Alon USA Partners Reports Second Quarter Results

Declares Quarterly Cash Distribution

Partnership schedules conference call for August 7, 2013 at 10:00 a.m. Eastern

News provided by

Alon USA Partners, LP

Aug 05, 2013, 05:57 ET

DALLAS, Aug. 5, 2013 /PRNewswire/ -- Alon USA Partners, LP (NYSE: ALDW) (the "Partnership") today announced results for the second quarter of 2013. Net income for the second quarter of 2013 was $45.3 million, or $0.73 per unit, compared to $100.2 million for the same period last year. Net income for the first half of 2013 was $138.8 million, or $2.22 per unit, compared to $148.3 million for the same period last year.

The Board of Directors of Alon USA Partners GP, LLC, the general partner of Alon Partners, declared a distribution of $0.71 per unit payable in cash on August 23, 2013 to common unitholders of record at the close of business on August 16, 2013. Cash available for distribution for the three months ended June 30, 2013 totaled $44.1 million.

Paul Eisman, CEO and President, commented, "Our Big Spring Refinery had an excellent operational quarter recording its highest ever quarterly crude throughput of 70,807 barrels per day with total throughput of 72,124 barrels per day. We experienced a sharp decline in the WTI to WTS spread, declining approximately $11 per barrel for the second quarter compared to first quarter of 2013. The Gulf Coast 3/2/1 crack spreads declined by approximately $7 per barrel for the second quarter compared to first quarter of 2013. We are focused on opportunities to improve our assets and are planning a project that will be implemented during the Big Spring turnaround in 2014 that will increase overall distillate yield by 2% and will also increase total refinery throughput by 3,000 barrels per day.

"In addition, in the second quarter we were impacted by sharp increases in RINs prices. We recorded approximately $8 million of costs in the second quarter for RINs obligations. We are actively working to mitigate these costs primarily by blending biodiesel into our Big Spring product beginning in September. We anticipate at current RINs pricing that our RINs obligation at Big Spring for the year will be approximately $20 million.

"Looking forward to the third quarter, we expect total throughput at Big Spring to average approximately 69,000 barrels per day."

SECOND QUARTER 2013

Refinery operating margin was $16.21 per barrel for the second quarter of 2013 compared to $25.79 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 second quarter of 2013 averaged 72,124 barrels per day ("bpd") compared to 64,558 bpd for the same period in 2012. Throughput for the second quarter of 2012 was impacted by downtime for the planned regeneration of our reformer catalyst and replacement of several catalyst beds during the period.

The average Gulf Coast 3/2/1 crack spread was $21.17 per barrel for the second quarter of 2013 compared to $26.04 per barrel for the second quarter of 2012. The average WTI to WTS spread for the second quarter of 2013 was $0.36 per barrel compared to $5.36 per barrel for the same period in 2012.

YEAR-TO-DATE 2013

Refinery operating margin was $21.85 per barrel for the first half of 2013 compared to $20.32 per barrel for the same period in 2012. This increase is mainly due to a wider WTI to WTS spread partially offset by lower Gulf Coast 3/2/1 crack spreads. The refinery's throughput for the first half of 2013 averaged 65,835 bpd compared to 67,035 bpd for the same period in 2012.

The average Gulf Coast 3/2/1 crack spread was $24.76 per barrel for the first half of 2013 compared to $25.41 per barrel for the same period in 2012. The average WTI to WTS spread for the first half of 2013 was $5.86 per barrel compared to $3.76 per barrel for the same period in 2012.

CONFERENCE CALL

The Partnership has scheduled a conference call which will also be webcast live on Wednesday, August 7, 2013 at 10:00 a.m. eastern time (9:00 a.m. central time), to discuss the second quarter 2013 results. To access the call, please dial 800-941-6009 or 480-629-9722, for international callers, at least 10 minutes prior to the start time and ask for the Alon USA Partners, LP call. Investors may also access the live webcast on the Alon Partners website, http://www.alonpartners.com by logging on that site and clicking "Investors." A telephonic replay of the conference call will be available through August 21, 2013, and may be accessed by calling 800-406-7325, or 303-590-3030, for international callers, and using the passcode 4630534#. 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.

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 is 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:

Claire Hart, Senior Vice President

Alon USA Partners GP, LLC
972-367-3649




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

- 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, 2012, IS UNAUDITED)

















For the Three Months Ended

For the Six Months Ended

June 30,

June 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)

$

865,694


$

823,769

$

1,669,861


$

1,708,043

Operating costs and expenses:








Cost of sales

767,322


672,270

1,417,525


1,460,164

Direct operating expenses

27,314


25,073

57,736


47,743

Selling, general and administrative expenses

5,065


3,909

12,730


7,754

Depreciation and amortization

11,243


11,424

23,307


23,390

Total operating costs and expenses

810,944


712,676

1,511,298


1,539,051

Operating income

54,750


111,093

158,563


168,992

Interest expense

(8,970)


(5,683)

(18,362)


(10,757)

Interest expense - related parties

—


(4,266)

—


(8,533)

Other income (loss), net

14


(4)

18


17

Income before state income tax expense

45,794


101,140

140,219


149,719

State income tax expense

473


917

1,373


1,420

Net income

$

45,321


$

100,223

$

138,846


$

148,299

Earnings per unit

$

0.73




$

2.22



Weighted average common units outstanding (in thousands)

62,502




62,502



CASH FLOW DATA:








Net cash provided by (used in):








Operating activities

$

(13,403)


$

143,668

$

153,243


$

187,143

Investing activities

(7,257)


(11,823)

(13,976)


(19,104)

Financing activities

(143,128)


(126,105)

(178,584)


(262,286)

OTHER DATA:








Adjusted EBITDA (2)

$

66,007


$

122,513

$

181,888


$

192,399

Capital expenditures

6,216


5,820

9,157


11,042

Capital expenditures for turnaround and chemical catalyst

1,041


6,003

4,819


8,062

KEY OPERATING STATISTICS:








Per barrel of throughput:








Refinery operating margin (3)

$

16.21


$

25.79

$

21.85


$

20.32

Refinery direct operating expense (4)

4.16


4.27

4.85


3.92

PRICING STATISTICS:








Crack spreads (per barrel):








Gulf Coast 3/2/1 (5)

$

21.17


$

26.04

$

24.76


$

25.41

WTI crude oil (per barrel)

$

94.20


$

93.45

$

94.23


$

98.23

Crude oil differentials (per barrel):








WTI less WTS (6)

$

0.36


$

5.36

$

5.86


$

3.76

Product price (dollars per gallon):








Gulf Coast unleaded gasoline

$

2.69


$

2.80

$

2.77


$

2.89

Gulf Coast ultra-low sulfur diesel

2.86


2.95

2.97


3.05

Natural gas (per MMBtu)

4.02


2.35

3.76


2.43










June 30,
2013

December 31,
2012

BALANCE SHEET DATA (end of period):

 (dollars in thousands)

Cash and cash equivalents

$

26,684

$

66,001

Working capital

(24,973)

1,702

Total assets

729,815

763,423

Total debt

245,312

295,311

Total partners' equity

192,443

181,726


(A)

Earnings per unit information is not presented for the three and six months ended June 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 six months ended June 30, 2012.
























THROUGHPUT AND PRODUCTION DATA:

For the Three Months Ended

For the Six Months Ended

June 30,

June 30,

2013

2012

2013

2012




Predecessor





Predecessor

bpd

%

bpd

%

bpd

%

bpd

%

Refinery throughput:
















WTS crude

53,627

74.4


52,250

81.0

49,446

75.1


53,898

80.4

WTI crude

17,180

23.8


10,738

16.6

14,380

21.8


11,472

17.1

Blendstocks

1,317

1.8


1,570

2.4

2,009

3.1


1,665

2.5

Total refinery throughput (7)

72,124

100.0


64,558

100.0

65,835

100.0


67,035

100.0

Refinery production:
















Gasoline

35,057

48.7


30,885

47.8

32,436

49.4


33,012

49.2

Diesel/jet

24,748

34.4


21,242

32.9

22,038

33.6


21,739

32.5

Asphalt

4,453

6.2


4,041

6.2

3,909

6.0


4,288

6.4

Petrochemicals

4,628

6.4


3,838

5.9

4,179

6.4


3,988

6.0

Other

3,088

4.3


4,655

7.2

3,029

4.6


3,921

5.9

Total refinery production (8)

71,974

100.0


64,661

100.0

65,591

100.0


66,948

100.0

Refinery utilization (9)

101.2

%



98.9

%


97.1

%



97.8

%


 



CASH AVAILABLE FOR DISTRIBUTION DATA:

For the Three Months Ended

June 30, 2013

(dollars in thousands, except

per unit data)

Net sales

$

865,694

Operating costs and expenses:

Cost of sales

767,322

Direct operating expenses

27,314

Selling, general and administrative expenses

5,065

Depreciation and amortization

11,243

Total operating costs and expenses

810,944

Operating income

54,750

Interest expense

(8,970)

Other income, net

14

Income before state income tax expense

45,794

State income tax expense

473

Net income

45,321

Adjustments to reconcile net income to Adjusted EBITDA:

Interest expense

8,970

State income tax expense

473

Depreciation and amortization

11,243

Adjusted EBITDA

66,007

Adjustments to reconcile Adjusted EBITDA to cash available for distribution before special expenses:

less: Maintenance/growth capital expenditures

6,216

less: Turnaround and catalyst replacement capital expenditures

1,041

less: Major turnaround reserve

1,150

less: Principal payments

625

less: State income tax expense

473

less: Interest paid in cash

8,296

Cash available for distribution before special expenses

48,206

less: Special turnaround reserve

4,104

Cash available for distribution

$

44,102



Common units outstanding (in 000's)

62,502



Cash available for distribution per unit

$

0.71

________________

(1)

Includes sales to related parties of $156,043 and $148,171 for the three months ended June 30, 2013 and 2012, respectively, and $297,942 and $298,734 for the six months ended June 30, 2013 and 2012, respectively.

(2)

Adjusted EBITDA represents earnings before state income tax expense, interest expense, depreciation and amortization, and gain 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, gain 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.

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, 2013 and 2012, respectively:






















For the Three Months Ended

For the Six Months Ended

June 30,

June 30,

2013

2012

2013

2012


Predecessor



Predecessor

(dollars in thousands)

Net income

$

45,321


$

100,223

$

138,846


$

148,299

State income tax expense

473


917

1,373


1,420

Interest expense

8,970


5,683

18,362


10,757

Interest expense - related parties

—


4,266

—


8,533

Depreciation and amortization

11,243


11,424

23,307


23,390

Adjusted EBITDA

$

66,007


$

122,513

$

181,888


$

192,399




(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.

The refinery operating margin excludes charges of $8,016 related to RINs obligations for the three and six months ended June 30, 2013.

(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.

SOURCE Alon USA Partners, LP