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

Schedules conference call for November 3, 2015 at 9:00 a.m. Eastern

News provided by

Alon USA Partners, LP

Nov 02, 2015, 05:15 ET

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

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