Alon USA Partners, LP Reports Third Quarter 2016 Results and Declares Quarterly Cash Distribution

Schedules conference call for October 28, 2016 at 9:30 a.m. Eastern

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Oct 26, 2016, 06:07 ET

DALLAS, Oct. 26, 2016 /PRNewswire/ -- Alon USA Partners, LP (NYSE: ALDW) ("Alon Partners") today announced results for the third quarter of 2016. Net income for the third quarter of 2016 was $2.1 million, or $0.03 per unit, compared to $53.8 million, or $0.86 per unit, for the same period last year. Net loss for the first nine months of 2016 was $(5.3) million, or $(0.08) per unit, compared to net income of $149.7 million, or $2.39 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 2016 of $0.15 per unit payable on November 22, 2016 to common unitholders of record at the close of business on November 11, 2016, based on cash available for distribution of $9.4 million.

Paul Eisman, President and CEO commented, "Our third quarter results reflect a continuation of the difficult refining environment experienced in the first two quarters of 2016. While crack spreads were relatively flat with the second quarter of 2016, the average benchmark crack spread in the third quarter was down approximately $6.50 per barrel relative to the same quarter last year. As discussed in our previous earnings release, our third quarter results were also negatively impacted by a reformer regeneration in August. We estimate that the lost opportunity cost and maintenance expense associated with the reformer regeneration negatively impacted Alon Partners' adjusted EBITDA by approximately $8 million which reduced cash available for distribution by $0.13 per unit for the third quarter. Additionally, high RINs costs continue to weigh on our profitability.

"The Big Spring refinery achieved total throughput of 70,000 barrels per day and generated refinery operating margin of $9.22 per barrel. Our direct operating expense of $3.90 per barrel was negatively impacted by the reformer regeneration, which lowered throughput volumes and increased maintenance expense. We expect total throughput to average approximately 77,000 barrels per day for the fourth quarter of 2016. Based on current forward curve crack spreads, it is our expectation that with operations consistent with our plan we should generate sufficient cash available for distribution during the fourth quarter of 2016."

THIRD QUARTER 2016

Refinery operating margin was $9.22 per barrel for the third quarter of 2016 compared to $16.71 per barrel for the same period in 2015. This decrease in operating margin was primarily due to a lower Gulf Coast 3/2/1 crack spread and increased RINs costs, partially offset by a widening of both the WTI Cushing to WTI Midland and WTI Cushing to WTS spreads and an increased benefit from the contango market environment which reduced the cost of crude. Refinery average throughput for the third quarter of 2016 was 70,063 barrels per day ("bpd") compared to 75,797 bpd for the same period in 2015. The reduced throughput was the result of a reformer regeneration during the third quarter of 2016.

The average Gulf Coast 3/2/1 crack spread was $13.31 per barrel for the third quarter of 2016 compared to $19.77 per barrel for the third quarter of 2015. The average WTI Cushing to WTI Midland spread for the third quarter of 2016 was $0.31 per barrel compared to $(0.72) per barrel for the third quarter of 2015. The average WTI Cushing to WTS spread for the third quarter of 2016 was $0.92 per barrel compared to $(1.46) per barrel for the third quarter of 2015. The average Brent to WTI Cushing spread for the third quarter of 2016 was $0.74 per barrel compared to $3.78 per barrel for the same period in 2015. The contango environment in the third quarter of 2016 created an average cost of crude benefit of $0.84 per barrel compared to an average cost of crude benefit of $0.57 per barrel for the same period in 2015. The average RINs cost effect on refinery operating margin was $0.58 per barrel in the third quarter of 2016, compared to $0.27 per barrel for the same period in 2015.

YEAR-TO-DATE 2016

Refinery operating margin was $8.52 per barrel for the first nine months of 2016 compared to $15.95 per barrel for the same period in 2015. This decrease in operating margin was primarily due to a lower Gulf Coast 3/2/1 crack spread and a narrowing of the WTI Cushing to WTI Midland spread, partially offset by a widening of the WTI Cushing to WTS spread and an increased benefit from the contango market environment which reduced the cost of crude. Refinery average throughput for the first nine months of 2016 was 69,586 bpd compared to 74,562 bpd for the same period in 2015. The reduced throughput during the first nine months of 2016 was the result of a reformer regeneration during the first quarter of 2016, which was repeated during the third quarter of 2016. Additionally, throughput was reduced as a result of a catalyst replacement for our diesel hydrotreater unit in the first quarter of 2016 and unplanned downtime during the second quarter of 2016 due to a power outage caused by inclement weather, which affected multiple units.

The average Gulf Coast 3/2/1 crack spread was $12.57 per barrel for the first nine months of 2016 compared to $19.08 per barrel for the same period in 2015. The average WTI Cushing to WTI Midland spread for the first nine months of 2016 was $0.12 per barrel compared to $0.60 per barrel for the same period in 2015. The average WTI Cushing to WTS spread for the first nine months of 2016 was $0.53 per barrel compared to $0.02 per barrel for the same period in 2015. The average Brent to WTI Cushing spread for the first nine months of 2016 was $0.35 per barrel compared to $4.28 per barrel for the same period in 2015. The contango environment for the first nine months of 2016 created an average cost of crude benefit of $1.39 per barrel compared to an average cost of crude benefit of $1.04 per barrel for the same period in 2015.

CONFERENCE CALL

Alon Partners has scheduled a conference call, which will be broadcast live over the Internet on Friday, October 28, 2016 at 9:30 a.m. Eastern Time (8:30 a.m. Central Time), to discuss the third quarter 2016 financial results. To access the call, please dial 877-404-9648, or 412-902-0030 for international callers, and ask for the Alon Partners call at least 10 minutes prior to the start time. Investors may also listen to the conference live by logging on to the Alon Partners website at www.alonpartners.com. A telephonic replay of the conference call will be available through November 4, 2016 and may be accessed by calling 877-660-6853, or 201-612-7415 for international callers, and using the passcode 13646174#. A webcast archive will also be available at 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 [email protected].

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. (NYSE: ALJ) ("Alon Energy"). Alon Partners owns and operates a crude oil refinery in Big Spring, Texas, with a crude oil throughput capacity of 73,000 barrels per day. Alon Partners refines crude oil into finished products, which are marketed primarily in Central and West Texas, Oklahoma, New Mexico and Arizona through its integrated wholesale distribution network to both Alon Energy's retail convenience stores and other third-party distributors.

Contacts:

Stacey Morris, 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

- Tables to follow -

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, 2015, IS UNAUDITED)	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(dollars in thousands, except per unit data, per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)	$	462,257	$	551,813	$	1,298,723	$	1,719,319
Operating costs and expenses:
Cost of sales	404,207		439,678		1,134,275		1,397,395
Direct operating expenses	25,125		24,136		73,424		71,837
Selling, general and administrative expenses	8,153		8,536		24,264		24,654
Depreciation and amortization	14,581		13,697		43,454		41,281
Total operating costs and expenses	452,066		486,047		1,275,417		1,535,167
Operating income	10,191		65,766		23,306		184,152
Interest expense	(8,144)		(11,505)		(28,651)		(34,045)
Other income, net	353		40		550		26
Income (loss) before state income tax expense	2,400		54,301		(4,795)		150,133
State income tax expense	317		525		493		480
Net income (loss)	$	2,083	$	53,776	$	(5,288)	$	149,653
Earnings (loss) per unit	$	0.03	$	0.86	$	(0.08)	$	2.39
Weighted average common units outstanding (in thousands)	62,520		62,510		62,515		62,508
Cash distribution per unit	$	0.14	$	1.04	$	0.22	$	2.45
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	11,870	$	84,834	$	58,457	$	219,232
Investing activities	(5,954)		(5,532)		(26,878)		(15,322)
Financing activities	36,027		(93,908)		39,231		(174,957)
OTHER DATA:
Adjusted EBITDA (2)	$	25,125	$	79,503	$	67,310	$	225,459
Capital expenditures	4,499		4,322		17,199		12,108
Capital expenditures for turnarounds and catalysts	1,455		1,210		9,679		3,214
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin (3)	$	9.22	$	16.71	$	8.52	$	15.95
Refinery direct operating expense (4)	3.90		3.46		3.85		3.53
PRICING STATISTICS:
Crack spreads (per barrel):
Gulf Coast 3/2/1 (5)	$	13.31	$	19.77	$	12.57	$	19.08
WTI Cushing crude oil (per barrel)	$	44.88	$	46.41	$	41.23	$	50.91
Crude oil differentials (per barrel):
WTI Cushing less WTI Midland (6)	$	0.31	$	(0.72)	$	0.12	$	0.60
WTI Cushing less WTS (6)	0.92		(1.46)		0.53		0.02
Brent less WTI Cushing (6)	0.74		3.78		0.35		4.28
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	1.39	$	1.61	$	1.30	$	1.66
Gulf Coast ultra-low sulfur diesel	1.37		1.52		1.25		1.68
Natural gas (per MMBtu)	2.79		2.73		2.34		2.76


									September 30, 2016				December 31, 2015
BALANCE SHEET DATA (end of period):									(dollars in thousands)
Cash and cash equivalents									$	203,763			$	132,953
Working capital									10,460				(53,804)
Total assets									825,050				748,584
Total debt									291,486				292,082
Total debt less cash and cash equivalents									87,723				159,129
Total partners' equity									111,968				130,957


THROUGHPUT AND PRODUCTION DATA:	For the Three Months Ended						For the Nine Months Ended
THROUGHPUT AND PRODUCTION DATA:	September 30,						September 30,
	2016			2015			2016					2015
	bpd	%		bpd	%		bpd	%			bpd				%
Refinery throughput:
WTS crude	34,292	48.9		30,810	40.6		32,189	46.3			35,041				47.0
WTI crude	32,503	46.4		42,503	56.1		34,428	49.4			36,834				49.4
Blendstocks	3,268	4.7		2,484	3.3		2,969	4.3			2,687				3.6
Total refinery throughput (7)	70,063	100.0		75,797	100.0		69,586	100.0			74,562				100.0
Refinery production:
Gasoline	33,637	48.1		37,503	49.5		33,826	48.7			37,155				49.6
Diesel/jet	26,004	37.2		28,623	37.8		25,108	36.1			27,596				36.9
Asphalt	2,818	4.0		2,452	3.2		2,846	4.1			2,733				3.7
Petrochemicals	3,861	5.5		4,588	6.1		3,611	5.2			4,770				6.4
Other	3,661	5.2		2,595	3.4		4,084	5.9			2,510				3.4
Total refinery production (8)	69,981	100.0		75,761	100.0		69,475	100.0			74,764				100.0
Refinery utilization (9)		99.1	%		100.4	%		95.5	%						98.5	%



CASH AVAILABLE FOR DISTRIBUTION DATA:	For the Three Months Ended
	September 30, 2016
	(dollars in thousands, except per unit data)

Net sales (1)	$	462,257
Operating costs and expenses:
Cost of sales	404,207
Direct operating expenses	25,125
Selling, general and administrative expenses	8,153
Depreciation and amortization	14,581
Total operating costs and expenses	452,066
Operating income	10,191
Interest expense	(8,144)
Other income, net	353
Income before state income tax expense	2,400
State income tax expense	317
Net income	2,083
Adjustments to reconcile net loss to Adjusted EBITDA:
Interest expense	8,144
State income tax expense	317
Depreciation and amortization	14,581
Adjusted EBITDA (2)	25,125
Adjustments to reconcile Adjusted EBITDA to cash available for distribution:
less: Maintenance/growth capital expenditures	4,499
less: Turnaround and catalyst replacement capital expenditures	1,455
less: Major turnaround reserve for future years	1,500
less: Principal payments	625
less: State income tax payments	317
less: Interest paid in cash	7,337
Calculated cash available for distribution	$	9,392

Common units outstanding (in 000's)	62,520

Cash available for distribution per unit	$	0.15

________________

(1)

Includes sales to related parties of $82,717 and $97,014 for the three months ended September 30, 2016 and 2015, respectively, and $222,711 and $281,136 for the nine months ended September 30, 2016 and 2015, respectively.

(2)

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

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

•

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

•

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

•

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

•

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

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

The following table reconciles net income (loss) to Adjusted EBITDA for the three and nine months ended September 30, 2016 and 2015:


	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(dollars in thousands)
Net income (loss)	$	2,083	$	53,776	$	(5,288)	$	149,653
State income tax expense		317		525		493		480
Interest expense		8,144		11,505		28,651		34,045
Depreciation and amortization		14,581		13,697		43,454		41,281
Adjusted EBITDA	$	25,125	$	79,503	$	67,310	$	225,459

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

	Refinery operating margin for the three and nine months ended September 30, 2016 excludes gains (losses) related to inventory adjustments of $(1,419) and $2,046, respectively. Refinery operating margin for the three and nine months ended September 30, 2015 excludes losses related to inventory adjustments of $(4,385) and $(2,763), respectively.

(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.