Alon USA Energy, Inc. - FORM 8-K - EX-99.1 - PRESS RELEASE

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8-K - 8-K - Alon USA Energy, Inc.	alj2016q2aldwearningsrelea.htm



	NEWS RELEASE

	Contacts:	Stacey Morris, 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

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

Schedules conference call for July 29, 2016 at 9:30 a.m. Eastern

DALLAS, TEXAS, July 28, 2016 - Alon USA Partners, LP (NYSE: ALDW) (“Alon Partners”) today announced results for the second quarter of 2016. Net income for the second quarter of 2016 was $1.2 million, or $0.02 per unit, compared to $59.4 million, or $0.95 per unit, for the same period last year. Net loss for the first half of 2016 was $(7.4) million, or $(0.12) per unit, compared to net income of $95.9 million, or $1.53 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 2016 of $0.14 per unit payable on August 25, 2016 to common unitholders of record at the close of business on August 18, 2016, based on cash available for distribution of $8.8 million.

Paul Eisman, President and CEO, commented, “The refining environment in the second quarter of 2016 remained challenging as crack spreads were pressured by high product inventories. While crack spreads improved seasonally from the first quarter of 2016, the average benchmark crack spread in the second quarter was down approximately $6.50 per barrel relative to the same quarter last year. As previously discussed, our second quarter results were also negatively impacted by unplanned downtime related to a power outage in late May. We estimate the lost opportunity cost and maintenance cost associated with the power outage negatively impacted Alon Partners’ adjusted EBITDA by approximately $10 million or the distribution by $0.16 per unit.

“Big Spring’s refinery operating margin of $8.53 per barrel was negatively impacted by approximately $1.30 per barrel due to the unplanned downtime during the quarter. Despite the interruption to normal operations, the refinery achieved low operating costs of $3.59 per barrel. We currently expect to perform maintenance on the Big Spring refinery’s reformer in August. As a result, we expect total throughput at the Big Spring refinery to average approximately 69,000 barrels per day for the third quarter and 70,000 barrels per day for the full year 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 third quarter of 2016.”

SECOND QUARTER 2016

Refinery operating margin was $8.53 per barrel for the second quarter of 2016 compared to $17.22 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, a narrowing of the WTI Cushing to WTI Midland spread and a reduced cost of crude benefit from the contango market in 2016, partially offset by a widening of the WTI Cushing to WTS spread. The Big Spring refinery average throughput for the second quarter of 2016 was 71,153 barrels per day (“bpd”) compared to 75,491 bpd for the same period in 2015. The Big Spring refinery’s throughput and operating margin were negatively affected by the unplanned downtime during the second quarter of 2016 due to a power outage caused by inclement weather, which affected multiple units.

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The average Gulf Coast 3/2/1 crack spread was $13.16 per barrel for the second quarter of 2016 compared to $19.71 per barrel for the second quarter of 2015. The average WTI Cushing to WTI Midland spread for the second quarter of 2016 was $0.17 per barrel compared to $0.60 per barrel for the second quarter of 2015. The average WTI Cushing to WTS spread for the second quarter of 2016 was $0.75 per barrel compared to $(0.21) per barrel for the second quarter of 2015. The average Brent to WTI Cushing spread for the second quarter of 2016 was $(0.18) per barrel compared to $3.66 per barrel for the same period in 2015. The contango environment in the second quarter of 2016 created an average cost of crude benefit of $1.49 per barrel compared to an average cost of crude benefit of $1.90 per barrel for the same period in 2015.

YEAR-TO-DATE 2016

Refinery operating margin was $8.16 per barrel for the first half of 2016 compared to $15.56 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 both the WTI Cushing to WTI Midland and the WTI Cushing to WTS spreads, partially offset by the cost of crude benefit from the market moving further into contango in 2016. The Big Spring refinery average throughput for the first half of 2016 was 69,345 bpd compared to 73,934 bpd for the same period in 2015. The Big Spring refinery’s throughput and operating margin were negatively affected by the planned downtime to complete a reformer regeneration and catalyst replacement for our diesel hydrotreater unit in the beginning of the first quarter of 2016, as well as unplanned downtime during the second quarter of 2016 due to a power outage caused by inclement weather, which affected multiple units.

The average Gulf Coast 3/2/1 crack spread was $12.20 per barrel for the first half of 2016 compared to $18.73 per barrel for the same period in 2015. The average WTI Cushing to WTI Midland spread for the first half of 2016 was $0.02 per barrel compared to $1.27 per barrel for the same period in 2015. The average WTI Cushing to WTS spread for the first half of 2016 was $0.32 per barrel compared to $0.76 per barrel for the same period in 2015. The average Brent to WTI Cushing spread for the first half of 2016 was $0.15 per barrel compared to $4.54 per barrel for the same period in 2015. The contango environment for the first half of 2016 created an average cost of crude benefit of $1.66 per barrel compared to an average cost of crude benefit of $1.28 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, July 29, 2016 at 9:30 a.m. Eastern Time (8:30 a.m. Central Time), to discuss the second 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 August 12, 2016 and may be accessed by calling 877-660-6853, or 201-612-7415 for international callers, and using the passcode 13640014#. 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 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. (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.

- 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, 2015, IS UNAUDITED)	For the Three Months Ended						For the Six Months Ended
	June 30,						June 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)	$	468,457		$	625,064		$	836,466		$	1,167,506
Operating costs and expenses:
Cost of sales	410,735			507,122			730,068			957,717
Direct operating expenses	23,255			24,285			48,299			47,701
Selling, general and administrative expenses	8,802			10,215			16,111			16,118
Depreciation and amortization	14,667			13,591			28,873			27,584
Total operating costs and expenses	457,459			555,213			823,351			1,049,120
Operating income	10,998			69,851			13,115			118,386
Interest expense	(9,920		)	(10,847		)	(20,507		)	(22,540		)
Other income (loss), net	113			27			197			(14		)
Income (loss) before state income tax expense (benefit)	1,191			59,031			(7,195		)	95,832
State income tax expense (benefit)	—			(395		)	176			(45		)
Net income (loss)	$	1,191		$	59,426		$	(7,371	)	$	95,877
Earnings (loss) per unit	$	0.02		$	0.95		$	(0.12	)	$	1.53
Weighted average common units outstanding (in thousands)	62,515			62,509			62,512			62,508
Cash distribution per unit	$	—		$	0.71		$	0.08		$	1.41
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	34,862		$	107,311		$	46,587		$	134,398
Investing activities	(5,068		)	(5,985		)	(20,924		)	(9,790		)
Financing activities	8,830			(61,829		)	3,204			(81,049		)
OTHER DATA:
Adjusted EBITDA (2)	$	25,778		$	83,469		$	42,185		$	145,956
Capital expenditures	4,588			5,465			12,700			7,786
Capital expenditures for turnarounds and catalysts	480			520			8,224			2,004
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin (3)	$	8.53		$	17.22		$	8.16		$	15.56
Refinery direct operating expense (4)	3.59			3.54			3.83			3.56
PRICING STATISTICS:
Crack spreads (per barrel):
Gulf Coast 3/2/1 (5)	$	13.16		$	19.71		$	12.20		$	18.73
WTI Cushing crude oil (per barrel)	$	45.48		$	57.86		$	39.39		$	53.20
Crude oil differentials (per barrel):
WTI Cushing less WTI Midland (6)	$	0.17		$	0.60		$	0.02		$	1.27
WTI Cushing less WTS (6)	0.75			(0.21		)	0.32			0.76
Brent less WTI Cushing (6)	(0.18		)	3.66			0.15			4.54
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	1.42		$	1.86		$	1.25		$	1.69
Gulf Coast ultra-low sulfur diesel	1.34			1.83			1.19			1.76
Natural gas (per MMBtu)	2.25			2.74			2.12			2.77

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	June 30, 2016			December 31, 2015
BALANCE SHEET DATA (end of period):	(dollars in thousands)
Cash and cash equivalents	$	161,820		$	132,953
Working capital	(40,661		)	(53,804		)
Total assets	792,661			748,584
Total debt	291,681			292,082
Total debt less cash and cash equivalents	129,861			159,129
Total partners’ equity	118,613			130,957



THROUGHPUT AND PRODUCTION DATA:	For the Three Months Ended						For the Six Months Ended
THROUGHPUT AND PRODUCTION DATA:	June 30,						June 30,
	2016			2015			2016			2015
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
WTS crude	25,698	36.1		29,605	39.2		31,126	44.9		37,193	50.3
WTI crude	43,040	60.5		43,659	57.8		35,400	51.0		33,952	45.9
Blendstocks	2,415	3.4		2,227	3.0		2,819	4.1		2,789	3.8
Total refinery throughput (7)	71,153	100.0		75,491	100.0		69,345	100.0		73,934	100.0
Refinery production:
Gasoline	33,744	47.6		37,755	49.8		33,922	49.0		36,978	49.8
Diesel/jet	26,627	37.6		28,052	37.0		24,655	35.6		27,074	36.5
Asphalt	2,572	3.6		2,479	3.3		2,860	4.2		2,876	3.9
Petrochemicals	3,354	4.7		4,915	6.5		3,485	5.0		4,863	6.5
Other	4,569	6.5		2,537	3.4		4,298	6.2		2,466	3.3
Total refinery production (8)	70,866	100.0		75,738	100.0		69,220	100.0		74,257	100.0
Refinery utilization (9)		94.2	%		100.4	%		93.7	%		97.5	%

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

Net sales (1)	$	468,457
Operating costs and expenses:
Cost of sales	410,735
Direct operating expenses	23,255
Selling, general and administrative expenses	8,802
Depreciation and amortization	14,667
Total operating costs and expenses	457,459
Operating income	10,998
Interest expense	(9,920		)
Other income, net	113
Income before state income tax expense	1,191
State income tax expense	—
Net income	1,191
Adjustments to reconcile net loss to Adjusted EBITDA:
Interest expense	9,920
State income tax expense	—
Depreciation and amortization	14,667
Adjusted EBITDA (2)	25,778
Adjustments to reconcile Adjusted EBITDA to cash available for distribution:
less: Maintenance/growth capital expenditures	4,588
less: Turnaround and catalyst replacement capital expenditures	480
less: Major turnaround reserve for future years	1,500
less: Principal payments	625
less: State income tax payments	—
less: Interest paid in cash	9,738
Calculated cash available for distribution	$	8,847

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

Cash available for distribution per unit	$	0.14

________________


(1)	Includes sales to related parties of $76,884 and $101,233 for the three months ended June 30, 2016 and 2015, respectively, and $139,994 and $184,122 for the six months ended June 30, 2016 and 2015, respectively.

(2)

Adjusted EBITDA represents earnings before state income tax expense (benefit), 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 (benefit), 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 (loss) to Adjusted EBITDA for the three and six months ended June 30, 2016 and 2015:



	For the Three Months Ended					For the Six Months Ended
	June 30,					June 30,
	2016		2015			2016			2015
	(dollars in thousands)
Net income (loss)	$	1,191	$	59,426		$	(7,371	)	$	95,877
State income tax expense (benefit)	—		(395		)	176			(45		)
Interest expense	9,920		10,847			20,507			22,540
Depreciation and amortization	14,667		13,591			28,873			27,584
Adjusted EBITDA	$	25,778	$	83,469		$	42,185		$	145,956

(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 six months ended June 30, 2016 excludes gains related to inventory adjustments of $2,519 and $3,465, respectively. Refinery operating margin for the three and six months ended June 30, 2015 excludes gains (losses) related to inventory adjustments of $(368) and $1,622, 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.

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Alon USA Energy, Inc. - FORM 8-K - EX-99.1 - PRESS RELEASE - July 28, 2016

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Alon USA Energy, Inc. Reports