Alon USA Partners, LP Reports Third Quarter 2015 Results and Declares Quarterly Cash Distribution

November 2, 2015 3:15 PM

DALLAS, Nov. 2, 2015 /PRNewswire/ — Alon USA Partners, LP (NYSE: ALDW) (“Alon Partners”) today announced results for the third quarter of 2015. Net income for the third quarter of 2015 was $53.8 million, or $0.86 per unit, compared to $77.0 million, or $1.23 per unit, for the same period last year. Net income for the first nine months of 2015 was $149.7 million, or $2.39 per unit, compared to $127.0 million, or $2.03 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 2015 of $0.98 per unit payable on November 25, 2015 to common unitholders of record at the close of business on November 18, 2015, based on cash available for distribution of $61.3 million.

Paul Eisman, President and CEO, commented, “We are pleased with our strong results, which resulted in cash available for distribution of $0.98 per unit in the third quarter of 2015. In the last four quarters, we have generated total cash available for distribution of $3.43 per unit.

“The Big Spring refinery capitalized on a robust crack spread environment during the third quarter of 2015 to generate solid margins. The refinery ran well during the quarter, achieving total throughput of almost 76,000 barrels per day. Despite unfavorable Midland crude differentials, Big Spring generated a refinery operating margin of $16.71 per barrel. The refinery also achieved low direct operating expense of $3.46 per barrel. Our results benefited from a strong wholesale marketing environment driven by a robust gasoline market. During the quarter, our wholesale marketing business sold on average approximately 3,800 barrels per day of gasoline into the Phoenix market.

“We expect total throughput at the Big Spring refinery to average approximately 75,000 barrels per day for the fourth quarter of 2015.

“While strong financial results are an important driver of unitholder value, we are also focused on unlocking the value embedded in our assets. We are continuing work on a number of capital projects which will enhance the profitability of the partnership. In addition, we have identified $37 million in existing logistics EBITDA at Alon Partners as discussed in the detail below. We are committed to realizing value from these assets, which we believe are undervalued in our current structure.”

STRATEGIC UPDATE – LOGISTICS

Alon Partners has identified approximately $37 million in existing logistics EBITDA associated with the Big Spring refinery and wholesale marketing business as shown in the table below.

Logistics master limited partnerships (MLPs) continue to trade at a premium to independent refiners and refining MLPs, implying that these assets are undervalued in Alon Partners’ current structure. The management team is committed to realizing the value of these logistics assets for Alon Partners’ unitholders.



Existing Logistics Assets	Assumed Utilization	Estimated Annual EBITDA
		(dollars in thousands)
Wholesale marketing business	75,000 bpd	$	24,000
Crude and product storage*	2.56 MMBbls	9,000
Other assets (rail and truck racks, product rack, pipelines, salt wells, etc.)		4,000
Total Alon USA Partners Logistics EBITDA		$	37,000

* Represents shell capacity.

THIRD QUARTER 2015

Refinery operating margin was $16.71 per barrel for the third quarter of 2015 compared to $19.98 per barrel for the same period in 2014. This decrease in operating margin was primarily due to the less favorable industry margin environment. The unfavorable contraction in the WTI Cushing to WTI Midland and the WTI Cushing to WTS spreads was greater than the improvement in the Gulf Coast 3/2/1 spread and the cost of crude benefit from the market moving from backwardation into contango. The Big Spring refinery average throughput for the third quarter of 2015 was 75,797 barrels per day (“bpd”) compared to 74,838 bpd for the same period in 2014.

The average WTI Cushing to WTI Midland spread for the third quarter of 2015 was $(0.72) per barrel compared to $9.93 per barrel for the third quarter of 2014. The average WTI Cushing to WTS spread for the third quarter of 2015 was $(1.46) per barrel compared to $8.14 per barrel for the third quarter of 2014. The average Gulf Coast 3/2/1 crack spread was $19.77 per barrel for the third quarter of 2015 compared to $15.90 per barrel for the third quarter of 2014. The contango environment for the third quarter of 2015 created a cost of crude benefit of $0.57 per barrel compared to the backwardated environment creating a cost of crude detriment of $1.16 per barrel for the same period in 2014.

YEAR-TO-DATE 2015

Refinery operating margin was $15.95 per barrel for the first nine months of 2015 compared to $17.35 per barrel for the same period in 2014. This decrease in operating margin was primarily due to the less favorable industry margin environment. The unfavorable contraction in the WTI Cushing to WTI Midland and the WTI Cushing to WTS spreads was greater than the improvement in the Gulf Coast 3/2/1 spread and the cost of crude benefit from the market moving from backwardation into contango. The Big Spring refinery average throughput for the first nine months of 2015 was 74,562 bpd compared to 62,382 bpd for the same period in 2014. During the first nine months of 2014, refinery throughput was reduced as we completed both the planned major turnaround and the vacuum tower project.

The average WTI Cushing to WTI Midland spread for the first nine months of 2015 was $0.60 per barrel compared to $7.31 per barrel for the same period in 2014. The average WTI Cushing to WTS spread for the first nine months of 2015 was $0.02 per barrel compared to $6.58 per barrel for the same period in 2014. The average Gulf Coast 3/2/1 crack spread was $19.08 per barrel for the first nine months of 2015 compared to $16.37 per barrel for the same period in 2014. The contango environment for the first nine months of 2015 created a cost of crude benefit of $1.04 per barrel compared to the backwardated environment creating a cost of crude detriment of $0.74 per barrel for the same period in 2014.

CONFERENCE CALL

Alon Partners has scheduled a conference call, which will be broadcast live over the Internet on Tuesday, November 3, 2015 at 9:00 a.m. Eastern Time (8:00 a.m. Central Time), to discuss the third quarter 2015 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 17, 2015, and may be accessed by calling 877-660-6853, or 201-612-7415 for international callers, and using the passcode 13621444#. 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. (“Alon Energy”) (NYSE: ALJ). 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 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 –

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, 2014, IS UNAUDITED)	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(dollars in thousands, except per unit data, per barrel data and pricing statistics)
STATEMENT OF OPERATIONS DATA:
Net sales (1)	$	551,813	$	838,882	$	1,719,319	$	2,421,194
Operating costs and expenses:
Cost of sales	439,678		701,331		1,397,395		2,125,775
Direct operating expenses	24,136		25,723		71,837		79,816
Selling, general and administrative expenses	8,536		8,353		24,654		19,505
Depreciation and amortization	13,697		13,852		41,281		33,427
Total operating costs and expenses	486,047		749,259		1,535,167		2,258,523
Operating income	65,766		89,623		184,152		162,671
Interest expense	(11,505)		(11,584)		(34,045)		(34,477)
Other income, net	40		14		26		627
Income before state income tax expense	54,301		78,053		150,133		128,821
State income tax expense	525		1,060		480		1,785
Net income	$	53,776	$	76,993	$	149,653	$	127,036
Earnings per unit	$	0.86	$	1.23	$	2.39	$	2.03
Weighted average common units outstanding (in thousands)	62,510		62,507		62,508		62,505
Cash distribution per unit	$	1.04	$	0.13	$	2.45	$	1.00
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	84,834	$	94,142	$	219,232	$	139,374
Investing activities	(5,532)		(26,195)		(15,322)		(63,081)
Financing activities	(93,908)		(33,751)		(174,957)		(114,581)
OTHER DATA:
Adjusted EBITDA (2)	$	79,503	$	103,489	$	225,459	$	196,725
Capital expenditures	4,322		2,492		12,108		13,931
Capital expenditures for turnarounds and catalysts	1,210		23,703		3,214		49,150
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin (3)	$	16.71	$	19.98	$	15.95	$	17.35
Refinery direct operating expense (4)	3.46		3.74		3.53		4.69
PRICING STATISTICS:
Crack spreads (per barrel):
Gulf Coast 3/2/1 (5)	$	19.77	$	15.90	$	19.08	$	16.37
WTI Cushing crude oil (per barrel)	$	46.41	$	97.55	$	50.91	$	99.74
Crude oil differentials (per barrel):
WTI Cushing less WTI Midland (6)	$	(0.72)	$	9.93	$	0.60	$	7.31
WTI Cushing less WTS (6)	(1.46)		8.14		0.02		6.58
Brent less WTI Cushing (6)	3.78		4.15		4.28		7.25
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	1.61	$	2.65	$	1.66	$	2.71
Gulf Coast ultra-low sulfur diesel	1.52		2.80		1.68		2.88
Natural gas (per MMBtu)	2.73		3.95		2.76		4.41



	September 30, 2015		December 31, 2014
BALANCE SHEET DATA (end of period):	(dollars in thousands)
Cash and cash equivalents	$	135,278	$	106,325
Working capital (deficit)	908		(4,561)
Total assets	798,887		770,246
Total debt	290,946		302,376
Total debt less cash and cash equivalents	155,668		196,051
Total partners’ equity	184,950		188,402



THROUGHPUT AND PRODUCTION DATA:	For the Three Months Ended						For the Nine Months Ended
THROUGHPUT AND PRODUCTION DATA:	September 30,						September 30,
	2015			2014			2015			2014
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
WTS crude	30,810	40.6		37,566	50.2		35,041	47.0		28,524	45.7
WTI crude	42,503	56.1		34,633	46.3		36,834	49.4		31,330	50.2
Blendstocks	2,484	3.3		2,639	3.5		2,687	3.6		2,528	4.1
Total refinery throughput (7)	75,797	100.0		74,838	100.0		74,562	100.0		62,382	100.0
Refinery production:
Gasoline	37,503	49.5		36,842	49.0		37,155	49.6		30,207	48.4
Diesel/jet	28,623	37.8		28,857	38.4		27,596	36.9		21,964	35.2
Asphalt	2,452	3.2		3,052	4.1		2,733	3.7		2,705	4.3
Petrochemicals	4,588	6.1		4,305	5.7		4,770	6.4		3,514	5.6
Other	2,595	3.4		2,078	2.8		2,510	3.4		4,030	6.5
Total refinery production (8)	75,761	100.0		75,134	100.0		74,764	100.0		62,420	100.0
Refinery utilization (9)		100.4	%		98.9	%		98.5	%		97.0	%



CASH AVAILABLE FOR DISTRIBUTION DATA:	For the Three Months Ended
	September 30, 2015
	(dollars in thousands, except per unit data)

Net sales (1)	$	551,813
Operating costs and expenses:
Cost of sales	439,678
Direct operating expenses	24,136
Selling, general and administrative expenses	8,536
Depreciation and amortization	13,697
Total operating costs and expenses	486,047
Operating income	65,766
Interest expense	(11,505)
Other income, net	40
Income before state income tax expense	54,301
State income tax expense	525
Net income	53,776
Adjustments to reconcile net income to Adjusted EBITDA:
Interest expense	11,505
State income tax expense	525
Depreciation and amortization	13,697
Adjusted EBITDA (2)	79,503
Adjustments to reconcile Adjusted EBITDA to cash available for distribution:
less: Maintenance/growth capital expenditures	4,322
less: Turnaround and catalyst replacement capital expenditures	1,210
less: Major turnaround reserve for future years	1,500
less: Principal payments	625
less: State income tax payments	525
less: Interest paid in cash	10,010
Cash available for distribution	$	61,311

Common units outstanding (in 000’s)	62,510

Cash available for distribution per unit	$	0.98

__________

(1)	Includes sales to related parties of $97,014 and $156,131 for the three months ended September 30, 2015 and 2014, respectively, and $281,136 and $447,314 for the nine months ended September 30, 2015 and 2014, 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 to Adjusted EBITDA for the three and nine months ended September 30, 2015 and 2014:


	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(dollars in thousands)
Net income	$	53,776	$	76,993	$	149,653	$	127,036
State income tax expense	525		1,060		480		1,785
Interest expense	11,505		11,584		34,045		34,477
Depreciation and amortization	13,697		13,852		41,281		33,427
Adjusted EBITDA	$	79,503	$	103,489	$	225,459	$	196,725


(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, 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.

Contacts:	Stacey Hudson, Investor Relations Manager Alon USA Partners GP, LLC 972-367-3808

	Investors: Jack Lascar/Stephanie Zhadkevich Dennard – Lascar Associates, LLC 713-529-6600

	Media: Blake Lewis Lewis Public Relations 214-635-3020

SOURCE Alon USA Partners, LP

Alon USA Partners, LP Reports Third Quarter 2015 Results and Declares Quarterly Cash Distribution

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