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

Schedules conference call for October 31, 2014 at 10:00 a.m. Eastern

DALLAS, Oct. 29, 2014 /PRNewswire/ -- Alon USA Partners, LP ALDW ("Alon Partners") today announced results for the third quarter of 2014. Net income for the third quarter of 2014 was $77.0 million, or $1.23 per unit, compared to net loss of $(16.1) million, or $(0.26) per unit, for the same period last year. Net income for the first nine months of 2014 was $127.0 million, or $2.03 per unit, compared to $122.7 million, or $1.96 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 third quarter of 2014 of $1.02 per unit payable on November 28, 2014 to common unitholders of record at the close of business on November 10, 2014, based on cash available for distribution of $63.6 million.

Paul Eisman, President and CEO, commented, "Our third quarter results reflect excellent operational performance at the Big Spring refinery resulting in a record total refinery throughput of 74,800 barrels per day. In addition, as a result of the completion of the vacuum tower project during the recent turnaround, the refinery increased its distillate yield by 5% in the third quarter of 2014 as compared to the distillate yield achieved in the same quarter last year.

"The Big Spring refinery's operational performance for the third quarter was complemented by strong refinery operating margin of almost $20 per barrel. The operating margin was driven primarily by record combined gasoline and distillate yield of almost 88%, liquid recovery of over 100% as well as wide discounts in Midland-priced crudes. The third quarter operational performance also led to direct operating expense of only $3.74 per barrel. These were the key contributors to adjusted EBITDA for the third quarter of over $103 million resulting in cash available for distribution of over $1 per unit.

"Looking forward, we expect total throughput at the Big Spring refinery for the fourth quarter to be 75,000 barrels per day."

THIRD QUARTER 2014

Refinery operating margin was $19.98 per barrel for the third quarter of 2014 compared to $6.46 per barrel for the same period in 2013. This increase in operating margin was primarily due to a higher Gulf Coast 3/2/1 crack spread and a widening of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread. The total refinery throughput for the third quarter of 2014 averaged 74,838 barrels per day ("bpd") compared to 63,090 bpd for the same period in 2013. The increased throughput rate was due to the completion of both the planned turnaround and the vacuum tower project during the second quarter of 2014 and the impact of unplanned downtime at our refinery during the third quarter of 2013.

The average Gulf Coast 3/2/1 crack spread was $15.90 per barrel for the third quarter of 2014 compared to $14.23 per barrel for the third quarter of 2013. The average WTI Cushing to WTS spread for the third quarter of 2014 was $8.14 per barrel compared to $0.08 per barrel for the third quarter of 2013. The average WTI Cushing to WTI Midland spread for the third quarter of 2014 was $9.93 per barrel compared to $0.27 per barrel for the third quarter of 2013.

YEAR-TO-DATE 2014

Refinery operating margin was $17.35 per barrel for the first nine months of 2014 compared to $16.35 per barrel for the same period in 2013. This increase 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 a lower Gulf Coast 3/2/1 crack spread. The total refinery throughput for the first nine months of 2014 averaged 62,382 bpd compared to 64,910 bpd for the same period in 2013. The reduced throughput during the first nine months of 2014 was the result of completing both the planned turnaround and the vacuum tower project at our refinery in the second quarter.

The average Gulf Coast 3/2/1 crack spread was $16.37 per barrel for the first nine months of 2014 compared to $21.21 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 nine months of 2014 was $8.52 per barrel compared to $13.25 per barrel for the same period in 2013. The average WTI Cushing to WTS spread for the first nine months of 2014 was $6.58 per barrel compared to $3.91 per barrel for the same period in 2013. The average WTI Cushing to WTI Midland spread for the first nine months of 2014 was $7.31 per barrel compared to $2.69 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, October 31, 2014 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time), to discuss the third quarter 2014 results. To access the call, please dial 888-427-9419, or 719-785-1753 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 November 14, 2014, and may be accessed by calling 888-203-1112, or 719-457-0820 for international callers, and using the passcode 7180601#. 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") 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 -

Contacts:

Stacey Hudson, Investor Relations Manager

Alon USA Partners GP, LLC

972-367-3808

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 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 Nine Months Ended
	September 30,				September 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)	$	838,882	$	881,902	$	2,421,194	$	2,551,763
Operating costs and expenses:
Cost of sales	701,331		844,423		2,125,775		2,261,948
Direct operating expenses	25,723		26,281		79,816		84,017
Selling, general and administrative expenses	8,353		4,134		19,505		16,864
Depreciation and amortization	13,852		10,975		33,427		34,282
Total operating costs and expenses	749,259		885,813		2,258,523		2,397,111
Loss on disposition of assets	—		(21)		—		(21)
Operating income (loss)	89,623		(3,932)		162,671		154,631
Interest expense	(11,584)		(12,127)		(34,477)		(30,489)
Other income, net	14		—		627		18
Income (loss) before state income tax expense	78,053		(16,059)		128,821		124,160
State income tax expense	1,060		61		1,785		1,434
Net income (loss)	$	76,993	$	(16,120)	$	127,036	$	122,726
Earnings (loss) per unit	$	1.23	$	(0.26)	$	2.03	$	1.96
Weighted average common units outstanding (in thousands)	62,507		62,502		62,505		62,502
Cash distribution per unit	$	0.13	$	0.71	$	1.00	$	2.76
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	94,142	$	6,476	$	139,374	$	159,719
Investing activities	(26,195)		(7,682)		(63,081)		(21,658)
Financing activities	(33,751)		34,998		(114,581)		(143,586)
OTHER DATA:
Adjusted EBITDA (2)	$	103,489	$	7,064	$	196,725	$	188,952
Capital expenditures	2,492		7,477		13,931		16,634
Capital expenditures for turnarounds and catalysts	23,703		205		49,150		5,024
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin (3)	$	19.98	$	6.46	$	17.35	$	16.35
Refinery direct operating expense (4)	3.74		4.53		4.69		4.74
PRICING STATISTICS:
Crack spreads (per barrel):
Gulf Coast 3/2/1 (5)	$	15.90	$	14.23	$	16.37	$	21.21
WTI Cushing crude oil (per barrel)	$	97.55	$	105.82	$	99.74	$	98.14
Crude oil differentials (per barrel):
WTI Cushing less WTI Midland (6)	$	9.93	$	0.27	$	7.31	$	2.69
WTI Cushing less WTS (6)	8.14		0.08		6.58		3.91
Brent less WTI Cushing (6)	5.13		5.91		8.52		13.25
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	2.65	$	2.78	$	2.71	$	2.77
Gulf Coast ultra-low sulfur diesel	2.80		3.02		2.88		2.99
Natural gas (per MMBtu)	3.95		3.56		4.41		3.69

	September 30, 2014		December 31, 2013
BALANCE SHEET DATA (end of period):	(dollars in thousands)
Cash and cash equivalents	$	115,295	$	153,583
Working capital	10,796		18,007
Total assets	842,435		849,924
Total debt	292,858		344,322
Total debt less cash and cash equivalents	177,563		190,739
Total partners' equity	210,028		145,442

THROUGHPUT AND PRODUCTION DATA:	For the Three Months Ended						For the Nine Months Ended
THROUGHPUT AND PRODUCTION DATA:	September 30,						September 30,
	2014			2013			2014			2013
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
WTS crude	37,566	50.2		36,340	57.6		28,524	45.7		45,029	69.3
WTI crude	34,633	46.3		25,169	39.9		31,330	50.2		18,016	27.8
Blendstocks	2,639	3.5		1,581	2.5		2,528	4.1		1,865	2.9
Total refinery throughput (7)	74,838	100.0		63,090	100.0		62,382	100.0		64,910	100.0
Refinery production:
Gasoline	36,842	49.0		30,861	49.2		30,207	48.4		31,905	49.4
Diesel/jet	28,857	38.4		20,999	33.4		21,964	35.2		21,688	33.5
Asphalt	3,052	4.1		3,312	5.3		2,705	4.3		3,708	5.7
Petrochemicals	4,305	5.7		3,599	5.7		3,514	5.6		3,984	6.2
Other	2,078	2.8		4,045	6.4		4,030	6.5		3,371	5.2
Total refinery production (8)	75,134	100.0		62,816	100.0		62,420	100.0		64,656	100.0
Refinery utilization (9)		98.9	%		87.9	%		97.0	%		93.8	%



CASH AVAILABLE FOR DISTRIBUTION DATA:	For the Three Months Ended
	September 30, 2014
	(dollars in thousands, except per unit data)

Net sales (1)	$	838,882
Operating costs and expenses:
Cost of sales	701,331
Direct operating expenses	25,723
Selling, general and administrative expenses	8,353
Depreciation and amortization	13,852
Total operating costs and expenses	749,259
Operating income	89,623
Interest expense	(11,584)
Other income, net	14
Income before state income tax expense	78,053
State income tax expense	1,060
Net income	76,993
Adjustments to reconcile net income to Adjusted EBITDA:
Interest expense	11,584
State income tax expense	1,060
Depreciation and amortization	13,852
Adjusted EBITDA (2)	103,489
Adjustments to reconcile Adjusted EBITDA to cash available for distribution:
less: Maintenance/growth capital expenditures	2,492
less: Major and non-major turnaround and catalyst replacement capital expenditures	23,703
less: Major turnaround reserve for future years	1,500
less: Principal payments	625
less: State income tax expense	1,060
less: Interest paid in cash	10,542
Cash available for distribution	$	63,567

Common units outstanding (in 000's)	62,507

Cash available for distribution per unit	$	1.02

________________

(1)	Includes sales to related parties of $156,131 and $164,338 for the three months and $447,314 and $462,280 for the nine months ended September 30, 2014 and 2013, 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 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 nine months ended September 30, 2014 and 2013:


	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
	(dollars in thousands)
Net income (loss)	$	76,993	$	(16,120)	$	127,036	$	122,726
State income tax expense	1,060		61		1,785		1,434
Interest expense	11,584		12,127		34,477		30,489
Depreciation and amortization	13,852		10,975		33,427		34,282
Loss on disposition of assets	—		21		—		21
Adjusted EBITDA	$	103,489	$	7,064	$	196,725	$	188,952


(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.

SOURCE Alon USA Partners, LP

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