DALLAS, Aug. 3, 2015 /PRNewswire/ -- Alon
USA Partners, LP (NYSE: ALDW)
("Alon Partners") today announced results for the second quarter of
2015. Net income for the second quarter of 2015 was $59.4 million, or $0.95 per unit, compared to $7.8 million, or $0.12 per unit, for the same period last year.
Net income for the first half of 2015 was $95.9 million, or $1.53 per unit, compared to $50.0 million, or $0.80 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 2015 of $1.04 per unit payable on
August 25, 2015 to common unitholders
of record at the close of business on August
18, 2015, based on cash available for distribution of
$64.8 million.
Paul Eisman, President and CEO,
commented, "We are pleased to have generated cash available for
distribution of $1.04 per unit in the
second quarter of 2015. In the last four quarters since the
turnaround in 2014, we have generated total cash available for
distribution of $3.47 per unit.
"Our strong results in the second quarter were supported by
excellent operational performance at the Big Spring refinery and a favorable crack
spread environment. Big Spring
achieved a refinery operating margin of $17.22 per barrel and low direct operating
expense of only $3.54 per barrel. The
crude flexibility of the Big
Spring refinery continues to be an advantage. The refinery
processed approximately 44,000 barrels per day of WTI Midland
during the second quarter of 2015 to set a new record for WTI
Midland rate. On the product side, our wholesale marketing business
successfully sold approximately 6,000 barrels per day in
June 2015 into the premium
Arizona market.
"We expect total throughput at the Big
Spring refinery to average approximately 74,000 barrels per
day for the third quarter of 2015 and 74,000 barrels per day for
the full year of 2015."
SECOND QUARTER 2015
Refinery operating margin was
$17.22 per barrel for the second
quarter of 2015 compared to $17.04
per barrel for the same period in 2014. This increase in operating
margin was primarily due to improved light product yields,
partially offset by the industry margin environment. The
contango environment in the second quarter of 2015 created a cost
of crude benefit of $1.90 per barrel
compared to the backwardated environment creating a cost of crude
detriment of $0.93 per barrel for the
same period in 2014. The Big
Spring refinery average throughput for the second quarter of
2015 was 75,491 barrels per day ("bpd") compared to 38,994 bpd for
the same period in 2014. During the second quarter of 2014,
refinery throughput was reduced as we completed both the planned
turnaround and the vacuum tower project.
The average Gulf Coast 3/2/1 crack spread was $19.71 per barrel for the second quarter of 2015
compared to $16.42 per barrel for the
second quarter of 2014. The average WTI Cushing to WTS spread for
the second quarter of 2015 was $(0.21) per barrel compared to $7.88 per barrel for the second quarter of 2014.
The average WTI Cushing to WTI Midland spread for the second
quarter of 2015 was $0.60 per barrel
compared to $8.37 per barrel for the
second quarter of 2014.
YEAR-TO-DATE 2015
Refinery operating margin was
$15.56 per barrel for the first half
of 2015 compared to $15.56 per barrel
for the same period in 2014. The operating margin was flat relative
to the same period last year primarily due to improved light
product yields being offset by the industry margin
environment. The contango environment for the first half of 2015
created a cost of crude benefit of $1.28 per barrel compared to the backwardated
environment creating a cost of crude detriment of $0.53 per barrel for the same period in 2014. The
Big Spring refinery average
throughput for the first half of 2015 was 73,934 bpd compared to
56,050 bpd for the same period in 2014. During the second quarter
of 2014, refinery throughput was reduced as we completed both the
planned turnaround and the vacuum tower project.
The average Gulf Coast 3/2/1 crack spread was $18.73 per barrel for the first half of 2015
compared to $16.61 per barrel for the
same period in 2014. The average WTI Cushing to WTS spread for the
first half of 2015 was $0.76 per
barrel compared to $5.79 per barrel
for the same period in 2014. The average WTI Cushing to WTI Midland
spread for the first half of 2015 was $1.27 per barrel compared to $5.96 per barrel for the same period in 2014.
CONFERENCE CALL
Alon Partners has scheduled a
conference call, which will be broadcast live over the Internet on
Tuesday, August 4, 2015 at
9:00 a.m. Eastern Time (8:00 a.m. Central Time), to discuss the second
quarter 2015 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 18, 2015, and may be accessed
by calling 877-660-6853, or 201-612-7415 for international callers,
and using the passcode 13612043#. A webcast archive will also be
available at www.alonpartners.com shortly after the call and
will be accessible for approximately 90 days. For more information,
please contact Donna Washburn at
Dennard § Lascar Associates at 713-529-6600 or email
dwashburn@dennardlascar.com.
This release serves as qualified notice to nominees under
Treasury Regulation Section 1.1446-4(b). Please note that 100% of
Alon Partners' distributions to foreign investors are attributable
to income that is effectively connected with a United States trade or business. Accordingly,
all of Alon Partners' distributions to foreign investors are
subject to federal income tax withholding at the highest effective
tax rate for individuals or corporations, as applicable. Nominees,
and not Alon Partners, are treated as the withholding agents
responsible for withholding on the distributions received by them
on behalf of foreign investors.
Any statements in this release that are not statements of
historical fact are forward-looking statements. Forward-looking
statements reflect our current expectations regarding future
events, results or outcomes. These expectations may or may not be
realized. Some of these expectations may be based upon assumptions
or judgments that prove to be incorrect. In addition, our business
and operations involve numerous risks and uncertainties, many of
which are beyond our control, which could result in our
expectations not being realized or otherwise materially affect our
financial condition, results of operations and cash flows.
Additional information regarding these and other risks is contained
in our filings with the Securities and Exchange Commission.
Alon USA Partners, LP is a
Delaware limited partnership
formed in August 2012 by Alon
USA Energy, Inc. ("Alon Energy")
(NYSE: ALJ). 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 West Texas,
Central Texas, Oklahoma, New
Mexico and Arizona through
its wholesale distribution network to both Alon Energy's retail
convenience stores and other third-party distributors.
|
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, 2014, IS UNAUDITED)
|
For the Three
Months Ended
|
|
For the Six Months
Ended
|
|
June
30,
|
|
June
30,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
(dollars in
thousands, except per unit data, per barrel data and pricing
statistics)
|
|
STATEMENT OF
OPERATIONS DATA:
|
|
|
|
|
|
|
|
|
Net sales
(1)
|
$
|
625,064
|
|
|
$
|
725,852
|
|
|
$
|
1,167,506
|
|
|
$
|
1,582,312
|
|
|
Operating costs and
expenses:
|
|
|
|
|
|
|
|
|
Cost of
sales
|
507,122
|
|
|
665,398
|
|
|
957,717
|
|
|
1,424,444
|
|
|
Direct
operating expenses
|
24,285
|
|
|
25,152
|
|
|
47,701
|
|
|
54,093
|
|
|
Selling,
general and administrative expenses
|
10,215
|
|
|
6,784
|
|
|
16,118
|
|
|
11,152
|
|
|
Depreciation
and amortization
|
13,591
|
|
|
9,508
|
|
|
27,584
|
|
|
19,575
|
|
|
Total
operating costs and expenses
|
555,213
|
|
|
706,842
|
|
|
1,049,120
|
|
|
1,509,264
|
|
|
Operating
income
|
69,851
|
|
|
19,010
|
|
|
118,386
|
|
|
73,048
|
|
|
Interest
expense
|
(10,847)
|
|
|
(11,569)
|
|
|
(22,540)
|
|
|
(22,893)
|
|
|
Other income (loss),
net
|
27
|
|
|
601
|
|
|
(14)
|
|
|
613
|
|
|
Income before state
income tax expense (benefit)
|
59,031
|
|
|
8,042
|
|
|
95,832
|
|
|
50,768
|
|
|
State income tax
expense (benefit)
|
(395)
|
|
|
240
|
|
|
(45)
|
|
|
725
|
|
|
Net income
|
$
|
59,426
|
|
|
$
|
7,802
|
|
|
$
|
95,877
|
|
|
$
|
50,043
|
|
|
Earnings per
unit
|
$
|
0.95
|
|
|
$
|
0.12
|
|
|
$
|
1.53
|
|
|
$
|
0.80
|
|
|
Weighted average
common units outstanding (in thousands)
|
62,509
|
|
|
62,504
|
|
|
62,508
|
|
|
62,504
|
|
|
Cash distribution per
unit
|
$
|
0.71
|
|
|
$
|
0.69
|
|
|
$
|
1.41
|
|
|
$
|
0.87
|
|
|
CASH FLOW
DATA:
|
|
|
|
|
|
|
|
|
Net cash provided by
(used in):
|
|
|
|
|
|
|
|
|
Operating
activities
|
$
|
107,311
|
|
|
$
|
(35)
|
|
|
$
|
134,398
|
|
|
$
|
45,232
|
|
|
Investing
activities
|
(5,985)
|
|
|
(18,259)
|
|
|
(9,790)
|
|
|
(36,886)
|
|
|
Financing
activities
|
(61,829)
|
|
|
(68,955)
|
|
|
(81,049)
|
|
|
(80,830)
|
|
|
OTHER
DATA:
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
(2)
|
$
|
83,469
|
|
|
$
|
29,119
|
|
|
$
|
145,956
|
|
|
$
|
93,236
|
|
|
Capital
expenditures
|
5,465
|
|
|
7,277
|
|
|
7,786
|
|
|
11,439
|
|
|
Capital expenditures
for turnarounds and catalysts
|
520
|
|
|
10,982
|
|
|
2,004
|
|
|
25,447
|
|
|
KEY OPERATING
STATISTICS:
|
|
|
|
|
|
|
|
|
Per barrel of
throughput:
|
|
|
|
|
|
|
|
|
Refinery
operating margin (3)
|
$
|
17.22
|
|
|
$
|
17.04
|
|
|
$
|
15.56
|
|
|
$
|
15.56
|
|
|
Refinery direct
operating expense (4)
|
3.54
|
|
|
7.09
|
|
|
3.56
|
|
|
5.33
|
|
|
PRICING
STATISTICS:
|
|
|
|
|
|
|
|
|
Crack spreads (per
barrel):
|
|
|
|
|
|
|
|
|
Gulf Coast
3/2/1 (5)
|
$
|
19.71
|
|
|
$
|
16.42
|
|
|
$
|
18.73
|
|
|
$
|
16.61
|
|
|
WTI Cushing crude oil
(per barrel)
|
$
|
57.86
|
|
|
$
|
103.04
|
|
|
$
|
53.20
|
|
|
$
|
100.86
|
|
|
Crude oil
differentials (per barrel):
|
|
|
|
|
|
|
|
|
WTI Cushing
less WTI Midland (6)
|
$
|
0.60
|
|
|
$
|
8.37
|
|
|
$
|
1.27
|
|
|
$
|
5.96
|
|
|
WTI Cushing
less WTS (6)
|
(0.21)
|
|
|
7.88
|
|
|
0.76
|
|
|
5.79
|
|
|
Brent less WTI
Cushing (6)
|
3.66
|
|
|
7.22
|
|
|
4.54
|
|
|
8.83
|
|
|
Product price
(dollars per gallon):
|
|
|
|
|
|
|
|
|
Gulf Coast
unleaded gasoline
|
$
|
1.86
|
|
|
$
|
2.81
|
|
|
$
|
1.69
|
|
|
$
|
2.73
|
|
|
Gulf Coast
ultra-low sulfur diesel
|
1.83
|
|
|
2.92
|
|
|
1.76
|
|
|
2.93
|
|
|
Natural gas
(per MMBtu)
|
2.74
|
|
|
4.58
|
|
|
2.77
|
|
|
4.65
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2015
|
|
December 31,
2014
|
|
BALANCE SHEET DATA
(end of period):
|
(dollars in
thousands)
|
|
Cash and cash
equivalents
|
$
|
149,884
|
|
|
$
|
106,325
|
|
|
Working
capital
|
166
|
|
|
(4,561)
|
|
|
Total
assets
|
807,757
|
|
|
770,246
|
|
|
Total debt
|
281,420
|
|
|
302,376
|
|
|
Total debt less cash
and cash equivalents
|
131,536
|
|
|
196,051
|
|
|
Total partners'
equity
|
196,165
|
|
|
188,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
THROUGHPUT AND
PRODUCTION DATA:
|
For the Three
Months Ended
|
|
For the Six Months
Ended
|
|
June
30,
|
|
June
30,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
bpd
|
|
%
|
|
bpd
|
|
%
|
|
bpd
|
|
%
|
|
bpd
|
|
%
|
|
Refinery
throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTS
crude
|
29,605
|
|
|
39.2
|
|
|
12,634
|
|
|
32.4
|
|
|
37,193
|
|
|
50.3
|
|
|
23,927
|
|
|
42.7
|
|
|
WTI
crude
|
43,659
|
|
|
57.8
|
|
|
23,391
|
|
|
60.0
|
|
|
33,952
|
|
|
45.9
|
|
|
29,652
|
|
|
52.9
|
|
|
Blendstocks
|
2,227
|
|
|
3.0
|
|
|
2,969
|
|
|
7.6
|
|
|
2,789
|
|
|
3.8
|
|
|
2,471
|
|
|
4.4
|
|
|
Total refinery
throughput (7)
|
75,491
|
|
|
100.0
|
|
|
38,994
|
|
|
100.0
|
|
|
73,934
|
|
|
100.0
|
|
|
56,050
|
|
|
100.0
|
|
|
Refinery
production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
37,755
|
|
|
49.8
|
|
|
17,484
|
|
|
45.1
|
|
|
36,978
|
|
|
49.8
|
|
|
26,835
|
|
|
48.0
|
|
|
Diesel/jet
|
28,052
|
|
|
37.0
|
|
|
12,315
|
|
|
31.8
|
|
|
27,074
|
|
|
36.5
|
|
|
18,461
|
|
|
33.0
|
|
|
Asphalt
|
2,479
|
|
|
3.3
|
|
|
1,660
|
|
|
4.3
|
|
|
2,876
|
|
|
3.9
|
|
|
2,529
|
|
|
4.5
|
|
|
Petrochemicals
|
4,915
|
|
|
6.5
|
|
|
1,825
|
|
|
4.7
|
|
|
4,863
|
|
|
6.5
|
|
|
3,111
|
|
|
5.5
|
|
|
Other
|
2,537
|
|
|
3.4
|
|
|
5,483
|
|
|
14.1
|
|
|
2,466
|
|
|
3.3
|
|
|
5,022
|
|
|
9.0
|
|
|
Total refinery
production (8)
|
75,738
|
|
|
100.0
|
|
|
38,767
|
|
|
100.0
|
|
|
74,257
|
|
|
100.0
|
|
|
55,958
|
|
|
100.0
|
|
|
Refinery utilization
(9)
|
|
|
100.4
|
%
|
|
|
|
85.4
|
%
|
|
|
|
97.5
|
%
|
|
|
|
95.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AVAILABLE FOR
DISTRIBUTION DATA:
|
|
For the Three
Months Ended
|
|
|
June 30,
2015
|
|
|
(dollars in
thousands, except per unit data)
|
|
|
|
|
Net sales
(1)
|
|
$
|
625,064
|
|
|
Operating costs and
expenses:
|
|
|
|
Cost of
sales
|
|
507,122
|
|
|
Direct
operating expenses
|
|
24,285
|
|
|
Selling,
general and administrative expenses
|
|
10,215
|
|
|
Depreciation
and amortization
|
|
13,591
|
|
|
Total operating costs and expenses
|
|
555,213
|
|
|
Operating
income
|
|
69,851
|
|
|
Interest
expense
|
|
(10,847)
|
|
|
Other income,
net
|
|
27
|
|
|
Income before state
income tax benefit
|
|
59,031
|
|
|
State income tax
benefit
|
|
(395)
|
|
|
Net income
|
|
59,426
|
|
|
Adjustments to
reconcile net income to Adjusted EBITDA:
|
|
|
|
Interest
expense
|
|
10,847
|
|
|
State income tax
benefit
|
|
(395)
|
|
|
Depreciation and
amortization
|
|
13,591
|
|
|
Adjusted EBITDA
(2)
|
|
83,469
|
|
|
Adjustments to
reconcile Adjusted EBITDA to cash available for
distribution:
|
|
|
|
less:
Maintenance/growth capital expenditures
|
|
5,465
|
|
|
less: Turnaround and catalyst replacement
capital expenditures
|
|
520
|
|
|
less: Major
turnaround reserve for future years
|
|
1,500
|
|
|
less: Principal
payments
|
|
625
|
|
|
less: State
income tax payments
|
|
341
|
|
|
less: Interest
paid in cash
|
|
10,236
|
|
|
Cash available for
distribution
|
|
$
|
64,782
|
|
|
|
|
|
Common units
outstanding (in 000's)
|
|
62,510
|
|
|
|
|
|
Cash available for
distribution per unit
|
|
$
|
1.04
|
|
________________
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(1)
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Includes sales to
related parties of $101,233 and $152,170 for the three months ended
June 30, 2015 and 2014, respectively, and $184,122 and $291,183 for
the six months ended June 30, 2015 and 2014,
respectively.
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(2)
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Adjusted EBITDA
represents earnings before state income tax expense (benefit),
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
(benefit), 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.
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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:
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- 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.
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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.
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The following table
reconciles net income to Adjusted EBITDA for the three and six
months ended June 30, 2015 and 2014:
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For the Three
Months Ended
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For the Six Months
Ended
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June
30,
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June
30,
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2015
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2014
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2015
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2014
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(dollars in
thousands)
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Net income
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$
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59,426
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$
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7,802
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$
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95,877
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$
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50,043
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State income tax
expense (benefit)
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(395)
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240
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(45)
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725
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Interest
expense
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10,847
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11,569
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22,540
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22,893
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Depreciation and
amortization
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13,591
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9,508
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27,584
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19,575
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Adjusted
EBITDA
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$
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83,469
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$
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29,119
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$
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145,956
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$
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93,236
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(3)
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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.
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Refinery operating
margin for the three and six months ended June 30, 2015 excludes
gains (losses) related to inventory adjustments of $(368) and
$1,622, respectively.
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(4)
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Refinery direct
operating expense is a per barrel measurement calculated by
dividing direct operating expenses by total throughput
volumes.
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(5)
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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.
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(6)
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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.
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(7)
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Total refinery
throughput represents the total barrels per day of crude oil and
blendstock inputs in the refinery production process.
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(8)
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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.
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(9)
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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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Contacts:
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Stacey Hudson,
Investor Relations Manager
Alon USA Partners GP,
LLC
972-367-3808
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Investors: Jack
Lascar/Stephanie Smith
Dennard § Lascar
Associates, LLC 713-529-6600
Media: Blake
Lewis
Lewis Public
Relations
214-635-3020
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To view the original version on PR Newswire,
visit:http://www.prnewswire.com/news-releases/alon-usa-partners-lp-reports-second-quarter-2015-results-and-declares-quarterly-cash-distribution-300122736.html
SOURCE Alon USA Partners,
LP