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

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8-K - 8-K - Alon USA Energy, Inc.	alj2013q3aldwearningsrelea.htm



	NEWS RELEASE

	Contacts:	Stacey Hudson, Investor Relations Manager Alon USA Partners GP, LLC 972-367-3808
FOR IMMEDIATE RELEASE
		Investors: Jack Lascar/ Sheila Stuewe 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 Reports Third Quarter Results

Partnership schedules conference call for November 8, 2013 at 10:00 a.m. Eastern

DALLAS, TEXAS, November 6, 2013 - Alon USA Partners, LP (NYSE: ALDW) (the “Partnership”) today announced results for the third quarter of 2013. Net loss for the third quarter of 2013 was $(16.1) million, or $(0.26) per unit, compared to net income of $120.4 million for the same period last year. Net income for the first nine months of 2013 was $122.7 million, or $1.96 per unit, compared to $268.7 million for the same period last year.

Paul Eisman, CEO and President, commented, “Our third quarter results were impacted by a volatile and deteriorating margin environment resulting primarily from decreasing discounts for West Texas crude oil. In addition, our results were affected by backwardation in the crude market and unplanned downtime at our Big Spring refinery during the second half of September. Versus the second quarter, higher West Texas crude oil prices negatively impacted our results by approximately $55 million with an additional $5 million negative impact resulting from crude oil backwardation. The Big Spring FCC outage during the quarter resulted in additional expenses and lost opportunity costs of approximately $12 million, or $0.19 per unit. Without the FCC outage effect, the third quarter results would have been a net loss of $(0.07) per unit.

“As a result of these factors, there is no cash available for distribution this quarter. However, we remain bullish on the future for Big Spring as the continued growth in Permian Basin crude production will provide a sustainable long term crude sourcing advantage for the refinery as Midland priced West Texas crudes will trade at a wider spread to Brent priced crudes. Though WTI Cushing and WTS traded near parity during the third quarter, we believe this dynamic is temporary given the transportation cost to Cushing and the Gulf Coast, and the difference in product value between sweet and sour crudes. In the fourth quarter to date, the WTI Cushing to WTS spread has widened $4.35 per barrel to our benefit. In addition, we are working on a number of initiatives at Big Spring that will further enhance future profitability of the refinery and will positively impact future distributions.

“For the fourth quarter of 2013, we expect the throughput at Big Spring to average approximately 72,000 barrels per day. We are continuing planning and preparation work for the first quarter 2014 turnaround at Big Spring. This is a major event that will affect throughput in the first quarter. We estimate that first quarter throughput at the refinery will average 55,000 barrels per day.

“Though RINs prices have declined from the highs reached in July, we continue to work to mitigate the costs associated with our RINs obligations. To that end, we have begun biodiesel blending at Big Spring and will continue to evaluate blending economics. We recorded approximately $1.2 million of costs in the third quarter for RINs obligations. We anticipate that our RINs obligation at Big Spring for the fourth quarter will be approximately $1.0 million, which would result in a full year 2013 impact of $10.2 million.”

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THIRD QUARTER 2013

Refinery operating margin was $6.46 per barrel for the third quarter of 2013 compared to $27.75 per barrel for the same period in 2012. This decrease is mainly due to lower Gulf Coast 3/2/1 crack spreads and a narrowing WTI to WTS spread. The refinery’s throughput for the third quarter of 2013 averaged 63,090 barrels per day (“bpd”) compared to 69,563 bpd for the same period in 2012. Throughput and refinery operating margin for the third quarter of 2013 were impacted by unplanned downtime at the refinery during the second half of September 2013. Also impacting refinery operating margin was approximately $1.2 million of costs associated with RINs obligations for the third quarter of 2013.

The average Gulf Coast 3/2/1 crack spread was $14.23 per barrel for the third quarter of 2013 compared to $31.76 per barrel for the third quarter of 2012. The average WTI to WTS spread for the third quarter of 2013 was $0.08 per barrel compared to $3.70 per barrel for the same period in 2012.

YEAR-TO-DATE 2013

Refinery operating margin was $16.35 per barrel for the first nine months of 2013 compared to $22.88 per barrel for the same period in 2012. This decrease is mainly due to lower Gulf Coast 3/2/1 crack spreads partially offset by a wider WTI to WTS spread. The refinery’s throughput for the first nine months of 2013 averaged 64,910 bpd compared to 67,884 bpd for the same period in 2012. Also impacting refinery operating margin was approximately $9.2 million of costs associated with RINs obligations for the first nine months of 2013.

The average Gulf Coast 3/2/1 crack spread was $21.21 per barrel for the first nine months of 2013 compared to $27.54 per barrel for the same period in 2012. The average WTI to WTS spread for the first nine months of 2013 was $3.91 per barrel compared to $3.74 per barrel for the same period in 2012.

CONFERENCE CALL

The Partnership has scheduled a conference call which will also be webcast live on Friday, November 8, 2013 at 10:00 a.m. eastern time (9:00 a.m. central time), to discuss the third quarter 2013 results. To access the call, please dial 800-762-8779 or 480-629-9645, for international callers, at least 10 minutes prior to the start time and ask for the Alon USA Partners, LP 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 22, 2013, and may be accessed by calling 800-406-7325, or 303-590-3030, for international callers, and using the passcode 4642287#. The archived webcast 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 total throughput capacity of approximately 70,000 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, 2012, IS UNAUDITED)	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
				Predecessor (B)						Predecessor (B)
	(dollars in thousands, except per unit data, per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA: (A)
Net sales (1)	$	881,902		$	943,148		$	2,551,763		$	2,651,191
Operating costs and expenses:
Cost of sales	844,423			765,538			2,261,948			2,225,702
Direct operating expenses	26,281			25,480			84,017			73,223
Selling, general and administrative expenses	4,134			10,316			16,864			18,070
Depreciation and amortization	10,975			11,573			34,282			34,963
Total operating costs and expenses	885,813			812,907			2,397,111			2,351,958
Loss on disposition of assets	(21		)	—			(21		)	—
Operating income (loss)	(3,932		)	130,241			154,631			299,233
Interest expense	(12,127		)	(4,313		)	(30,489		)	(15,070		)
Interest expense - related parties	—			(4,457		)	—			(12,990		)
Other income (loss), net	—			(6		)	18			11
Income (loss) before state income tax expense	(16,059		)	121,465			124,160			271,184
State income tax expense	61			1,098			1,434			2,518
Net income (loss)	$	(16,120	)	$	120,367		$	122,726		$	268,666
Earnings (loss) per unit	$	(0.26	)				$	1.96
Weighted average common units outstanding (in thousands)	62,502						62,502
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities	$	6,476		$	176,473		$	159,719		$	363,616
Investing activities	(7,682		)	(6,351		)	(21,658		)	(25,455		)
Financing activities	34,998			(182,406		)	(143,586		)	(444,692		)
OTHER DATA:
Adjusted EBITDA (2)	$	7,064		$	141,808		$	188,952		$	334,207
Capital expenditures	7,477			6,286			16,634			17,328
Capital expenditures for turnaround and chemical catalyst	205			65			5,024			8,127
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin (3)	$	6.46		$	27.75		$	16.35		$	22.88
Refinery direct operating expense (4)	4.53			3.92			4.74			3.92
PRICING STATISTICS:
Crack spreads (per barrel):
Gulf Coast 3/2/1 (5)	$	14.23		$	31.76		$	21.21		$	27.54
WTI crude oil (per barrel)	$	105.82		$	92.09		$	98.14		$	96.17
Crude oil differentials (per barrel):
WTI less WTS (6)	$	0.08		$	3.70		$	3.91		$	3.74
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	2.78		$	2.89		$	2.77		$	2.89
Gulf Coast ultra-low sulfur diesel	3.02			3.07			2.99			3.06
Natural gas (per MMBtu)	3.56			2.89			3.69			2.58

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	September 30, 2013			December 31, 2012
BALANCE SHEET DATA (end of period):	(dollars in thousands)
Cash and cash equivalents	$	60,476		$	66,001
Working capital	(519		)	1,702
Total assets	758,699			763,423
Total debt	324,816			295,311
Total partners’ equity	131,946			181,726


(A)	Earnings (loss) per unit information is not presented for the three and nine months ended September 30, 2012 as there was no common equity or potential common equity publicly traded during that period and therefore is not required by Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) topic 260, Earnings per share.


(B)	The information presented contains the unaudited combined financial results of Alon USA Partners, LP Predecessor (“Predecessor”), our predecessor for accounting purposes, for the three and nine months ended September 30, 2012.



THROUGHPUT AND PRODUCTION DATA:	For the Three Months Ended						For the Nine Months Ended
THROUGHPUT AND PRODUCTION DATA:	September 30,						September 30,
	2013			2012			2013			2012
				Predecessor						Predecessor
	bpd	%		bpd	%		bpd	%		bpd	%
Refinery throughput:
WTS crude	36,340	57.6		52,108	74.9		45,029	69.3		53,297	78.6
WTI crude	25,169	39.9		15,398	22.1		18,016	27.8		12,790	18.8
Blendstocks	1,581	2.5		2,057	3.0		1,865	2.9		1,797	2.6
Total refinery throughput (7)	63,090	100.0		69,563	100.0		64,910	100.0		67,884	100.0
Refinery production:
Gasoline	30,861	49.2		34,918	50.3		31,905	49.4		33,653	49.6
Diesel/jet	20,999	33.4		23,215	33.5		21,688	33.5		22,234	32.8
Asphalt	3,312	5.3		4,148	6.0		3,708	5.7		4,241	6.3
Petrochemicals	3,599	5.7		4,040	5.8		3,984	6.2		4,005	5.9
Other	4,045	6.4		3,045	4.4		3,371	5.2		3,627	5.4
Total refinery production (8)	62,816	100.0		69,366	100.0		64,656	100.0		67,760	100.0
Refinery utilization (9)		87.9	%		96.4	%		93.8	%		97.3	%

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CASH AVAILABLE FOR DISTRIBUTION DATA:	For the Three Months Ended
	September 30, 2013
	(dollars in thousands, except per unit data)

Net sales	$	881,902
Operating costs and expenses:
Cost of sales	844,423
Direct operating expenses	26,281
Selling, general and administrative expenses	4,134
Depreciation and amortization	10,975
Total operating costs and expenses	885,813
Loss on disposition of assets	(21		)
Operating loss	(3,932		)
Interest expense	(12,127		)
Other income, net	—
Loss before state income tax expense	(16,059		)
State income tax expense	61
Net loss	(16,120		)
Adjustments to reconcile net income to Adjusted EBITDA:
Interest expense	12,127
State income tax expense	61
Depreciation and amortization	10,975
Loss on disposition of assets	21
Adjusted EBITDA	7,064
Adjustments to reconcile Adjusted EBITDA to cash available for distribution before special expenses:
less: Maintenance/growth capital expenditures	7,477
less: Turnaround and catalyst replacement capital expenditures	205
less: Major turnaround reserve	1,150
less: Principal payments	625
less: State income tax expense	61
less: Interest paid in cash	11,626
Cash available for distribution before special expenses	(14,080		)
less: Special turnaround reserve	4,104
Cash available for distribution	$	(18,184	)

Common units outstanding (in 000’s)	62,502

Cash available for distribution per unit	$	—

________________


(1)	Includes sales to related parties of $164,338 and $151,682 for the three months ended September 30, 2013 and 2012, respectively, and $462,280 and $450,416 for the nine months ended September 30, 2013 and 2012, 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.

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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 nine months ended September 30, 2013 and 2012, respectively:



	For the Three Months Ended					For the Nine Months Ended
	September 30,					September 30,
	2013			2012		2013		2012
				Predecessor				Predecessor
	(dollars in thousands)
Net income (loss)	$	(16,120	)	$	120,367	$	122,726	$	268,666
State income tax expense	61			1,098		1,434		2,518
Interest expense	12,127			4,313		30,489		15,070
Interest expense - related parties	—			4,457		—		12,990
Depreciation and amortization	10,975			11,573		34,282		34,963
Loss on disposition of assets	21			—		21		—
Adjusted EBITDA	$	7,064		$	141,808	$	188,952	$	334,207

(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 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/WTS, or sweet/sour, spread represents the differential between the average value per barrel of Cushing WTI crude oil and the average value per barrel of Midland WTS 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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