Alon USA Partners (ALDW) 10-Q 2013 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

___________________________________________________

FORM 10-Q

þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2013

OR

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE TRANSITION PERIOD FROM __________TO __________

Commission file number: 001-35742

ALON USA PARTNERS, LP

(Exact name of Registrant as specified in its charter)

___________________________________________________

Delaware	46-0810241
(State of incorporation)	(I.R.S. Employer
	Identification No.)

12700 Park Central Dr., Suite 1600, Dallas, Texas 75251

(Address of principal executive offices) (Zip Code)

(972) 367-3600

(Registrant’s telephone number, including area code)

___________________________________________________

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes  þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:

Large accelerated filer o Accelerated filer o Non-accelerated filer þ Smaller reporting company o

Indicate by check whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The number of the Registrant’s common limited partner units outstanding as of November 1, 2013, was 62,502,467.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION	1
ITEM 1. FINANCIAL STATEMENTS	1
CONSOLIDATED BALANCE SHEETS	1
CONSOLIDATED STATEMENTS OF OPERATIONS	2
CONSOLIDATED STATEMENTS OF CASH FLOWS	3
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	4
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	12
FORWARD-LOOKING STATEMENTS	12
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	23
ITEM 4. CONTROLS AND PROCEDURES	24
PART II. OTHER INFORMATION	25
ITEM 6. EXHIBITS	25
SIGNATURES	26
EXHIBITS	27
EX-31.1 CERTIFICATION OF CEO PURSUANT TO SECTION 302
EX-31.2 CERTIFICATION OF CFO PURSUANT TO SECTION 302
EX-32.1 CERTIFICATION OF CEO AND CFO PURSUANT TO SECTION 906

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALON USA PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	September 30, 2013		December 31, 2012
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	60,476	$	66,001
Accounts and other receivables, net	98,600		104,119
Accounts and other receivables, net - related parties	14,612		14,519
Inventories	76,199		57,034
Prepaid expenses and other current assets	7,642		6,868
Total current assets	257,529		248,541
Property, plant and equipment, net	472,859		483,061
Other assets, net	28,311		31,821
Total assets	$	758,699	$	763,423
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	207,795	$	202,121
Accrued liabilities	47,753		42,218
Current portion of long-term debt	2,500		2,500
Total current liabilities	258,048		246,839
Other non-current liabilities	46,389		42,047
Long-term debt	322,316		292,811
Total liabilities	626,753		581,697
Commitments and Contingencies (Note 11)
Partners’ equity:
General Partner	—		—
Common unitholders - Public (11,502,467 and 11,500,000 units issued and outstanding at September 30, 2013 and December 31, 2012, respectively)	24,274		33,438
Common unitholders - Alon Energy (51,000,000 units issued and outstanding at September 30, 2013 and December 31, 2012, respectively)	107,672		148,288
Total partners’ equity	131,946		181,726
Total liabilities and partners' equity	$	758,699	$	763,423

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

1

ALON USA PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, dollars in thousands except per unit data)

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
				Predecessor						Predecessor
Net sales (1)	$	881,902		$	943,148		$	2,551,763		$	2,651,191
Operating costs and expenses:
Cost of sales	844,423			765,538			2,261,948			2,225,702
Direct operating expenses	26,281			25,480			84,017			73,223
Selling, general and administrative expenses	4,134			10,316			16,864			18,070
Depreciation and amortization	10,975			11,573			34,282			34,963
Total operating costs and expenses	885,813			812,907			2,397,111			2,351,958
Loss on disposition of assets	(21		)	—			(21		)	—
Operating income (loss)	(3,932		)	130,241			154,631			299,233
Interest expense	(12,127		)	(4,313		)	(30,489		)	(15,070		)
Interest expense - related parties	—			(4,457		)	—			(12,990		)
Other income (loss), net	—			(6		)	18			11
Income (loss) before state income tax expense	(16,059		)	121,465			124,160			271,184
State income tax expense	61			1,098			1,434			2,518
Net income (loss)	$	(16,120	)	$	120,367		$	122,726		$	268,666
Earnings (loss) per unit	$	(0.26	)				$	1.96
Weighted average common units outstanding (in thousands)	62,502						62,502

___________

(1) Includes sales to related parties of $164,338 and $151,682 for the three months and $462,280 and $450,416 for the nine months ended September 30, 2013 and 2012, respectively.

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

2

ALON USA PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited, dollars in thousands)
	For the Nine Months Ended
	September 30,
	2013			2012
				Predecessor
Cash flows from operating activities:
Net income	$	122,726		$	268,666
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	34,282			34,963
Loss on disposition of assets	21			—
Non-cash interest on subordinated debt - related parties	—			12,990
Amortization of debt issuance costs	1,488			1,455
Amortization of original issuance discount	380			—
Changes in operating assets and liabilities:
Accounts and other receivables, net	5,519			(14,282		)
Accounts and other receivables, net - related parties	(93		)	(1,930		)
Inventories	(19,165		)	(25,610		)
Prepaid expenses and other current assets	(774		)	(1,082		)
Other assets	(216		)	(1,058		)
Accounts payable	5,674			82,510
Accrued liabilities	5,535			381
Other non-current liabilities	4,342			6,613
Net cash provided by operating activities	159,719			363,616
Cash flows from investing activities:
Capital expenditures	(16,634		)	(17,328		)
Capital expenditures for turnarounds and catalysts	(5,024		)	(8,127		)
Net cash used in investing activities	(21,658		)	(25,455		)
Cash flows from financing activities:
Distributions paid to unitholders	(31,746		)	—
Distributions paid to unitholders - Alon Energy	(140,760		)	—
Net cash payments to partner - Alon Energy	—			(326,120		)
Deferred debt issuance costs	(205		)	(2,572		)
Revolving credit facility, net	31,000			(116,000		)
Payments on long-term debt	(1,875		)	—
Net cash used in financing activities	(143,586		)	(444,692		)
Net decrease in cash and cash equivalents	(5,525		)	(106,531		)
Cash and cash equivalents, beginning of period	66,001			135,945
Cash and cash equivalents, end of period	$	60,476		$	29,414
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$	29,538		$	14,188
Cash paid for income tax	$	1,434		$	2,597

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

3

ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited, dollars in thousands except as noted)

(1) Basis of Presentation

As used in this report, the terms "Alon" or the "Partnership" refer to Alon USA Partners, LP, one or more of its consolidated subsidiaries or all of them taken as a whole. References in this report to "Alon Energy" refer collectively to Alon USA Energy, Inc. and any of its subsidiaries other than Alon USA Partners, LP, its subsidiaries and its general partner. The information presented in this Quarterly Report on Form 10-Q contains the unaudited combined financial results of Alon USA Partners, LP Predecessor ("Predecessor"), our predecessor for accounting purposes, for the three and nine months ended September 30, 2012. The unaudited consolidated financial results for the three and nine months ended September 30, 2013 include the results of operations for the Partnership. The balance sheets as of September 30, 2013 and December 31, 2012 present solely the consolidated financial position of the Partnership.

Alon is a Delaware limited partnership formed in August 2012 by Alon Energy and its wholly-owned subsidiary Alon USA Partners GP, LLC (the "General Partner"). On November 26, 2012, the Partnership completed its initial public offering (the "Offering") of 11,500,000 common units representing limited partner interests.

After completion of the Offering, Alon Energy contributed to the Partnership its equity interests in Alon USA, LP and Alon USA Refining, Inc. Prior to completion of the Offering, the assets, liabilities and results of operations of the aforementioned assets related to our Predecessor.

These consolidated financial statements and notes are unaudited and have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements.

In the opinion of the General Partner’s management, the information included in these consolidated financial statements reflects all adjustments, consisting of normal and recurring adjustments, which are necessary for a fair presentation of Alon’s 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. The results of operations for the interim periods are not necessarily indicative of the operating results that may be obtained for the year ending December 31, 2013.

The consolidated balance sheet as of December 31, 2012 has been derived from the audited financial statements as of that date. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in Alon’s Annual Report on Form 10-K for the year ended December 31, 2012.

New Accounting Standards

Effective January 1, 2013, Alon adopted Accounting Standards Update (“ASU”) No. 2011- 11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities and ASU No. 2013- 01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities issued by the Financial Accounting Standards Board (“FASB”). These updates require an entity to disclose both gross information and net information of recognized derivative instruments, repurchase agreements and securities borrowing and lending transactions offset in the consolidated balance sheet. The updated guidance was applied retrospectively, effective January 1, 2013. The adoption concerns disclosure only and did not have any financial impact on the consolidated financial statements.

(2) Fair Value

Alon must 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. As required, Alon utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy. Alon generally applies the “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.

The carrying amounts of Alon’s cash and cash equivalents, receivables, payables and accrued liabilities approximate fair value due to the short-term maturities of these assets and liabilities. The reported amounts of long-term debt approximate fair value. Derivative financial instruments are carried at fair value, which is based on quoted market prices. Derivative instruments are the only financial assets and liabilities measured at fair value on a recurring basis.

4

ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

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 September 30, 2013 and December 31, 2012:

	Quoted Prices in Active Markets For Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Consolidated Total
As of September 30, 2013
Liabilities:
Commodity contracts (futures and forwards)	$	44	$	—	$	—	$	44
Fair value hedge	—		4,157		—		4,157
As of December 31, 2012
Assets:
Commodity contracts (futures and forwards)	$	2,365	$	—	$	—	$	2,365
Liabilities:
Fair value hedge	—		327		—		327

(3) Derivative Financial Instruments

Commodity Derivatives — Mark to Market

Alon selectively utilizes commodity derivatives to manage its exposure to commodity price fluctuations and uses crude oil and refined product commodity derivative contracts to reduce risk associated with potential price changes on committed obligations. Alon does not speculate using derivative instruments. Credit risk on Alon’s derivative instruments is substantially mitigated by transacting with counterparties meeting established collateral and credit criteria.

Fair Value Hedge

Fair value hedges are used to hedge price volatility in certain refining inventories and firm commitments to purchase inventories. The level of activity for fair value hedges is based on the level of operating inventories. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk, is recognized currently in earnings in the same period.

As of September 30, 2013, Alon has accounted for certain commodity contracts as fair value hedges with contract purchase volumes of 333 thousand barrels of crude oil with remaining contract terms through May 2019.

The following table presents the effect of derivative instruments on the consolidated statements of financial position:

	As of September 30, 2013
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	1,395	Accrued liabilities	$	(1,439	)
Total derivatives not designated as hedging instruments		$	1,395		$	(1,439	)
Derivatives designated as hedging instruments:
Fair value hedge		$	—	Other non-current liabilities	$	(4,157	)
Total derivatives designated as hedging instruments		—			(4,157		)
Total derivatives		$	1,395		$	(5,596	)

5

ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

	As of December 31, 2012
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	2,365		$	—
Total derivatives not designated as hedging instruments		$	2,365		$	—
Derivatives designated as hedging instruments:
Fair value hedge		$	—	Other non-current liabilities	$	(327	)
Total derivatives designated as hedging instruments		—			(327		)
Total derivatives		$	2,365		$	(327	)

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

Derivatives in fair value hedging relationships:

		Gain (Loss) Recognized in Income
		For the Three Months Ended						For the Nine Months Ended
		September 30,						September 30,
	Location	2013			2012			2013			2012
					Predecessor						Predecessor
Fair value hedge	Cost of sales	$	(2,232	)	$	(591	)	$	(3,830	)	$	(591	)
Total derivatives		$	(2,232	)	$	(591	)	$	(3,830	)	$	(591	)

Derivatives not designated as hedging instruments:

		Gain (Loss) Recognized in Income
		For the Three Months Ended					For the Nine Months Ended
		September 30,					September 30,
	Location	2013			2012		2013		2012
					Predecessor				Predecessor
Commodity contracts (futures & forwards)	Cost of sales	$	(2,091	)	$	7,270	$	4,559	$	12,446
Commodity contracts (swaps) (a)	Cost of sales	—			—		—		(13,951		)
Total derivatives		$	(2,091	)	$	7,270	$	4,559	$	(1,505	)

__________

(a) Related to derivative transactions with a related party.

6

ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

Offsetting Assets and Liabilities

Alon's derivative financial instruments are subject to master netting arrangements to manage counterparty credit risk associated with derivatives, however, Alon does not offset on its consolidated balance sheets the fair value amounts recorded for derivative instruments under these agreements.

The following table presents offsetting information regarding Alon's derivatives by type of transaction as of September 30, 2013 and December 31, 2012:

	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset in the Statement of Financial Position		Net Amounts of Assets (Liabilities) 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 September 30, 2013
Commodity Derivative Assets:
Futures & forwards	$	1,395		$	—	$	1,395		$	(1,395	)	$	—	$	—
Commodity Derivative Liabilities:
Futures & forwards	(1,439		)	—		(1,439		)	1,395			—		(44		)
As of December 31, 2012
Commodity Derivative Assets:
Futures & forwards	$	2,365		$	—	$	2,365		$	—		$	—	$	2,365

Compliance Program Price Risk

Alon is exposed to market risk related to the volatility in the price of credits needed to comply with various governmental and regulatory programs. The most significant programs impacting operations are those that require Alon to blend biofuels into the products produced. Alon is obligated to blend biofuels into the products produced at a rate that is at least equal to the required annual quotas. To the degree Alon is unable to blend at the applicable rate, biofuel credits (primarily RINs) must be purchased to cover this deficit. Alon is exposed to the volatility in the market price of these credits, and Alon manages that risk by purchasing biofuel credits when prices are deemed favorable utilizing fixed price purchase contracts. Some of these contracts are derivative instruments; however, Alon elects the normal purchase and sale exception and does not record these contracts at their fair values.

The cost of meeting Alon's obligations under these compliance programs was $1,178 and $9,194 for the three and nine months ended September 30, 2013, respectively. These amounts are reflected in cost of sales.

(4) Inventories

Alon's inventories (including inventory consigned to others) are stated at the lower of cost or market. Cost is determined under the last-in, first-out (LIFO) method for crude oil, refined products and blendstock inventories. Materials and supplies are stated at average cost.

Carrying value of inventories consisted of the following:

	September 30, 2013		December 31, 2012
Crude oil, refined products and blendstocks	$	41,247	$	24,661
Crude oil inventory consigned to others	25,232		23,086
Materials and supplies	9,720		9,287
Total inventories	$	76,199	$	57,034

Market values of crude oil, refined products and blendstock inventories exceeded LIFO costs by $28,046 and $12,477 at September 30, 2013 and December 31, 2012, respectively.

7

ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

(5) Inventory Financing Agreement

Alon has entered into a Supply and Offtake Agreement and other associated agreements (together the “Supply and Offtake Agreement”), with J. Aron & Company (“J. Aron”). Pursuant to the Supply and Offtake Agreement, (i) J. Aron agreed to sell to Alon, and Alon agreed to buy from J. Aron, at market prices, crude oil for processing at the Big Spring refinery and (ii) Alon agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced at the Big Spring refinery.

The Supply and Offtake Agreement also provided for the sale, at market prices, of Alon's crude oil and certain refined product inventories to J. Aron, the lease to J. Aron of crude oil and refined product storage facilities, and to identify prospective purchasers of refined products on J. Aron's behalf. The Supply and Offtake Agreement was amended in February 2013 and has an initial term that expires in May 2019. J. Aron may elect to terminate the Supply and Offtake Agreement prior to the expiration of the initial term beginning in May 2016 and upon each anniversary thereof, on six months prior notice. Alon may elect to terminate in May 2018 on six months prior notice.

Following expiration or termination of the Supply and Offtake Agreement, Alon is obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the Big Spring refinery.

At September 30, 2013 and December 31, 2012, Alon had net current payables of $5,307 and $16,038 for sales and purchases to J. Aron, respectively, non-current liabilities related to the original financing of $35,672 and $31,842, respectively, and a consignment inventory receivable representing a deposit paid to J. Aron of $6,290 and $6,290, respectively.

Additionally, Alon had current payables of $1,439 and current receivables of $4,136 at September 30, 2013 and December 31, 2012, 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:

	September 30, 2013			December 31, 2012
Refining facilities	$	668,362		$	652,910
Less: Accumulated depreciation	(195,503		)	(169,849		)
Property, plant and equipment, net	$	472,859		$	483,061

(7) Additional Financial Information

The tables that follow provide additional financial information related to the consolidated financial statements:

(a) Other Assets, Net

	September 30, 2013		December 31, 2012
Deferred debt issuance costs	$	8,166	$	9,449
Receivable from supply agreement	6,290		6,290
Deferred turnaround and chemical catalyst cost	5,418		7,622
Other	8,437		8,460
Total other assets	$	28,311	$	31,821

8

ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

(b) Accrued Liabilities and Other Non-Current Liabilities

	September 30, 2013		December 31, 2012
Accrued Liabilities:
Taxes other than income taxes, primarily excise taxes	$	20,525	$	28,112
Accrued finance charges	1,350		1,927
Environmental accrual (Note 11)	831		831
Commodity contracts	1,439		—
Environmental compliance obligation	17,604		—
Other	6,004		11,348
Total accrued liabilities	$	47,753	$	42,218
Other Non-Current Liabilities:
Consignment inventory	$	35,672	$	31,842
Environmental accrual (Note 11)	5,966		5,516
Asset retirement obligations	1,952		1,890
Other	2,799		2,799
Total other non-current liabilities	$	46,389	$	42,047

(8) Indebtedness

Debt consisted of the following:

	September 30, 2013			December 31, 2012
Term loan credit facility	$	244,816		$	246,311
Revolving credit facility	80,000			49,000
Total debt	324,816			295,311
Less: Current portion	(2,500		)	(2,500		)
Total long-term debt	$	322,316		$	292,811

Outstanding letters of credit under the revolving credit facility were $88,672 and $58,759 at September 30, 2013 and December 31, 2012, respectively.

Alon's revolving credit facility contains certain restrictive covenants, including maintenance financial covenants. At September 30, 2013, Alon was in compliance with these maintenance financial covenants.

(9) Partners' Equity (unit values in dollars)

Cash Distributions. Alon has adopted a policy pursuant to which it will distribute all of the available cash it generates each quarter, as defined in the partnership agreement and subject to the approval of the board of directors of the General Partner. The per unit amount of available cash to be distributed each quarter, if any, will be distributed within 60 days following the end of such quarter.

During the nine months ended September 30, 2013, Alon paid the following cash distributions:

Date Paid	Distribution Amount Per Unit		Total Distribution Amount
March 1, 2013	$	0.57	$	35,626
May 15, 2013	$	1.48	$	92,503
August 23, 2013	$	0.71	$	44,377

Restricted Units. During the nine months ended September 30, 2013, Alon granted awards totaling 2,467 restricted common units at an average grant date price of $20.27 per unit to non-employee directors of the General Partner. The restricted common units granted to the non-employee directors vest over a period of three years, assuming continued service at vesting.

9

ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

(10) Related-Party Transactions

Sales and Receivables

Sales to related parties include motor fuels and asphalt sold to other Alon Energy operations at prices substantially determined by market commodity pricing information. These sales are included in net sales in the consolidated statements of operations. Accounts receivable from related parties include sales of motor fuels and are shown separately on the consolidated balance sheets.

Costs Allocated from Alon Energy

(a) Corporate Overhead Allocations

Alon is a subsidiary of Alon Energy and is operated as a component of the integrated operations of Alon Energy and its other subsidiaries. As such, the executive officers of Alon Energy, who are employed by another subsidiary of Alon Energy, also serve as executive officers of the General Partner and Alon Energy's other subsidiaries. Alon Energy performs general corporate and administrative services and functions for Alon and Alon Energy'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. Alon Energy allocates the expenses actually incurred in performing these services to Alon and to its other subsidiaries based primarily on the estimated amount of time the individuals performing such services devote to Alon's business affairs relative to the amount of time they devote to the business affairs of Alon Energy's other subsidiaries. The management of Alon Energy and the General Partner consider these allocations to be reasonable. Alon records the amount of such allocations to its consolidated financial statements as selling, general and administrative expenses. Alon's share of Alon Energy's selling, general and administrative expenses were $2,124 and $3,519, for the three months ended September 30, 2013 and 2012, respectively, and $8,568 and $10,298 for the nine months ended September 30, 2013 and 2012, respectively.

(b) Labor Costs

Alon has no employees and, as a result, actual employee expense costs for Alon Energy employees working in Alon's operations have been allocated and recorded as payroll expense and included in direct operating expenses and selling, general and administrative expenses within the consolidated statements of operations. Alon's share of Alon Energy's employee expense costs included in direct operating expenses were $6,211 and $5,762 for the three months ended September 30, 2013 and 2012, respectively, and $18,169 and $17,167 for the nine months ended September 30, 2013 and 2012, respectively.

(c) Insurance Costs

Insurance costs related to the Big Spring refinery and wholesale marketing operations are allocated to Alon by Alon Energy based on estimated insurance premiums on a stand-alone basis relative to Alon Energy's total insurance premium. Insurance costs included in direct operating expenses was $3,038 and $2,642 for the three months ended September 30, 2013 and 2012, respectively, and $8,300 and $7,804 for the nine months ended September 30, 2013 and 2012, respectively.

Distributions

On March 1, 2013, the Partnership paid a cash distribution for the period of November 27, 2012 through and including December 31, 2012 of $35,626, of which $29,070 was paid to Alon Energy. On May 15, 2013, the Partnership paid a cash distribution for the period of January 1, 2013 through and including March 31, 2013 of $92,503, of which $75,480 was paid to Alon Energy. On August 23, 2013, the Partnership paid a cash distribution for the period of April 1, 2013 through and including June 30, 2013 of $44,377, of which $36,210 was paid to Alon Energy.

During the nine months ended September 30, 2012, the Predecessor made net cash payments to Alon Energy of $326,120.

(11) Commitments and Contingencies

(a) Commitments

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

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ALON USA PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(unaudited, dollars in thousands except as noted)

(b) Contingencies

Alon is involved in various legal actions arising in the ordinary course of business. Alon believes the ultimate disposition of these matters will not have a material effect on Alon's financial position, results of operations or liquidity.

(c) Environmental

Alon is subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These laws and regulations govern the discharge of materials into the environment and may require Alon 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; to compensate others for damage to property and natural resources and for remediation and restoration costs. These contingent obligations relate to sites owned by Alon and its past or present operations. Alon is currently participating in environmental investigations, assessments and cleanups pertaining to the refinery, pipelines and terminals. Alon may in the future be involved in additional 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 Alon's liability in proportion to other responsible parties.

Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Substantially all amounts accrued are expected to be paid out over the next 15 years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

Alon has accrued environmental remediation obligations of $6,797 ($831 accrued liability and $5,966 non-current liability) at September 30, 2013, and $6,347 ($831 accrued liability and $5,516 non-current liability) at December 31, 2012.

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

References in this report to the "Predecessor," "we," "our," "us" or like terms, when used in a historical context (periods prior to November 26, 2012) refers to Alon USA Partners, LP Predecessor, our predecessor for accounting purposes. References when used in the present tense or prospectively (after November 26, 2012) refer to Alon USA Partners, LP and its subsidiaries, also referred to as the "Partnership" or "Alon." Unless the context otherwise requires, references in this report to "Alon Energy" refers to Alon USA Energy, Inc. and any of its subsidiaries other than the Partnership, its subsidiaries and its general partner.

The following discussion of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2012.

Forward-Looking Statements

Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.

Forward-looking statements reflect our current expectations of future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations and cash flows.

Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:

• changes in general economic conditions and capital markets;

• changes in the underlying demand for our products;

• the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;

• changes in the spread between West Texas Intermediate ("WTI") crude oil and West Texas Sour ("WTS") crude oil;

• the effects of transactions involving forward contracts and derivative instruments;

• actions of customers and competitors;

• termination of our Supply and Offtake Agreement with J. Aron & Company (“J. Aron”), under which J. Aron is our largest supplier of crude oil and our largest customer of refined products. Additionally, we are obligated to repurchase all consigned inventories and certain other inventories upon termination of the Supply and Offtake Agreement;

• changes in fuel and utility costs incurred by our refinery;

• disruptions due to equipment interruption, pipeline disruptions or failure at our or third-party facilities;

• the execution of planned capital projects;

• adverse changes in the credit ratings assigned to our trade credit and debt instruments;

• the effects of and cost of compliance with the Renewable Fuel Standard, including the availability, cost and price volatility of Renewable Identification Numbers ("RINs");

• the effects and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;

• operating hazards, natural disasters, casualty losses and other matters beyond our control;

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

• the other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2012 under the caption “Risk Factors.”

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

Company Overview

On November 26, 2012, the Partnership completed its initial public offering (the "Offering") of 11,500,000 common units representing limited partner interests. After completion of the Offering, Alon Energy contributed to the Partnership its equity interests in Alon USA, LP and Alon USA Refining, Inc. Prior to completion of the Offering, the assets, liabilities and results of operations of the aforementioned assets are related to Alon USA Partners, LP Predecessor ("Predecessor"), our predecessor for accounting purposes.

We are a Delaware limited partnership formed in August 2012 by Alon USA Energy, Inc. (NYSE: ALJ) (“Alon Energy”) to own, operate and grow our strategically located refining and petroleum products marketing business. Our integrated downstream business operates primarily in the South Central and Southwestern regions of the United States. We own and operate a crude oil refinery in Big Spring, Texas with total crude oil throughput capacity of approximately 70,000 barrels per day (“bpd”), which we refer to as our Big Spring refinery. We refine crude oil into finished products, which we market primarily in West Texas, Central Texas, Oklahoma, New Mexico and Arizona through our wholesale distribution network to both Alon Energy’s retail convenience stores and third-party distributors.

We sell refined products in both the wholesale rack and bulk markets. We focus our marketing of transportation fuels on portions of Texas, Oklahoma, New Mexico and Arizona through our physically-integrated refining and distribution system. We distribute fuel products through a product pipeline and terminal network of pipelines and terminals that we own or access through leases or long-term throughput agreements.

Third Quarter Operational and Financial Highlights

Operating loss for the third quarter of 2013 was $3.9 million, compared to operating income of $130.2 million in the same period last year. Our operational and financial highlights for the third quarter of 2013 include the following:

• Big Spring refinery throughput for the third quarter of 2013 averaged 63,090 bpd compared to 69,563 bpd for the third quarter of 2012. The reduced throughput rate for the third quarter of 2013 was primarily due to unplanned downtime.

• Operating margin at the Big Spring refinery was $6.46 per barrel for the third quarter of 2013 compared to $27.75 per barrel for the same period in 2012. This decrease in operating margin is primarily due to lower Gulf Coast 3/2/1 crack spreads and a narrowing of the WTI to WTS spread.

• The average Gulf Coast 3/2/1 crack spread was $14.23 per barrel for the third quarter of 2013 compared to $31.76 per barrel for the third quarter of 2012. The average WTI to WTS spread for the third quarter of 2013 was $0.08 per barrel compared to $3.70 per barrel for the same period in 2012.

• Beginning in 2013, we became subject to the Renewable Fuel Standards requirement to begin blending biofuels in the products we produce and to the degree we are unable to blend at percentages required under these various governmental and regulatory programs, we must purchase biofuel credits to comply with these programs. RINs costs for the third quarter of 2013 were $1.2 million.

Major Influences on Results of Operations

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

In order to measure our operating performance, we compare our per barrel refinery operating margin to certain industry benchmarks. We calculate this margin for the Big Spring refinery by dividing the refinery’s gross margin by its throughput volumes. Gross margin is the difference between net sales and cost of sales.

The Big Spring refinery operating margin is compared to the Gulf Coast 3/2/1 crack spread that is intended to approximate the refinery's crude slate and product yield. The Gulf Coast 3/2/1 crack spread is calculated assuming that three barrels of WTI

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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 value of Cushing WTI crude oil and the value of Midland WTS, a medium, sour crude oil. We refer to this differential as the WTI/WTS, or sweet/sour, spread. A widening of the sweet/sour spread can 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 substantial quantities of crude oil and refined product inventories. Crude oil and refined products are commodities, and we have no control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market value under the LIFO inventory valuation methodology, price fluctuations generally have little effect on our financial results.

Factors Affecting Comparability

Our financial condition and operating results over the nine months ended September 30, 2013 and 2012, have been influenced by the following factors which are fundamental to understanding comparisons of our period-to-period financial performance.

Maintenance and Reduced Crude Oil Throughput

During the nine months ended September 30, 2013, the Big Spring refinery was impacted by unplanned downtime.

Renewable Fuel Standard

RINs costs for the three and nine months ended September 30, 2013 were $1.2 million and $9.2 million, respectively. We were not subject to the Renewable Fuel Standard requirements in 2012.

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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 mix of refined products produced and volume changes caused by operations.

Cost of Sales. Cost of sales primarily includes crude oil, other raw materials and transportation costs.

Direct Operating Expenses. Direct operating expenses include costs associated with the actual operations of the refinery and terminals, such as energy and utility costs, routine maintenance, labor, insurance and environmental compliance costs. Environmental compliance costs, including monitoring and routine maintenance, are expensed as incurred. Substantially all of the operating costs associated with our crude oil and product pipelines are considered to be transportation costs and are reflected in cost of sales in the consolidated statements of operations.

Selling, General and Administrative Expenses. Selling, general and administrative expenses, or SG&A, primarily include corporate overhead costs and marketing expenses.

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

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

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

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ALON USA PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED

Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for the three and nine months ended September 30, 2013 and 2012. The following data should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this Form 10-Q. All information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” except for Balance Sheet data as of December 31, 2012 is unaudited.

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
				Predecessor						Predecessor
	(dollars in thousands, except per unit data, per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA: (A)
Net sales (1)	$	881,902		$	943,148		$	2,551,763		$	2,651,191
Operating costs and expenses:
Cost of sales	844,423			765,538			2,261,948			2,225,702
Direct operating expenses	26,281			25,480			84,017			73,223
Selling, general and administrative expenses	4,134			10,316			16,864			18,070
Depreciation and amortization	10,975			11,573			34,282			34,963
Total operating costs and expenses	885,813			812,907			2,397,111			2,351,958
Loss on disposition of assets	(21		)	—			(21		)	—
Operating income (loss)	(3,932		)	130,241			154,631			299,233
Interest expense	(12,127		)	(4,313		)	(30,489		)	(15,070		)
Interest expense - related parties	—			(4,457		)	—			(12,990		)
Other income (loss), net	—			(6		)	18			11
Income (loss) before state income tax expense	(16,059		)	121,465			124,160			271,184
State income tax expense	61			1,098			1,434			2,518
Net income (loss)	$	(16,120	)	$	120,367		$	122,726		$	268,666
Earnings (loss) per unit	$	(0.26	)				$	1.96
Weighted average common units outstanding (in thousands)	62,502						62,502
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	6,476		$	176,473		$	159,719		$	363,616
Investing activities	(7,682		)	(6,351		)	(21,658		)	(25,455		)
Financing activities	34,998			(182,406		)	(143,586		)	(444,692		)
OTHER DATA:
Adjusted EBITDA (2)	$	7,064		$	141,808		$	188,952		$	334,207
Capital expenditures	7,477			6,286			16,634			17,328
Capital expenditures for turnaround and chemical catalyst	205			65			5,024			8,127
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin (3)	$	6.46		$	27.75		$	16.35		$	22.88
Refinery direct operating expense (4)	4.53			3.92			4.74			3.92
PRICING STATISTICS:
Crack spreads (per barrel):
Gulf Coast (WTI) 3/2/1	$	14.23		$	31.76		$	21.21		$	27.54
WTI crude oil (per barrel)	$	105.82		$	92.09		$	98.14		$	96.17
Crude oil differentials (per barrel):
WTI less WTS	$	0.08		$	3.70		$	3.91		$	3.74
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	2.78		$	2.89		$	2.77		$	2.89
Gulf Coast ultra-low sulfur diesel	3.02			3.07			2.99			3.06
Natural gas (per MMBtu)	3.56			2.89			3.69			2.58

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	September 30, 2013			December 31, 2012
BALANCE SHEET DATA (end of period):	(dollars in thousands)
Cash and cash equivalents	$	60,476		$	66,001
Working capital	(519		)	1,702
Total assets	758,699			763,423
Total debt	324,816			295,311
Total partners' equity	131,946			181,726

THROUGHPUT AND PRODUCTION DATA:	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
				Predecessor						Predecessor
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
WTS crude	36,340	57.6		52,108	74.9		45,029	69.3		53,297	78.6
WTI crude	25,169	39.9		15,398	22.1		18,016	27.8		12,790	18.8
Blendstocks	1,581	2.5		2,057	3.0		1,865	2.9		1,797	2.6
Total refinery throughput (5)	63,090	100.0		69,563	100.0		64,910	100.0		67,884	100.0
Refinery production:
Gasoline	30,861	49.2		34,918	50.3		31,905	49.4		33,653	49.6
Diesel/jet	20,999	33.4		23,215	33.5		21,688	33.5		22,234	32.8
Asphalt	3,312	5.3		4,148	6.0		3,708	5.7		4,241	6.3
Petrochemicals	3,599	5.7		4,040	5.8		3,984	6.2		4,005	5.9
Other	4,045	6.4		3,045	4.4		3,371	5.2		3,627	5.4
Total refinery production (6)	62,816	100.0		69,366	100.0		64,656	100.0		67,760	100.0
Refinery utilization (7)		87.9	%		96.4	%		93.8	%		97.3	%

(A) Earnings (loss) per unit information is not presented for the three and nine months ended September 30, 2012 as there was no common equity or potential common equity publicly traded during that period and therefore is not required by Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") topic 260, Earnings per share.

_____________________

(1) Includes sales to related parties of $164,338 and $151,682 for the three months ended September 30, 2013 and 2012, respectively, and $462,280 and $450,416 for the nine months ended September 30, 2013 and 2012, respectively.

(2) Adjusted EBITDA represents earnings before state income tax expense, interest expense, depreciation and amortization and loss on disposition of assets. 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, loss on disposition of assets 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

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• 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.

The following table reconciles net income (loss) to Adjusted EBITDA for the three and nine months ended September 30, 2013 and 2012, respectively:

	For the Three Months Ended					For the Nine Months Ended
	September 30,					September 30,
	2013			2012		2013		2012
				Predecessor				Predecessor
	(dollars in thousands)
Net income (loss)	$	(16,120	)	$	120,367	$	122,726	$	268,666
State income tax expense	61			1,098		1,434		2,518
Interest expense	12,127			4,313		30,489		15,070
Interest expense - related parties	—			4,457		—		12,990
Depreciation and amortization	10,975			11,573		34,282		34,963
Loss on disposition of assets	21			—		21		—
Adjusted EBITDA	$	7,064		$	141,808	$	188,952	$	334,207

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

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

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

(6) Total refinery production represents the barrels per day of various refined products produced from processing crude and other refinery feedstocks through the crude units and other conversion units.

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

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Three Months Ended September 30, 2013 Compared to the Three Months Ended September 30, 2012

Net Sales. Net sales for the three months ended September 30, 2013 were $881.9 million, compared to $943.1 million for the three months ended September 30, 2012, a decrease of $61.2 million. This decrease was primarily due to lower refinery throughput and lower refined product prices in the three months ended September 30, 2013 compared to the same period last year. Refinery throughput for the three months ended September 30, 2013 was 63,090 bpd compared to 69,563 bpd for the three months ended September 30, 2012, a decrease of 9.3%. The reduced throughput rate for the three months ended September 30, 2013 was primarily due to unplanned downtime. The average per gallon price of Gulf Coast gasoline for the three months ended September 30, 2013 decreased $0.11, or 3.8%, to $2.78, compared to $2.89 for the three months ended September 30, 2012. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the three months ended September 30, 2013 decreased $0.05, or 1.6%, to $3.02, compared to $3.07 for the three months ended September 30, 2012.

Cost of Sales. Cost of sales for the three months ended September 30, 2013 were $844.4 million, compared to $765.5 million for the three months ended September 30, 2012, an increase of $78.9 million. This increase was primarily due to higher crude oil prices, partially offset by lower refinery throughput. The average price of WTI for the three months ended September 30, 2013 was $105.82, which was $13.73, or 14.9%, higher than the $92.09 per barrel average for the three months ended September 30, 2012. Additionally, the average price of WTS was higher as the differential to WTI narrowed to $0.08 per barrel, a decrease of 97.8%, for the three months ended September 30, 2013 compared to $3.70 per barrel for the three months ended September 30, 2012.

Direct Operating Expenses. Direct operating expenses for the three months ended September 30, 2013 were $26.3 million, compared to $25.5 million for the three months ended September 30, 2012, an increase of $0.8 million, or 3.1%. This increase was primarily due to higher insurance costs and property taxes.

Selling, General and Administrative Expenses. SG&A expenses for the three months ended September 30, 2013 were $4.1 million, compared to $10.3 million for the three months ended September 30, 2012, a decrease of $6.2 million, or 60.2%, primarily due to lower employee related costs.

Depreciation and Amortization. Depreciation and amortization for the three months ended September 30, 2013 was $11.0 million, compared to $11.6 million for the three months ended September 30, 2012, a decrease of $0.6 million, or 5.2%.

Operating Income (Loss). Operating loss for the three months ended September 30, 2013 was $3.9 million, compared to operating income of $130.2 million for the three months ended September 30, 2012, a decrease of $134.1 million. This decrease was primarily due to lower refinery margins resulting from decreased Gulf Coast (WTI) 3/2/1 crack spreads, a narrowing WTI to WTS spread and unplanned downtime at the refinery. Refinery operating margin was $6.46 per barrel for the three months ended September 30, 2013, compared to $27.75 per barrel for the three months ended September 30, 2012. The average Gulf Coast (WTI) 3/2/1 crack spread decreased to $14.23 per barrel for the three months ended September 30, 2013, compared to $31.76 per barrel for the three months ended September 30, 2012. Additionally, the WTI to WTS spread narrowed for the three months ended September 30, 2013 to $0.08 per barrel compared to $3.70 per barrel for the three months ended September 30, 2012. Also impacting operating income and refinery operating margin was approximately $1.2 million of costs associated with the RINs obligation for the three months ended September 30, 2013.

Interest Expense. Interest expense for the three months ended September 30, 2013 was $12.1 million, compared to total interest expense of $8.8 million, including interest expense to related parties, for the three months ended September 30, 2012, an increase of $3.3 million. This increase was primarily due to higher financing costs associated with crude oil purchases and higher bank fees.

Net Income (Loss). Net loss for the three months ended September 30, 2013 was $16.1 million, compared to net income of $120.4 million for the three months ended September 30, 2012, a decrease of $136.5 million. This decrease was attributable to the factors discussed above.

Nine Months EndedSeptember 30, 2013 Compared to the Nine Months EndedSeptember 30, 2012

Net Sales. Net sales for the nine months ended September 30, 2013 were $2,551.8 million, compared to $2,651.2 million for the nine months ended September 30, 2012, a decrease of $99.4 million. This decrease was due to lower refinery throughput and lower refined product prices. Refinery throughput for the nine months ended September 30, 2013 was 64,910 bpd compared to 67,884 bpd for the nine months ended September 30, 2012, a decrease of 4.4%. The average per gallon price of Gulf Coast gasoline for the nine months ended September 30, 2013 decreased $0.12, or 4.2%, to $2.77, compared to $2.89 for

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the nine months ended September 30, 2012. The average per gallon price of Gulf Coast ultra low-sulfur diesel for the nine months ended September 30, 2013 decreased $0.07, or 2.3%, to $2.99, compared to $3.06 for the nine months ended September 30, 2012.

Cost of Sales. Cost of sales were $2,261.9 million for the nine months ended September 30, 2013, compared to $2,225.7 million for the nine months ended September 30, 2012, an increase of $36.2 million. This increase was primarily due to an increase in crude oil prices, partially offset by decreased refinery throughput. The average price of WTI increased 2.0% to $98.14 per barrel for the nine months ended September 30, 2013 from $96.17 per barrel for the nine months ended September 30, 2012.

Direct Operating Expenses. Direct operating expenses for the nine months ended September 30, 2013 were $84.0 million, compared to $73.2 million for the nine months ended September 30, 2012, an increase of $10.8 million, or 14.8%. This increase was primarily due to higher major maintenance costs, property tax expenses and higher natural gas costs for the nine months ended September 30, 2013.

Selling, General and Administrative Expenses. SG&A expenses for the nine months ended September 30, 2013 were $16.9 million, compared to $18.1 million for the nine months ended September 30, 2012, a decrease of $1.2 million, or 6.6%. This decrease was primarily due to lower employee related costs for the nine months ended September 30, 2013.

Depreciation and Amortization. Depreciation and amortization for the nine months ended September 30, 2013 was $34.3 million, compared to $35.0 million for the nine months ended September 30, 2012, a decrease of $0.7 million.

Operating Income. Operating income was $154.6 million for the nine months ended September 30, 2013, compared to $299.2 million for the nine months ended September 30, 2012, a decrease of $144.6 million. This decrease was primarily due to lower refinery margins and higher direct operating expenses. Refinery operating margin was $16.35 per barrel for the nine months ended September 30, 2013, compared to $22.88 per barrel for the nine months ended September 30, 2012. This decrease in operating margin was primarily due to lower Gulf Coast (WTI) 3/2/1 crack spreads partially offset by a widening of the WTI to WTS spread. The average Gulf Coast (WTI) 3/2/1 crack spread decreased 23.0% to $21.21 per barrel for the nine months ended September 30, 2013, compared to $27.54 per barrel for the nine months ended September 30, 2012. The WTI to WTS spread widened 4.5% to $3.91 per barrel for the nine months ended September 30, 2013, compared to $3.74 per barrel for the nine months ended September 30, 2012. Also impacting operating income and refinery operating margin was approximately $9.2 million of costs associated with the RINs obligation for the nine months ended September 30, 2013.

Interest Expense. Interest expense was $30.5 million for the nine months ended September 30, 2013, compared to total interest expense of $28.1 million, including interest expense to related parties, for the nine months ended September 30, 2012, an increase of $2.4 million. This increase was primarily due to higher financing costs associated with crude oil purchases.

Net Income. Net income for the nine months ended September 30, 2013 was $122.7 million, compared to $268.7 million for the nine months ended September 30, 2012, a decrease of $146.0 million. This decrease was attributable to the factors discussed above.

Liquidity and Capital Resources

Our primary sources of liquidity are cash on hand, cash generated from our operating activities, borrowings under our revolving credit facility, inventory supply and offtake arrangement and other credit lines.

We have an agreement with J. Aron for the supply of crude oil that will support the operations of the Big Spring refinery. This arrangement substantially reduces our need to issue letters of credit to support crude oil purchases. In addition, the structure allows us to acquire crude oil without the constraints of a maximum facility size during periods of high crude oil prices.

We believe that the aforementioned sources of funds and other sources of capital available to us will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next twelve months. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive, and other factors beyond our control.

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Cash Flows

The following table sets forth our consolidated cash flows for the nine months ended September 30, 2013 and 2012:

	For the Nine Months Ended
	September 30,
	2013			2012
				Predecessor
	(dollars in thousands)
Cash provided by (used in):
Operating activities	$	159,719		$	363,616
Investing activities	(21,658		)	(25,455		)
Financing activities	(143,586		)	(444,692		)
Net decrease in cash and cash equivalents	$	(5,525	)	$	(106,531	)

Cash Flows Provided by Operating Activities

Net cash provided by operating activities was $159.7 million during the nine months ended September 30, 2013 compared to $363.6 million during the nine months ended September 30, 2012. The reduction in net cash provided by operating activities of $203.9 million was primarily attributable to lower net income after adjusting for non-cash items of $159.2 million and lower cash on reduction of accounts payable and accrued liabilities of $71.7 million, partially offset by higher cash collected on accounts receivables of $21.6 million and lower cash used on reduction of inventories of $6.4 million.

Cash Flows Used In Investing Activities

Net cash used in investing activities was $21.7 million during the nine months ended September 30, 2013 compared to $25.5 million during the nine months ended September 30, 2012. The reduction in net cash used in investing activities of $3.8 million was primarily due to a decrease in capital expenditures and capital expenditures for turnarounds and catalysts.

Cash Flows Used In Financing Activities

Net cash used in financing activities was $143.6 million during the nine months ended September 30, 2013 compared to $444.7 million during the nine months ended September 30, 2012. The reduction in net cash used in financing activities of $301.1 million was primarily attributable to lower net payments to equity holders of $153.6 million as well as increased borrowings on our revolving credit facility of $147.0 million.

Indebtedness

Revolving Credit Facility. We have a $240.0 million revolving credit facility (the “Revolving Credit Facility”) that will mature in March 2016. 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 bear interest at the Eurodollar rate plus 3.50% per annum subject to an overall minimum interest rate of 4.00%.

The Revolving Credit Facility is secured by (i) a first lien on our cash, accounts receivables, inventories and related assets and (ii) a second lien on our fixed assets.

The Revolving Credit Facility contains certain restrictive covenants, including maintenance financial covenants. At September 30, 2013, we were in compliance with these maintenance financial covenants.

Borrowings of $80.0 million and $49.0 million were outstanding under the Revolving Credit Facility at September 30, 2013 and December 31, 2012, respectively. At September 30, 2013 and December 31, 2012, outstanding letters of credit under the Revolving Credit Facility were $88.7 million and $58.8 million, respectively.

Capital Spending

Each year the Board of Directors of our General Partner approves capital projects, including regulatory and planned turnaround projects that our management is authorized to undertake in our annual capital budget. Additionally, at times when conditions warrant or as new opportunities arise, other projects or the expansion of existing projects may be approved. Our total

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capital expenditure and turnaround/chemical catalyst plan for 2013 is $39.9 million. Approximately $21.7 million has been spent during the nine months ended September 30, 2013.

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, 2012.

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, 2012. 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 chemical catalysts replacements. No significant changes to these accounting policies have occurred subsequent to December 31, 2012.

New Accounting Standards and Disclosures

New accounting standards if any are disclosed in Note (1) Basis of Presentation included in the consolidated financial statements included in Item 1 of this report.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

In order to manage the uncertainty relating to inventory price volatility, we have consistently applied a policy of maintaining inventories at or below a targeted operating level. In the past, circumstances have occurred, such as timing of crude oil cargo deliveries, turnaround schedules or shifts in market demand that have resulted in variances between our actual inventory level and our desired target level. Upon the review and approval of Alon Energy's risk management committee, we may utilize the commodity futures market to manage these anticipated inventory variances.

We maintain inventories of crude oil, refined products and blendstocks, the values of which are subject to wide fluctuations in market prices driven by world economic conditions, regional and global inventory levels and seasonal conditions. As of September 30, 2013, we held approximately 0.8 million barrels of crude oil and refined product inventories valued under the LIFO valuation method. Market value exceeded carrying value of LIFO costs by $28.0 million. We refer to this excess as our LIFO reserve. If the market value of these inventories had been $1.00 per barrel lower, our LIFO reserve would have been reduced by $0.8 million.

In accordance with fair value provisions of ASC 825-10, all commodity contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section of our consolidated financial statements. “Forwards” represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period. “Futures” represent trades which have been executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period. A “long” represents an obligation to purchase product and a “short” represents an obligation to sell product.

The following table provides information about our derivative commodity instruments as of September 30, 2013:

Description	Contract Volume		Wtd Avg Purchase		Wtd Avg Sales		Contract			Market			Gain
of Activity	(barrels)		Price/BBL		Price/BBL		Value			Value			(Loss)
							(in thousands)
Forwards-long (Crude)	248,662		$	106.52	$	—	$	26,489		$	25,384		$	(1,105	)
Forwards-short (Gasoline)	(34,581	)	—		113.55		(3,927		)	(3,783		)	144
Forwards-long (Distillate)	25,815		129.43		—		3,341			3,246			(95		)
Forwards-short (Jet)	(13,371	)	—		125.30		(1,675		)	(1,600		)	75
Forwards-long (Slurry)	3,884		93.58		—		363			362			(1		)
Forwards-long (Catfeed)	142,026		113.32		—		16,094			15,523			(571		)
Forwards-short (Slop)	(4,577	)	—		96.24		(440		)	(422		)	18
Forwards-short (Propane)	(43,956	)	—		44.19		(1,942		)	(1,846		)	96
Futures-short (Crude)	(372,000	)	—		103.55		(38,520		)	(38,067		)	453
Futures-short (Gasoline)	(165,000	)	—		113.72		(18,764		)	(18,213		)	551
Futures-short (Distillate)	(60,000	)	—		131.32		(7,879		)	(7,488		)	391

Interest Rate Risk

As of September 30, 2013, our outstanding debt balance of approximately $328.1 million, excluding discounts, was subject to floating interest rates. Approximately $248.1 million was charged interest at the Eurodollar rate (with a floor of 1.25%) plus a margin of 8.00% and approximately $80.0 million was charged interest at the Eurodollar rate plus 3.5%, subject to a minimum interest rate of 4.0%.

An increase of 1% in the Eurodollar rate on indebtedness would result in an increase in our interest expense of approximately $0.5 million per year.

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ITEM 4. CONTROLS AND PROCEDURES

(1) Disclosure controls and procedures.

Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as amended (the “Exchange Act”)) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or furnish under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or 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.

The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring companies to file reports with the SEC to include a management report on such company's internal control over financial reporting in its annual report. In addition, our independent registered public accounting firm must attest to our internal control over financial reporting. Our first Annual Report on Form 10-K did not include a report of management's assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to new public companies. Management will be required to provide an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2013.

(2) Changes in internal control over financial reporting.

There has been no change in our internal control over financial reporting (as described in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 6. EXHIBITS

Exhibit
Number	Description of Exhibit
31.1	Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2	Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
101	The following financial information from Alon USA Partners, LP’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows and (iv) Notes to the Consolidated Financial Statements.

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SIGNATURES

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

		Alon USA Partners, LP
		By:	Alon USA Partners GP, LLC
			its general partner
Date:	November 8, 2013	By:	/s/ David Wiessman
			David Wiessman
			Executive Chairman of the Board
Date:	November 8, 2013	By:	/s/ Paul Eisman
			Paul Eisman
			President, Chief Executive Officer and Director
Date:	November 8, 2013	By:	/s/ Shai Even
			Shai Even
			Senior Vice President and Chief Financial Officer
			(Principal Accounting Officer)

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EXHIBITS

Exhibit
Number	Description of Exhibit
31.1	Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2	Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
101	The following financial information from Alon USA Partners, LP’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows and (iv) Notes to the Consolidated Financial Statements.

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