~FIFO ~~crude~~cost ~~oil~~or ~~inventories exceeded LIFO costs,~~ net ofrealizable ~~the fair~~ value ~~hedged item, by $2,930 and $5,236, respectively~~.

~~(5)~~Prior ~~Inventory~~to ~~Financing~~July ~~Agreement~~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.

~~We have entered into a Supply and Offtake Agreement and other associated agreements (together the “Supply and Offtake Agreement”) with J~~6. Crude ~~Aron~~Oil ~~& Company (“J. Aron”). Pursuant to the~~ Supply and ~~Offtake~~Inventory ~~Agreement,~~Purchase ~~(i) J.~~Agreements 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.

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 ~~provided~~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.

~~The~~Effective ~~Supply~~July ~~and~~1, ~~Offtake~~2017, ~~Agreement has an initial term that expires~~ in ~~May 2021.~~connection J.with ~~Aron~~the ~~may~~Delek/Alon ~~elect~~Merger, ~~to terminate~~ the Supply and Offtake Agreement ~~prior~~is toaccounted ~~the~~for ~~expiration~~as ofa ~~the~~product ~~initial~~financing ~~term~~arrangement. ~~beginning~~We inincurred ~~May~~fees ~~2018~~payable ~~and~~to ~~upon~~J. ~~each~~Aron ~~anniversary~~of ~~thereof~~$1,455 onduring ~~six~~the three months ~~prior~~ended ~~notice~~September 30, 2017. WeThese ~~may~~amounts ~~elect~~are toincluded ~~terminate~~as ina ~~May~~component ~~2020~~of oninterest ~~six~~expense ~~months~~in ~~prior~~the ~~notice~~condensed consolidated statements of income.

~~Following~~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 ~~are~~will ~~obligated~~be required to ~~purchase~~repurchase the consigned crude oil and refined ~~product~~products ~~inventories~~from J. Aron at then-prevailing ~~owned~~market byprices. At September 30, 2017, we had 1.6 million barrels of inventory consigned from J. Aron, and ~~located~~we athave ~~the~~recorded ~~Big~~liabilities ~~Spring~~associated ~~refinery~~with atthis ~~then~~consigned ~~current~~inventory ~~market~~of ~~prices~~$99,108 in the condensed consolidated balance sheet.

~~Associated~~Prior to July 1, 2017, associated with the Supply and Offtake Agreement, weour ~~have~~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 ~~are~~were recorded as interest expense in the consolidated statements of operations.

At June 30, 2017 and December 31, 2016, we had net current receivables of $24,534 and $10,569, respectively, with J. Aron for purchases and sales, and a consignment inventory receivable representing a deposit paid to J. Aron of $6,290 and $6,290, respectively. At June 30, 2017 and December 31, 2016, we had non-current liabilities for the original financing of $5,888 and $7,550, respectively, net of the related fair value hedge.12

Additionally, we had net current payables of $351 and $719 at June 30, 2017 and December 31, 2016, respectively, for forward commitments related to month-end consignment inventory target levels differing from projected levels and the associated pricing with these inventory level differences.

(6) Property, Plant and Equipment, Net

Property, plant and equipment, net consisted of the following:

	June 30, 2017			December 31, 2016
Refining facilities	$	744,690		$	732,697
Accumulated depreciation	(331,657		)	(312,143		)
Property, plant and equipment, net	$	413,033		$	420,554

Table of Contents

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, ~~Additional~~net ~~Financial~~of ~~Information~~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.

~~The~~7. Property, ~~following~~Plant ~~tables~~and ~~provide additional financial information related to the consolidated financial statements.~~Equipment

~~(a)~~Property, ~~Other~~plant ~~Assets~~and equipment, ~~Net~~net and depreciation expense are as follows:

	June 30, 2017			December 31, 2016
	Successor				Predecessor
Deferred turnaround and catalyst cost	$	27,218		$	34,252
	September 30, 2017				December 31, 2016
Receivable from supply and offtake agreement (Note 5)	6,290			6,290
Refining facilities	$	424,154			$	732,697
Fair value hedge of consigned inventory (Note 3)	5,130			4,389
Less: Accumulated depreciation	(6,048		)		(312,143		)
Other	7,083			8,280
Property, plant and equipment, net	$	418,106			$	420,554
Total other assets	$	45,721		$	53,211

~~(b)~~Depreciation ~~Accounts~~expense ~~Payable~~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.

~~Included~~8. Other inAssets ~~accounts payable was $130,364~~ and ~~$78,565~~Liabilities ~~related to RINs financing transactions as of June 30, 2017 and December 31, 2016, respectively.~~

~~(c)~~The ~~Accrued~~detail ~~Liabilities~~of ~~and~~other ~~Other Non~~non-~~Current~~current ~~Liabilities~~assets is as follows:

	June 30, 2017		December 31, 2016
Accrued Liabilities:
Taxes other than income taxes, primarily excise taxes	$	27,740	$	31,882
Accrued finance charges	364		372
Environmental accrual (Note 11)	796		796
Commodity contracts	662		719
Other	7,915		9,331
Total accrued liabilities	$	37,477	$	43,100
Other Non-Current Liabilities:
Consignment inventory obligation (Note 5)	$	11,018	$	11,939
Environmental accrual (Note 11)	5,796		5,796
Asset retirement obligations	3,222		3,131
RINs financing transactions	—		39,478
Other	2,536		2,536
Total other non-current liabilities	$	22,572	$	62,880

Other Non-Current Assets, Net

(8) Indebtedness



	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:

	June 30, 2017		December 31, 2016
	Successor			Predecessor
Term loan credit facility	$	235,996	$	236,319
	September 30, 2017			December 31, 2016
Revolving credit facility	50,000		—
Term loan credit facility	$	238,125		$	236,319
Total debt	285,996		236,319
Revolving credit facility	100,000			—
Less: Current portion	2,500		2,500
Total debt	338,125			236,319
Total long-term debt	$	283,496	$	233,819
Less: Current portion	2,500			2,500
Total long-term debt	$	335,625		$	233,819

~~Outstanding~~At ~~letters~~July of1, ~~credit~~2017, ~~under~~all ~~the~~outstanding ~~revolving~~debt ~~credit~~was ~~facility~~adjusted ~~were~~to ~~$48,730~~fair ~~and~~value ~~$100,613~~pursuant atto ~~June 30,~~the ~~2017~~push-down ~~and~~of ~~December 31,~~the ~~2016,~~acquisition ~~respectively~~method of accounting.

~~The~~Term ~~revolving~~Loan ~~credit~~Credit ~~facility contains maintenance financial covenants. At June 30, 2017, we were in compliance with these covenants.~~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.

Table of Contents

ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

~~(9)~~14. Related ~~Partners'~~Party ~~Equity~~Transactions ~~(unit values in dollars)~~

~~Cash~~Acquisition ~~Distributions~~of Alon Energy

WeThe ~~have~~general ~~adopted~~and alimited ~~policy~~partner ~~pursuant~~interests tothat ~~which~~were wepreviously ~~will~~owned ~~distribute~~by ~~all~~Alon ofEnergy ~~the~~were ~~available~~contributed ~~cash~~to ~~generated~~Delek ~~each~~in ~~quarter~~connection with the Delek/Alon Merger, as ~~defined~~described in Note 1. As a result of the ~~partnership~~Delek/Alon ~~agreement~~Merger, ~~subject~~both tothe 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 ~~approval~~owner of the General Partner, Delek is responsible for appointing all members of the board of directors of ~~the~~our General Partner, including all of our General Partner’s independent directors. The ~~per~~Partnership ~~unit~~has ~~amount~~various ofoperating ~~available~~and ~~cash~~administrative toagreements bewith ~~distributed~~Alon ~~each~~Energy ~~quarter,~~(now ~~if any~~Delek), ~~will~~including bethe ~~distributed~~agreements ~~within~~described 60below. Delek ~~days~~performs ~~following~~ the ~~end~~administrative offunctions defined in such ~~quarter~~agreements on the Partnership’s behalf.

The following table summarizes the Partnership’s cash distribution activity during the period:

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

_______________________

(1) Represents the aggregate cash available for distribution per unit attributable to the period indicated. This represents the difference between cash available for distribution and distributions paid in the table above.

Restricted Units

(10) Related Party Transactions

Sales and Receivables

Sales to related parties include ~~motor~~feedstock, ~~fuels~~refined and blended product and asphalt sold to other ~~Alon~~Delek ~~Energy~~ subsidiaries at prices substantially determined by reference to market commodity pricing information. These sales are included in net sales in the consolidated statements of operations. Accounts receivable from related parties includes sales of motor fuels and is shown separately on the consolidated balance sheets.

~~Costs~~Purchases ~~Allocated~~and ~~from Alon Energy~~Payables

~~The~~We ~~Partnership~~had ispurchases aof ~~subsidiary~~crude ofoil, ~~Alon~~products ~~Energy~~and RINs from Delek of $770 and is$175 ~~operated~~for asthe aSuccessor ~~component~~three-month ofperiod ended September 30, 2017 and the ~~integrated~~Predecessor ~~operations~~three-month ofperiod ~~Alon~~ended ~~Energy.~~September 30, As2016, ~~such~~respectively, and $22,239 and $960 for the ~~executive~~Predecessor ~~officers~~six ofmonths ~~Alon~~ended ~~Energy~~June 30, ~~who~~2017 ~~are~~and ~~employed~~and bythe ~~another~~Predecessor ~~subsidiary~~nine-month ofperiod ~~Alon~~ended ~~Energy~~September 30, ~~also~~2016, ~~serve~~respectively. Accounts aspayable ~~executive~~includes ~~officers~~a ofbalance ~~the~~outstanding ~~General~~to ~~Partner~~Delek ~~and~~of ~~Alon~~$84,631 ~~Energy’s~~at ~~other~~September 30, ~~subsidiaries~~2017.

~~Effective~~Costs ~~July~~Allocated 1,from ~~2017, with the completion of the merger between~~ Delek and Alon Energy, Delek indirectly owns 100% of our General Partner and 81.6% of our limited partner interest. As the owner of the General Partner, Delek is responsible for appointing all members of the board of directors of our General Partner, including all of our General Partner’s independent directors.

(The Partnership is a) ~~Corporate~~subsidiary ~~Overhead~~of ~~Allocations~~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.

~~Alon~~Corporate ~~Energy~~Overhead performs general corporate and administrative services and functions for us and their other subsidiaries, which include accounting, treasury, cash management, tax, information technology, insurance administration and claims processing, legal, environmental, risk management, audit, payroll and employee benefit processing and internal audit services. Alon Energy allocates the expenses actually incurred in performing these services to the Partnership based primarily on the estimated amount of time the individuals performing such services devote to our business and affairs relative to the amount of time they devote to the business and affairs of Alon Energy’s other subsidiaries. The management of Alon Energy and the General Partner consider these allocations to be reasonable. We record the amount of such allocations as selling, general and administrative expenses. Our allocation for selling, general and administrative expenses were $3,116 and $4,245, for the three months ended June 30, 2017 and 2016, respectively, and $5,766 and $7,665 for the six months ended June 30, 2017 and 2016, respectively.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)

(b) Labor Costs

As we are operated as a component of Alon Energy’s integrated operations, we have no employees. As a result, employee expense costs for Alon Energy employees working in our operations have been allocated to us and recorded as payroll expense in direct operating expenses and selling, general and administrative expenses. The allocated portion of Alon Energy’s employee expense costs included in direct operating expenses were $7,451 and $7,070 for the three months ended June 30, 2017 and 2016, respectively, and $14,474 and $14,332 for the six months ended June 30, 2017 and 2016, respectively. The allocated portion of Alon Energy’s employee expense costs included in selling, general and administrative expenses were $947 and $1,280 for the three months ended June 30, 2017 and 2016, respectively, and $1,967 and $2,235 for the six months ended June 30, 2017 and 2016, respectively.

Insurance costs related to the Big Spring refinery and wholesale marketing operations are allocated to us by Alon Energy based on estimated insurance premiums on a stand-alone basis relative to Alon Energy’s total insurance premium. Our allocation for insurance costs included in direct operating expenses were $1,118 and $1,512 for the three months ended June 30, 2017 and 2016, respectively, and $2,246 and $2,372 for the six months ended June 30, 2017 and 2016, respectively.

Leasing Agreements

InIncluded ~~June~~as ~~2014~~a component of selling, wegeneral ~~entered~~and ~~into~~administrative ~~six-year~~expenses ~~lease~~are ~~agreements~~payments ~~with~~to a subsidiary of Alon Energy tofor ~~lease~~use of certain equipment at the Big Spring refinery. ~~The~~totaling ~~lease agreements were effective July~~ $1,230 ~~2014~~for ~~and~~the ~~require~~both ~~fixed~~Successor ~~monthly~~three-month ~~payments~~period ~~amounting~~ended ~~to $4~~September 30,~~920~~ ~~annually.~~2017 ~~Related~~and the toPredecessor ~~these~~three-month ~~agreements,~~period weended ~~recorded~~September 30, ~~selling~~2016, ~~general and administrative expense of~~ $12,~~230~~460 for the ~~three~~Predecessor ~~months~~six-month period ended June 30, 2017 and ~~2016 and~~ $23,~~460~~690 for the ~~six~~the ~~months~~Predecessor nine-month period ended ~~June~~September 30, ~~2017 and~~ 2016.

~~Transactions~~Cash ~~with Delek US Holdings, Inc.~~Distributions

WeOur ~~have~~common ~~transactions~~unitholders ~~with~~are ~~Delek~~entitled ~~that~~to ~~occur~~receive indistributions ~~the~~of ~~ordinary~~available ~~course~~cash ofas ~~business.~~it Weis ~~had~~determined ~~purchases,~~by ~~net~~the board of ~~sales,~~directors of ~~crude~~the General ~~oil,~~Partner ~~products~~in ~~and~~accordance ~~RINs~~with ~~from~~the ~~Delek~~terms and provisions of ~~$19,458~~our ~~and~~Partnership ~~$371~~Agreement. ~~for~~During the Successor three-month ~~months~~period ended ~~June~~ September 30, 2017 ~~and~~we ~~2016,~~paid ~~respectively~~cash distributions of $21,885, ~~and~~or $220.35 per unit,~~239~~ ~~and~~of which $~~785~~17,850 ~~for~~was paid to Delek. During the Predecessor six-month ~~months~~period ended June 30, 2017 and the Predecessor nine-month period ended September 30, 2016, ~~respectively.~~we ~~Accounts~~paid ~~payable~~cash ~~includes~~distributions aof ~~balance~~$30,638 ~~outstanding~~or to$0.49 ~~Delek~~per unit, and $13,754, or $0.22 per unit, of which $124,~~824~~990 atand ~~June 30~~$11,220 ~~2017~~was paid to Alon Energy, respectively.

~~Distributions~~15. Commitments and Contingencies

During the six months ended June 30, 2017, we paid cash distributions of $30,638, or $0.49 per unit, of which $24,990 was paid to Alon Energy. During the six months ended June 30, 2016, we paid cash distributions of $5,001, or $0.08 per unit, of which $4,080 was paid to Alon Energy.Commitments

(11) Commitments and Contingencies

(a) Commitments

In the normal course of business, we have long-term commitments to purchase, at market prices, utilities such as natural gas, electricity and water for use by our refinery, terminals and pipelines. We are also party to various refined product and crude oil supply and exchange agreements, which are typically short-term in nature or provide terms for cancellation.

~~(b) Contingencies~~Litigation

WeIn ~~are involved in various legal actions arising in~~ the ordinary ~~course~~conduct of our business., Wewe ~~believe~~are ~~the~~from ~~ultimate~~time ~~disposition~~to oftime ~~these~~subject ~~matters~~to ~~will~~lawsuits, ~~not~~investigations ~~have~~and ~~a material effect on our financial position~~claims, ~~results~~including ofenvironmental ~~operations~~claims orand ~~liquidity~~employee-related matters.

~~(c)~~Although ~~Environmental~~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.

~~We are subject to loss contingencies pursuant to federal~~Environmental, ~~state,~~Health and local environmental laws and regulations. These laws and regulations govern the discharge of materials into the environment and may require us to incur future obligations to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites; to remediate or restore these sites and to compensate others for damage to property and natural resources. These contingent obligations relate to sites owned by the Partnership and are associated with past or present operations. We are currently participating in environmental investigations, assessments and cleanups pertaining to the refinery, pipelines and terminals. We may be involved in additional future environmental investigations, assessments and cleanups. The magnitude of future costs are unknown and will depend on factors such as the nature and contamination at many sites, the timing, extent and method of the remedial actions which may be required, and the determination of our liability in proportion to other responsible parties.Safety

~~Environmental~~We ~~expenditures~~ are ~~expensed~~subject orto ~~capitalized~~extensive ~~depending~~federal, onstate ~~their~~and ~~future~~local ~~economic~~environmental ~~benefit.~~and ~~Expenditures~~safety ~~that~~laws ~~relate~~and toregulations anenforced ~~existing condition caused~~ by ~~past~~various ~~operations~~agencies, ~~and~~including ~~that~~the ~~have~~EPA, nothe ~~future~~United ~~economic~~States ~~benefit~~Department ~~are expensed. Liabilities for expenditures~~ of aTransportation, ~~non-capital~~the ~~nature~~Occupational ~~are~~Safety ~~recorded when environmental assessment~~ and~~/or~~ ~~remediation~~Health ~~is probable~~Administration, ~~and~~ the ~~costs~~Texas ~~can~~Commission beon ~~reasonably~~Environmental ~~estimated.~~Quality, ~~Substantially~~and ~~all amounts accrued are expected to be paid out over~~ the ~~next~~Railroad 15Commission ~~years. The level~~ of ~~future~~Texas, ~~expenditures~~as ~~for~~well ~~environmental~~as ~~remediation~~other ~~obligations~~state ~~cannot~~and befederal ~~determined with any degree of reliability~~agencies.

WeThese ~~have~~laws ~~accrued~~and ~~environmental~~regulations ~~remediation~~govern ~~obligations~~the discharge of $6materials into the environment,~~592~~ ~~($796~~waste ~~current~~management ~~liability~~practices, pollution prevention measures and ~~$5,796~~the ~~non-current~~composition ~~liability)~~of atthe ~~June 30,~~fuels ~~2017~~we produce, as well as the safe operation of our plants and ~~$6,592~~pipelines ~~($796~~and ~~accrued~~the ~~liability~~safety of our workers and $5the public. Numerous permits or other authorizations are required under these laws and regulations for the operation of our refineries,~~796~~ ~~non-current~~terminals, ~~liability)~~pipelines atand ~~December 31~~related operations, ~~2016~~and may be subject to revocation, modification and renewal.

These 11laws 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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ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

(12) Subsequent Event

Distribution Declared

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

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

References in this report to the “Partnership,” “~~Alon,” “~~we,” “our” and “us” or like terms refer to Alon USA Partners, LP and its consolidated subsidiaries. Unless the context otherwise requires, references in this report to “Alon Energy” refer collectively to Alon USA Energy, Inc. and any of its consolidated subsidiaries other than Alon USA Partners, LP, its subsidiaries and its general partner. ~~Effective~~In ~~July~~January 1, 2017, ~~with~~it ~~the~~was ~~completion~~announced ofthat ~~the merger between~~ Delek US Holdings, Inc. (and various related entities) had entered into an Agreement and Plan of Merger with Alon Energy (NYSE: ALJ), ~~references~~as insubsequently ~~this~~amended ~~report~~on toFebruary 27 and April 21, 2017 (as so amended, the "Merger Agreement"). The related mergers (the “Merger” of the “Delek/Alon Merger”) ~~refer~~were toeffective 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 ~~any~~the ofprevious ~~its~~Delek ~~consolidated~~US Holdings, Inc. (“Old Delek”) surviving as wholly-owned subsidiaries. ~~The~~New ~~following~~Delek ~~discussion~~is ofthe ~~our~~successor ~~financial~~issuer ~~condition~~to Old Delek and ~~results~~Alon Energy pursuant to Rule 12g-3(c) under the Securities Exchange Act of ~~operations~~1934, ~~should~~as beamended ~~read~~(the in"Exchange ~~conjunction~~Act"). ~~with~~In addition, as a result of the ~~audited~~Delek/Alon ~~consolidated~~Merger, ~~financial~~the ~~statements~~shares of common stock of Old Delek and ~~notes~~Alon ~~thereto~~Energy ~~included~~were delisted from the New York Stock Exchange in ~~our~~July ~~Annual~~2017, ~~Report~~and ontheir ~~Form~~respective ~~10-K~~reporting ~~for~~obligations under the ~~year~~Exchange ~~ended~~Act ~~December 31~~were terminated. Effective July 1, ~~2016~~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 ~~completed merger between~~ Delek ~~and~~ /Alon ~~Energy~~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;

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•	operating hazards, accidents, fires, severe weather, floods and other natural disasters, casualty losses and other matters beyond our control, which could result in unscheduled downtime;


•	the effect of any national or international financial crisis on our business and financial condition; and


•	the other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2016 under the caption “Risk Factors.”

Any one of these factors or a combination of these factors could materially affect our future results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by securities laws to do so.

Company Overview

We are a limited partnership formed in August 2012 and engaged principally in the business of operating a crude oil refinery in Big Spring, Texas, with a crude oil throughput capacity of 73,000 barrels per day (“bpd”). We refine crude oil into finished products, which we market primarily in Central and West Texas, Oklahoma, New Mexico and Arizona through our integrated wholesale distribution network to both Alon Energy’s retail convenience stores and other third-party distributors. We distribute fuel products through a network of pipelines and terminals that we own or access through leases or long-term throughput agreements.

Effective July 1, 2017, with the completion of the merger between Delek and Alon Energy, Delek indirectly owns 100% of our General Partner and 81.6% of our limited partner interest. Our General Partner manages our operations and activities subject to the terms and conditions specified in our partnership agreement. The operations of our General Partner in its capacity as general partner are managed by its board of directors.

For additional information on our business, see Items 1. and 2. “Business and Properties” included in our Annual Report on Form 10-K for the year ended December 31, 2016.

~~Second~~Recent ~~Quarter Operational and Financial Highlights~~Developments

~~Our~~Planned ~~operational~~Acquisition ~~and~~of ~~financial~~Non-controlling ~~highlights~~Interest ~~for~~in the ~~second quarter of 2017 include the following:~~Partnership

•On ~~Operating~~November ~~income~~8, ~~for~~2017, Delek and the ~~second~~Partnership ~~quarter~~announced a definitive merger agreement under which Delek will acquire all of ~~2017~~the ~~was~~outstanding ~~$31~~limited partner units which Delek does not already own in an all-equity transaction.1 ~~million~~Delek currently owns approximately 51,000 ~~compared~~limited topartner ~~$11~~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 ~~million~~Delek shares for each limited partner unit of the ~~second~~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 ~~2016~~2018.

• Big Spring refinery average throughput for the second quarter of 2017 was 72,763 bpd compared to 71,153 bpd for the second quarter of 2016. Refinery throughput for the second quarter of 2017 was affected by maintenance on the FCCU and refinery throughput for the second quarter of 2016 was affected by unplanned downtime due to a power outage caused by inclement weather, which affected multiple units.19

• Refinery operating margin was $12.68 per barrel for the second quarter of 2017 compared to $8.53 per barrel for the same period in 2016. This increase in operating margin was primarily due to a higher Gulf Coast 3/2/1 crack spread, a widening of both the WTI Cushing to WTI Midland and WTI Cushing to WTS spreads and a stronger wholesale marketing environment, partially offset by a reduced benefit from the contango market environment which increased the cost of crude.

• The average Gulf Coast 3/2/1 crack spread was $15.07 per barrel for the second quarter of 2017 compared to $13.16 per barrel for the second quarter of 2016.

• The average WTI Cushing to WTI Midland spread for the second quarter of 2017 was $0.84 per barrel compared to $0.17 per barrel for the same period in 2016. The average WTI Cushing to WTS spread for the second quarter of 2017 was $1.24 per barrel compared to $0.75 per barrel for the same period in 2016. The average Brent to WTI Cushing spread for the second quarter of 2017 was $1.21 per barrel compared to $(0.18) per barrel for the same period in 2016.

• The average RINs cost effect on refinery operating margin was $0.34 per barrel for the second quarter of 2017, compared to $0.32 per barrel for the same period in 2016.

• The contango environment in the second quarter of 2017 created an average cost of crude benefit of $0.55 per barrel compared to an average cost of crude benefit of $1.49 per barrel for the same period in 2016.

• During the second quarter of 2017, we generated cash available for distribution of $0.35 per unit, compared to$0.14 per unit during the second quarter of 2016.

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Major Influences on Results of Operations

Earnings and cash flows are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. These prices depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation. While our sales and operating revenues fluctuate significantly with movements in crude oil and refined product prices, it is the spread between crude oil and refined product prices, not necessarily fluctuations in those prices, that affects our earnings.

In order to measure our operating performance, we compare our per barrel refinery operating margin to certain industry benchmarks. We calculate this margin for the Big Spring refinery by dividing the refinery’s gross margin by its ~~throughput~~sales volumes. Gross margin is the difference between net sales and cost of ~~sales~~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. Because our inventory is valued at the lower of cost or market value under the last-in, first-out (“LIFO”) inventory valuation methodology, price fluctuations generally have little effect on our financial results.

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Factors Affecting Comparability

Our financial condition and operating results over the three and ~~six~~nine months ended ~~June~~September 30, 2017 and 2016 have been influenced by the following ~~factor~~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 ~~six~~nine months ended ~~June~~ September 30, 2017 , throughput at the refinery was affected by maintenance on the FCCU. During the ~~six~~nine months ended ~~June~~ 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 ~~sales~~goods sold. Cost of ~~sales~~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 ~~sales~~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 ~~Alon~~Delek ~~Energy~~ and allocated to us.

Depreciation and amortization. Depreciation and amortization represents an allocation of the cost of capital assets to expense within the consolidated statements of operations. The cost is expensed based on the straight-line method over the estimated useful life of the related asset. Depreciation and amortization also includes deferred turnaround and catalyst replacement costs. Turnaround and catalyst replacement costs are currently deferred and amortized on a straight-line basis beginning the month after the completion of the turnaround and ending immediately prior to the next scheduled turnaround.

Operating income. Operating income represents our net sales less our total operating costs and expenses.

Interest expense. Interest expense includes interest expense, letters of credit, financing costs associated with crude oil purchases, financing fees, and amortization of both original issuance discount and deferred debt issuance costs but excludes capitalized interest.

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Table of Contents

~~ALON~~A ~~USA~~discussion ~~PARTNERS~~and analysis of the factors contributing to our results of operations is presented below. The financial statements, LPtogether ~~AND~~with ~~SUBSIDIARIES~~the ~~CONSOLIDATED~~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.

~~Summary Financial Tables.~~ The following tables ~~provide~~and ~~summary~~discussion ~~financial~~present ~~data~~a ~~and~~summary ~~selected~~of ~~key~~our ~~operating~~consolidated ~~statistics~~results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2017 and 2016., ~~The~~including ~~following~~a ~~data~~reconciliation ~~should~~of beEarnings ~~read~~Before inInterest, ~~conjunction~~Taxes, ~~with~~Depreciation ~~our~~and ~~consolidated~~Amortization ~~financial~~(“EBITDA”) ~~statements~~ and ~~the~~Adjusted ~~notes~~EBITDA ~~thereto~~to ~~included~~net ~~elsewhere~~income inand ~~this~~distributable ~~Form~~cash ~~10-Q.~~flow ~~All information~~ (in ~~“Management’s~~thousands, ~~Discussion~~except ~~and~~unit ~~Analysis of Financial Condition~~ and ~~Results~~per ofunit ~~Operations” except for Balance Sheet data as of December 31, 2016 is unaudited~~amounts).

	For the Three Months Ended							For the Six Months Ended
	Successor				Predecessor
	June 30,							June 30,
	Three Months Ended September 30, 2017				Three Months Ended September 30, 2016
	2017			2016				2017			2016
Net sales:
	(dollars in thousands, except per unit data, per barrel data and pricing statistics)
Affiliate	$	94,536			$	82,717
STATEMENTS OF OPERATIONS DATA:
Third party	400,942				379,540
Net sales (1)	$	521,751		$	468,457			$	1,066,283		$	836,466
Net sales	495,478				462,257
Operating costs and expenses:
Cost of sales	440,895			410,735				911,366			730,068
Cost of goods sold	415,386				404,207
Direct operating expenses	27,878			23,255				52,638			48,299
Operating expenses	26,548				25,125
Selling, general and administrative expenses	7,~~392~~741			~~8,802~~	8,153			~~14,156~~			~~16,111~~
Depreciation and amortization	147,~~462~~620			~~14,667~~	14,581			~~28,691~~			~~28,873~~
Total operating costs and expenses	490,627			457,459				1,006,851			823,351
Loss on disposition of assets	—				—
Loss on disposition of assets	(23		)	—				(23		)	—
Total operating costs and expenses	457,295				452,066
Operating income	3138,~~101~~183			~~10,998~~	10,191			~~59,409~~			~~13,115~~
Interest expense	(8,652		)	(9,920		)		(16,497		)	(20,507		)
Interest expense, net	8,817				8,144
Other income (loss), net	(459		)	113				(554		)	197
Other expense (income), net	5				(353		)
Income (loss) before state income tax expense	21,990			1,191				42,358			(7,195		)
Total non-operating expense	8,822				7,791
State income tax expense	310			—				566			176
Income before income tax expense	29,361				2,400
Net income (loss)	$	21,680		$	1,191			$	41,792		$	(7,371	)
Income tax expense	125				317
Earnings (loss) per unit	$	0.35		$	0.02			$	0.67		$	(0.12	)
Net income attributable to partners	$	29,236			$	2,083
Weighted average common units outstanding (in thousands)	62,525			62,515				62,523			62,512
Comprehensive income attributable to partners	$	29,236			$	2,083
Cash distribution per unit	$	0.38		$	—			$	0.49		$	0.08
Net income per unit - (basic and diluted)	$	0.47			$	0.03
CASH FLOW DATA:
Weighted average common units outstanding (in thousands) - (basic and diluted)	62,529				62,520
Net cash provided by (used in):
Cash distribution per unit	$	0.35			$	0.14
Operating activities	$	35,373		$	39,925			$	77,145		$	46,587
Cash Flow Data:
Investing activities	(7,316		)	(10,131		)		(13,191		)	(20,924		)
Net cash provided by (used in):
Financing activities	30,148			8,830				29,761			3,204
Operating activities	$	94,574			$	11,870
OTHER DATA:
Investing activities	(17,738		)		(5,954		)
Adjusted EBITDA (2)	$	45,127		$	25,778			$	87,569		$	42,185
Financing activities	24,497				36,027
Capital expenditures	7,149			4,588				12,175			12,700
Other Data:
Capital expenditures for turnarounds and catalysts	167			5,543				1,016			8,224
Adjusted EBITDA	$	67,798			$	25,125
KEY OPERATING STATISTICS:
Capital expenditures	12,681				4,499
Per barrel of throughput:
Capital expenditures for operating lease purchase	9,200				—
Refinery operating margin (3)	$	12.68		$	8.53			$	11.47		$	8.16
Capital expenditures for turnaround and catalysts	—				1,455
Refinery direct operating expense (4)	4.21			3.59				3.86			3.83
Key Operating Statistics:
PRICING STATISTICS:
Per barrel of throughput:
Crack spreads (per barrel):
Refinery operating margin (1)	$	12.49			$	9.22
Gulf Coast 3/2/1	$	15.07		$	13.16			$	14.41		$	12.20
Refinery direct operating expense (2)	4.14				3.90
WTI Cushing crude oil (per barrel)	$	48.25		$	45.48			$	50.00		$	39.39
Crude oil differentials (per barrel):
WTI Cushing less WTI Midland	$	0.84		$	0.17			$	0.11		$	0.02
WTI Cushing less WTS	1.24			0.75				1.26			0.32
Brent less WTI Cushing	1.21			(0.18		)		1.44			0.15
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	1.52		$	1.42			$	1.54		$	1.25
Gulf Coast ultra-low sulfur diesel	1.48			1.34				1.52			1.19
Natural gas (per MMBtu)	3.14			2.25				3.10			2.12

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	June 30, 2017			December 31, 2016
	Successor				Predecessor			Predecessor
	(dollars in thousands)
	Period from July 1, 2017 to September 30, 2017				Period from January 1, 2017 to June 30, 2017			Nine Months Ended September 30, 2016
BALANCE SHEET DATA (end of period):
Net sales:
Cash and cash equivalents	$	167,239		$	73,524
Affiliate	$	94,536			$	185,760		$	222,711
Working capital	(37,982		)	(73,563		)
Third party	400,942				880,523			1,076,012
Total assets	787,442			695,637
Net sales	495,478				1,066,283			1,298,723
Total debt	285,996			236,319
Operating costs and expenses:
Total debt less cash and cash equivalents	118,757			162,795
Cost of goods sold	415,386				911,366			1,134,275
Total partners’ equity	114,704			103,503
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

THROUGHPUT AND PRODUCTION DATA:	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
WTS crude	17,680	24.3		25,698	36.1		23,955	31.8		31,126	44.9
WTI crude	52,207	71.7		43,040	60.5		47,568	63.2		35,400	51.0
Blendstocks	2,876	4.0		2,415	3.4		3,722	5.0		2,819	4.1
Total refinery throughput (5)	72,763	100.0		71,153	100.0		75,245	100.0		69,345	100.0
Refinery production:
Gasoline	33,506	46.5		33,744	47.6		36,084	48.2		33,922	49.0
Diesel/jet	27,885	38.7		26,627	37.6		28,375	37.9		24,655	35.6
Asphalt	2,020	2.8		2,572	3.6		2,454	3.3		2,860	4.2
Petrochemicals	3,827	5.3		3,354	4.7		4,176	5.6		3,485	5.0
Other	4,755	6.7		4,569	6.5		3,700	5.0		4,298	6.2
Total refinery production (6)	71,993	100.0		70,866	100.0		74,789	100.0		69,220	100.0
Refinery utilization (7)		99.0	%		94.2	%		99.6	%		93.7	%

(1) Includes sales to related parties of $94,323 and $76,884 for the three months ended and $185,760 and $139,994 for the six months ended June 30, 2017 and 2016, respectively.

(2) Adjusted EBITDA represents earnings before state income tax expense, interest expense and depreciation and amortization. Adjusted EBITDA is not a recognized measurement under GAAP; however, the amounts included in Adjusted EBITDA are derived from amounts included in our consolidated financial statements. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors, and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of state income tax expense, interest expense and the accounting effects of capital expenditures and acquisitions, items that may vary for different companies for reasons unrelated to overall operating performance.

Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:

• Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

• Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;

• Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and

• Our calculation of Adjusted EBITDA may differ from EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.

Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.

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~~The~~Because the following ~~table~~information ~~reconciles~~is ~~net~~not ~~income~~impacted ~~(loss)~~by topush-down ~~Adjusted~~accounting ~~EBITDA~~and ~~for~~other ~~the~~differences ~~three~~related ~~and~~to ~~six~~the ~~months~~Delek/Alon ~~ended~~Merger ~~June 30~~affecting comparability, ~~2017~~the ~~and~~following ~~2016:~~information does not reflect Predecessor/Successor delineation.

	For the Three Months Ended				For the Six Months Ended
PRICING STATISTICS:	For the Three Months Ended				For the Nine Months Ended
	June 30,				June 30,
	September 30,				September 30,
	2017		2016		2017		2016
	(dollars in thousands)
Crack spreads (per barrel):
Net income (loss)	$	21,680	$	1,191	$	41,792	$	(7,371	)
Gulf Coast 3/2/1	$	20.16	$	13.31	16.20		$	12.25
State income tax expense	310		—		566		176
WTI Cushing crude oil (per barrel)	$	48.16	$	44.88	49.31		$	41.40
Interest expense	8,652		9,920		16,497		20,507
Crude oil differentials (per barrel):
Depreciation and amortization	14,462		14,667		28,691		28,873
WTI Cushing less WTI Midland	$	0.79	$	0.31	0.53		$	0.18
Adjusted EBITDA	$	45,127	$	25,778	$	87,569	$	42,185
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

(3) Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales (exclusive of certain inventory adjustments) by the refinery’s throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margin to these crack spreads to assess our operating performance relative to other participants in our industry.



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 ~~for~~is ~~the~~a ~~three~~per ~~and~~barrel ~~six~~measurement ~~months~~calculated ~~ended~~by ~~June 30,~~dividing ~~2017~~the ~~excludes~~margin ~~losses~~between ~~related~~net tosales ~~inventory~~and ~~adjustments~~cost of ~~$(3,106)~~goods ~~and~~sold $(~~1,264~~exclusive of certain inventory adjustments), ~~respectively~~by the refinery’s throughput volumes. ~~Refinery~~Industry-wide ~~operating~~refining ~~margin~~results ~~for~~are driven and measured by the ~~three~~margins between refined product prices and ~~six~~the ~~months~~prices ~~ended~~for ~~June 30~~crude oil, ~~2016~~which ~~excludes~~are ~~gains~~referred ~~related~~to as crack spreads. We compare our refinery operating margin to ~~inventory~~these ~~adjustments~~crack ofspreads ~~$2,519~~to ~~and~~assess ~~$3,465,~~our ~~respectively~~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 (4losses) ~~Refinery~~related ~~direct~~to inventory adjustments of $0 and $1,264, respectively. Refinery operating ~~expense~~margin isfor athe ~~per~~Predecessor ~~barrel~~three- ~~measurement~~and ~~calculated~~nine-month byperiods ~~dividing~~ended ~~direct~~September 30, ~~operating~~2016 ~~expenses~~excludes bygains ~~total~~(losses) ~~throughput~~related ~~volumes~~to inventory adjustments of $1,419 and $2,046, respectively.

(52) ~~Total~~Refinery ~~refinery~~direct ~~throughput~~operating ~~represents~~expense ~~the~~is ~~total~~a ~~barrels~~ per ~~day~~barrel ofmeasurement ~~crude~~calculated ~~and~~by ~~blendstock~~dividing ~~inputs~~direct inoperating ~~the~~expenses ~~refinery~~by ~~production~~total ~~process~~throughput volumes.

(63) Total refinery ~~production~~throughput represents the total barrels per day of ~~various refined products produced from processing~~ crude and ~~other~~blendstock ~~refinery~~inputs ~~blendstocks~~in ~~through~~ the ~~crude~~refinery ~~units~~production ~~and other conversion units~~process.

~~(7)~~ ~~Refinery utilization represents average daily crude throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.~~25

Table of Contents

~~Three~~(4) ~~Months~~Total ~~Ended~~refinery ~~June 30,~~production ~~2017~~represents ~~Compared~~the tobarrels per day of various refined products produced from processing crude and other refinery blendstocks through the ~~Three~~crude ~~Months~~units ~~Ended~~and ~~June 30,~~other ~~2016~~conversion units.

~~Net Sales. Net sales for the three months ended June 30, 2017 were $521.8 million, compared to $468.~~(5) ~~million~~Refinery ~~for~~utilization ~~the~~represents ~~three~~average ~~months~~daily ~~ended~~crude ~~June 30, 2016, an increase of $53.3 million, or 11.4%. This increase was primarily due to higher refined product prices and higher refinery~~ throughput. ~~The~~divided ~~average~~by ~~per~~crude ~~gallon~~oil ~~price of Gulf Coast gasoline for the three months ended June 30~~capacity, ~~2017~~excluding ~~increased~~planned ~~$0.10,~~periods ~~or 7.0%, to $1.52, compared to $1.42 for the three months ended June 30, 2016. The average per gallon price~~ of ~~Gulf~~downtime ~~Coast ultra-low sulfur diesel~~ for ~~the~~maintenance ~~three~~and ~~months ended June 30, 2017 increased $0~~turnarounds.14, or 10.4%, to $1.48, compared to $1.34 for the three months ended June 30, 2016. Refinery average throughput for the three months ended June 30, 2017 was 72,763 bpd, compared to 71,153 bpd for the three months ended June 30, 2016, an increase of 2.3%.

~~Cost of Sales. Cost of sales for the three months ended June 30~~EBITDA, ~~2017~~Adjusted ~~were~~EBITDA ~~$440.9 million, compared to $410.7 million for the three months ended June 30, 2016, an increase of $30.2 million, or 7.4%. This increase was primarily due to increased crude oil prices~~ and ~~higher~~Cash ~~refinery~~Available ~~throughput. The average price of WTI Cushing increased 6.1% to $48.25 per barrel~~ for ~~the three months ended June 30, 2017 from $45.48 per barrel for the three months ended June 30, 2016.~~Distribution

~~Direct~~To ~~Operating~~supplement ~~Expenses. Direct~~our ~~operating~~financial ~~expenses~~information ~~for~~presented ~~the~~in ~~three~~accordance ~~months~~with ~~ended~~United ~~June 30,~~States ~~2017~~generally ~~were~~accepted ~~$27.9~~accounting ~~million~~principles (“GAAP”), ~~compared~~management touses ~~$23.3~~additional ~~million~~measures ~~for~~that ~~the~~are ~~three~~known ~~months~~as ~~ended~~“non-GAAP ~~June 30,~~financial ~~2016,~~measures” anin ~~increase~~its evaluation of ~~$4.6~~past ~~million,~~performance orand 19prospectus for the future.~~7%.~~ ~~This~~The ~~increase~~primary ~~was~~measures ~~primarily~~used ~~due~~by tomanagement ~~higher~~are ~~maintenance~~EBITDA, ~~expenses~~Adjusted EBITDA and ~~increased~~cash ~~natural~~available ~~gas~~for ~~costs~~distribution.

~~Selling~~EBITDA and Adjusted EBITDA represent earnings before income tax expense, ~~General~~interest expense, depreciation and ~~Administrative~~amortization ~~Expenses~~and in the case of Adjusted EBITDA, the inventory fair value adjustment. ~~SG&A~~ ~~expenses~~Neither ~~for~~EBITDA nor Adjusted EBITDA is a recognized measurement under GAAP; however, the ~~three~~amounts ~~months~~included ~~ended~~in ~~June 30~~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, ~~2017~~investors, ~~were~~and $7other interested parties in the evaluation of companies in our industry.4 ~~million~~In addition, our management believes that EBITDA and Adjusted EBITDA are useful in evaluating our operating performance compared to ~~$8.8~~that ~~million~~of ~~for~~other companies in our industry because the ~~three~~calculation ~~months~~of ~~ended~~EBITDA ~~June 30,~~and ~~2016~~Adjusted EBITDA generally eliminates the effects of income tax expense, ainterest ~~decrease~~expense and the accounting effects of ~~$1.4~~capital ~~million~~expenditures and acquisitions, oritems ~~15.9%.~~that ~~This~~may ~~decrease~~vary ~~was~~for ~~primarily~~different ~~due~~companies for reasons unrelated to ~~lower~~overall ~~corporate~~operating ~~allocations~~performance.

~~Depreciation~~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 ~~Amortization. Depreciation~~other contractual obligations, and ~~amortization~~reserves for future operating or capital needs that the ~~three~~board ~~months~~of ~~ended~~directors ~~June 30,~~of ~~2017~~our ~~was~~general ~~$14.5~~partner ~~million,~~deems ~~compared~~necessary toor ~~$14.7~~appropriate, ~~million~~including reserves for our expenses in the ~~three~~quarters ~~months~~in ~~ended~~which ~~June 30,~~our ~~2016,~~planned aturnarounds ~~decrease~~and ofcatalyst ~~$0.2~~replacement ~~million,~~occur orand 1special reserves for cost increase in capital expenditures associated with the consent decree.~~4%.~~

~~Operating~~Our ~~Income. Operating~~management ~~income~~believes ~~for~~that the ~~three~~presentation ~~months~~of ~~ended~~cash ~~June 30,~~available ~~2017~~for ~~was~~distribution ~~$31.1~~is ~~million,~~useful ~~compared~~ to ~~$11.0~~investors ~~million~~because ~~for~~it ~~the~~is ~~three~~frequently ~~months~~used ~~ended~~by ~~June 30~~securities analysts, ~~2016~~investors, anand ~~increase~~other ofinterested ~~$20.1~~parties ~~million.~~in ~~This~~the ~~increase~~evaluation ~~was~~of ~~primarily~~companies ~~due~~in toour ~~higher refinery operating margin and higher refinery throughput~~industry. ~~Refinery~~In ~~operating margin was $12.68 per barrel for the three months ended June 30~~addition, ~~2017,~~our ~~compared~~management tobelieves ~~$8.53~~that ~~per~~cash ~~barrel~~available for ~~the~~distribution ~~three~~is ~~months~~useful ~~ended June 30, 2016. This increase~~ in ~~operating~~evaluating ~~margin~~our ~~was~~ability ~~primarily due~~ to agenerate ~~higher~~sufficient ~~Gulf~~cash ~~Coast~~flow ~~3/2/1 crack spread, a widening of both the WTI Cushing~~ to ~~WTI~~make ~~Midland~~distributions ~~and WTI Cushing~~ to ~~WTS~~our ~~spreads and a stronger wholesale marketing environment, partially offset by a reduced benefit from the contango market environment which increased the cost of crude~~unitholders.

~~The~~We ~~average~~believe ~~Gulf~~that ~~Coast~~the ~~3/2/1~~presentation ~~crack~~of ~~spread~~EBITDA, ~~was~~Adjusted ~~$15.07~~EBITDA ~~per~~and ~~barrel~~cash available for ~~the~~distribution ~~three~~provides ~~months~~useful ~~ended~~information ~~June 30, 2017, compared~~ to ~~$13.16~~investors ~~per~~in ~~barrel~~assessing ~~for~~our ~~the~~financial ~~three~~condition ~~months~~and ~~ended~~results ~~June 30,~~of ~~2016~~operations. EBITDA, ~~The~~Adjusted ~~average~~EBITDA ~~WTI~~and ~~Cushing~~cash toavailable ~~WTI~~for ~~Midland~~distribution ~~spread~~should ~~was~~not ~~$0.84~~be ~~per~~considered ~~barrel~~alternatives ~~for~~to ~~the~~net ~~three~~income, ~~months~~operating ~~ended June 30~~income, ~~2017,~~cash ~~compared~~flow tofrom ~~$0.17~~operating ~~per~~activities ~~barrel~~or ~~for~~any ~~the~~other ~~three~~measure ~~months~~of ~~ended~~financial ~~June 30,~~performance ~~2016.~~or ~~The~~liquidity ~~average~~presented ~~WTI~~in ~~Cushing~~accordance towith ~~WTS~~U.S. ~~spread~~GAAP. EBITDA, ~~was~~Adjusted ~~$1.24~~EBITDA ~~per~~and ~~barrel~~cash available for ~~the~~distribution ~~three~~have ~~months~~important ~~ended~~limitations ~~June 30,~~as ~~2017,~~analytical ~~compared~~tools tobecause ~~$0.75~~they ~~per~~exclude ~~barrel~~some ~~for~~but ~~the~~not ~~three~~all ~~months~~items ~~ended~~that ~~June 30,~~affect ~~2016.~~net ~~The~~income ~~average~~and ~~Brent~~net tocash ~~WTI~~provided ~~Cushing~~by ~~spread~~operating ~~was $1~~activities.21 Additionally, ~~per~~because ~~barrel~~EBITDA, ~~for~~Adjusted ~~the~~EBITDA ~~three~~and ~~months~~cash ~~ended~~available ~~June 30,~~for ~~2017,~~distribution may ~~compared~~be todefined ~~$(0.18)~~differently ~~per~~by ~~barrel~~other ~~for~~companies ~~the~~in ~~three~~our ~~months~~industry, ~~ended~~our ~~June 30~~definition of EBITDA, ~~2016.~~Adjusted ~~The~~EBITDA ~~contango~~and ~~environment~~cash available for ~~the~~distribution ~~three~~may ~~months~~not ~~ended~~be ~~June 30,~~comparable ~~2017~~to ~~created~~similarly antitled ~~average~~measures ~~cost~~ of ~~crude~~other ~~benefit~~companies, ofthereby ~~$0.55~~diminishing ~~per~~its ~~barrel,~~utility. Because ~~compared~~of tothese anlimitations, ~~average~~EBITDA, Adjusted ~~cost~~EBITDA ofand ~~crude~~cash ~~benefit~~available offor ~~$1.49~~distribution ~~per~~should ~~barrel~~not ~~for~~be ~~the~~considered ~~three~~a ~~months~~measure ~~ended~~of ~~June 30,~~discretionary ~~2016.~~cash ~~The~~available ~~average~~to ~~RINs~~us ~~cost~~to ~~effect~~invest onin ~~refinery~~the ~~operating~~growth ~~margin~~of ~~was~~our $0business.34 ~~per~~We ~~barrel~~compensate for ~~the~~these ~~three~~limitations ~~months~~by ~~ended~~relying ~~June 30,~~primarily ~~2017,~~on ~~compared~~our toGAAP ~~$0.32~~results ~~per~~and ~~barrel~~using ~~for~~EBITDA, ~~the~~Adjusted ~~three~~EBITDA ~~months~~and ~~ended~~cash ~~June 30,~~available ~~2016~~for distribution only supplementally.

~~Interest~~ Expense. Interest expense for the three months ended June 30, 2017 was $8.7 million, compared to $9.9 million for the three months ended June 30, 2016, a decrease of $1.2 million, or 12.1%. This decrease was primarily due to lower finance fees associated with our supply and offtake agreements.26

State Income Tax Expense. State income tax expense was $0.3 million for the three months ended June 30, 2017, compared to $0.0 million for the three months ended June 30, 2016, an increase of $0.3 million.

Net Income. Net income for the three months ended June 30, 2017 was $21.7 million, compared to $1.2 million for the three months ended June 30, 2016, an increase of $20.5 million. This increase was attributable to the factors discussed above.

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~~Six~~The ~~Months~~following ~~Ended~~table ~~June 30~~reconciles net income (loss), ~~2017~~as ~~Compared~~determined under GAAP, to ~~the~~Adjusted ~~Six~~EBITDA ~~Months~~and ~~Ended~~cash ~~June 30,~~available ~~2016~~for distribution:

Net Sales. Net sales for the six months ended June 30, 2017 were $1,066.3 million, compared to $836.5 million for the six months ended June 30, 2016, an increase of $229.8 million, or 27.5%. This increase was primarily due to higher refined product prices and higher refinery throughput. The average per gallon price of Gulf Coast gasoline for the six months ended June 30, 2017 increased $0.29, or 23.2%, to $1.54, compared to $1.25 for the six months ended June 30, 2016. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the six months ended June 30, 2017 increased $0.33, or 27.7%, to $1.52, compared to $1.19 for the six months ended June 30, 2016. Refinery average throughput for the six months ended June 30, 2017 was 75,245 bpd compared to 69,345 bpd for the six months ended June 30, 2016, an increase of 8.5%. Refinery throughput for the first half of 2017 was affected by maintenance on the FCCU. The reduced throughput during the six months ended June 30, 2016 was primarily the result of planned downtime to complete a reformer regeneration and catalyst replacement for our diesel hydrotreater unit in the first quarter of 2016, as well as unplanned downtime during the second quarter of 2016 due to a power outage caused by inclement weather, which affected multiple units.



	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

~~Cost~~ of Sales. Cost of sales for the six months ended June 30, 2017 were $911.4 million, compared to $730.1 million for the six months ended June 30, 2016, an increase of $181.3 million, or 24.8%. This increase was primarily due to increased crude oil prices and higher refinery throughput. The average price of WTI Cushing increased 26.9% to $50.00 per barrel for the six months ended June 30, 2017 from $39.39 per barrel for the six months ended June 30, 2016.27

Direct Operating Expenses. Direct operating expenses for the six months ended June 30, 2017 were $52.6 million, compared to $48.3 million for the six months ended June 30, 2016, an increase of $4.3 million, or 8.9%. This increase was primarily due to higher natural gas costs.

Selling, General and Administrative Expenses. SG&A expenses for the six months ended June 30, 2017 were $14.2 million, compared to $16.1 million for the six months ended June 30, 2016, a decrease of $1.9 million, or 11.8%. This decrease was primarily due to lower corporate allocations.

Depreciation and Amortization. Depreciation and amortization for the six months ended June 30, 2017 was $28.7 million, compared to $28.9 million for the six months ended June 30, 2016, a decrease of $0.2 million, or 0.7%.

Operating Income. Operating income for the six months ended June 30, 2017 was $59.4 million, compared to $13.1 million for the six months ended June 30, 2016, an increase of $46.3 million. This increase was primarily due to higher refinery throughput and higher refinery operating margin. Refinery operating margin for the six months ended June 30, 2017 was $11.47 per barrel, compared to $8.16 per barrel for the six months ended June 30, 2016. This increase in operating margin was primarily due to a higher Gulf Coast 3/2/1 crack spread and a widening of both the WTI Cushing to WTI Midland and WTI Cushing to WTS spreads, partially offset by increased RINs costs and a reduced benefit from the contango market environment which increased the cost of crude.

The average Gulf Coast 3/2/1 crack spread was $14.41 per barrel for the six months ended June 30, 2017, compared to $12.20 per barrel for the six months ended June 30, 2016. The average WTI Cushing to WTI Midland spread was $0.11 per barrel for the six months ended June 30, 2017, compared to $0.02 per barrel for the six months ended June 30, 2016. The average WTI Cushing to WTS spread was $1.26 per barrel for the six months ended June 30, 2017, compared to $0.32 per barrel for the six months ended June 30, 2016. The average Brent to WTI Cushing spread was $1.44 per barrel for the six months ended June 30, 2017 compared to $0.15 per barrel for the six months ended June 30, 2016. The contango environment for the six months ended June 30, 2017 created an average cost of crude benefit of $0.77 per barrel, compared to an average cost of crude benefit of $1.66 per barrel for the six months ended June 30, 2016. The average RINs cost effect on refinery operating margin was $0.47 per barrel for the six months ended June 30, 2017, compared to $0.23 per barrel for the six months ended June 30, 2016.

Interest Expense. Interest expense for the six months ended June 30, 2017 was $16.5 million, compared to $20.5 million for the six months ended June 30, 2016, a decrease of $4.0 million, or 19.5%. This decrease was primarily due to lower finance fees associated with our supply and offtake agreements.

State Income Tax Expense. State income tax expense for the six months ended June 30, 2017 was $0.6 million, compared to $0.2 million for the six months ended June 30, 2016.

Net Income (Loss). Net income for the six months ended June 30, 2017 was $41.8 million, compared to net loss of $(7.4) million for the six months ended June 30, 2016, an increase of $49.2 million. This increase was attributable to the factors discussed above.

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	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 ~~a $60.0 million~~ letter of credit ~~facility~~facilities through ~~Alon~~Delek ~~Energy~~ for our crude and product purchases.

We have an agreement with J. Aron for the supply of crude oil that supports the operations of the Big Spring refinery. ~~This~~In Predecessor periods, this arrangement substantially ~~reduces~~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 ~~six~~nine months ended ~~June~~September 30, 2017 and 2016:

	For the Six Months Ended
	For the Nine Months Ended
	June 30,
	September 30,
	2017			2016
	(dollars in thousands)
Cash provided by (used in):
Operating activities	$171,719	~~77,145~~		$58,457	~~46,587~~
Investing activities	(1330,~~191~~929		)	(2026,~~924~~878		)
Financing activities	2954,~~761~~258			339,~~204~~231
Net increase in cash and cash equivalents	$	93195,~~715~~048		$	2870,~~867~~810

Cash Flows Provided by Operating Activities

Net cash provided by operating activities was $~~77.1~~171,719 ~~million~~ during the ~~six~~nine months ended ~~June~~September 30, 2017 compared to $~~46.6~~58,457 ~~million~~ during the ~~six~~nine months ended ~~June~~September 30, 2016. The increase in net cash provided by operating activities of $~~30.5~~113,262 ~~million~~ was primarily due to the following: increased net income ~~after~~(adjusted ~~adjusting~~ for certain non-cash items) of $~~48.9~~68,752 ~~million~~combined ~~and~~with increased cash provided by inventories of $~~21.5 million~~20,818, ~~partially~~increased ~~offset by reduced~~ cash collected on accounts receivable of $~~5.1 million~~14, ~~increased cash used for other assets of $4.6 million~~324, increased cash ~~used~~provided ~~for~~by accounts ~~payable~~receivable/payables ~~and~~with ~~accrued~~related ~~liabilities~~parties of $~~15.2 million~~77,025, ~~reduced~~and ~~cash~~partially ~~provided~~offset by an ~~other~~increase ~~non-current~~in ~~liabilities of $13.7 million and increased~~ cash used ~~for~~to ~~prepaid~~pay ~~expenses~~accounts payable and ~~other~~settle ~~current~~accrued ~~assets~~liabilities of $169,727.~~3 million.~~

Cash Flows Used in Investing Activities

Net cash used in investing activities was $~~13.2~~30,929 ~~million~~ during the ~~six~~nine months ended ~~June~~ September 30, 2017 compared to $~~20.9~~26,878 ~~million~~ during the ~~six~~nine months ended ~~June~~September 30, 2016. The ~~decrease~~increase in net cash used in investing activities of $~~7.7~~4,051 ~~million~~ was primarily due to ~~completing~~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 $~~29.8~~54,258 ~~million~~ during the ~~six~~nine months ended ~~June~~September 30, 2017 compared to $~~3.2~~39,231 ~~million~~ during the ~~six~~nine months ended ~~June~~September 30, 2016. The ~~change~~increase in net cash provided by financing activities of $~~26.6~~15,027 ~~million~~ was primarily due to increased cash from net borrowings on our credit facility of $~~50.0~~100,000 ~~million~~ and ~~increased~~decreased cash received from RINs financing transactions of $~~2.2 million~~43,211, partially offset by increased distributions to unitholders of $2538,769.~~6 million.~~

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Cash Position and Indebtedness

~~Revolving~~As ~~Credit~~of ~~Facility.~~September 30, We2017, ~~have~~our acash ~~$240.0~~and ~~million~~cash ~~revolving~~equivalents ~~credit~~were ~~facility~~$268,572 ~~that can be used both for borrowings~~ and ~~the~~we ~~issuance~~had oftotal ~~letters~~indebtedness of ~~credit.~~approximately ~~At June 30, 2017 there were~~ $50338,125.0 Total ~~million~~unused ~~outstanding~~credit ~~borrowings~~commitments ~~under~~or ~~this~~borrowing ~~facility~~base availability, ~~compared~~as ~~to no borrowings at December 31~~applicable, ~~2016.~~under Atour ~~June 30,~~credit ~~2017~~facilities ~~and~~was ~~December 31,~~approximately ~~2016~~$125,602 and we had letters of credit ~~outstanding~~issued of approximately $4814,398.7 We ~~million~~believe ~~and~~we ~~$100.6~~were ~~million~~in compliance with our covenants in all debt facilities as of September 30, ~~respectively~~2017.

Capital Spending

~~Each~~The ~~year~~nature ~~the board~~ of ~~directors~~capital ofexpenditures ~~our~~is ~~General~~not ~~Partner~~impacted ~~approves~~by ~~capital~~the ~~projects,~~differences ~~including~~in ~~sustaining~~the ~~maintenance,~~Successor ~~regulatory~~ and ~~planned~~Predecessor ~~turnaround~~basis and ~~catalyst~~accounting ~~projects that our management is authorized to undertake in our annual capital budget~~policies. ~~Additionally~~Therefore, ~~our~~we ~~management~~have ~~assesses~~not ~~opportunities~~delineated ~~for~~between ~~growth~~Successor and ~~profit~~Predecessor ~~improvement~~periods ~~projects~~in onthe anfollowing ~~ongoing~~discussion. ~~basis~~The ~~and~~following ~~any~~table ~~related~~summarizes ~~projects require further approval from the board of directors of~~ our ~~General~~actual ~~Partner. Our total~~ capital ~~expenditure plan for 2017 is $64.3 million, which includes~~ expenditures for ~~catalysts~~the ~~and~~three ~~turnarounds of $11.1 million, growth~~ and ~~profit~~nine ~~improvement projects of $10.0 million and sustaining and regulatory projects of $42.9 million. Approximately $13.2 million has been spent during the six~~ months ended ~~June~~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 NoNote ~~significant~~1 ~~changes~~for toadditional ~~these~~information on our critical accounting policies, ~~have~~including ~~occurred~~conforming ~~subsequent~~changes tobetween ~~December 31,~~the ~~2016~~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, ~~if any,~~ 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

~~Changes~~These disclosures should be read in ~~commodity~~conjunction ~~prices,~~with ~~purchased~~the ~~fuel~~condensed ~~prices~~consolidated financial statements, "Management's Discussion and ~~interest~~Analysis ~~rates~~of ~~are~~Financial ~~our~~Condition ~~primary~~and ~~sources~~Results of ~~market~~Operations," ~~risk.~~and ~~Alon~~other ~~Energy’s~~information ~~risk~~presented ~~management~~herein ~~committee~~as ~~oversees~~well ~~all~~as ~~activities~~in ~~associated~~the ~~with~~"Quantitative ~~the~~and ~~identification,~~Qualitative ~~assessment~~Disclosures ~~and~~About ~~management~~Market ofRisk" section contained in our ~~market~~Annual ~~risk~~Report ~~exposure~~on Form 10-K.

~~Commodity~~Changes ~~Price~~in ~~Risk~~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.

WePrice ~~are~~Risk ~~exposed~~Management to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refinery operations. Our financial results can be affected significantly by fluctuations in these prices, which depend on many factors, including demand for crude oil, gasoline and other refined products, changes in the economy, worldwide production levels, worldwide inventory levels and governmental regulatory initiatives. Alon Energy’s risk management strategy identifies circumstances in which we may utilize the commodity futures market to manage risk associated with these price fluctuations.Activities

InAt ~~order~~times, we enter into commodity derivative contracts to manage ~~the~~our ~~uncertainty~~price ~~relating~~exposure to our inventory ~~price volatility~~positions, wefuture ~~have~~purchases ~~consistently~~of ~~applied~~crude aoil, ~~policy~~blendstock, future sales of ~~maintaining~~refined ~~inventories~~products ator to fix margins on future production. We also enter into future commitments to purchase or ~~below~~sell aRINs ~~targeted~~at ~~operating~~fixed ~~level~~prices and quantities, which are used to manage the costs associated with our RINs obligations. These Infuture RIN commitments meet the ~~past,~~definition ~~circumstances~~of ~~have~~derivative ~~occurred~~instruments under ASC 815, ~~such~~Derivatives asand ~~timing~~Hedging of("ASC ~~crude~~815"). In ~~oil~~accordance ~~cargo~~with ~~deliveries~~ASC 815, ~~turnaround~~all ~~schedules~~of orthese ~~shifts~~commodity incontracts ~~market~~and ~~demand~~future ~~that~~purchase ~~have~~commitments ~~resulted~~are recorded at fair value, and any change in ~~variances~~fair value between ~~our~~periods ~~actual~~has ~~inventory~~historically ~~level~~been recorded in the profit and loss section of our ~~desired~~condensed ~~target~~consolidated ~~level~~financial statements. Occasionally, ~~Upon~~at inception, the ~~review~~company ~~and~~will ~~approval~~elect ofto ~~Alon~~designate ~~Energy’s~~the ~~risk~~commodity ~~management~~derivative ~~committee,~~contracts weas ~~may~~cash ~~utilize~~flow ~~the~~hedges under ASC 815. Gains or losses on commodity ~~futures~~derivative ~~market~~contracts toaccounted ~~manage~~for ~~these~~as ~~anticipated~~cash ~~inventory~~flow ~~variances~~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 ~~maintain~~are ~~inventories~~exposed ofto ~~crude~~market ~~oil,~~risks ~~refined~~related ~~products~~to ~~and blendstocks,~~ the ~~values~~volatility of ~~which~~crude ~~are~~oil ~~subject~~and torefined ~~wide~~product ~~fluctuations~~prices, as well as volatility in ~~market~~the ~~prices~~price ~~driven~~of bynatural ~~world~~gas ~~economic~~used ~~conditions,~~in ~~regional~~our ~~and~~refinery ~~global~~operations. ~~inventory~~Our ~~levels~~financial ~~and~~results ~~seasonal~~can ~~conditions.~~be Ataffected ~~June 30,~~significantly ~~2017,~~by ~~the~~fluctuations ~~market~~in ~~value~~these ofprices, ~~refined~~which ~~products~~depend ~~and~~on ~~blendstock~~many ~~inventories~~factors, ~~was~~including ~~less~~demand ~~than~~for ~~inventories~~crude onoil, agasoline ~~LIFO~~and ~~cost~~other ~~basis~~refined ~~which~~products, ~~resulted~~changes in ~~recording~~the aeconomy, ~~lower~~worldwide ofproduction ~~cost~~levels, orworldwide ~~market~~inventory ~~reserve~~levels ofand ~~$7.5~~governmental ~~million~~regulatory initiatives. AtDelek’s ~~June 30,~~risk ~~2017,~~management ~~the~~strategy ~~market~~identifies ~~value~~circumstances ofin ~~crude~~which ~~oil~~we ~~inventories~~may ~~exceeded~~utilize ~~LIFO~~the ~~costs,~~commodity ~~net~~futures ofmarket ~~the~~to ~~fair~~manage ~~value~~risk ~~hedged~~associated ~~item,~~with bythese ~~$2.9~~price ~~million~~fluctuations.

AsIn oforder ~~June 30,~~to ~~2017,~~manage wethe ~~held~~uncertainty ~~0.3~~relating ~~million~~to ~~barrels~~inventory ofprice ~~refined~~volatility, ~~products~~we ~~and~~have ~~blendstock~~consistently ~~and~~applied ~~0.2~~a ~~million~~policy ~~barrels~~ of ~~crude~~maintaining ~~oil~~ inventories ~~valued~~at ~~under~~or ~~the~~below ~~LIFO~~a ~~valuation~~targeted ~~method~~operating level. IfIn the ~~market~~past, ~~value~~circumstances ofhave ~~refined~~occurred, ~~products~~such ~~and~~as ~~blendstock~~timing ~~inventories~~of ~~would~~crude ~~have~~oil ~~been~~cargo ~~$1.00 per barrel lower~~deliveries, ~~the~~turnaround ~~lower~~schedules ofor ~~cost~~shifts orin market ~~adjustment~~demand ~~recorded~~that ~~for the six months ended June 30, 2017 would~~ have ~~been~~resulted ~~$0.3~~in ~~million~~variances ~~higher.~~between Ifour ~~the~~actual ~~market~~inventory ~~value~~level ofand ~~crude~~our ~~oil~~desired ~~would~~target ~~have been $1~~level.00 ~~per~~Upon ~~barrel lower,~~ the ~~market~~review ~~value~~and ofapproval ~~crude~~by ~~oil~~management, ~~inventories~~we ~~would~~may ~~have~~utilize ~~exceeded~~the ~~LIFO~~commodity ~~costs,~~futures ~~net~~market ofto ~~the~~manage ~~fair~~these ~~value~~anticipated ~~hedged~~inventory ~~item, by $2~~variances.~~7 million.~~

All commodity derivative contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section of our consolidated financial statements. “Forwards” represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period. “Futures” represent trades which have been executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period. A “long” represents an obligation to purchase product and a “short” represents an obligation to sell product.

The following table ~~provides~~sets forth information ~~about~~relating to our open commodity derivative contracts as of ~~June~~September 30, 2017:

Description	Contract Volume			Wtd Avg Purchase		Wtd Avg Sales			Contract			Market			Gain
	Total Outstanding					Notional Contract Volume by Year of Maturity
of Activity	(barrels)			Price/BBL		Price/BBL			Value			Value			(Loss)
Contract Description	Fair Value				Notional Contract Volume	2017		2018			2019
									(in thousands)
Contracts not designated as hedging instruments:
Forwards-short (Crude)	(186,716	)		$	—	$	45.20		$	(8,439	)	$	(8,675	)	$	(236	)
Commodity contracts (futures) - long(1)	$	(8	)		11	11		—			—
Forwards-long (Gasoline)	63,926			60.98		—			3,898			3,984			86
Commodity contracts (futures) - short(1)	121				421	421		—			—
Forwards-short (Distillate)	(156,892	)		—		61.11			(9,588		)	(10,234		)	(646		)
RIN commitment contracts - long(2)	(34,771		)		185,716	185,716		—			—
Forwards-long (Jet)	8,101			56.98		—			462			485			23
RIN commitment contracts - short(2)	28,157				134,500	134,500		—			—
Forwards-long (Slurry)	1,039			39.11		—			41			45			4
Total	$	(6,501	)		320,648	320,648		—			—
Forwards-long (Catfeed)	198,036			56.02		—			11,094			11,524			430
Forwards-long (Slop)	6,615			35.20		—			233			240			7
Forwards-short (Propane)	(35,000	)		—		23.66			(828		)	(873		)	(45		)
Forwards-long (Butane)	22,755			29.67		—			675			701			26
Futures-long (Crude)	150,000			45.72		—			6,858			6,906			48
Futures-short (Gasoline)	(230,000	)		—		61.60			(14,169		)	(14,623		)	(454		)
Futures-long (Distillate)	94,000			61.27		—			5,760			5,855			95

(1)Volume 25in thousands of barrels

(2)Volume in thousands of RINs

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Interest ~~Rate~~ Risk Management Activities

We have market exposure to changes in interest rates relating to our outstanding floating rate borrowings. As of ~~June~~September 30, 2017, our outstanding debt balance of $~~288.8 million~~338,125, excluding discounts and ~~debt~~ issuance costs, was subject to floating interest rates~~, of which $50~~.~~0 million was charged interest at the Eurodollar rate plus 3.00% and $238.8 million was charged interest at the Eurodollar rate (with a floor of 1.25%) plus a margin of 8.00%.~~

An ~~increase~~The annualized impact of 1%a inhypothetical ~~the~~one ~~Eurodollar~~percent ~~rate~~change in interest rates on our ~~indebtedness~~floating ~~would~~rate ~~result~~debt inoutstanding anas ~~increase~~of inSeptember 30, ~~our~~2017 would be to change interest expense ofby approximately $23,400.~~7 million per year.~~

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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 ~~June~~ 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

~~There~~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 ~~June~~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.
31.1*		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.
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.
32.1**		Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
101		The following financial information from Alon USA Partners, LP’s Quarterly Report on Form 10-Q for the quarter ended ~~June~~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 28herewith.

** Furnished herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		Alon USA Partners, LP
		By:	Alon USA Partners GP, LLC
			its general partner
Date:	~~August~~November 19, 2017	By:	/s/ ~~David~~Frederec ~~Wiessman~~Green
			David Wiessman
			Frederec Green
			Executive Chairman of the Board
			Executive Vice President and Chief Executive Officer of Alon USA Partners GP, LLC
Date:	August 1, 2017	By:	/s/ Alan Moret
			Alan Moret
			Chief Executive Officer
			(Principal Executive Officer)
Date:	~~August~~November 19, 2017	By:	/s/ ~~Shai~~Kevin ~~Even~~Kremke
			Shai Even
			Kevin Kremke
			President and Chief Financial Officer
			Executive Vice President, Chief Financial Officer and Secretary of Alon USA Partners GP, LLC
			(Principal Accounting Officer)

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