Alon USA Partners, LP Reports First Quarter 2017 Results and Declares Quarterly Cash Distribution
Schedules conference call for May 9, 2017 at 11:30 a.m. Eastern
DALLAS, May 8, 2017 /PRNewswire/ -- Alon USA Partners, LP (NYSE: ALDW) ("Alon Partners") today announced results for the first quarter of 2017. Net income for the first quarter of 2017 was $20.1 million, or $0.32 per unit, compared to net loss of $(8.6) million, or $(0.14) 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 first quarter of 2017 of $0.38 per unit payable on May 30, 2017 to common unitholders of record at the close of business on May 22, 2017, based on cash available for distribution of $23.7 million.
Alan Moret, CEO, commented, "We are pleased with our performance in the first quarter of 2017, which resulted in cash available for distribution of $0.38 per unit. Our first quarter results benefited from an improvement in our benchmark Gulf Coast crack spread relative to the fourth quarter of 2016 and the same quarter last year. The improvement in the crack spread was complemented by strong operations, with the Big Spring refinery setting a new record for quarterly total throughput. We have been encouraged by the positive trends we have seen in refining into the second quarter of 2017, including attractive discounts for Midland-priced crudes and improved crack spreads."
Shai Even, President and CFO, commented, "The Big Spring refinery achieved record quarterly total throughput of almost 78,000 barrels per day in the first quarter of 2017. The refinery operating margin of $10.32 per barrel benefited from a strong wholesale marketing environment. Direct operating expense was only $3.54 per barrel as a result of efficient operations in the first quarter.
"We expect total throughput at the Big Spring refinery to average 73,000 barrels per day for the second quarter of 2017 and 75,000 barrels per day for the full year of 2017. 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 second quarter of 2017."
FIRST QUARTER 2017
Refinery operating margin was $10.32 per barrel for the first quarter of 2017 compared to $7.77 per barrel for the same period in 2016. This increase in operating margin was primarily due to a higher Gulf Coast 3/2/1 crack spread and a widening of the WTI Cushing to WTS spread, partially offset by the increased premium in WTI Midland compared to WTI Cushing, increased RINs costs and a reduced benefit from the contango market environment which increased the cost of crude. Refinery average throughput for the first quarter of 2017 was 77,754 barrels per day ("bpd") compared to 67,536 bpd for the same period in 2016. The reduced throughput during the first quarter of 2016 was the result of planned downtime to complete a reformer regeneration and catalyst replacement for our diesel hydrotreater unit.
The average Gulf Coast 3/2/1 crack spread was $13.75 per barrel for the first quarter of 2017 compared to $11.24 per barrel for the first quarter of 2016. The average WTI Cushing to WTI Midland spread for the first quarter of 2017 was $(0.64) per barrel compared to $(0.13) per barrel for the first quarter of 2016. The average WTI Cushing to WTS spread for the first quarter of 2017 was $1.27 per barrel compared to $(0.10) per barrel for the first quarter of 2016. The average Brent to WTI Cushing spread for the first quarter of 2017 was $1.66 per barrel compared to $0.49 per barrel for the same period in 2016. The contango environment in the first quarter of 2017 created an average cost of crude benefit of $1.00 per barrel compared to an average cost of crude benefit of $1.83 per barrel for the same period in 2016. The average RINs cost effect on refinery operating margin was $0.59 per barrel in the first quarter of 2017, compared to $0.13 per barrel for the same period in 2016.
CONFERENCE CALL
Alon Partners has scheduled a conference call, which will be broadcast live over the Internet on Tuesday, May 9, 2017 at 11:30 a.m. Eastern Time (10:30 a.m. Central Time), to discuss the first quarter 2017 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 May 16, 2017 and may be accessed by calling 877-660-6853, or 201-612-7415 for international callers, and using the passcode 13660047#. 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.
| Contacts: |
Stacey Morris, Investor Relations Manager Alon USA Partners GP, LLC |
| Investors: Jack Lascar 713-529-6600 |
|
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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, 2016, IS UNAUDITED) |
For the Three Months Ended |
|||||||
| March 31, |
||||||||
| 2017 |
2016 |
|||||||
| (dollars in thousands, except per unit |
||||||||
| STATEMENTS OF OPERATIONS DATA: |
||||||||
| Net sales (1) |
$ |
544,532 |
$ |
368,009 |
||||
| Operating costs and expenses: |
||||||||
| Cost of sales |
470,471 |
319,333 |
||||||
| Direct operating expenses |
24,760 |
25,044 |
||||||
| Selling, general and administrative expenses |
6,764 |
7,309 |
||||||
| Depreciation and amortization |
14,229 |
14,206 |
||||||
| Total operating costs and expenses |
516,224 |
365,892 |
||||||
| Operating income |
28,308 |
2,117 |
||||||
| Interest expense |
(7,845) |
(10,587) |
||||||
| Other income (loss), net |
(95) |
84 |
||||||
| Income (loss) before state income tax expense |
20,368 |
(8,386) |
||||||
| State income tax expense |
256 |
176 |
||||||
| Net income (loss) |
$ |
20,112 |
$ |
(8,562) |
||||
| Earnings (loss) per unit |
$ |
0.32 |
$ |
(0.14) |
||||
| Weighted average common units outstanding (in thousands) |
62,520 |
62,510 |
||||||
| Cash distribution per unit |
$ |
0.11 |
$ |
0.08 |
||||
| CASH FLOW DATA: |
||||||||
| Net cash provided by (used in): |
||||||||
| Operating activities |
$ |
41,772 |
$ |
6,662 |
||||
| Investing activities |
(5,875) |
(10,793) |
||||||
| Financing activities |
(387) |
(5,626) |
||||||
| OTHER DATA: |
||||||||
| Adjusted EBITDA (2) |
$ |
42,442 |
$ |
16,407 |
||||
| Capital expenditures |
5,026 |
8,112 |
||||||
| Capital expenditures for turnarounds and catalysts |
849 |
2,681 |
||||||
| KEY OPERATING STATISTICS: |
||||||||
| Per barrel of throughput: |
||||||||
| Refinery operating margin (3) |
$ |
10.32 |
$ |
7.77 |
||||
| Refinery direct operating expense (4) |
3.54 |
4.07 |
||||||
| PRICING STATISTICS: |
||||||||
| Crack spreads (per barrel): |
||||||||
| Gulf Coast 3/2/1 (5) |
$ |
13.75 |
$ |
11.24 |
||||
| WTI Cushing crude oil (per barrel) |
$ |
51.78 |
$ |
33.30 |
||||
| Crude oil differentials (per barrel): |
||||||||
| WTI Cushing less WTI Midland (6) |
$ |
(0.64) |
$ |
(0.13) |
||||
| WTI Cushing less WTS (6) |
1.27 |
(0.10) |
||||||
| Brent less WTI Cushing (6) |
1.66 |
0.49 |
||||||
| Product price (dollars per gallon): |
||||||||
| Gulf Coast unleaded gasoline |
$ |
1.56 |
$ |
1.07 |
||||
| Gulf Coast ultra-low sulfur diesel |
1.57 |
1.03 |
||||||
| Natural gas (per MMBtu) |
3.07 |
1.98 |
||||||
| March 31, |
December 31, |
|||||||
| (dollars in thousands) |
||||||||
| BALANCE SHEET DATA (end of period): |
||||||||
| Cash and cash equivalents |
$ |
109,034 |
$ |
73,524 |
||||
| Working capital |
(92,271) |
(73,563) |
||||||
| Total assets |
719,487 |
695,637 |
||||||
| Total debt |
236,152 |
236,319 |
||||||
| Total debt less cash and cash equivalents |
127,118 |
162,795 |
||||||
| Total partners' equity |
116,761 |
103,503 |
||||||
| THROUGHPUT AND PRODUCTION DATA: |
For the Three Months Ended |
|||||||||||
| March 31, |
||||||||||||
| 2017 |
2016 |
|||||||||||
| bpd |
% |
bpd |
% |
|||||||||
| Refinery throughput: |
||||||||||||
| WTS crude |
30,301 |
39.0 |
36,554 |
54.1 |
||||||||
| WTI crude |
42,877 |
55.1 |
27,760 |
41.1 |
||||||||
| Blendstocks |
4,576 |
5.9 |
3,222 |
4.8 |
||||||||
| Total refinery throughput (7) |
77,754 |
100.0 |
67,536 |
100.0 |
||||||||
| Refinery production: |
||||||||||||
| Gasoline |
38,690 |
49.9 |
34,100 |
50.5 |
||||||||
| Diesel/jet |
28,871 |
37.2 |
22,682 |
33.6 |
||||||||
| Asphalt |
2,893 |
3.7 |
3,148 |
4.6 |
||||||||
| Petrochemicals |
4,530 |
5.8 |
3,617 |
5.3 |
||||||||
| Other |
2,633 |
3.4 |
4,027 |
6.0 |
||||||||
| Total refinery production (8) |
77,617 |
100.0 |
67,574 |
100.0 |
||||||||
| Refinery utilization (9) |
100.2% |
93.2% |
||||||||||
| CASH AVAILABLE FOR DISTRIBUTION DATA: |
For the Three |
|||
| March 31, 2017 |
||||
| (dollars in |
||||
| Net sales (1) |
$ |
544,532 |
||
| Operating costs and expenses: |
||||
| Cost of sales |
470,471 |
|||
| Direct operating expenses |
24,760 |
|||
| Selling, general and administrative expenses |
6,764 |
|||
| Depreciation and amortization |
14,229 |
|||
| Total operating costs and expenses |
516,224 |
|||
| Operating income |
28,308 |
|||
| Interest expense |
(7,845) |
|||
| Other loss, net |
(95) |
|||
| Income before state income tax expense |
20,368 |
|||
| State income tax expense |
256 |
|||
| Net income |
20,112 |
|||
| Adjustments to reconcile net income to Adjusted EBITDA: |
||||
| Interest expense |
7,845 |
|||
| State income tax expense |
256 |
|||
| Depreciation and amortization |
14,229 |
|||
| Adjusted EBITDA (2) |
42,442 |
|||
| Adjustments to reconcile Adjusted EBITDA to cash available for distribution: |
||||
| less: Maintenance/growth capital expenditures |
5,026 |
|||
| less: Turnaround and catalyst replacement capital expenditures |
849 |
|||
| less: Major turnaround reserve for future years (a) |
3,500 |
|||
| less: Principal payments |
625 |
|||
| less: State income tax payments |
256 |
|||
| less: Interest paid in cash |
8,465 |
|||
| Cash available for distribution |
$ |
23,721 |
||
| Common units outstanding (in 000's) |
62,520 |
|||
| Cash available for distribution per unit |
$ |
0.38 |
||
| a. |
Major turnaround reserve for future years was increased from $1,500 in prior quarters to $3,500 in the first quarter of 2017 to reflect an increase in the estimated cost of the next major five-year turnaround from $30,000 to $50,000. |
|||
________________
| (1) |
Includes sales to related parties of $91,000 and $63,110 for the three months ended March 31, 2017 and 2016, 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 months ended March 31, 2017 and 2016: |
|||
| For the Three Months Ended |
|||||||||
| March 31, |
|||||||||
| 2017 |
2016 |
||||||||
| (dollars in thousands) |
|||||||||
| Net income (loss) |
$ |
20,112 |
$ |
(8,562) |
|||||
| State income tax expense |
256 |
176 |
|||||||
| Interest expense |
7,845 |
10,587 |
|||||||
| Depreciation and amortization |
14,229 |
14,206 |
|||||||
| Adjusted EBITDA |
$ |
42,442 |
$ |
16,407 |
|||||
| (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 months ended March 31, 2017 and 2016 excludes gains related to inventory adjustments of $1,842 and $946, 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
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