DALLAS, Nov. 2, 2015 /PRNewswire/ -- Alon USA Partners, LP (NYSE: ALDW) ("Alon
Partners") today announced results for the third quarter of 2015.
Net income for the third quarter of 2015 was $53.8 million, or $0.86 per unit, compared to $77.0 million, or $1.23 per unit, for the same period last year.
Net income for the first nine months of 2015 was $149.7 million, or $2.39 per unit, compared to $127.0 million, or $2.03 per unit, for the same period last
year.
The Board of Directors of Alon USA Partners GP, LLC, the general partner of
Alon Partners, declared a cash distribution for the third quarter
of 2015 of $0.98 per unit payable on
November 25, 2015 to common unitholders of record at the close
of business on November 18, 2015, based on cash available for
distribution of $61.3 million.
Paul Eisman, President and CEO,
commented, "We are pleased with our strong results, which resulted
in cash available for distribution of $0.98 per unit in the third quarter of 2015. In
the last four quarters, we have generated total cash available for
distribution of $3.43 per unit.
"The Big Spring refinery
capitalized on a robust crack spread environment during the third
quarter of 2015 to generate solid margins. The refinery ran well
during the quarter, achieving total throughput of almost 76,000
barrels per day. Despite unfavorable Midland crude differentials,
Big Spring generated a refinery
operating margin of $16.71 per
barrel. The refinery also achieved low direct operating expense of
$3.46 per barrel. Our results
benefited from a strong wholesale marketing environment driven by a
robust gasoline market. During the quarter, our wholesale marketing
business sold on average approximately 3,800 barrels per day of
gasoline into the Phoenix
market.
"We expect total throughput at the Big
Spring refinery to average approximately 75,000 barrels per
day for the fourth quarter of 2015.
"While strong financial results are an important driver of
unitholder value, we are also focused on unlocking the value
embedded in our assets. We are continuing work on a number of
capital projects which will enhance the profitability of the
partnership. In addition, we have identified $37 million in existing logistics EBITDA at Alon
Partners as discussed in the detail below. We are committed to
realizing value from these assets, which we believe are undervalued
in our current structure."
STRATEGIC UPDATE - LOGISTICS
Alon Partners has identified approximately $37 million in existing logistics EBITDA
associated with the Big Spring
refinery and wholesale marketing business as shown in the table
below.
Logistics master limited partnerships (MLPs) continue to trade
at a premium to independent refiners and refining MLPs, implying
that these assets are undervalued in Alon Partners' current
structure. The management team is committed to realizing the value
of these logistics assets for Alon Partners' unitholders.
|
|
|
|
|
|
|
|
|
Existing Logistics
Assets
|
|
Assumed
Utilization
|
|
Estimated Annual
EBITDA
|
|
|
|
|
(dollars in
thousands)
|
|
Wholesale marketing
business
|
|
75,000 bpd
|
|
$
|
24,000
|
|
|
Crude and product
storage*
|
|
2.56
MMBbls
|
|
9,000
|
|
|
Other assets (rail
and truck racks, product rack, pipelines, salt wells,
etc.)
|
|
|
|
4,000
|
|
|
Total Alon USA
Partners Logistics EBITDA
|
|
|
|
$
|
37,000
|
|
|
|
|
|
* Represents shell capacity.
|
|
THIRD QUARTER 2015
Refinery operating margin was $16.71 per barrel for the third quarter of 2015
compared to $19.98 per barrel for the
same period in 2014. This decrease in operating margin was
primarily due to the less favorable industry margin environment.
The unfavorable contraction in the WTI Cushing to WTI Midland and
the WTI Cushing to WTS spreads was greater than the improvement in
the Gulf Coast 3/2/1 spread and the cost of crude benefit from the
market moving from backwardation into contango. The Big Spring refinery average throughput for the
third quarter of 2015 was 75,797 barrels per day ("bpd") compared
to 74,838 bpd for the same period in 2014.
The average WTI Cushing to WTI Midland spread for the third
quarter of 2015 was $(0.72) per
barrel compared to $9.93 per barrel
for the third quarter of 2014. The average WTI Cushing to WTS
spread for the third quarter of 2015 was $(1.46) per barrel compared to $8.14 per barrel for the third quarter of 2014.
The average Gulf Coast 3/2/1 crack spread was $19.77 per barrel for the third quarter of 2015
compared to $15.90 per barrel for the
third quarter of 2014. The contango environment for the third
quarter of 2015 created a cost of crude benefit of $0.57 per barrel compared to the backwardated
environment creating a cost of crude detriment of $1.16 per barrel for the same period in 2014.
YEAR-TO-DATE 2015
Refinery operating margin was $15.95 per barrel for the first nine months of
2015 compared to $17.35 per barrel
for the same period in 2014. This decrease in operating margin was
primarily due to the less favorable industry margin environment.
The unfavorable contraction in the WTI Cushing to WTI Midland and
the WTI Cushing to WTS spreads was greater than the improvement in
the Gulf Coast 3/2/1 spread and the cost of crude benefit from the
market moving from backwardation into contango. The Big Spring refinery average throughput for the
first nine months of 2015 was 74,562 bpd compared to 62,382 bpd for
the same period in 2014. During the first nine months of 2014,
refinery throughput was reduced as we completed both the planned
major turnaround and the vacuum tower project.
The average WTI Cushing to WTI Midland spread for the first nine
months of 2015 was $0.60 per barrel
compared to $7.31 per barrel for the
same period in 2014. The average WTI Cushing to WTS spread for the
first nine months of 2015 was $0.02
per barrel compared to $6.58 per
barrel for the same period in 2014. The average Gulf Coast 3/2/1
crack spread was $19.08 per barrel
for the first nine months of 2015 compared to $16.37 per barrel for the same period in 2014.
The contango environment for the first nine months of 2015 created
a cost of crude benefit of $1.04 per
barrel compared to the backwardated environment creating a cost of
crude detriment of $0.74 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, November 3, 2015
at 9:00 a.m. Eastern Time
(8:00 a.m. Central Time), to discuss
the third 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
November 17, 2015, and may be
accessed by calling 877-660-6853, or 201-612-7415 for international
callers, and using the passcode 13621444#. 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.
- 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, 2014, IS UNAUDITED)
|
For the Three
Months Ended
|
|
For the Nine
Months Ended
|
|
September 30,
|
|
September 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)
|
$
|
551,813
|
|
|
$
|
838,882
|
|
|
$
|
1,719,319
|
|
|
$
|
2,421,194
|
|
|
Operating costs and
expenses:
|
|
|
|
|
|
|
|
|
Cost of
sales
|
439,678
|
|
|
701,331
|
|
|
1,397,395
|
|
|
2,125,775
|
|
|
Direct operating
expenses
|
24,136
|
|
|
25,723
|
|
|
71,837
|
|
|
79,816
|
|
|
Selling, general and
administrative expenses
|
8,536
|
|
|
8,353
|
|
|
24,654
|
|
|
19,505
|
|
|
Depreciation and
amortization
|
13,697
|
|
|
13,852
|
|
|
41,281
|
|
|
33,427
|
|
|
Total operating costs
and expenses
|
486,047
|
|
|
749,259
|
|
|
1,535,167
|
|
|
2,258,523
|
|
|
Operating
income
|
65,766
|
|
|
89,623
|
|
|
184,152
|
|
|
162,671
|
|
|
Interest
expense
|
(11,505)
|
|
|
(11,584)
|
|
|
(34,045)
|
|
|
(34,477)
|
|
|
Other income,
net
|
40
|
|
|
14
|
|
|
26
|
|
|
627
|
|
|
Income before state
income tax expense
|
54,301
|
|
|
78,053
|
|
|
150,133
|
|
|
128,821
|
|
|
State income tax
expense
|
525
|
|
|
1,060
|
|
|
480
|
|
|
1,785
|
|
|
Net income
|
$
|
53,776
|
|
|
$
|
76,993
|
|
|
$
|
149,653
|
|
|
$
|
127,036
|
|
|
Earnings per
unit
|
$
|
0.86
|
|
|
$
|
1.23
|
|
|
$
|
2.39
|
|
|
$
|
2.03
|
|
|
Weighted average
common units outstanding (in thousands)
|
62,510
|
|
|
62,507
|
|
|
62,508
|
|
|
62,505
|
|
|
Cash distribution per
unit
|
$
|
1.04
|
|
|
$
|
0.13
|
|
|
$
|
2.45
|
|
|
$
|
1.00
|
|
|
CASH FLOW
DATA:
|
|
|
|
|
|
|
|
|
Net cash provided by
(used in):
|
|
|
|
|
|
|
|
|
Operating
activities
|
$
|
84,834
|
|
|
$
|
94,142
|
|
|
$
|
219,232
|
|
|
$
|
139,374
|
|
|
Investing
activities
|
(5,532)
|
|
|
(26,195)
|
|
|
(15,322)
|
|
|
(63,081)
|
|
|
Financing
activities
|
(93,908)
|
|
|
(33,751)
|
|
|
(174,957)
|
|
|
(114,581)
|
|
|
OTHER
DATA:
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
(2)
|
$
|
79,503
|
|
|
$
|
103,489
|
|
|
$
|
225,459
|
|
|
$
|
196,725
|
|
|
Capital
expenditures
|
4,322
|
|
|
2,492
|
|
|
12,108
|
|
|
13,931
|
|
|
Capital expenditures
for turnarounds and catalysts
|
1,210
|
|
|
23,703
|
|
|
3,214
|
|
|
49,150
|
|
|
KEY OPERATING
STATISTICS:
|
|
|
|
|
|
|
|
|
Per barrel of
throughput:
|
|
|
|
|
|
|
|
|
Refinery operating
margin (3)
|
$
|
16.71
|
|
|
$
|
19.98
|
|
|
$
|
15.95
|
|
|
$
|
17.35
|
|
|
Refinery direct
operating expense (4)
|
3.46
|
|
|
3.74
|
|
|
3.53
|
|
|
4.69
|
|
|
PRICING
STATISTICS:
|
|
|
|
|
|
|
|
|
Crack spreads (per
barrel):
|
|
|
|
|
|
|
|
|
Gulf Coast 3/2/1
(5)
|
$
|
19.77
|
|
|
$
|
15.90
|
|
|
$
|
19.08
|
|
|
$
|
16.37
|
|
|
WTI Cushing crude oil
(per barrel)
|
$
|
46.41
|
|
|
$
|
97.55
|
|
|
$
|
50.91
|
|
|
$
|
99.74
|
|
|
Crude oil
differentials (per barrel):
|
|
|
|
|
|
|
|
|
WTI Cushing less WTI
Midland (6)
|
$
|
(0.72)
|
|
|
$
|
9.93
|
|
|
$
|
0.60
|
|
|
$
|
7.31
|
|
|
WTI Cushing less WTS
(6)
|
(1.46)
|
|
|
8.14
|
|
|
0.02
|
|
|
6.58
|
|
|
Brent less WTI
Cushing (6)
|
3.78
|
|
|
4.15
|
|
|
4.28
|
|
|
7.25
|
|
|
Product price
(dollars per gallon):
|
|
|
|
|
|
|
|
|
Gulf Coast unleaded
gasoline
|
$
|
1.61
|
|
|
$
|
2.65
|
|
|
$
|
1.66
|
|
|
$
|
2.71
|
|
|
Gulf Coast ultra-low
sulfur diesel
|
1.52
|
|
|
2.80
|
|
|
1.68
|
|
|
2.88
|
|
|
Natural gas (per
MMBtu)
|
2.73
|
|
|
3.95
|
|
|
2.76
|
|
|
4.41
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2015
|
|
December 31, 2014
|
|
BALANCE SHEET DATA
(end of period):
|
(dollars in
thousands)
|
|
Cash and cash
equivalents
|
$
|
135,278
|
|
|
$
|
106,325
|
|
|
Working capital
(deficit)
|
908
|
|
|
(4,561)
|
|
|
Total
assets
|
798,887
|
|
|
770,246
|
|
|
Total debt
|
290,946
|
|
|
302,376
|
|
|
Total debt less cash
and cash equivalents
|
155,668
|
|
|
196,051
|
|
|
Total partners'
equity
|
184,950
|
|
|
188,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
THROUGHPUT AND
PRODUCTION DATA:
|
For the Three
Months Ended
|
|
For the Nine
Months Ended
|
|
September 30,
|
|
September 30,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
bpd
|
|
%
|
|
bpd
|
|
%
|
|
bpd
|
|
%
|
|
bpd
|
|
%
|
|
Refinery
throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTS crude
|
30,810
|
|
|
40.6
|
|
|
37,566
|
|
|
50.2
|
|
|
35,041
|
|
|
47.0
|
|
|
28,524
|
|
|
45.7
|
|
|
WTI crude
|
42,503
|
|
|
56.1
|
|
|
34,633
|
|
|
46.3
|
|
|
36,834
|
|
|
49.4
|
|
|
31,330
|
|
|
50.2
|
|
|
Blendstocks
|
2,484
|
|
|
3.3
|
|
|
2,639
|
|
|
3.5
|
|
|
2,687
|
|
|
3.6
|
|
|
2,528
|
|
|
4.1
|
|
|
Total refinery
throughput (7)
|
75,797
|
|
|
100.0
|
|
|
74,838
|
|
|
100.0
|
|
|
74,562
|
|
|
100.0
|
|
|
62,382
|
|
|
100.0
|
|
|
Refinery
production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
37,503
|
|
|
49.5
|
|
|
36,842
|
|
|
49.0
|
|
|
37,155
|
|
|
49.6
|
|
|
30,207
|
|
|
48.4
|
|
|
Diesel/jet
|
28,623
|
|
|
37.8
|
|
|
28,857
|
|
|
38.4
|
|
|
27,596
|
|
|
36.9
|
|
|
21,964
|
|
|
35.2
|
|
|
Asphalt
|
2,452
|
|
|
3.2
|
|
|
3,052
|
|
|
4.1
|
|
|
2,733
|
|
|
3.7
|
|
|
2,705
|
|
|
4.3
|
|
|
Petrochemicals
|
4,588
|
|
|
6.1
|
|
|
4,305
|
|
|
5.7
|
|
|
4,770
|
|
|
6.4
|
|
|
3,514
|
|
|
5.6
|
|
|
Other
|
2,595
|
|
|
3.4
|
|
|
2,078
|
|
|
2.8
|
|
|
2,510
|
|
|
3.4
|
|
|
4,030
|
|
|
6.5
|
|
|
Total refinery
production (8)
|
75,761
|
|
|
100.0
|
|
|
75,134
|
|
|
100.0
|
|
|
74,764
|
|
|
100.0
|
|
|
62,420
|
|
|
100.0
|
|
|
Refinery utilization
(9)
|
|
|
100.4
|
%
|
|
|
|
98.9
|
%
|
|
|
|
98.5
|
%
|
|
|
|
97.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AVAILABLE FOR
DISTRIBUTION DATA:
|
|
For the Three
Months Ended
|
|
|
September 30,
2015
|
|
|
(dollars in
thousands, except per unit data)
|
|
|
|
|
Net sales
(1)
|
|
$
|
551,813
|
|
|
Operating costs and
expenses:
|
|
|
|
Cost of
sales
|
|
439,678
|
|
|
Direct operating
expenses
|
|
24,136
|
|
|
Selling, general and
administrative expenses
|
|
8,536
|
|
|
Depreciation and
amortization
|
|
13,697
|
|
|
Total operating costs
and expenses
|
|
486,047
|
|
|
Operating
income
|
|
65,766
|
|
|
Interest
expense
|
|
(11,505)
|
|
|
Other income,
net
|
|
40
|
|
|
Income before state
income tax expense
|
|
54,301
|
|
|
State income tax
expense
|
|
525
|
|
|
Net income
|
|
53,776
|
|
|
Adjustments to
reconcile net income to Adjusted EBITDA:
|
|
|
|
Interest
expense
|
|
11,505
|
|
|
State income tax
expense
|
|
525
|
|
|
Depreciation and
amortization
|
|
13,697
|
|
|
Adjusted EBITDA
(2)
|
|
79,503
|
|
|
Adjustments to
reconcile Adjusted EBITDA to cash available for
distribution:
|
|
|
|
less:
Maintenance/growth capital expenditures
|
|
4,322
|
|
|
less: Turnaround and
catalyst replacement capital expenditures
|
|
1,210
|
|
|
less: Major
turnaround reserve for future years
|
|
1,500
|
|
|
less: Principal
payments
|
|
625
|
|
|
less: State income
tax payments
|
|
525
|
|
|
less: Interest paid
in cash
|
|
10,010
|
|
|
Cash available for
distribution
|
|
$
|
61,311
|
|
|
|
|
|
Common units
outstanding (in 000's)
|
|
62,510
|
|
|
|
|
|
Cash available for
distribution per unit
|
|
$
|
0.98
|
|
__________
|
(1)
|
Includes sales to related parties of $97,014 and
$156,131 for the three months ended September 30, 2015 and 2014,
respectively, and $281,136 and $447,314 for the nine months ended
September 30, 2015 and 2014, 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 to Adjusted EBITDA for the three and nine
months ended September 30, 2015 and 2014:
|
|
|
|
|
|
|
For the Three
Months Ended
|
|
For the Nine
Months Ended
|
|
|
|
September 30,
|
|
September 30,
|
|
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
|
|
(dollars in
thousands)
|
|
|
Net income
|
$
|
53,776
|
|
|
$
|
76,993
|
|
|
$
|
149,653
|
|
|
$
|
127,036
|
|
|
|
State income tax
expense
|
525
|
|
|
1,060
|
|
|
480
|
|
|
1,785
|
|
|
|
Interest
expense
|
11,505
|
|
|
11,584
|
|
|
34,045
|
|
|
34,477
|
|
|
|
Depreciation and
amortization
|
13,697
|
|
|
13,852
|
|
|
41,281
|
|
|
33,427
|
|
|
|
Adjusted
EBITDA
|
$
|
79,503
|
|
|
$
|
103,489
|
|
|
$
|
225,459
|
|
|
$
|
196,725
|
|
|
|
|
(3)
|
Refinery operating margin is a per barrel measurement
calculated by dividing the margin between net sales and cost of
sales (exclusive of certain inventory adjustments) by the
refinery's throughput volumes. Industry-wide refining results are
driven and measured by the margins between refined product prices
and the prices for crude oil, which are referred to as crack
spreads. We compare our refinery operating margin to these crack
spreads to assess our operating performance relative to other
participants in our industry.
|
|
|
|
Refinery operating
margin for the three and nine months ended September 30, 2015
excludes losses related to inventory adjustments of $4,385 and
$2,763, respectively.
|
|
|
|
(4)
|
Refinery direct operating expense is a per barrel
measurement calculated by dividing direct operating expenses by
total throughput volumes.
|
|
|
|
(5)
|
We compare our refinery operating margin to the Gulf
Coast 3/2/1 crack spread. A Gulf Coast 3/2/1 crack spread is
calculated assuming that three barrels of WTI Cushing crude oil are
converted, or cracked, into two barrels of Gulf Coast conventional
gasoline and one barrel of Gulf Coast ultra-low sulfur
diesel.
|
|
|
|
(6)
|
The WTI Cushing less WTI Midland spread represents
the differential between the average price per barrel of WTI
Cushing crude oil and the average price per barrel of WTI Midland
crude oil. The WTI Cushing less WTS, or sweet/sour, spread
represents the differential between the average price per barrel of
WTI Cushing crude oil and the average price per barrel of WTS crude
oil. The Brent less WTI Cushing spread represents the differential
between the average price per barrel of Brent crude oil and the
average price per barrel of WTI Cushing crude
oil.
|
|
|
|
(7)
|
Total refinery throughput represents the total
barrels per day of crude oil and blendstock inputs in the refinery
production process.
|
|
|
|
(8)
|
Total refinery production represents the barrels per
day of various refined products produced from processing crude and
other refinery feedstocks through the crude units and other
conversion units.
|
|
|
|
(9)
|
Refinery utilization represents average daily crude
oil throughput divided by crude oil capacity, excluding planned
periods of downtime for maintenance and
turnarounds.
|
|
Contacts:
|
Stacey Hudson,
Investor Relations Manager
Alon USA Partners GP,
LLC
972-367-3808
|
|
|
|
Investors: Jack
Lascar/Stephanie Zhadkevich
Dennard - Lascar
Associates, LLC
713-529-6600
|
|
|
|
Media: Blake
Lewis
Lewis Public
Relations
214-635-3020
|
To view the original version on PR Newswire,
visit:http://www.prnewswire.com/news-releases/alon-usa-partners-lp-reports-third-quarter-2015-results-and-declares-quarterly-cash-distribution-300170692.html
SOURCE Alon USA Partners,
LP