Alon USA Partners, LP Reports Fourth Quarter and Full Year 2016 Results
Schedules conference call for February 24, 2017 at 10:00 a.m. Eastern
DALLAS, Feb. 22, 2017 /PRNewswire/ -- Alon USA Partners, LP (NYSE: ALDW) ("Alon Partners") today announced results for the quarter and year ended December 31, 2016. Net income for the fourth quarter of 2016 was $0.9 million, or $0.01 per unit, compared to net income of $7.2 million, or $0.12 per unit, for the same period last year. Net loss for the full year 2016 was $(4.4) million, or $(0.07) per unit, compared to net income of $156.9 million, or $2.51 per unit, for the same period last year.
Alan Moret, CEO, commented, "Our fourth quarter results reflected the weak refining margin environment that existed throughout 2016, which was exacerbated by high RINs prices negatively impacting our refinery operating margin. The Partnership declared a cash distribution of $0.11 per unit on February 9, 2017 related to our performance in the fourth quarter of 2016. We have been encouraged by the improvement in refining fundamentals that we saw at the end of 2016 and into 2017, including widened discounts for domestic crude relative to Brent and widened discounts in WTS relative to WTI Cushing. We have also been pleased to see RIN prices decline."
During 2016, we generated cash available for distribution of $0.40 per unit compared to $2.81 per unit during 2015.
Shai Even, President and CFO, commented, "The Big Spring refinery ran well in the fourth quarter, achieving total throughput of almost 77,000 barrels per day. The refinery also set a new quarterly record by processing over 44,000 barrels per day of WTI Midland in the quarter, further demonstrating the flexibility of the asset. The refinery operating margin of $7.65 per barrel for the fourth quarter is net of a negative impact of approximately $1.10 per barrel related to RINs costs. Operating expense in the fourth quarter was low at $3.39 per barrel.
"As we've said before, we do not expect any major maintenance at Big Spring in 2017. We expect total throughput at the Big Spring refinery to average 77,000 barrels per day for the first 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 first quarter of 2017."
FOURTH QUARTER 2016
Refinery operating margin was $7.65 per barrel for the fourth quarter of 2016 compared to $10.02 per barrel for the same period in 2015. This decrease in operating margin was primarily due to increased RINs costs, a reduced benefit from the contango market environment which increased the cost of crude and unfavorable differences in Group III to Gulf Coast gasoline and diesel prices in the fourth quarter of 2016 compared to the same period in 2015. Refinery average throughput for the fourth quarter of 2016 was 76,654 barrels per day ("bpd") compared to 75,925 bpd for the same period in 2015.
The average Gulf Coast 3/2/1 crack spread was $12.83 per barrel for the fourth quarter of 2016 compared to $10.90 per barrel for the same period in 2015. The average WTI Cushing to WTI Midland spread for the fourth quarter of 2016 was $0.25 per barrel compared to $(0.20) per barrel for the same period in 2015. The average WTI Cushing to WTS spread for the fourth quarter of 2016 was $1.33 per barrel compared to $(0.26) per barrel for the same period in 2015. The average Brent to WTI Cushing spread for the fourth quarter of 2016 was $(0.20) per barrel compared to $1.35 per barrel for the same period in 2015.
The contango environment in the fourth quarter of 2016 created an average cost of crude benefit of $0.79 per barrel compared to an average cost of crude benefit of $0.94 per barrel for the same period in 2015. The average RINs cost effect on refinery operating margin was $1.08 per barrel in the fourth quarter of 2016, compared to $0.45 per barrel for the same period in 2015.
FULL-YEAR 2016
Refinery operating margin was $8.28 per barrel for 2016 compared to $14.43 per barrel for 2015. This decrease in operating margin was primarily due to a lower Gulf Coast 3/2/1 crack spread, a narrowing of the WTI Cushing to WTI Midland spread and increased RINs costs, 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 2016 was 71,363 bpd compared to 74,906 bpd for 2015. The reduced throughput during 2016 was the result of a reformer regeneration during the first quarter of 2016 and 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 for 2016 was $12.64 per barrel compared to $17.02 per barrel for 2015. The average WTI Cushing to WTI Midland spread for 2016 was $0.15 per barrel compared to $0.39 per barrel for 2015. The average WTI Cushing to WTS spread for 2016 was $0.73 per barrel compared to $(0.06) per barrel for 2015. The average Brent to WTI Cushing spread for 2016 was $0.21 per barrel compared to $3.54 per barrel for 2015. The contango environment in 2016 created an average cost of crude benefit of $1.24 per barrel compared to an average cost of crude benefit of $1.01 per barrel in 2015. The average RINs cost effect on refinery operating margin was $0.55 per barrel in 2016, compared to $0.42 per barrel in 2015.
CONFERENCE CALL
Alon Partners has scheduled a conference call, which will be broadcast live over the Internet on Friday, February 24, 2017, at 10:00 a.m. Eastern Time (9:00 a.m. Central Time), to discuss the fourth quarter and year-end 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 March 3, 2017, and may be accessed by calling 877-660-6853, or 201-612-7415 for international callers, and using the passcode 13653001#. 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 withholdings 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, AND INCOME STATEMENT DATA FOR THE YEAR ENDED DECEMBER 31, 2015, IS UNAUDITED)
For the Three Months Ended
For the Year Ended
December 31,
December 31,
2016
2015
2016
2015
(dollars in thousands, except per unit data, per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)
$
509,009
$
437,872
$
1,807,732
$
2,157,191
Operating costs and expenses:
Cost of sales
453,944
369,896
1,588,219
1,767,291
Direct operating expenses
23,914
27,092
97,338
98,929
Selling, general and administrative expenses
7,719
7,699
31,983
32,353
Depreciation and amortization
14,070
13,831
57,524
55,112
Total operating costs and expenses
499,647
418,518
1,775,064
1,953,685
Operating income
9,362
19,354
32,668
203,506
Interest expense
(8,477)
(11,942)
(37,128)
(45,987)
Other income, net
43
26
593
52
Income (loss) before state income tax expense
928
7,438
(3,867)
157,571
State income tax expense
44
192
537
672
Net income (loss)
$
884
$
7,246
$
(4,404)
$
156,899
Earnings (loss) per unit
$
0.01
$
0.12
$
(0.07)
$
2.51
Weighted average common units outstanding (in thousands)
62,520
62,510
62,516
62,509
Cash distribution per unit
$
0.15
$
0.98
$
0.37
$
3.43
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities
$
19,658
$
20,513
$
78,115
$
239,745
Investing activities
(6,473)
(14,228)
(33,351)
(29,550)
Financing activities
(143,424)
(8,610)
(104,193)
(183,567)
OTHER DATA:
Adjusted EBITDA (2)
$
23,475
$
33,211
$
90,785
$
258,670
Cash available for distribution (2)
6,991
5,019
Capital expenditures
6,388
11,458
23,587
23,566
Capital expenditures for turnarounds and catalysts
85
2,770
9,764
5,984
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin (3)
$
7.65
$
10.02
$
8.28
$
14.43
Refinery direct operating expense (4)
3.39
3.88
3.73
3.62
For the Three Months Ended
For the Year Ended
December 31,
December 31,
2016
2015
2016
2015
(dollars in thousands, except per unit data, per barrel data and pricing statistics)
PRICING STATISTICS:
Crack spreads (per barrel):
Gulf Coast 3/2/1 (5)
$
12.83
$
10.90
$
12.64
$
17.02
WTI Cushing crude oil (per barrel)
$
49.21
$
42.05
$
43.24
$
48.68
Crude oil differentials (per barrel):
WTI Cushing less WTI Midland (6)
$
0.25
$
(0.20)
$
0.15
$
0.39
WTI Cushing less WTS (6)
1.33
(0.26)
0.73
(0.06)
Brent less WTI Cushing (6)
(0.20)
1.35
0.21
3.54
Product price (dollars per gallon):
Gulf Coast unleaded gasoline
$
1.45
$
1.25
$
1.34
$
1.56
Gulf Coast ultra-low sulfur diesel
1.52
1.29
1.32
1.58
Natural gas (per MMBtu)
3.18
2.23
2.55
2.63
As of December 31,
2016
2015
(dollars in thousands)
BALANCE SHEET DATA (end of period):
Cash and cash equivalents
$
73,524
$
132,953
Working capital
(73,563)
(53,804)
Total assets
695,637
748,584
Total debt
236,319
292,082
Total debt less cash and cash equivalents
162,795
159,129
Total partners' equity
103,503
130,957
THROUGHPUT AND PRODUCTION DATA:
For the Three Months Ended
December 31,
For the Year Ended
December 31,
2016
2015
2016
2015
bpd
%
bpd
%
bpd
%
bpd
%
Refinery throughput:
WTS crude
27,458
35.8
29,510
38.9
31,000
43.4
33,647
44.9
WTI crude
44,112
57.5
43,968
57.9
36,862
51.7
38,632
51.6
Blendstocks
5,084
6.7
2,447
3.2
3,501
4.9
2,627
3.5
Total refinery throughput (7)
76,654
100.0
75,925
100.0
71,363
100.0
74,906
100.0
Refinery production:
Gasoline
39,371
51.2
38,600
50.8
35,220
49.4
37,519
50.0
Diesel/jet
27,619
35.9
27,812
36.6
25,739
36.1
27,651
36.8
Asphalt
2,533
3.3
2,362
3.1
2,767
3.9
2,639
3.5
Petrochemicals
4,647
6.1
4,012
5.3
3,872
5.4
4,579
6.1
Other
2,714
3.5
3,176
4.2
3,740
5.2
2,678
3.6
Total refinery production (8)
76,884
100.0
75,962
100.0
71,338
100.0
75,066
100.0
Refinery utilization (9)
98.0
%
100.7
%
96.1
%
99.0
%
(1)
Includes sales to related parties of $84,786 and $77,058 for the three months ended December 31, 2016 and 2015, respectively, and $307,497 and $358,194 for the years ended December 31, 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 months and years ended December 31, 2016 and 2015:
For the Three Months Ended
For the Year Ended
December 31,
December 31,
2016
2015
2016
2015
(dollars in thousands)
Net income (loss)
$
884
$
7,246
$
(4,404)
$
156,899
State income tax expense
44
192
537
672
Interest expense
8,477
11,942
37,128
45,987
Depreciation and amortization
14,070
13,831
57,524
55,112
Adjusted EBITDA
$
23,475
$
33,211
$
90,785
$
258,670
Cash available for distribution is not a recognized term under GAAP. Our management believes that the presentation of cash available for distribution is useful to investors because it is frequently used by securities analysts, investors, and other interested parties in the evaluation of entities in our industry. Cash available for distribution should not be considered in isolation or as an alternative to net income or operating income as a measure of operating performance. In addition, cash available for distribution is not presented as, and should not be considered, an alternative to cash flows from operations or as a measure of liquidity. Cash available for distribution as reported may not be comparable to similarly titled measures of other entities, thereby limiting its usefulness as a comparative measure.
Available cash for each quarter generally equals our Adjusted EBITDA for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, including reserves for our expenses in the quarters in which our planned major turnarounds and catalyst replacements occur. Actual distributions are set by the board of directors of our general partner. The board of directors of our general partner may modify our cash distribution policy at any time, and our partnership agreement does not require us to make distributions at all.
The following table reconciles Adjusted EBITDA to cash available for distribution for the three months ended December 31, 2016 and 2015:
For the Three Months Ended
December 31,
2016
2015
(dollars in thousands)
Adjusted EBITDA
$
23,475
$
33,211
less: Maintenance/growth capital expenditures
6,388
11,458
less: Turnaround and catalyst replacement capital expenditures
85
2,770
less: Major turnaround reserve for future years
1,500
1,500
less: Principal payments
625
625
less: State income tax payments
44
377
less: Interest paid in cash
7,842
11,462
Cash available for distribution
$
6,991
$
5,019
(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 and year ended December 31, 2016 excludes gains related to inventory adjustments of $1,137 and $3,183, respectively. Refinery operating margin for the three months and year ended December 31, 2015 excludes losses related to inventory adjustments of $(1,983) and $(4,746), 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.
To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/alon-usa-partners-lp-reports-fourth-quarter-and-full-year-2016-results-300412097.html
SOURCE Alon USA Partners, LP
DALLAS, Feb. 22, 2017 /PRNewswire/ -- Alon USA Partners, LP (NYSE: ALDW) ("Alon Partners") today announced results for the quarter and year ended December 31, 2016. Net income for the fourth quarter of 2016 was $0.9 million, or $0.01 per unit, compared to net income of $7.2 million, or $0.12 per unit, for the same period last year. Net loss for the full year 2016 was $(4.4) million, or $(0.07) per unit, compared to net income of $156.9 million, or $2.51 per unit, for the same period last year.
Alan Moret, CEO, commented, "Our fourth quarter results reflected the weak refining margin environment that existed throughout 2016, which was exacerbated by high RINs prices negatively impacting our refinery operating margin. The Partnership declared a cash distribution of $0.11 per unit on February 9, 2017 related to our performance in the fourth quarter of 2016. We have been encouraged by the improvement in refining fundamentals that we saw at the end of 2016 and into 2017, including widened discounts for domestic crude relative to Brent and widened discounts in WTS relative to WTI Cushing. We have also been pleased to see RIN prices decline."
During 2016, we generated cash available for distribution of $0.40 per unit compared to $2.81 per unit during 2015.
Shai Even, President and CFO, commented, "The Big Spring refinery ran well in the fourth quarter, achieving total throughput of almost 77,000 barrels per day. The refinery also set a new quarterly record by processing over 44,000 barrels per day of WTI Midland in the quarter, further demonstrating the flexibility of the asset. The refinery operating margin of $7.65 per barrel for the fourth quarter is net of a negative impact of approximately $1.10 per barrel related to RINs costs. Operating expense in the fourth quarter was low at $3.39 per barrel.
"As we've said before, we do not expect any major maintenance at Big Spring in 2017. We expect total throughput at the Big Spring refinery to average 77,000 barrels per day for the first 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 first quarter of 2017."
FOURTH QUARTER 2016
Refinery operating margin was $7.65 per barrel for the fourth quarter of 2016 compared to $10.02 per barrel for the same period in 2015. This decrease in operating margin was primarily due to increased RINs costs, a reduced benefit from the contango market environment which increased the cost of crude and unfavorable differences in Group III to Gulf Coast gasoline and diesel prices in the fourth quarter of 2016 compared to the same period in 2015. Refinery average throughput for the fourth quarter of 2016 was 76,654 barrels per day ("bpd") compared to 75,925 bpd for the same period in 2015.
The average Gulf Coast 3/2/1 crack spread was $12.83 per barrel for the fourth quarter of 2016 compared to $10.90 per barrel for the same period in 2015. The average WTI Cushing to WTI Midland spread for the fourth quarter of 2016 was $0.25 per barrel compared to $(0.20) per barrel for the same period in 2015. The average WTI Cushing to WTS spread for the fourth quarter of 2016 was $1.33 per barrel compared to $(0.26) per barrel for the same period in 2015. The average Brent to WTI Cushing spread for the fourth quarter of 2016 was $(0.20) per barrel compared to $1.35 per barrel for the same period in 2015.
The contango environment in the fourth quarter of 2016 created an average cost of crude benefit of $0.79 per barrel compared to an average cost of crude benefit of $0.94 per barrel for the same period in 2015. The average RINs cost effect on refinery operating margin was $1.08 per barrel in the fourth quarter of 2016, compared to $0.45 per barrel for the same period in 2015.
FULL-YEAR 2016
Refinery operating margin was $8.28 per barrel for 2016 compared to $14.43 per barrel for 2015. This decrease in operating margin was primarily due to a lower Gulf Coast 3/2/1 crack spread, a narrowing of the WTI Cushing to WTI Midland spread and increased RINs costs, 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 2016 was 71,363 bpd compared to 74,906 bpd for 2015. The reduced throughput during 2016 was the result of a reformer regeneration during the first quarter of 2016 and 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 for 2016 was $12.64 per barrel compared to $17.02 per barrel for 2015. The average WTI Cushing to WTI Midland spread for 2016 was $0.15 per barrel compared to $0.39 per barrel for 2015. The average WTI Cushing to WTS spread for 2016 was $0.73 per barrel compared to $(0.06) per barrel for 2015. The average Brent to WTI Cushing spread for 2016 was $0.21 per barrel compared to $3.54 per barrel for 2015. The contango environment in 2016 created an average cost of crude benefit of $1.24 per barrel compared to an average cost of crude benefit of $1.01 per barrel in 2015. The average RINs cost effect on refinery operating margin was $0.55 per barrel in 2016, compared to $0.42 per barrel in 2015.
CONFERENCE CALL
Alon Partners has scheduled a conference call, which will be broadcast live over the Internet on Friday, February 24, 2017, at 10:00 a.m. Eastern Time (9:00 a.m. Central Time), to discuss the fourth quarter and year-end 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 March 3, 2017, and may be accessed by calling 877-660-6853, or 201-612-7415 for international callers, and using the passcode 13653001#. 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 withholdings 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
Media: Blake Lewis |
- Tables to follow -
|
ALON USA PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED |
|||||||||||||||
|
EARNINGS RELEASE |
|||||||||||||||
|
RESULTS OF OPERATIONS - FINANCIAL DATA |
For the Three Months Ended |
For the Year Ended |
|||||||||||||
|
December 31, |
December 31, |
||||||||||||||
|
2016 |
2015 |
2016 |
2015 |
||||||||||||
|
(dollars in thousands, except per unit data, per barrel data and pricing statistics) |
|||||||||||||||
|
STATEMENTS OF OPERATIONS DATA: |
|||||||||||||||
|
Net sales (1) |
$ |
509,009 |
$ |
437,872 |
$ |
1,807,732 |
$ |
2,157,191 |
|||||||
|
Operating costs and expenses: |
|||||||||||||||
|
Cost of sales |
453,944 |
369,896 |
1,588,219 |
1,767,291 |
|||||||||||
|
Direct operating expenses |
23,914 |
27,092 |
97,338 |
98,929 |
|||||||||||
|
Selling, general and administrative expenses |
7,719 |
7,699 |
31,983 |
32,353 |
|||||||||||
|
Depreciation and amortization |
14,070 |
13,831 |
57,524 |
55,112 |
|||||||||||
|
Total operating costs and expenses |
499,647 |
418,518 |
1,775,064 |
1,953,685 |
|||||||||||
|
Operating income |
9,362 |
19,354 |
32,668 |
203,506 |
|||||||||||
|
Interest expense |
(8,477) |
(11,942) |
(37,128) |
(45,987) |
|||||||||||
|
Other income, net |
43 |
26 |
593 |
52 |
|||||||||||
|
Income (loss) before state income tax expense |
928 |
7,438 |
(3,867) |
157,571 |
|||||||||||
|
State income tax expense |
44 |
192 |
537 |
672 |
|||||||||||
|
Net income (loss) |
$ |
884 |
$ |
7,246 |
$ |
(4,404) |
$ |
156,899 |
|||||||
|
Earnings (loss) per unit |
$ |
0.01 |
$ |
0.12 |
$ |
(0.07) |
$ |
2.51 |
|||||||
|
Weighted average common units outstanding (in thousands) |
62,520 |
62,510 |
62,516 |
62,509 |
|||||||||||
|
Cash distribution per unit |
$ |
0.15 |
$ |
0.98 |
$ |
0.37 |
$ |
3.43 |
|||||||
|
CASH FLOW DATA: |
|||||||||||||||
|
Net cash provided by (used in): |
|||||||||||||||
|
Operating activities |
$ |
19,658 |
$ |
20,513 |
$ |
78,115 |
$ |
239,745 |
|||||||
|
Investing activities |
(6,473) |
(14,228) |
(33,351) |
(29,550) |
|||||||||||
|
Financing activities |
(143,424) |
(8,610) |
(104,193) |
(183,567) |
|||||||||||
|
OTHER DATA: |
|||||||||||||||
|
Adjusted EBITDA (2) |
$ |
23,475 |
$ |
33,211 |
$ |
90,785 |
$ |
258,670 |
|||||||
|
Cash available for distribution (2) |
6,991 |
5,019 |
|||||||||||||
|
Capital expenditures |
6,388 |
11,458 |
23,587 |
23,566 |
|||||||||||
|
Capital expenditures for turnarounds and catalysts |
85 |
2,770 |
9,764 |
5,984 |
|||||||||||
|
KEY OPERATING STATISTICS: |
|||||||||||||||
|
Per barrel of throughput: |
|||||||||||||||
|
Refinery operating margin (3) |
$ |
7.65 |
$ |
10.02 |
$ |
8.28 |
$ |
14.43 |
|||||||
|
Refinery direct operating expense (4) |
3.39 |
3.88 |
3.73 |
3.62 |
|||||||||||
|
For the Three Months Ended |
For the Year Ended |
||||||||||||||
|
December 31, |
December 31, |
||||||||||||||
|
2016 |
2015 |
2016 |
2015 |
||||||||||||
|
(dollars in thousands, except per unit data, per barrel data and pricing statistics) |
|||||||||||||||
|
PRICING STATISTICS: |
|||||||||||||||
|
Crack spreads (per barrel): |
|||||||||||||||
|
Gulf Coast 3/2/1 (5) |
$ |
12.83 |
$ |
10.90 |
$ |
12.64 |
$ |
17.02 |
|||||||
|
WTI Cushing crude oil (per barrel) |
$ |
49.21 |
$ |
42.05 |
$ |
43.24 |
$ |
48.68 |
|||||||
|
Crude oil differentials (per barrel): |
|||||||||||||||
|
WTI Cushing less WTI Midland (6) |
$ |
0.25 |
$ |
(0.20) |
$ |
0.15 |
$ |
0.39 |
|||||||
|
WTI Cushing less WTS (6) |
1.33 |
(0.26) |
0.73 |
(0.06) |
|||||||||||
|
Brent less WTI Cushing (6) |
(0.20) |
1.35 |
0.21 |
3.54 |
|||||||||||
|
Product price (dollars per gallon): |
|||||||||||||||
|
Gulf Coast unleaded gasoline |
$ |
1.45 |
$ |
1.25 |
$ |
1.34 |
$ |
1.56 |
|||||||
|
Gulf Coast ultra-low sulfur diesel |
1.52 |
1.29 |
1.32 |
1.58 |
|||||||||||
|
Natural gas (per MMBtu) |
3.18 |
2.23 |
2.55 |
2.63 |
|||||||||||
|
As of December 31, |
|||||||||||||||
|
2016 |
2015 |
||||||||||||||
|
(dollars in thousands) |
|||||||||||||||
|
BALANCE SHEET DATA (end of period): |
|||||||||||||||
|
Cash and cash equivalents |
$ |
73,524 |
$ |
132,953 |
|||||||||||
|
Working capital |
(73,563) |
(53,804) |
|||||||||||||
|
Total assets |
695,637 |
748,584 |
|||||||||||||
|
Total debt |
236,319 |
292,082 |
|||||||||||||
|
Total debt less cash and cash equivalents |
162,795 |
159,129 |
|||||||||||||
|
Total partners' equity |
103,503 |
130,957 |
|||||||||||||
|
THROUGHPUT AND PRODUCTION DATA: |
For the Three Months Ended |
For the Year Ended |
|||||||||||||||||||||
|
2016 |
2015 |
2016 |
2015 |
||||||||||||||||||||
|
bpd |
% |
bpd |
% |
bpd |
% |
bpd |
% |
||||||||||||||||
|
Refinery throughput: |
|||||||||||||||||||||||
|
WTS crude |
27,458 |
35.8 |
29,510 |
38.9 |
31,000 |
43.4 |
33,647 |
44.9 |
|||||||||||||||
|
WTI crude |
44,112 |
57.5 |
43,968 |
57.9 |
36,862 |
51.7 |
38,632 |
51.6 |
|||||||||||||||
|
Blendstocks |
5,084 |
6.7 |
2,447 |
3.2 |
3,501 |
4.9 |
2,627 |
3.5 |
|||||||||||||||
|
Total refinery throughput (7) |
76,654 |
100.0 |
75,925 |
100.0 |
71,363 |
100.0 |
74,906 |
100.0 |
|||||||||||||||
|
Refinery production: |
|||||||||||||||||||||||
|
Gasoline |
39,371 |
51.2 |
38,600 |
50.8 |
35,220 |
49.4 |
37,519 |
50.0 |
|||||||||||||||
|
Diesel/jet |
27,619 |
35.9 |
27,812 |
36.6 |
25,739 |
36.1 |
27,651 |
36.8 |
|||||||||||||||
|
Asphalt |
2,533 |
3.3 |
2,362 |
3.1 |
2,767 |
3.9 |
2,639 |
3.5 |
|||||||||||||||
|
Petrochemicals |
4,647 |
6.1 |
4,012 |
5.3 |
3,872 |
5.4 |
4,579 |
6.1 |
|||||||||||||||
|
Other |
2,714 |
3.5 |
3,176 |
4.2 |
3,740 |
5.2 |
2,678 |
3.6 |
|||||||||||||||
|
Total refinery production (8) |
76,884 |
100.0 |
75,962 |
100.0 |
71,338 |
100.0 |
75,066 |
100.0 |
|||||||||||||||
|
Refinery utilization (9) |
98.0 |
% |
100.7 |
% |
96.1 |
% |
99.0 |
% |
|||||||||||||||
|
(1) |
Includes sales to related parties of $84,786 and $77,058 for the three months ended December 31, 2016 and 2015, respectively, and $307,497 and $358,194 for the years ended December 31, 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 months and years ended December 31, 2016 and 2015: |
||
|
For the Three Months Ended |
For the Year Ended |
||||||||||||||||
|
December 31, |
December 31, |
||||||||||||||||
|
2016 |
2015 |
2016 |
2015 |
||||||||||||||
|
(dollars in thousands) |
|||||||||||||||||
|
Net income (loss) |
$ |
884 |
$ |
7,246 |
$ |
(4,404) |
$ |
156,899 |
|||||||||
|
State income tax expense |
44 |
192 |
537 |
672 |
|||||||||||||
|
Interest expense |
8,477 |
11,942 |
37,128 |
45,987 |
|||||||||||||
|
Depreciation and amortization |
14,070 |
13,831 |
57,524 |
55,112 |
|||||||||||||
|
Adjusted EBITDA |
$ |
23,475 |
$ |
33,211 |
$ |
90,785 |
$ |
258,670 |
|||||||||
|
Cash available for distribution is not a recognized term under GAAP. Our management believes that the presentation of cash available for distribution is useful to investors because it is frequently used by securities analysts, investors, and other interested parties in the evaluation of entities in our industry. Cash available for distribution should not be considered in isolation or as an alternative to net income or operating income as a measure of operating performance. In addition, cash available for distribution is not presented as, and should not be considered, an alternative to cash flows from operations or as a measure of liquidity. Cash available for distribution as reported may not be comparable to similarly titled measures of other entities, thereby limiting its usefulness as a comparative measure. |
||
|
Available cash for each quarter generally equals our Adjusted EBITDA for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, including reserves for our expenses in the quarters in which our planned major turnarounds and catalyst replacements occur. Actual distributions are set by the board of directors of our general partner. The board of directors of our general partner may modify our cash distribution policy at any time, and our partnership agreement does not require us to make distributions at all. |
||
|
The following table reconciles Adjusted EBITDA to cash available for distribution for the three months ended December 31, 2016 and 2015: |
|
For the Three Months Ended |
||||||||
|
December 31, |
||||||||
|
2016 |
2015 |
|||||||
|
(dollars in thousands) |
||||||||
|
Adjusted EBITDA |
$ |
23,475 |
$ |
33,211 |
||||
|
less: Maintenance/growth capital expenditures |
6,388 |
11,458 |
||||||
|
less: Turnaround and catalyst replacement capital expenditures |
85 |
2,770 |
||||||
|
less: Major turnaround reserve for future years |
1,500 |
1,500 |
||||||
|
less: Principal payments |
625 |
625 |
||||||
|
less: State income tax payments |
44 |
377 |
||||||
|
less: Interest paid in cash |
7,842 |
11,462 |
||||||
|
Cash available for distribution |
$ |
6,991 |
$ |
5,019 |
||||
|
(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 and year ended December 31, 2016 excludes gains related to inventory adjustments of $1,137 and $3,183, respectively. Refinery operating margin for the three months and year ended December 31, 2015 excludes losses related to inventory adjustments of $(1,983) and $(4,746), 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. |
||||||
To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/alon-usa-partners-lp-reports-fourth-quarter-and-full-year-2016-results-300412097.html
SOURCE Alon USA Partners, LP