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

Schedules conference call for August 4, 2015 at 9:00 a.m. Eastern

Aug 03, 2015, 16:30 ET from Alon USA Partners, LP

DALLAS, Aug. 3, 2015 /PRNewswire/ -- Alon USA Partners, LP (NYSE: ALDW) ("Alon Partners") today announced results for the second quarter of 2015. Net income for the second quarter of 2015 was $59.4 million, or $0.95 per unit, compared to $7.8 million, or $0.12 per unit, for the same period last year. Net income for the first half of 2015 was $95.9 million, or $1.53 per unit, compared to $50.0 million, or $0.80 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 2015 of $1.04 per unit payable on August 25, 2015 to common unitholders of record at the close of business on August 18, 2015, based on cash available for distribution of $64.8 million.

Paul Eisman, President and CEO, commented, "We are pleased to have generated cash available for distribution of $1.04 per unit in the second quarter of 2015. In the last four quarters since the turnaround in 2014, we have generated total cash available for distribution of $3.47 per unit.

"Our strong results in the second quarter were supported by excellent operational performance at the Big Spring refinery and a favorable crack spread environment. Big Spring achieved a refinery operating margin of $17.22 per barrel and low direct operating expense of only $3.54 per barrel. The crude flexibility of the Big Spring refinery continues to be an advantage. The refinery processed approximately 44,000 barrels per day of WTI Midland during the second quarter of 2015 to set a new record for WTI Midland rate. On the product side, our wholesale marketing business successfully sold approximately 6,000 barrels per day in June 2015 into the premium Arizona market.

"We expect total throughput at the Big Spring refinery to average approximately 74,000 barrels per day for the third quarter of 2015 and 74,000 barrels per day for the full year of 2015."

SECOND QUARTER 2015 Refinery operating margin was $17.22 per barrel for the second quarter of 2015 compared to $17.04 per barrel for the same period in 2014. This increase in operating margin was primarily due to improved light product yields, partially offset by the industry margin environment. The contango environment in the second quarter of 2015 created a cost of crude benefit of $1.90 per barrel compared to the backwardated environment creating a cost of crude detriment of $0.93 per barrel for the same period in 2014. The Big Spring refinery average throughput for the second quarter of 2015 was 75,491 barrels per day ("bpd") compared to 38,994 bpd for the same period in 2014. During the second quarter of 2014, refinery throughput was reduced as we completed both the planned turnaround and the vacuum tower project.

The average Gulf Coast 3/2/1 crack spread was $19.71 per barrel for the second quarter of 2015 compared to $16.42 per barrel for the second quarter of 2014. The average WTI Cushing to WTS spread for the second quarter of 2015 was $(0.21) per barrel compared to $7.88 per barrel for the second quarter of 2014. The average WTI Cushing to WTI Midland spread for the second quarter of 2015 was $0.60 per barrel compared to $8.37 per barrel for the second quarter of 2014.

YEAR-TO-DATE 2015 Refinery operating margin was $15.56 per barrel for the first half of 2015 compared to $15.56 per barrel for the same period in 2014. The operating margin was flat relative to the same period last year primarily due to improved light product yields being offset by the industry margin environment. The contango environment for the first half of 2015 created a cost of crude benefit of $1.28 per barrel compared to the backwardated environment creating a cost of crude detriment of $0.53 per barrel for the same period in 2014. The Big Spring refinery average throughput for the first half of 2015 was 73,934 bpd compared to 56,050 bpd for the same period in 2014. During the second quarter of 2014, refinery throughput was reduced as we completed both the planned turnaround and the vacuum tower project.

The average Gulf Coast 3/2/1 crack spread was $18.73 per barrel for the first half of 2015 compared to $16.61 per barrel for the same period in 2014. The average WTI Cushing to WTS spread for the first half of 2015 was $0.76 per barrel compared to $5.79 per barrel for the same period in 2014. The average WTI Cushing to WTI Midland spread for the first half of 2015 was $1.27 per barrel compared to $5.96 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, August 4, 2015 at 9:00 a.m. Eastern Time (8:00 a.m. Central Time), to discuss the second 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 August 18, 2015, and may be accessed by calling 877-660-6853, or 201-612-7415 for international callers, and using the passcode 13612043#. 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.

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 Six Months Ended

June 30,

June 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)

$

625,064

$

725,852

$

1,167,506

$

1,582,312

Operating costs and expenses:

 Cost of sales

507,122

665,398

957,717

1,424,444

 Direct operating expenses

24,285

25,152

47,701

54,093

 Selling, general and administrative expenses

10,215

6,784

16,118

11,152

 Depreciation and amortization

13,591

9,508

27,584

19,575

   Total operating costs and expenses

555,213

706,842

1,049,120

1,509,264

Operating income

69,851

19,010

118,386

73,048

Interest expense

(10,847)

(11,569)

(22,540)

(22,893)

Other income (loss), net

27

601

(14)

613

Income before state income tax expense (benefit)

59,031

8,042

95,832

50,768

State income tax expense (benefit)

(395)

240

(45)

725

Net income

$

59,426

$

7,802

$

95,877

$

50,043

Earnings per unit

$

0.95

$

0.12

$

1.53

$

0.80

Weighted average common units outstanding (in thousands)

62,509

62,504

62,508

62,504

Cash distribution per unit

$

0.71

$

0.69

$

1.41

$

0.87

CASH FLOW DATA:

Net cash provided by (used in):

 Operating activities

$

107,311

$

(35)

$

134,398

$

45,232

 Investing activities

(5,985)

(18,259)

(9,790)

(36,886)

 Financing activities

(61,829)

(68,955)

(81,049)

(80,830)

OTHER DATA:

Adjusted EBITDA (2)

$

83,469

$

29,119

$

145,956

$

93,236

Capital expenditures

5,465

7,277

7,786

11,439

Capital expenditures for turnarounds and catalysts

520

10,982

2,004

25,447

KEY OPERATING STATISTICS:

Per barrel of throughput:

 Refinery operating margin (3)

$

17.22

$

17.04

$

15.56

$

15.56

 Refinery direct operating expense (4)

3.54

7.09

3.56

5.33

PRICING STATISTICS:

Crack spreads (per barrel):

 Gulf Coast 3/2/1 (5)

$

19.71

$

16.42

$

18.73

$

16.61

WTI Cushing crude oil (per barrel)

$

57.86

$

103.04

$

53.20

$

100.86

Crude oil differentials (per barrel):

 WTI Cushing less WTI Midland (6)

$

0.60

$

8.37

$

1.27

$

5.96

 WTI Cushing less WTS (6)

(0.21)

7.88

0.76

5.79

 Brent less WTI Cushing (6)

3.66

7.22

4.54

8.83

Product price (dollars per gallon):

 Gulf Coast unleaded gasoline

$

1.86

$

2.81

$

1.69

$

2.73

 Gulf Coast ultra-low sulfur diesel

1.83

2.92

1.76

2.93

 Natural gas (per MMBtu)

2.74

4.58

2.77

4.65

 

June 30, 2015

December 31, 2014

BALANCE SHEET DATA (end of period):

(dollars in thousands)

Cash and cash equivalents

$

149,884

$

106,325

Working capital

166

(4,561)

Total assets

807,757

770,246

Total debt

281,420

302,376

Total debt less cash and cash equivalents

131,536

196,051

Total partners' equity

196,165

188,402

THROUGHPUT AND PRODUCTION DATA:

For the Three Months Ended

For the Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

bpd

%

bpd

%

bpd

%

bpd

%

Refinery throughput:

 WTS crude

29,605

39.2

12,634

32.4

37,193

50.3

23,927

42.7

 WTI crude

43,659

57.8

23,391

60.0

33,952

45.9

29,652

52.9

 Blendstocks

2,227

3.0

2,969

7.6

2,789

3.8

2,471

4.4

Total refinery throughput (7)

75,491

100.0

38,994

100.0

73,934

100.0

56,050

100.0

Refinery production:

 Gasoline

37,755

49.8

17,484

45.1

36,978

49.8

26,835

48.0

 Diesel/jet

28,052

37.0

12,315

31.8

27,074

36.5

18,461

33.0

 Asphalt

2,479

3.3

1,660

4.3

2,876

3.9

2,529

4.5

 Petrochemicals

4,915

6.5

1,825

4.7

4,863

6.5

3,111

5.5

 Other

2,537

3.4

5,483

14.1

2,466

3.3

5,022

9.0

Total refinery production (8)

75,738

100.0

38,767

100.0

74,257

100.0

55,958

100.0

Refinery utilization (9)

100.4

%

85.4

%

97.5

%

95.7

%

 

CASH AVAILABLE FOR DISTRIBUTION DATA:

For the Three Months Ended

June 30, 2015

(dollars in thousands, except per unit data)

Net sales (1)

$

625,064

Operating costs and expenses:

 Cost of sales

507,122

 Direct operating expenses

24,285

 Selling, general and administrative expenses

10,215

 Depreciation and amortization

13,591

    Total operating costs and expenses

555,213

Operating income

69,851

Interest expense

(10,847)

Other income, net

27

Income before state income tax benefit

59,031

State income tax benefit

(395)

Net income

59,426

Adjustments to reconcile net income to Adjusted EBITDA:

Interest expense

10,847

State income tax benefit

(395)

Depreciation and amortization

13,591

Adjusted EBITDA (2)

83,469

Adjustments to reconcile Adjusted EBITDA to cash available for distribution:

 less: Maintenance/growth capital expenditures

5,465

 less: Turnaround and catalyst replacement capital expenditures

520

 less: Major turnaround reserve for future years

1,500

 less: Principal payments

625

 less: State income tax payments

341

 less: Interest paid in cash

10,236

Cash available for distribution

$

64,782

Common units outstanding (in 000's)

62,510

Cash available for distribution per unit

$

1.04

________________

(1)

Includes sales to related parties of $101,233 and $152,170 for the three months ended June 30, 2015 and 2014, respectively, and $184,122 and $291,183 for the six months ended June 30, 2015 and 2014, 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.

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, 2015 and 2014:

For the Three Months Ended

For the Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

(dollars in thousands)

Net income

$

59,426

$

7,802

$

95,877

$

50,043

State income tax expense (benefit)

(395)

240

(45)

725

Interest expense

10,847

11,569

22,540

22,893

Depreciation and amortization

13,591

9,508

27,584

19,575

Adjusted EBITDA

$

83,469

$

29,119

$

145,956

$

93,236

(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, 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.

 

Contacts:

Stacey Hudson, Investor Relations Manager

Alon USA Partners GP, LLC

972-367-3808

Investors: Jack Lascar/Stephanie Smith

Dennard § Lascar Associates, LLC 713-529-6600

Media: Blake Lewis

Lewis Public Relations

214-635-3020

 

SOURCE Alon USA Partners, LP



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