UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

        

____________

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) of the

Securities Exchange Act of 1934

Date of report (Date of earliest event reported): August 6, 2014

ALON USA PARTNERS, LP

(Exact Name of Registrant as Specified in Charter)

Delaware (State or Other Jurisdiction of Incorporation)	001-35742 (Commission File Number)	46-0810241 (IRS Employer Identification No.)

12700 Park Central Dr., Suite 1600

Dallas, Texas 75251

(Address of Principal Executive Offices) (Zip Code)

Registrant's telephone number, including area code: (972) 367-3600

____________________________

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

        

o		Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o		Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o		Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o		Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

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Item 2.02.  Results of Operations and Financial Condition.

On August 6, 2014, Alon USA Partners, LP (the “Partnership”) issued a press release (the “Press Release”) reporting its financial results for the quarter ended June 30, 2014. A copy of the Press Release is furnished as Exhibit 99.1 to this Current Report on Form 8-K, and is incorporated by reference into this Item 2.02.

Item 9.01. Financial Statements and Exhibits.

(d)    Exhibits.

Exhibit Number		Description
99.1		Press Release dated August 6, 2014.

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SIGNATURE

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 hereunto duly authorized.

		Alon USA Partners, LP
		By:	Alon USA Partners GP, LLC
			its general partner
Date:	August 6, 2014	By:	/s/ Shai Even
			Shai Even
			Senior Vice President and Chief Financial Officer

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INDEX TO EXHIBITS

Exhibit Number		Description
99.1		Press Release dated August 6, 2014.

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	NEWS RELEASE
	Contacts:	Stacey Hudson, Investor Relations Manager Alon USA Partners GP, LLC 972-367-3808
FOR IMMEDIATE RELEASE
		Investors: Jack Lascar Dennard § Lascar Associates, LLC 713-529-6600 Media: Blake Lewis Lewis Public Relations 214-635-3020 Ruth Sheetrit SMG Public Relations 011-972-547-555551

Alon USA Partners, LP Reports Second Quarter 2014 Results and Declares Quarterly Cash Distribution

Schedules conference call for August 8, 2014 at 10:00 a.m. Eastern

DALLAS, TEXAS, August 6, 2014 - Alon USA Partners, LP (NYSE: ALDW) (“Alon Partners”) today announced results for the second quarter of 2014. Net income for the second quarter of 2014 was $7.8 million, or $0.12 per unit, compared to $45.3 million, or $0.73 per unit, for the same period last year. Net income for the first half of 2014 was $50.0 million, or $0.80 per unit, compared to $138.8 million, or $2.22 per unit, for the same period last year.

The Board of Directors of Alon USA Partners GP, LLC, the general partner of Alon Partners, declared a cash distribution for the second quarter of 2014 of $0.13 per unit payable on August 25, 2014 to common unitholders of record at the close of business on August 18, 2014, based on cash available for distribution of $8.4 million.

Paul Eisman, CEO and President, commented, “During the second quarter we completed the planned major turnaround of the Big Spring refinery while also completing the vacuum tower revamp project. The turnaround and the vacuum tower revamp project allow us to increase the refinery’s crude throughput by 3,000 barrels per day to 73,000 barrels per day. In addition, the distillate recovery and energy savings resulting from the vacuum tower revamp project are exceeding expectations as distillate yield has increased by more than 3,000 barrels per day. This will drive improvement in our margin capture rate going forward.

“The turnaround was challenging given its very significant scope. The turnaround duration was impacted by difficult weather conditions and a longer than expected maintenance period particularly in the FCC. This resulted in lower throughput than planned in the second quarter. However, we were very pleased with the good safety performance of our people and our contractors during the turnaround. We’ve also been encouraged by the operating performance of the refinery since the turnaround.

“Looking forward, we expect to operate the Big Spring refinery at a total throughput of 74,000 barrels per day in the third quarter and 75,000 barrels per day in the fourth quarter. We also expect to fully take advantage of the distillate recovery and energy savings benefits of the vacuum tower revamp project. The profitability of the Big Spring refinery should be supported in the third quarter by widening differentials for Midland-priced crude oil. Midland-priced crudes traded at attractive discounts to WTI Cushing in June and July, which will positively affect the cost of crude and refinery operating margin at our Big Spring refinery in the third quarter. The WTI Cushing to WTI Midland differentials that will favorably affect the cost of crude for July and August averaged $8.59 per barrel.”

SECOND QUARTER 2014

Refinery operating margin was $17.04 per barrel for the second quarter of 2014 compared to $14.99 per barrel for the same period in 2013. This increase in operating margin was primarily due to a widening of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread, partially offset by lower Gulf Coast 3/2/1 crack spreads. The refinery’s throughput for the second quarter of 2014 averaged 38,994 barrels per day (“bpd”) compared to 72,124 bpd for the same period in 2013. The lower throughput rate during the second quarter of 2014 was due to our planned turnaround that was completed in June

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2014. Also impacting the refinery operating margin for the second quarter of 2014 were RINs credits of $0.8 million, generated as a result of reduced production during the planned turnaround, compared to RINs costs of $8.0 million for the second quarter of 2013.

The average Gulf Coast 3/2/1 crack spread was $16.42 per barrel for the second quarter of 2014 compared to $21.17 per barrel for the second quarter of 2013, which was influenced by a reduction in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for the second quarter of 2014 was $7.56 per barrel compared to $12.51 per barrel for the same period in 2013. The average WTI Cushing to WTS spread for the second quarter of 2014 was $7.88 per barrel compared to $0.36 per barrel for the second quarter of 2013. The average WTI Cushing to WTI Midland spread for the second quarter of 2014 was $8.37 per barrel compared to $0.14 per barrel for the second quarter of 2013.

YEAR-TO-DATE 2014

Refinery operating margin was $15.56 per barrel for the first half of 2014 compared to $21.18 per barrel for the same period in 2013. This decrease was primarily due to a lower Gulf Coast 3/2/1 crack spread, partially offset by a widening WTI Cushing to WTI Midland spread. The refinery’s throughput for the first half of 2014 averaged 56,050 bpd compared to 65,835 bpd for the same period in 2013. Also impacting refinery operating margin was $2.2 million of costs associated with RINs obligations for the first half of 2014, compared to $8.0 million for the first half of 2013.

The average Gulf Coast 3/2/1 crack spread was $16.61 per barrel for the first half of 2014 compared to $24.76 per barrel for the same period in 2013, which was primarily influenced by a reduction in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for the first half of 2014 was $10.25 per barrel compared to $16.98 per barrel for the same period in 2013. The average WTI Cushing to WTI Midland spread for the first half of 2014 was $5.96 per barrel compared to $3.91 per barrel for the same period in 2013.

CONFERENCE CALL

Alon Partners has scheduled a conference call which will also be webcast live on Friday, August 8, 2014 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time), to discuss the second quarter 2014 results. To access the call, please dial 888-438-5519, or 719-325-2393 for international callers, at least 10 minutes prior to the start time and ask for the Alon Partners call. Investors may also listen to the conference live by logging on to the Alon Partners' website, http://www.alonpartners.com. A telephonic replay of the conference call will be available through August 22, 2014, and may be accessed by calling 888-203-1112, or 719-457-0820 for international callers, and using the passcode 6155917#. The archived webcast will also be available at http://www.alonpartners.com shortly after the call and will be accessible for approximately 90 days. For more information, please contact Donna Washburn at Dennard § Lascar Associates at 713-529-6600 or email dwashburn@dennardlascar.com.

This release serves as qualified notice to nominees under Treasury Regulation Section 1.1446-4(b). Please note that 100% of Alon Partners’ distributions to foreign investors are attributable to income that is effectively connected with a United States trade or business. Accordingly, all of Alon Partners’ distributions to foreign investors are subject to federal income tax withholding at the highest effective tax rate for individuals or corporations, as applicable. Nominees, and not Alon Partners, are treated as the withholding agents responsible for withholding on the distributions received by them on behalf of foreign investors.

Any statements in this release that are not statements of historical fact are forward-looking statements. Forward-looking statements reflect our current expectations regarding 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. Additional information regarding these and other risks is contained in our filings with the Securities and Exchange Commission.

Alon USA Partners, LP is a Delaware limited partnership formed in August 2012 by Alon USA Energy, Inc. (“Alon Energy”) (NYSE: ALJ). Alon Partners owns and operates a crude oil refinery in Big Spring, Texas with total crude oil throughput capacity of approximately 73,000 barrels per day. Alon Partners refines crude oil into finished products, which are marketed primarily in West Texas, Central Texas, Oklahoma, New Mexico and Arizona through its wholesale distribution network to both Alon Energy’s retail convenience stores and other third-party distributors.

- Tables to follow -

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ALON USA PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED

EARNINGS RELEASE

RESULTS OF OPERATIONS - FINANCIAL DATA (ALL INFORMATION IN THIS PRESS RELEASE EXCEPT FOR BALANCE SHEET DATA AS OF DECEMBER 31, 2013, IS UNAUDITED)	For the Three Months Ended								For the Six Months Ended
	June 30,								June 30,
	2014				2013				2014				2013
	(dollars in thousands, except per unit data, per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	725,852			$	865,694			$	1,582,312			$	1,669,861
Operating costs and expenses:
Cost of sales	665,398				767,322				1,424,444				1,417,525
Direct operating expenses	25,152				27,314				54,093				57,736
Selling, general and administrative expenses	6,784				5,065				11,152				12,730
Depreciation and amortization	9,508				11,243				19,575				23,307
Total operating costs and expenses	706,842				810,944				1,509,264				1,511,298
Operating income	19,010				54,750				73,048				158,563
Interest expense	(11,569		)		(8,970		)		(22,893		)		(18,362		)
Other income, net	601				14				613				18
Income before state income tax expense	8,042				45,794				50,768				140,219
State income tax expense	240				473				725				1,373
Net income	$	7,802			$	45,321			$	50,043			$	138,846
Earnings per unit	$	0.12			$	0.73			$	0.80			$	2.22
Weighted average common units outstanding (in thousands)	62,504				62,502				62,504				62,502
Cash distribution per unit	$	0.69			$	1.48			$	0.87			$	2.05
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	(35	)		$	(13,403	)		$	45,232			$	153,243
Investing activities	(18,259		)		(7,257		)		(36,886		)		(13,976		)
Financing activities	(68,955		)		(143,128		)		(80,830		)		(178,584		)
OTHER DATA:
Adjusted EBITDA (2)	$	29,119			$	66,007			$	93,236			$	181,888
Capital expenditures	7,277				6,216				11,439				9,157
Capital expenditures for turnarounds and catalysts	10,982				1,041				25,447				4,819
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin (3)	$	17.04			$	14.99			$	15.56			$	21.18
Refinery direct operating expense (4)	7.09				4.16				5.33				4.85
PRICING STATISTICS:
Crack spreads (per barrel):
Gulf Coast 3/2/1 (5)	$	16.42			$	21.17			$	16.61			$	24.76
WTI Cushing crude oil (per barrel)	$	103.04			$	94.20			$	100.86			$	94.23
Crude oil differentials (per barrel):
WTI Cushing less WTI Midland (6)	$	8.37			$	0.14			$	5.96			$	3.91
WTI Cushing less WTS (6)	7.88				0.36				5.79				5.86
Brent less WTI Cushing (6)	7.56				12.51				10.25				16.98
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	2.81			$	2.69			$	2.73			$	2.77
Gulf Coast ultra-low sulfur diesel	2.92				2.86				2.93				2.97
Natural gas (per MMBtu)	4.58				4.02				4.65				3.76

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	June 30, 2014				December 31, 2013
BALANCE SHEET DATA (end of period):	(dollars in thousands)
Cash and cash equivalents	$	81,099			$	153,583
Working capital	(17,346		)		18,007
Total assets	812,323				849,924
Total debt	343,344				344,322
Total debt less cash and cash equivalents	262,245				190,739
Total partners’ equity	141,145				145,442

THROUGHPUT AND PRODUCTION DATA:	For the Three Months Ended												For the Six Months Ended
	June 30,												June 30,
	2014						2013						2014						2013
	bpd			%			bpd			%			bpd			%			bpd			%
Refinery throughput:
WTS crude	12,634			32.4			53,627			74.4			23,927			42.7			49,446			75.1
WTI crude	23,391			60.0			17,180			23.8			29,652			52.9			14,380			21.8
Blendstocks	2,969			7.6			1,317			1.8			2,471			4.4			2,009			3.1
Total refinery throughput (7)	38,994			100.0			72,124			100.0			56,050			100.0			65,835			100.0
Refinery production:
Gasoline	17,484			45.1			35,057			48.7			26,835			48.0			32,436			49.4
Diesel/jet	12,315			31.8			24,748			34.4			18,461			33.0			22,038			33.6
Asphalt	1,660			4.3			4,453			6.2			2,529			4.5			3,909			6.0
Petrochemicals	1,825			4.7			4,628			6.4			3,111			5.5			4,179			6.4
Other	5,483			14.1			3,088			4.3			5,022			9.0			3,029			4.6
Total refinery production (8)	38,767			100.0			71,974			100.0			55,958			100.0			65,591			100.0
Refinery utilization (9)				85.4	%					101.2	%					95.7	%					97.1	%

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CASH AVAILABLE FOR DISTRIBUTION DATA:		For the Three Months Ended
		June 30, 2014
		(dollars in thousands, except per unit data)
Net sales (1)		$	725,852
Operating costs and expenses:
Cost of sales		665,398
Direct operating expenses		25,152
Selling, general and administrative expenses		6,784
Depreciation and amortization		9,508
Total operating costs and expenses		706,842
Operating income		19,010
Interest expense		(11,569		)
Other income, net		601
Income before state income tax expense		8,042
State income tax expense		240
Net income		7,802
Adjustments to reconcile net income to Adjusted EBITDA:
Interest expense		11,569
State income tax expense		240
Depreciation and amortization		9,508
Adjusted EBITDA (2)		29,119
Adjustments to reconcile Adjusted EBITDA to cash available for distribution:
less: Maintenance/growth capital expenditures		7,277
less: Major and non-major turnaround and catalyst replacement capital expenditures		10,982
add: Major turnaround and catalyst replacement capital expenditures previously reserved		(11,011		)
less: Major turnaround reserve for future years		1,500
less: Principal payments		625
less: State income tax expense		240
less: Interest paid in cash		11,106
Cash available for distribution		$	8,400
Common units outstanding (in 000’s)		62,507
Cash available for distribution per unit		$	0.13

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(1)	Includes sales to related parties of $152,170 and $156,043 for the three months and $291,183 and $297,942 for the six months ended June 30, 2014 and 2013, 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.

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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.

The following table reconciles net income to Adjusted EBITDA for the three and six months ended June 30, 2014 and 2013:

	For the Three Months Ended								For the Six Months Ended
	June 30,								June 30,
	2014				2013				2014				2013
	(dollars in thousands)
Net income	$	7,802			$	45,321			$	50,043			$	138,846
State income tax expense	240				473				725				1,373
Interest expense	11,569				8,970				22,893				18,362
Depreciation and amortization	9,508				11,243				19,575				23,307
Adjusted EBITDA	$	29,119			$	66,007			$	93,236			$	181,888

(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)	We compare our refinery operating margin to the Gulf Coast 3/2/1 crack spread. 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.

(6)

The WTI Cushing less WTI Midland spread represents the differential between the average price per barrel of WTI Cushing crude oil and the average price per barrel of WTI Midland crude oil. The WTI Cushing less WTS, or sweet/sour, spread represents the differential between the average price per barrel of WTI Cushing crude oil and the average price per barrel of WTS crude oil. The Brent less WTI Cushing spread represents the differential between the average price per barrel of Brent crude oil and the average price per barrel of WTI Cushing crude oil.

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

(8)	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.

(9)	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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