Alon USA Partners, LP

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

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Schedules conference call for August 8, 2014 at 10:00 a.m. Eastern

DALLAS, Aug. 6, 2014 /PRNewswire/ -- Alon USA Partners, LP (NYSE: ALDW) ("Alon Partners") today announced results for the second quarter of 2014. Net income for the second quarter of 2014 was $7.8 million, or $0.12 per unit, compared to $45.3 million, or $0.73 per unit, for the same period last year. Net income for the first half of 2014 was $50.0 million, or $0.80 per unit, compared to $138.8 million, or $2.22 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 2014 of $0.13 per unit payable on August 25, 2014 to common unitholders of record at the close of business on August 18, 2014, based on cash available for distribution of $8.4 million.

Paul Eisman, CEO and President, commented, "During the second quarter we completed the planned major turnaround of the Big Spring refinery while also completing the vacuum tower revamp project. The turnaround and the vacuum tower revamp project allow us to increase the refinery's crude throughput by 3,000 barrels per day to 73,000 barrels per day. In addition, the distillate recovery and energy savings resulting from the vacuum tower revamp project are exceeding expectations as distillate yield has increased by more than 3,000 barrels per day. This will drive improvement in our margin capture rate going forward.

"The turnaround was challenging given its very significant scope. The turnaround duration was impacted by difficult weather conditions and a longer than expected maintenance period particularly in the FCC. This resulted in lower throughput than planned in the second quarter. However, we were very pleased with the good safety performance of our people and our contractors during the turnaround. We've also been encouraged by the operating performance of the refinery since the turnaround.

"Looking forward, we expect to operate the Big Spring refinery at a total throughput of 74,000 barrels per day in the third quarter and 75,000 barrels per day in the fourth quarter. We also expect to fully take advantage of the distillate recovery and energy savings benefits of the vacuum tower revamp project. The profitability of the Big Spring refinery should be supported in the third quarter by widening differentials for Midland-priced crude oil. Midland-priced crudes traded at attractive discounts to WTI Cushing in June and July, which will positively affect the cost of crude and refinery operating margin at our Big Spring refinery in the third quarter. The WTI Cushing to WTI Midland differentials that will favorably affect the cost of crude for July and August averaged $8.59 per barrel."

SECOND QUARTER 2014
Refinery operating margin was $17.04 per barrel for the second quarter of 2014 compared to $14.99 per barrel for the same period in 2013. This increase in operating margin 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 lower Gulf Coast 3/2/1 crack spreads. The refinery's throughput for the second quarter of 2014 averaged 38,994 barrels per day ("bpd") compared to 72,124 bpd for the same period in 2013. The lower throughput rate during the second quarter of 2014 was due to our planned turnaround that was completed in June 2014. Also impacting the refinery operating margin for the second quarter of 2014 were RINs credits of $0.8 million, generated as a result of reduced production during the planned turnaround, compared to RINs costs of $8.0 million for the second quarter of 2013.

The average Gulf Coast 3/2/1 crack spread was $16.42 per barrel for the second quarter of 2014 compared to $21.17 per barrel for the second quarter of 2013, which was influenced by a reduction in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for the second quarter of 2014 was $7.56 per barrel compared to $12.51 per barrel for the same period in 2013. The average WTI Cushing to WTS spread for the second quarter of 2014 was $7.88 per barrel compared to $0.36 per barrel for the second quarter of 2013. The average WTI Cushing to WTI Midland spread for the second quarter of 2014 was $8.37 per barrel compared to $0.14 per barrel for the second quarter of 2013.

YEAR-TO-DATE 2014
Refinery operating margin was $15.56 per barrel for the first half of 2014 compared to $21.18 per barrel for the same period in 2013. This decrease was primarily due to a lower Gulf Coast 3/2/1 crack spread, partially offset by a widening WTI Cushing to WTI Midland spread. The refinery's throughput for the first half of 2014 averaged 56,050 bpd compared to 65,835 bpd for the same period in 2013. Also impacting refinery operating margin was $2.2 million of costs associated with RINs obligations for the first half of 2014, compared to $8.0 million for the first half of 2013.

The average Gulf Coast 3/2/1 crack spread was $16.61 per barrel for the first half of 2014 compared to $24.76 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 half of 2014 was $10.25 per barrel compared to $16.98 per barrel for the same period in 2013. The average WTI Cushing to WTI Midland spread for the first half of 2014 was $5.96 per barrel compared to $3.91 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, August 8, 2014 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time), to discuss the second quarter 2014 results. To access the call, please dial 888-438-5519, or 719-325-2393 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 August 22, 2014, and may be accessed by calling 888-203-1112, or 719-457-0820 for international callers, and using the passcode 6155917#. 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") (NYSE: 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.

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

- 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, 2013, IS UNAUDITED)

For the Three Months Ended


For the Six Months Ended


June 30,


June 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)

$

725,852



$

865,694



$

1,582,312



$

1,669,861

Operating costs and expenses:








Cost of sales

665,398



767,322



1,424,444



1,417,525

Direct operating expenses

25,152



27,314



54,093



57,736

Selling, general and administrative expenses

6,784



5,065



11,152



12,730

Depreciation and amortization

9,508



11,243



19,575



23,307

Total operating costs and expenses

706,842



810,944



1,509,264



1,511,298

Operating income

19,010



54,750



73,048



158,563

Interest expense

(11,569)



(8,970)



(22,893)



(18,362)

Other income, net

601



14



613



18

Income before state income tax expense

8,042



45,794



50,768



140,219

State income tax expense

240



473



725



1,373

Net income

$

7,802



$

45,321



$

50,043



$

138,846

Earnings per unit

$

0.12



$

0.73



$

0.80



$

2.22

Weighted average common units outstanding (in thousands)

62,504



62,502



62,504



62,502

Cash distribution per unit

$

0.69



$

1.48



$

0.87



$

2.05

CASH FLOW DATA:








Net cash provided by (used in):








Operating activities

$

(35)



$

(13,403)



$

45,232



$

153,243

Investing activities

(18,259)



(7,257)



(36,886)



(13,976)

Financing activities

(68,955)



(143,128)



(80,830)



(178,584)

OTHER DATA:








Adjusted EBITDA (2)

$

29,119



$

66,007



$

93,236



$

181,888

Capital expenditures

7,277



6,216



11,439



9,157

Capital expenditures for turnarounds and catalysts

10,982



1,041



25,447



4,819

KEY OPERATING STATISTICS:








Per barrel of throughput:








Refinery operating margin (3)

$

17.04



$

14.99



$

15.56



$

21.18

Refinery direct operating expense (4)

7.09



4.16



5.33



4.85

PRICING STATISTICS:








Crack spreads (per barrel):








Gulf Coast 3/2/1 (5)

$

16.42



$

21.17



$

16.61



$

24.76

WTI Cushing crude oil (per barrel)

$

103.04



$

94.20



$

100.86



$

94.23

Crude oil differentials (per barrel):








WTI Cushing less WTI Midland (6)

$

8.37



$

0.14



$

5.96



$

3.91

WTI Cushing less WTS (6)

7.88



0.36



5.79



5.86

Brent less WTI Cushing (6)

7.56



12.51



10.25



16.98

Product price (dollars per gallon):








Gulf Coast unleaded gasoline

$

2.81



$

2.69



$

2.73



$

2.77

Gulf Coast ultra-low sulfur diesel

2.92



2.86



2.93



2.97

Natural gas (per MMBtu)

4.58



4.02



4.65



3.76

 



June 30,
2014


December 31,
2013

BALANCE SHEET DATA (end of period):

(dollars in thousands)

Cash and cash equivalents

$

81,099



$

153,583

Working capital

(17,346)



18,007

Total assets

812,323



849,924

Total debt

343,344



344,322

Total debt less cash and cash equivalents

262,245



190,739

Total partners' equity

141,145



145,442


























THROUGHPUT AND PRODUCTION DATA:

For the Three Months Ended


For the Six Months Ended

June 30,


June 30,


2014


2013


2014


2013


bpd


%


bpd


%


bpd


%


bpd


%

Refinery throughput:
















WTS crude

12,634


32.4


53,627


74.4


23,927


42.7


49,446


75.1

WTI crude

23,391


60.0


17,180


23.8


29,652


52.9


14,380


21.8

Blendstocks

2,969


7.6


1,317


1.8


2,471


4.4


2,009


3.1

Total refinery throughput (7)

38,994


100.0


72,124


100.0


56,050


100.0


65,835


100.0

Refinery production:
















Gasoline

17,484


45.1


35,057


48.7


26,835


48.0


32,436


49.4

Diesel/jet

12,315


31.8


24,748


34.4


18,461


33.0


22,038


33.6

Asphalt

1,660


4.3


4,453


6.2


2,529


4.5


3,909


6.0

Petrochemicals

1,825


4.7


4,628


6.4


3,111


5.5


4,179


6.4

Other

5,483


14.1


3,088


4.3


5,022


9.0


3,029


4.6

Total refinery production (8)

38,767


100.0


71,974


100.0


55,958


100.0


65,591


100.0

Refinery utilization (9)



85.4%




101.2%




95.7%




97.1%






CASH AVAILABLE FOR DISTRIBUTION DATA:


For the Three



Months Ended



June 30, 2014



(dollars in
thousands,
except per unit data)




Net sales (1)


$

725,852

Operating costs and expenses:



Cost of sales


665,398

Direct operating expenses


25,152

Selling, general and administrative expenses


6,784

Depreciation and amortization


9,508

Total operating costs and expenses


706,842

Operating income


19,010

Interest expense


(11,569)

Other income, net


601

Income before state income tax expense


8,042

State income tax expense


240

Net income


7,802

Adjustments to reconcile net income to Adjusted EBITDA:



Interest expense


11,569

State income tax expense


240

Depreciation and amortization


9,508

Adjusted EBITDA (2)


29,119

Adjustments to reconcile Adjusted EBITDA to cash available for distribution:



less: Maintenance/growth capital expenditures


7,277

less: Major and non-major turnaround and catalyst replacement capital expenditures


10,982

add: Major turnaround and catalyst replacement capital expenditures previously reserved


(11,011)

less: Major turnaround reserve for future years


1,500

less: Principal payments


625

less: State income tax expense


240

less: Interest paid in cash


11,106

Cash available for distribution


$

8,400




Common units outstanding (in 000's)


62,507




Cash available for distribution per unit


$

0.13

________________



(1)

Includes sales to related parties of $152,170 and $156,043 for the three months and $291,183 and $297,942 for the six months ended June 30, 2014 and 2013, 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 six months ended June 30, 2014 and 2013:






For the Three Months Ended


For the Six Months Ended





June 30,


June 30,





2014


2013


2014


2013





(dollars in thousands)




Net income

$

7,802



$

45,321



$

50,043



$

138,846




State income tax expense

240



473



725



1,373




Interest expense

11,569



8,970



22,893



18,362




Depreciation and amortization

9,508



11,243



19,575



23,307




Adjusted EBITDA

$

29,119



$

66,007



$

93,236



$

181,888



(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