Alon USA Partners, LP Reports Third Quarter 2016 Results and Declares Quarterly Cash Distribution

Schedules conference call for October 28, 2016 at 9:30 a.m. Eastern

News provided by

Alon USA Partners, LP

Oct 26, 2016, 06:07 ET

DALLAS, Oct. 26, 2016 /PRNewswire/ -- Alon USA Partners, LP (NYSE: ALDW) ("Alon Partners") today announced results for the third quarter of 2016. Net income for the third quarter of 2016 was $2.1 million, or $0.03 per unit, compared to $53.8 million, or $0.86 per unit, for the same period last year. Net loss for the first nine months of 2016 was $(5.3) million, or $(0.08) per unit, compared to net income of $149.7 million, or $2.39 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 2016 of $0.15 per unit payable on November 22, 2016 to common unitholders of record at the close of business on November 11, 2016, based on cash available for distribution of $9.4 million.

Paul Eisman, President and CEO commented, "Our third quarter results reflect a continuation of the difficult refining environment experienced in the first two quarters of 2016. While crack spreads were relatively flat with the second quarter of 2016, the average benchmark crack spread in the third quarter was down approximately $6.50 per barrel relative to the same quarter last year. As discussed in our previous earnings release, our third quarter results were also negatively impacted by a reformer regeneration in August. We estimate that the lost opportunity cost and maintenance expense associated with the reformer regeneration negatively impacted Alon Partners' adjusted EBITDA by approximately $8 million which reduced cash available for distribution by $0.13 per unit for the third quarter. Additionally, high RINs costs continue to weigh on our profitability.

"The Big Spring refinery achieved total throughput of 70,000 barrels per day and generated refinery operating margin of $9.22 per barrel. Our direct operating expense of $3.90 per barrel was negatively impacted by the reformer regeneration, which lowered throughput volumes and increased maintenance expense. We expect total throughput to average approximately 77,000 barrels per day for the fourth quarter of 2016. Based on current forward curve crack spreads, it is our expectation that with operations consistent with our plan we should generate sufficient cash available for distribution during the fourth quarter of 2016."

THIRD QUARTER 2016

Refinery operating margin was $9.22 per barrel for the third quarter of 2016 compared to $16.71 per barrel for the same period in 2015. This decrease in operating margin was primarily due to a lower Gulf Coast 3/2/1 crack spread and increased RINs costs, partially offset by a widening of both the WTI Cushing to WTI Midland and WTI Cushing to WTS spreads and an increased benefit from the contango market environment which reduced the cost of crude. Refinery average throughput for the third quarter of 2016 was 70,063 barrels per day ("bpd") compared to 75,797 bpd for the same period in 2015. The reduced throughput was the result of a reformer regeneration during the third quarter of 2016.

The average Gulf Coast 3/2/1 crack spread was $13.31 per barrel for the third quarter of 2016 compared to $19.77 per barrel for the third quarter of 2015. The average WTI Cushing to WTI Midland spread for the third quarter of 2016 was $0.31 per barrel compared to $(0.72) per barrel for the third quarter of 2015. The average WTI Cushing to WTS spread for the third quarter of 2016 was $0.92 per barrel compared to $(1.46) per barrel for the third quarter of 2015. The average Brent to WTI Cushing spread for the third quarter of 2016 was $0.74 per barrel compared to $3.78 per barrel for the same period in 2015. The contango environment in the third quarter of 2016 created an average cost of crude benefit of $0.84 per barrel compared to an average cost of crude benefit of $0.57 per barrel for the same period in 2015. The average RINs cost effect on refinery operating margin was $0.58 per barrel in the third quarter of 2016, compared to $0.27 per barrel for the same period in 2015.

YEAR-TO-DATE 2016

Refinery operating margin was $8.52 per barrel for the first nine months of 2016 compared to $15.95 per barrel for the same period in 2015. This decrease in operating margin was primarily due to a lower Gulf Coast 3/2/1 crack spread and a narrowing of the WTI Cushing to WTI Midland spread, partially offset by a widening of the WTI Cushing to WTS spread and an increased benefit from the contango market environment which reduced the cost of crude. Refinery average throughput for the first nine months of 2016 was 69,586 bpd compared to 74,562 bpd for the same period in 2015. The reduced throughput during the first nine months of 2016 was the result of a reformer regeneration during the first quarter of 2016, which was repeated during the third quarter of 2016. Additionally, throughput was reduced as a result of a catalyst replacement for our diesel hydrotreater unit in the first quarter of 2016 and unplanned downtime during the second quarter of 2016 due to a power outage caused by inclement weather, which affected multiple units.

The average Gulf Coast 3/2/1 crack spread was $12.57 per barrel for the first nine months of 2016 compared to $19.08 per barrel for the same period in 2015. The average WTI Cushing to WTI Midland spread for the first nine months of 2016 was $0.12 per barrel compared to $0.60 per barrel for the same period in 2015. The average WTI Cushing to WTS spread for the first nine months of 2016 was $0.53 per barrel compared to $0.02 per barrel for the same period in 2015. The average Brent to WTI Cushing spread for the first nine months of 2016 was $0.35 per barrel compared to $4.28 per barrel for the same period in 2015. The contango environment for the first nine months of 2016 created an average cost of crude benefit of $1.39 per barrel compared to an average cost of crude benefit of $1.04 per barrel for the same period in 2015.

CONFERENCE CALL

Alon Partners has scheduled a conference call, which will be broadcast live over the Internet on Friday, October 28, 2016 at 9:30 a.m. Eastern Time (8:30 a.m. Central Time), to discuss the third quarter 2016 financial 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 4, 2016 and may be accessed by calling 877-660-6853, or 201-612-7415 for international callers, and using the passcode 13646174#. 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. (NYSE: ALJ) ("Alon Energy"). 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 Central and West Texas, Oklahoma, New Mexico and Arizona through its integrated wholesale distribution network to both Alon Energy's retail convenience stores and other third-party distributors.

Contacts:

Stacey Morris, 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

- 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, 2015, IS UNAUDITED)

For the Three Months Ended

For the Nine Months Ended

September 30,

September 30,

2016

2015

2016

2015

(dollars in thousands, except per unit data, per barrel data and pricing statistics)

STATEMENTS OF OPERATIONS DATA:






Net sales (1)

$

462,257

$

551,813

$

1,298,723

$

1,719,319

Operating costs and expenses:






Cost of sales

404,207

439,678

1,134,275

1,397,395

Direct operating expenses

25,125

24,136

73,424

71,837

Selling, general and administrative expenses

8,153

8,536

24,264

24,654

Depreciation and amortization

14,581

13,697

43,454

41,281

Total operating costs and expenses

452,066

486,047

1,275,417

1,535,167

Operating income

10,191

65,766

23,306

184,152

Interest expense

(8,144)

(11,505)

(28,651)

(34,045)

Other income, net

353

40

550

26

Income (loss) before state income tax expense

2,400

54,301

(4,795)

150,133

State income tax expense

317

525

493

480

Net income (loss)

$

2,083

$

53,776

$

(5,288)

$

149,653

Earnings (loss) per unit

$

0.03

$

0.86

$

(0.08)

$

2.39

Weighted average common units outstanding (in thousands)

62,520

62,510

62,515

62,508

Cash distribution per unit

$

0.14

$

1.04

$

0.22

$

2.45

CASH FLOW DATA:






Net cash provided by (used in):






Operating activities

$

11,870

$

84,834

$

58,457

$

219,232

Investing activities

(5,954)

(5,532)

(26,878)

(15,322)

Financing activities

36,027

(93,908)

39,231

(174,957)

OTHER DATA:






Adjusted EBITDA (2)

$

25,125

$

79,503

$

67,310

$

225,459

Capital expenditures

4,499

4,322

17,199

12,108

Capital expenditures for turnarounds and catalysts

1,455

1,210

9,679

3,214

KEY OPERATING STATISTICS:






Per barrel of throughput:






Refinery operating margin (3)

$

9.22

$

16.71

$

8.52

$

15.95

Refinery direct operating expense (4)

3.90

3.46

3.85

3.53

PRICING STATISTICS:






Crack spreads (per barrel):






Gulf Coast 3/2/1 (5)

$

13.31

$

19.77

$

12.57

$

19.08

WTI Cushing crude oil (per barrel)

$

44.88

$

46.41

$

41.23

$

50.91

Crude oil differentials (per barrel):






WTI Cushing less WTI Midland (6)

$

0.31

$

(0.72)

$

0.12

$

0.60

WTI Cushing less WTS (6)

0.92

(1.46)

0.53

0.02

Brent less WTI Cushing (6)

0.74

3.78

0.35

4.28

Product price (dollars per gallon):






Gulf Coast unleaded gasoline

$

1.39

$

1.61

$

1.30

$

1.66

Gulf Coast ultra-low sulfur diesel

1.37

1.52

1.25

1.68

Natural gas (per MMBtu)

2.79

2.73

2.34

2.76









September 30,
2016

December 31,
2015

BALANCE SHEET DATA (end of period):

 (dollars in thousands)

Cash and cash equivalents

$

203,763

$

132,953

Working capital

10,460

(53,804)

Total assets

825,050

748,584

Total debt

291,486

292,082

Total debt less cash and cash equivalents

87,723

159,129

Total partners' equity

111,968

130,957

























THROUGHPUT AND PRODUCTION DATA:

For the Three Months Ended

For the Nine Months Ended

September 30,

September 30,

2016

2015

2016

2015

bpd

%

bpd

%

bpd

%

bpd

%

Refinery throughput:














WTS crude

34,292

48.9

30,810

40.6

32,189

46.3

35,041

47.0

WTI crude

32,503

46.4

42,503

56.1

34,428

49.4

36,834

49.4

Blendstocks

3,268

4.7

2,484

3.3

2,969

4.3

2,687

3.6

Total refinery throughput (7)

70,063

100.0

75,797

100.0

69,586

100.0

74,562

100.0

Refinery production:














Gasoline

33,637

48.1

37,503

49.5

33,826

48.7

37,155

49.6

Diesel/jet

26,004

37.2

28,623

37.8

25,108

36.1

27,596

36.9

Asphalt

2,818

4.0

2,452

3.2

2,846

4.1

2,733

3.7

Petrochemicals

3,861

5.5

4,588

6.1

3,611

5.2

4,770

6.4

Other

3,661

5.2

2,595

3.4

4,084

5.9

2,510

3.4

Total refinery production (8)

69,981

100.0

75,761

100.0

69,475

100.0

74,764

100.0

Refinery utilization (9)

99.1

%


100.4

%


95.5

%


98.5

%






























CASH AVAILABLE FOR DISTRIBUTION DATA:

For the Three
Months Ended


September 30, 2016


(dollars in
thousands, except
per unit data)



Net sales (1)

$

462,257

Operating costs and expenses:

Cost of sales

404,207

Direct operating expenses

25,125

Selling, general and administrative expenses

8,153

Depreciation and amortization

14,581

Total operating costs and expenses

452,066

Operating income

10,191

Interest expense

(8,144)

Other income, net

353

Income before state income tax expense

2,400

State income tax expense

317

Net income

2,083

Adjustments to reconcile net loss to Adjusted EBITDA:

Interest expense

8,144

State income tax expense

317

Depreciation and amortization

14,581

Adjusted EBITDA (2)

25,125

Adjustments to reconcile Adjusted EBITDA to cash available for distribution:

less: Maintenance/growth capital expenditures

4,499

less: Turnaround and catalyst replacement capital expenditures

1,455

less: Major turnaround reserve for future years

1,500

less: Principal payments

625

less: State income tax payments

317

less: Interest paid in cash

7,337

Calculated cash available for distribution

$

9,392



Common units outstanding (in 000's)

62,520



Cash available for distribution per unit

$

0.15




________________



(1)

Includes sales to related parties of $82,717 and $97,014 for the three months ended September 30, 2016 and 2015, respectively, and $222,711 and $281,136 for the nine months ended September 30, 2016 and 2015, 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 (loss) to Adjusted EBITDA for the three and nine months ended September 30, 2016 and 2015:















For the Three Months Ended

For the Nine Months Ended


September 30,

September 30,


2016

2015

2016

2015


(dollars in thousands)

    Net income (loss)

$

2,083

$

53,776

$

(5,288)

$

149,653

    State income tax expense

317

525

493

480

    Interest expense

8,144

11,505

28,651

34,045

    Depreciation and amortization

14,581

13,697

43,454

41,281

    Adjusted EBITDA

$

25,125

$

79,503

$

67,310

$

225,459



(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, 2016 excludes gains (losses) related to inventory adjustments of $(1,419) and $2,046, respectively. 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.

SOURCE Alon USA Partners, LP