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Form 8-K Alon USA Energy, Inc. For: Oct 26

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October 27, 2016 6:04 AM EDT


 
 
    

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
        
____________________________
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) of the
Securities Exchange Act of 1934

Date of report (Date of earliest event reported): October 26, 2016

ALON USA ENERGY, INC.
(Exact Name of Registrant as Specified in Charter)

Delaware
(State or Other Jurisdiction
of Incorporation)
001-32567
(Commission
File Number)
74-2966572
(IRS Employer
Identification No.)

12700 Park Central Dr., Suite 1600
Dallas, Texas 75251
(Address of Principal Executive Offices) (Zip Code)

Registrant’s telephone number, including area code: (972) 367-3600

____________________________


Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
        
o
 
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o
 
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o
 
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o
 
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))









 
 




Item 2.02.  Results of Operations and Financial Condition.
On October 26, 2016, Alon USA Partners, LP (“Alon Partners”), a subsidiary of Alon USA Energy, Inc., issued a press release (the “Press Release”) reporting its financial results for the quarter ended September 30, 2016.  A copy of the Press Release is furnished as Exhibit 99.1 to this Current Report on Form 8-K, and is incorporated by reference into this Item 2.02.

Item 9.01. Financial Statements and Exhibits.
(d)    Exhibits.
Exhibit Number
 
Description
99.1
 
Press Release dated October 26, 2016.





SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 
 
Alon USA Energy, Inc.
Date:
October 26, 2016
By:  
/s/ Shai Even
 
 
 
Shai Even 
 
 
 
Senior Vice President and Chief Financial Officer








INDEX TO EXHIBITS

Exhibit Number
 
Description
99.1
 
Press Release dated October 26, 2016.




alonpartnerslogo1a04.jpg
 
NEWS RELEASE
 
 
 
 
Contacts:
Stacey Morris, Investor Relations Manager
Alon USA Partners GP, LLC
972-367-3808
FOR IMMEDIATE RELEASE
 
 
 
 
Investors: Jack Lascar
Dennard § Lascar Associates, LLC
713-529-6600

Media: Blake Lewis
Lewis Public Relations
214-635-3020
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
DALLAS, TEXAS, October 26, 2016 - 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

- 1 -


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 [email protected].
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.
- Tables to follow -

- 2 -


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


- 3 -


 
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
%

- 4 -


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.

- 5 -


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.

- 6 -

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