Alon USA Partners, LP Reports Second Quarter 2017 Results and Declares Quarterly Cash Distribution
Schedules conference call for July 28, 2017 at 10:00 a.m. Eastern
DALLAS, July 27, 2017 /PRNewswire/ -- Alon USA Partners, LP (NYSE: ALDW) ("Alon Partners") today announced results for the second quarter of 2017. Net income for the second quarter of 2017 was $21.7 million, or $0.35 per unit, compared to net income of $1.2 million, or $0.02 per unit, for the same period last year. Net income for the first half of 2017 was $41.8 million, or $0.67 per unit, compared to net loss of $(7.4) million, or $(0.12) 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 second quarter of 2017 of $0.35 per unit payable on August 24, 2017 to common unitholders of record at the close of business on August 17, 2017, based on cash available for distribution of $21.7 million.
Alan Moret, CEO, commented, "Our second quarter 2017 results benefited from an improvement in our benchmark Gulf Coast crack spread and discounts in Midland-sourced crude relative to WTI Cushing. The wholesale marketing environment remained strong as increased economic activity supported product demand in our markets."
Shai Even, President and CFO, commented, "The refinery achieved an operating margin of $12.68 per barrel in the second quarter of 2017. Our results were impacted by FCCU maintenance in the second quarter of 2017, which reduced adjusted EBITDA by $9.5 million and the distribution by $0.16 per unit. The FCCU maintenance negatively impacted the refinery's direct operating expense of $4.21 per barrel for the second quarter of 2017.
"We are encouraged by the production activity we have seen in the Permian Basin and the continued discounts for Midland crudes into the third quarter. 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 third quarter of 2017."
SECOND QUARTER 2017
Refinery operating margin was $12.68 per barrel for the second quarter of 2017 compared to $8.53 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, a widening of both the WTI Cushing to WTI Midland and WTI Cushing to WTS spreads and a stronger wholesale marketing environment, partially offset by a reduced benefit from the contango market environment which increased the cost of crude. Refinery average throughput for the second quarter of 2017 was 72,763 barrels per day ("bpd") compared to 71,153 bpd for the same period in 2016. Refinery throughput for the second quarter of 2017 was affected by maintenance on the FCCU and refinery throughput for the second quarter of 2016 was affected by unplanned downtime due to a power outage caused by inclement weather, which affected multiple units.
The average Gulf Coast 3/2/1 crack spread was $15.07 per barrel for the second quarter of 2017 compared to $13.16 per barrel for the second quarter of 2016. The average WTI Cushing to WTI Midland spread for the second quarter of 2017 was $0.84 per barrel compared to $0.17 per barrel for the second quarter of 2016. The average WTI Cushing to WTS spread for the second quarter of 2017 was $1.24 per barrel compared to $0.75 per barrel for the second quarter of 2016. The average Brent to WTI Cushing spread for the second quarter of 2017 was $1.21 per barrel compared to $(0.18) per barrel for the same period in 2016. The contango environment in the second quarter of 2017 created an average cost of crude benefit of $0.55 per barrel compared to an average cost of crude benefit of $1.49 per barrel for the same period in 2016. The average RINs cost effect on refinery operating margin was $0.34 per barrel in the second quarter of 2017, compared to $0.32 per barrel for the same period in 2016.
YEAR-TO-DATE 2017
Refinery operating margin was $11.47 per barrel for the first half of 2017 compared to $8.16 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 both the WTI Cushing to WTI Midland and WTI Cushing to WTS spreads, partially offset by increased RINs costs and a reduced benefit from the contango market environment which increased the cost of crude. Refinery average throughput for the first half of 2017 was 75,245 bpd compared to 69,345 bpd for the same period in 2016. Refinery throughput for the first half of 2017 was affected by maintenance on the FCCU. The lower throughput for the first half of 2016 was the result of a reformer regeneration and a catalyst replacement for our diesel hydrotreater unit in the first quarter of 2016, as well as 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 $14.41 per barrel for the first half of 2017 compared to $12.20 per barrel for the same period in 2016. The average WTI Cushing to WTI Midland spread for the first half of 2017 was $0.11 per barrel compared to $0.02 per barrel for the same period in 2016. The average WTI Cushing to WTS spread for the first half of 2017 was $1.26 per barrel compared to $0.32 per barrel for the same period in 2016. The average Brent to WTI Cushing spread for the first half of 2017 was $1.44 per barrel compared to $0.15 per barrel for the same period in 2016. The contango environment for the first half of 2017 created an average cost of crude benefit of $0.77 per barrel compared to an average cost of crude benefit of $1.66 per barrel for the same period in 2016. The average RINs cost effect on refinery operating margin was $0.47 per barrel in the first half of 2017, compared to $0.23 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 Friday, July 28, 2017 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time), to discuss the second 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 August 4, 2017 and may be accessed by calling 877-660-6853, or 201-612-7415 for international callers, and using the passcode 13666988#. 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 in which Delek US Holdings, Inc. (NYSE: DK) owns 100% of the general partner and 81.6% of the limited partner interest. 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 retail convenience stores owned by Delek US and other third-party distributors.
Contacts:
Keith Johnson
Vice President of Investor Relations
Delek US Holdings, Inc.
615-435-1366
- 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
For the Six Months Ended
June 30,
June 30,
2017
2016
2017
2016
(dollars in thousands, except per unit data, per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA:
Net sales (1)
$
521,751
$
468,457
$
1,066,283
$
836,466
Operating costs and expenses:
Cost of sales
440,895
410,735
911,366
730,068
Direct operating expenses
27,878
23,255
52,638
48,299
Selling, general and administrative expenses
7,392
8,802
14,156
16,111
Depreciation and amortization
14,462
14,667
28,691
28,873
Total operating costs and expenses
490,627
457,459
1,006,851
823,351
Loss on disposition of assets
(23)
—
(23)
—
Operating income
31,101
10,998
59,409
13,115
Interest expense
(8,652)
(9,920)
(16,497)
(20,507)
Other income (loss), net
(459)
113
(554)
197
Income (loss) before state income tax expense
21,990
1,191
42,358
(7,195)
State income tax expense
310
—
566
176
Net income (loss)
$
21,680
$
1,191
$
41,792
$
(7,371)
Earnings (loss) per unit
$
0.35
$
0.02
$
0.67
$
(0.12)
Weighted average common units outstanding (in thousands)
62,525
62,515
62,523
62,512
Cash distribution per unit
$
0.38
$
—
$
0.49
$
0.08
CASH FLOW DATA:
Net cash provided by (used in):
Operating activities
$
35,373
$
39,925
$
77,145
$
46,587
Investing activities
(7,316)
(10,131)
(13,191)
(20,924)
Financing activities
30,148
8,830
29,761
3,204
OTHER DATA:
Adjusted EBITDA (2)
$
45,127
$
25,778
$
87,569
$
42,185
Capital expenditures
7,149
4,588
12,175
12,700
Capital expenditures for turnarounds and catalysts
167
5,543
1,016
8,224
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin (3)
$
12.68
$
8.53
$
11.47
$
8.16
Refinery direct operating expense (4)
4.21
3.59
3.86
3.83
PRICING STATISTICS:
Crack spreads (per barrel):
Gulf Coast 3/2/1 (5)
$
15.07
$
13.16
$
14.41
$
12.20
WTI Cushing crude oil (per barrel)
$
48.25
$
45.48
$
50.00
$
39.39
Crude oil differentials (per barrel):
WTI Cushing less WTI Midland (6)
$
0.84
$
0.17
$
0.11
$
0.02
WTI Cushing less WTS (6)
1.24
0.75
1.26
0.32
Brent less WTI Cushing (6)
1.21
(0.18)
1.44
0.15
Product price (dollars per gallon):
Gulf Coast unleaded gasoline
$
1.52
$
1.42
$
1.54
$
1.25
Gulf Coast ultra-low sulfur diesel
1.48
1.34
1.52
1.19
Natural gas (per MMBtu)
3.14
2.25
3.10
2.12
June 30,
2017
December 31,
2016
(dollars in thousands)
BALANCE SHEET DATA (end of period):
Cash and cash equivalents
$
167,239
$
73,524
Working capital
(37,982)
(73,563)
Total assets
787,442
695,637
Total debt
285,996
236,319
Total debt less cash and cash equivalents
118,757
162,795
Total partners' equity
114,704
103,503
THROUGHPUT AND PRODUCTION DATA:
For the Three Months Ended
For the Six Months Ended
June 30,
June 30,
2017
2016
2017
2016
bpd
%
bpd
%
bpd
%
bpd
%
Refinery throughput:
WTS crude
17,680
24.3
25,698
36.1
23,955
31.8
31,126
44.9
WTI crude
52,207
71.7
43,040
60.5
47,568
63.2
35,400
51.0
Blendstocks
2,876
4.0
2,415
3.4
3,722
5.0
2,819
4.1
Total refinery throughput (7)
72,763
100.0
71,153
100.0
75,245
100.0
69,345
100.0
Refinery production:
Gasoline
33,506
46.5
33,744
47.6
36,084
48.2
33,922
49.0
Diesel/jet
27,885
38.7
26,627
37.6
28,375
37.9
24,655
35.6
Asphalt
2,020
2.8
2,572
3.6
2,454
3.3
2,860
4.2
Petrochemicals
3,827
5.3
3,354
4.7
4,176
5.6
3,485
5.0
Other
4,755
6.7
4,569
6.5
3,700
5.0
4,298
6.2
Total refinery production (8)
71,993
100.0
70,866
100.0
74,789
100.0
69,220
100.0
Refinery utilization (9)
99.0%
94.2%
99.6%
93.7%
CASH AVAILABLE FOR DISTRIBUTION DATA:
For the Three
Months Ended
June 30, 2017
(dollars in
thousands, except
per unit data)
Net sales (1)
$
521,751
Operating costs and expenses:
Cost of sales
440,895
Direct operating expenses
27,878
Selling, general and administrative expenses
7,392
Depreciation and amortization
14,462
Total operating costs and expenses
490,627
Operating income
31,101
Interest expense
(8,652)
Other loss, net
(459)
Income before state income tax expense
21,990
State income tax expense
310
Net income
21,680
Adjustments to reconcile net income to Adjusted EBITDA:
Interest expense
8,652
State income tax expense
310
Depreciation and amortization
14,462
Adjusted EBITDA (2)
45,127
Adjustments to reconcile Adjusted EBITDA to cash available for distribution:
less: Maintenance/growth capital expenditures
7,149
less: Turnaround and catalyst replacement capital expenditures
167
less: Major turnaround reserve for future years (a)
3,500
less: Principal payments
625
less: State income tax payments
310
less: Interest paid in cash
7,690
Cash available for distribution before special expenses
25,686
less: Special reserve for cost increase in capital expenditures associated with the consent decree (b)
4,000
Cash available for distribution
$
21,686
Common units outstanding (in 000's)
62,529
Cash available for distribution per unit
$
0.35
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.
b.
The Partnership is finalizing a consent decree with the U.S. Environmental Protection Agency to reduce air emissions from the Big Spring refinery, which will require additional capital expenditures. The Board of Directors of our general partner has elected to reserve $4 million from cash available for distribution each quarter through the fourth quarter of 2018 to cover a $28 million increase in the expected costs.
________________
(1)
Includes sales to related parties of $94,323 and $76,884 for the three months ended June 30, 2017 and 2016, respectively, and $185,760 and $139,994 for the six months ended June 30, 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 and six months ended June 30, 2017 and 2016:
For the Three Months Ended
For the Six Months Ended
June 30,
June 30,
2017
2016
2017
2016
(dollars in thousands)
Net income (loss)
$
21,680
$
1,191
$
41,792
$
(7,371)
State income tax expense
310
—
566
176
Interest expense
8,652
9,920
16,497
20,507
Depreciation and amortization
14,462
14,667
28,691
28,873
Adjusted EBITDA
$
45,127
$
25,778
$
87,569
$
42,185
(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 six months ended June 30, 2017 excludes losses related to inventory adjustments of $(3,106) and $(1,264), respectively. Refinery operating margin for the three and six months ended June 30, 2016 excludes gains related to inventory adjustments of $2,519 and $3,465, 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.
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SOURCE Alon USA Partners, LP
DALLAS, July 27, 2017 /PRNewswire/ -- Alon USA Partners, LP (NYSE: ALDW) ("Alon Partners") today announced results for the second quarter of 2017. Net income for the second quarter of 2017 was $21.7 million, or $0.35 per unit, compared to net income of $1.2 million, or $0.02 per unit, for the same period last year. Net income for the first half of 2017 was $41.8 million, or $0.67 per unit, compared to net loss of $(7.4) million, or $(0.12) 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 second quarter of 2017 of $0.35 per unit payable on August 24, 2017 to common unitholders of record at the close of business on August 17, 2017, based on cash available for distribution of $21.7 million.
Alan Moret, CEO, commented, "Our second quarter 2017 results benefited from an improvement in our benchmark Gulf Coast crack spread and discounts in Midland-sourced crude relative to WTI Cushing. The wholesale marketing environment remained strong as increased economic activity supported product demand in our markets."
Shai Even, President and CFO, commented, "The refinery achieved an operating margin of $12.68 per barrel in the second quarter of 2017. Our results were impacted by FCCU maintenance in the second quarter of 2017, which reduced adjusted EBITDA by $9.5 million and the distribution by $0.16 per unit. The FCCU maintenance negatively impacted the refinery's direct operating expense of $4.21 per barrel for the second quarter of 2017.
"We are encouraged by the production activity we have seen in the Permian Basin and the continued discounts for Midland crudes into the third quarter. 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 third quarter of 2017."
SECOND QUARTER 2017
Refinery operating margin was $12.68 per barrel for the second quarter of 2017 compared to $8.53 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, a widening of both the WTI Cushing to WTI Midland and WTI Cushing to WTS spreads and a stronger wholesale marketing environment, partially offset by a reduced benefit from the contango market environment which increased the cost of crude. Refinery average throughput for the second quarter of 2017 was 72,763 barrels per day ("bpd") compared to 71,153 bpd for the same period in 2016. Refinery throughput for the second quarter of 2017 was affected by maintenance on the FCCU and refinery throughput for the second quarter of 2016 was affected by unplanned downtime due to a power outage caused by inclement weather, which affected multiple units.
The average Gulf Coast 3/2/1 crack spread was $15.07 per barrel for the second quarter of 2017 compared to $13.16 per barrel for the second quarter of 2016. The average WTI Cushing to WTI Midland spread for the second quarter of 2017 was $0.84 per barrel compared to $0.17 per barrel for the second quarter of 2016. The average WTI Cushing to WTS spread for the second quarter of 2017 was $1.24 per barrel compared to $0.75 per barrel for the second quarter of 2016. The average Brent to WTI Cushing spread for the second quarter of 2017 was $1.21 per barrel compared to $(0.18) per barrel for the same period in 2016. The contango environment in the second quarter of 2017 created an average cost of crude benefit of $0.55 per barrel compared to an average cost of crude benefit of $1.49 per barrel for the same period in 2016. The average RINs cost effect on refinery operating margin was $0.34 per barrel in the second quarter of 2017, compared to $0.32 per barrel for the same period in 2016.
YEAR-TO-DATE 2017
Refinery operating margin was $11.47 per barrel for the first half of 2017 compared to $8.16 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 both the WTI Cushing to WTI Midland and WTI Cushing to WTS spreads, partially offset by increased RINs costs and a reduced benefit from the contango market environment which increased the cost of crude. Refinery average throughput for the first half of 2017 was 75,245 bpd compared to 69,345 bpd for the same period in 2016. Refinery throughput for the first half of 2017 was affected by maintenance on the FCCU. The lower throughput for the first half of 2016 was the result of a reformer regeneration and a catalyst replacement for our diesel hydrotreater unit in the first quarter of 2016, as well as 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 $14.41 per barrel for the first half of 2017 compared to $12.20 per barrel for the same period in 2016. The average WTI Cushing to WTI Midland spread for the first half of 2017 was $0.11 per barrel compared to $0.02 per barrel for the same period in 2016. The average WTI Cushing to WTS spread for the first half of 2017 was $1.26 per barrel compared to $0.32 per barrel for the same period in 2016. The average Brent to WTI Cushing spread for the first half of 2017 was $1.44 per barrel compared to $0.15 per barrel for the same period in 2016. The contango environment for the first half of 2017 created an average cost of crude benefit of $0.77 per barrel compared to an average cost of crude benefit of $1.66 per barrel for the same period in 2016. The average RINs cost effect on refinery operating margin was $0.47 per barrel in the first half of 2017, compared to $0.23 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 Friday, July 28, 2017 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time), to discuss the second 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 August 4, 2017 and may be accessed by calling 877-660-6853, or 201-612-7415 for international callers, and using the passcode 13666988#. 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 in which Delek US Holdings, Inc. (NYSE: DK) owns 100% of the general partner and 81.6% of the limited partner interest. 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 retail convenience stores owned by Delek US and other third-party distributors.
|
Contacts: |
Keith Johnson |
|
Vice President of Investor Relations |
|
|
Delek US Holdings, Inc. |
|
|
615-435-1366 |
- Tables to follow -
|
ALON USA PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED |
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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 |
For the Six Months Ended |
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|
June 30, |
June 30, |
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2017 |
2016 |
2017 |
2016 |
||||||||||||||||||
|
(dollars in thousands, except per unit data, per barrel data and pricing statistics) |
|||||||||||||||||||||
|
STATEMENTS OF OPERATIONS DATA: |
|||||||||||||||||||||
|
Net sales (1) |
$ |
521,751 |
$ |
468,457 |
$ |
1,066,283 |
$ |
836,466 |
|||||||||||||
|
Operating costs and expenses: |
|||||||||||||||||||||
|
Cost of sales |
440,895 |
410,735 |
911,366 |
730,068 |
|||||||||||||||||
|
Direct operating expenses |
27,878 |
23,255 |
52,638 |
48,299 |
|||||||||||||||||
|
Selling, general and administrative expenses |
7,392 |
8,802 |
14,156 |
16,111 |
|||||||||||||||||
|
Depreciation and amortization |
14,462 |
14,667 |
28,691 |
28,873 |
|||||||||||||||||
|
Total operating costs and expenses |
490,627 |
457,459 |
1,006,851 |
823,351 |
|||||||||||||||||
|
Loss on disposition of assets |
(23) |
— |
(23) |
— |
|||||||||||||||||
|
Operating income |
31,101 |
10,998 |
59,409 |
13,115 |
|||||||||||||||||
|
Interest expense |
(8,652) |
(9,920) |
(16,497) |
(20,507) |
|||||||||||||||||
|
Other income (loss), net |
(459) |
113 |
(554) |
197 |
|||||||||||||||||
|
Income (loss) before state income tax expense |
21,990 |
1,191 |
42,358 |
(7,195) |
|||||||||||||||||
|
State income tax expense |
310 |
— |
566 |
176 |
|||||||||||||||||
|
Net income (loss) |
$ |
21,680 |
$ |
1,191 |
$ |
41,792 |
$ |
(7,371) |
|||||||||||||
|
Earnings (loss) per unit |
$ |
0.35 |
$ |
0.02 |
$ |
0.67 |
$ |
(0.12) |
|||||||||||||
|
Weighted average common units outstanding (in thousands) |
62,525 |
62,515 |
62,523 |
62,512 |
|||||||||||||||||
|
Cash distribution per unit |
$ |
0.38 |
$ |
— |
$ |
0.49 |
$ |
0.08 |
|||||||||||||
|
CASH FLOW DATA: |
|||||||||||||||||||||
|
Net cash provided by (used in): |
|||||||||||||||||||||
|
Operating activities |
$ |
35,373 |
$ |
39,925 |
$ |
77,145 |
$ |
46,587 |
|||||||||||||
|
Investing activities |
(7,316) |
(10,131) |
(13,191) |
(20,924) |
|||||||||||||||||
|
Financing activities |
30,148 |
8,830 |
29,761 |
3,204 |
|||||||||||||||||
|
OTHER DATA: |
|||||||||||||||||||||
|
Adjusted EBITDA (2) |
$ |
45,127 |
$ |
25,778 |
$ |
87,569 |
$ |
42,185 |
|||||||||||||
|
Capital expenditures |
7,149 |
4,588 |
12,175 |
12,700 |
|||||||||||||||||
|
Capital expenditures for turnarounds and catalysts |
167 |
5,543 |
1,016 |
8,224 |
|||||||||||||||||
|
KEY OPERATING STATISTICS: |
|||||||||||||||||||||
|
Per barrel of throughput: |
|||||||||||||||||||||
|
Refinery operating margin (3) |
$ |
12.68 |
$ |
8.53 |
$ |
11.47 |
$ |
8.16 |
|||||||||||||
|
Refinery direct operating expense (4) |
4.21 |
3.59 |
3.86 |
3.83 |
|||||||||||||||||
|
PRICING STATISTICS: |
|||||||||||||||||||||
|
Crack spreads (per barrel): |
|||||||||||||||||||||
|
Gulf Coast 3/2/1 (5) |
$ |
15.07 |
$ |
13.16 |
$ |
14.41 |
$ |
12.20 |
|||||||||||||
|
WTI Cushing crude oil (per barrel) |
$ |
48.25 |
$ |
45.48 |
$ |
50.00 |
$ |
39.39 |
|||||||||||||
|
Crude oil differentials (per barrel): |
|||||||||||||||||||||
|
WTI Cushing less WTI Midland (6) |
$ |
0.84 |
$ |
0.17 |
$ |
0.11 |
$ |
0.02 |
|||||||||||||
|
WTI Cushing less WTS (6) |
1.24 |
0.75 |
1.26 |
0.32 |
|||||||||||||||||
|
Brent less WTI Cushing (6) |
1.21 |
(0.18) |
1.44 |
0.15 |
|||||||||||||||||
|
Product price (dollars per gallon): |
|||||||||||||||||||||
|
Gulf Coast unleaded gasoline |
$ |
1.52 |
$ |
1.42 |
$ |
1.54 |
$ |
1.25 |
|||||||||||||
|
Gulf Coast ultra-low sulfur diesel |
1.48 |
1.34 |
1.52 |
1.19 |
|||||||||||||||||
|
Natural gas (per MMBtu) |
3.14 |
2.25 |
3.10 |
2.12 |
|||||||||||||||||
|
June 30, |
December 31, |
||||||||||||||||||||
|
(dollars in thousands) |
|||||||||||||||||||||
|
BALANCE SHEET DATA (end of period): |
|||||||||||||||||||||
|
Cash and cash equivalents |
$ |
167,239 |
$ |
73,524 |
|||||||||||||||||
|
Working capital |
(37,982) |
(73,563) |
|||||||||||||||||||
|
Total assets |
787,442 |
695,637 |
|||||||||||||||||||
|
Total debt |
285,996 |
236,319 |
|||||||||||||||||||
|
Total debt less cash and cash equivalents |
118,757 |
162,795 |
|||||||||||||||||||
|
Total partners' equity |
114,704 |
103,503 |
|||||||||||||||||||
|
THROUGHPUT AND PRODUCTION DATA: |
For the Three Months Ended |
For the Six Months Ended |
|||||||||||||||||||||||||||
|
June 30, |
June 30, |
||||||||||||||||||||||||||||
|
2017 |
2016 |
2017 |
2016 |
||||||||||||||||||||||||||
|
bpd |
% |
bpd |
% |
bpd |
% |
bpd |
% |
||||||||||||||||||||||
|
Refinery throughput: |
|||||||||||||||||||||||||||||
|
WTS crude |
17,680 |
24.3 |
25,698 |
36.1 |
23,955 |
31.8 |
31,126 |
44.9 |
|||||||||||||||||||||
|
WTI crude |
52,207 |
71.7 |
43,040 |
60.5 |
47,568 |
63.2 |
35,400 |
51.0 |
|||||||||||||||||||||
|
Blendstocks |
2,876 |
4.0 |
2,415 |
3.4 |
3,722 |
5.0 |
2,819 |
4.1 |
|||||||||||||||||||||
|
Total refinery throughput (7) |
72,763 |
100.0 |
71,153 |
100.0 |
75,245 |
100.0 |
69,345 |
100.0 |
|||||||||||||||||||||
|
Refinery production: |
|||||||||||||||||||||||||||||
|
Gasoline |
33,506 |
46.5 |
33,744 |
47.6 |
36,084 |
48.2 |
33,922 |
49.0 |
|||||||||||||||||||||
|
Diesel/jet |
27,885 |
38.7 |
26,627 |
37.6 |
28,375 |
37.9 |
24,655 |
35.6 |
|||||||||||||||||||||
|
Asphalt |
2,020 |
2.8 |
2,572 |
3.6 |
2,454 |
3.3 |
2,860 |
4.2 |
|||||||||||||||||||||
|
Petrochemicals |
3,827 |
5.3 |
3,354 |
4.7 |
4,176 |
5.6 |
3,485 |
5.0 |
|||||||||||||||||||||
|
Other |
4,755 |
6.7 |
4,569 |
6.5 |
3,700 |
5.0 |
4,298 |
6.2 |
|||||||||||||||||||||
|
Total refinery production (8) |
71,993 |
100.0 |
70,866 |
100.0 |
74,789 |
100.0 |
69,220 |
100.0 |
|||||||||||||||||||||
|
Refinery utilization (9) |
99.0% |
94.2% |
99.6% |
93.7% |
|||||||||||||||||||||||||
|
CASH AVAILABLE FOR DISTRIBUTION DATA: |
For the Three |
|||
|
June 30, 2017 |
||||
|
(dollars in |
||||
|
Net sales (1) |
$ |
521,751 |
||
|
Operating costs and expenses: |
||||
|
Cost of sales |
440,895 |
|||
|
Direct operating expenses |
27,878 |
|||
|
Selling, general and administrative expenses |
7,392 |
|||
|
Depreciation and amortization |
14,462 |
|||
|
Total operating costs and expenses |
490,627 |
|||
|
Operating income |
31,101 |
|||
|
Interest expense |
(8,652) |
|||
|
Other loss, net |
(459) |
|||
|
Income before state income tax expense |
21,990 |
|||
|
State income tax expense |
310 |
|||
|
Net income |
21,680 |
|||
|
Adjustments to reconcile net income to Adjusted EBITDA: |
||||
|
Interest expense |
8,652 |
|||
|
State income tax expense |
310 |
|||
|
Depreciation and amortization |
14,462 |
|||
|
Adjusted EBITDA (2) |
45,127 |
|||
|
Adjustments to reconcile Adjusted EBITDA to cash available for distribution: |
||||
|
less: Maintenance/growth capital expenditures |
7,149 |
|||
|
less: Turnaround and catalyst replacement capital expenditures |
167 |
|||
|
less: Major turnaround reserve for future years (a) |
3,500 |
|||
|
less: Principal payments |
625 |
|||
|
less: State income tax payments |
310 |
|||
|
less: Interest paid in cash |
7,690 |
|||
|
Cash available for distribution before special expenses |
25,686 |
|||
|
less: Special reserve for cost increase in capital expenditures associated with the consent decree (b) |
4,000 |
|||
|
Cash available for distribution |
$ |
21,686 |
||
|
Common units outstanding (in 000's) |
62,529 |
|||
|
Cash available for distribution per unit |
$ |
0.35 |
||
|
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. |
|||
|
b. |
The Partnership is finalizing a consent decree with the U.S. Environmental Protection Agency to reduce air emissions from the Big Spring refinery, which will require additional capital expenditures. The Board of Directors of our general partner has elected to reserve $4 million from cash available for distribution each quarter through the fourth quarter of 2018 to cover a $28 million increase in the expected costs. |
|||
________________
|
(1) |
Includes sales to related parties of $94,323 and $76,884 for the three months ended June 30, 2017 and 2016, respectively, and $185,760 and $139,994 for the six months ended June 30, 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 and six months ended June 30, 2017 and 2016: |
|||||||||||||||||
|
For the Three Months Ended |
For the Six Months Ended |
|||||||||||||||||||||||||||
|
June 30, |
June 30, |
|||||||||||||||||||||||||||
|
2017 |
2016 |
2017 |
2016 |
|||||||||||||||||||||||||
|
(dollars in thousands) |
||||||||||||||||||||||||||||
|
Net income (loss) |
$ |
21,680 |
$ |
1,191 |
$ |
41,792 |
$ |
(7,371) |
||||||||||||||||||||
|
State income tax expense |
310 |
— |
566 |
176 |
||||||||||||||||||||||||
|
Interest expense |
8,652 |
9,920 |
16,497 |
20,507 |
||||||||||||||||||||||||
|
Depreciation and amortization |
14,462 |
14,667 |
28,691 |
28,873 |
||||||||||||||||||||||||
|
Adjusted EBITDA |
$ |
45,127 |
$ |
25,778 |
$ |
87,569 |
$ |
42,185 |
||||||||||||||||||||
|
(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 six months ended June 30, 2017 excludes losses related to inventory adjustments of $(3,106) and $(1,264), respectively. Refinery operating margin for the three and six months ended June 30, 2016 excludes gains related to inventory adjustments of $2,519 and $3,465, 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. |
|||||||||||||||||||||||||||
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SOURCE Alon USA Partners, LP