ALON USA ENERGY, INC. DALLAS, Oct. 26, 2016 /PRNewswire/ -- Alon USA Partners, LP (NYSE: ALDW) ("Alon Partners") today announced results for the third quarter of 2016. Net income for the third quarter of 2016 was $2.1 million, or $0.03 per unit, compared to $53.8 million, or $0.86 per unit, for the same period last year. Net loss for the first nine months of 2016 was $(5.3) million, or $(0.08) per unit, compared to net income of $149.7 million, or $2.39 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 2016 of $0.15 per unit payable on November 22, 2016 to common unitholders of record at the close of business on November 11, 2016, based on cash available for distribution of $9.4 million.
Paul Eisman, President and CEO commented, "Our third quarter results reflect a continuation of the difficult refining environment experienced in the first two quarters of 2016. While crack spreads were relatively flat with the second quarter of 2016, the average benchmark crack spread in the third quarter was down approximately $6.50 per barrel relative to the same quarter last year. As discussed in our previous earnings release, our third quarter results were also negatively impacted by a reformer regeneration in August. We estimate that the lost opportunity cost and maintenance expense associated with the reformer regeneration negatively impacted Alon Partners' adjusted EBITDA by approximately $8 million which reduced cash available for distribution by $0.13 per unit for the third quarter. Additionally, high RINs costs continue to weigh on our profitability.
"The Big Spring refinery achieved total throughput of 70,000 barrels per day and generated refinery operating margin of $9.22 per barrel. Our direct operating expense of $3.90 per barrel was negatively impacted by the reformer regeneration, which lowered throughput volumes and increased maintenance expense. We expect total throughput to average approximately 77,000 barrels per day for the fourth quarter of 2016. 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 fourth quarter of 2016."
THIRD QUARTER 2016
Refinery operating margin was $9.22 per barrel for the third quarter of 2016 compared to $16.71 per barrel for the same period in 2015. This decrease in operating margin was primarily due to a lower Gulf Coast 3/2/1 crack spread and increased RINs costs, partially offset by a widening of both the WTI Cushing to WTI Midland and WTI Cushing to WTS spreads and an increased benefit from the contango market environment which reduced the cost of crude. Refinery average throughput for the third quarter of 2016 was 70,063 barrels per day ("bpd") compared to 75,797 bpd for the same period in 2015. The reduced throughput was the result of a reformer regeneration during the third quarter of 2016.
The average Gulf Coast 3/2/1 crack spread was $13.31 per barrel for the third quarter of 2016 compared to $19.77 per barrel for the third quarter of 2015. The average WTI Cushing to WTI Midland spread for the third quarter of 2016 was $0.31 per barrel compared to $(0.72) per barrel for the third quarter of 2015. The average WTI Cushing to WTS spread for the third quarter of 2016 was $0.92 per barrel compared to $(1.46) per barrel for the third quarter of 2015. The average Brent to WTI Cushing spread for the third quarter of 2016 was $0.74 per barrel compared to $3.78 per barrel for the same period in 2015. The contango environment in the third quarter of 2016 created an average cost of crude benefit of $0.84 per barrel compared to an average cost of crude benefit of $0.57 per barrel for the same period in 2015. The average RINs cost effect on refinery operating margin was $0.58 per barrel in the third quarter of 2016, compared to $0.27 per barrel for the same period in 2015.
YEAR-TO-DATE 2016
Refinery operating margin was $8.52 per barrel for the first nine months of 2016 compared to $15.95 per barrel for the same period in 2015. This decrease in operating margin was primarily due to a lower Gulf Coast 3/2/1 crack spread and a narrowing of the WTI Cushing to WTI Midland spread, 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 the first nine months of 2016 was 69,586 bpd compared to 74,562 bpd for the same period in 2015. The reduced throughput during the first nine months of 2016 was the result of a reformer regeneration during the first quarter of 2016, which was repeated during the 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 was $12.57 per barrel for the first nine months of 2016 compared to $19.08 per barrel for the same period in 2015. The average WTI Cushing to WTI Midland spread for the first nine months of 2016 was $0.12 per barrel compared to $0.60 per barrel for the same period in 2015. The average WTI Cushing to WTS spread for the first nine months of 2016 was $0.53 per barrel compared to $0.02 per barrel for the same period in 2015. The average Brent to WTI Cushing spread for the first nine months of 2016 was $0.35 per barrel compared to $4.28 per barrel for the same period in 2015. The contango environment for the first nine months of 2016 created an average cost of crude benefit of $1.39 per barrel compared to an average cost of crude benefit of $1.04 per barrel for the same period in 2015.
CONFERENCE CALL
Alon Partners has scheduled a conference call, which will be broadcast live over the Internet on Friday, October 28, 2016 at 9:30 a.m. Eastern Time (8:30 a.m. Central Time), to discuss the third quarter 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 November 4, 2016 and may be accessed by calling 877-660-6853, or 201-612-7415 for international callers, and using the passcode 13646174#. 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. (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 For the Three Months Ended For the Nine Months Ended
(ALL INFORMATION IN THIS
PRESS RELEASE EXCEPT
FOR BALANCE SHEET DATA
AS OF DECEMBER 31,
2015, IS UNAUDITED)
September 30, September 30,
------------- -------------
2016 2015 2016 2015
---- ---- ---- ----
(dollars in thousands, except per unit data, per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS
DATA:
Net sales (1) $462,257 $551,813 $1,298,723 $1,719,319
Operating costs and
expenses:
Cost of sales 404,207 439,678 1,134,275 1,397,395
Direct operating
expenses 25,125 24,136 73,424 71,837
Selling, general and
administrative expenses 8,153 8,536 24,264 24,654
Depreciation and
amortization 14,581 13,697 43,454 41,281
------ ------ ------ ------
Total operating costs
and expenses 452,066 486,047 1,275,417 1,535,167
------- ------- --------- ---------
Operating income 10,191 65,766 23,306 184,152
Interest expense (8,144) (11,505) (28,651) (34,045)
Other income, net 353 40 550 26
--- --- --- ---
Income (loss) before
state income tax
expense 2,400 54,301 (4,795) 150,133
State income tax expense 317 525 493 480
--- --- --- ---
Net income (loss) $2,083 $53,776 $(5,288) $149,653
========
Earnings (loss) per unit $0.03 $0.86 $(0.08) $2.39
===== ===== ====== =====
Weighted average common
units outstanding (in
thousands) 62,520 62,510 62,515 62,508
====== ====== ====== ======
Cash distribution per
unit $0.14 $1.04 $0.22 $2.45
===== ===== ===== =====
CASH FLOW DATA:
Net cash provided by
(used in):
Operating activities $11,870 $84,834 $58,457 $219,232
Investing activities (5,954) (5,532) (26,878) (15,322)
Financing activities 36,027 (93,908) 39,231 (174,957)
OTHER DATA:
Adjusted EBITDA (2) $25,125 $79,503 $67,310 $225,459
Capital expenditures 4,499 4,322 17,199 12,108
Capital expenditures for
turnarounds and
catalysts 1,455 1,210 9,679 3,214
KEY OPERATING
STATISTICS:
Per barrel of
throughput:
Refinery operating
margin (3) $9.22 $16.71 $8.52 $15.95
Refinery direct
operating expense (4) 3.90 3.46 3.85 3.53
PRICING STATISTICS:
Crack spreads (per
barrel):
Gulf Coast 3/2/1 (5) $13.31 $19.77 $12.57 $19.08
WTI Cushing crude oil
(per barrel) $44.88 $46.41 $41.23 $50.91
Crude oil differentials
(per barrel):
WTI Cushing less WTI
Midland (6) $0.31 $(0.72) $0.12 $0.60
WTI Cushing less WTS (6) 0.92 (1.46) 0.53 0.02
Brent less WTI Cushing
(6) 0.74 3.78 0.35 4.28
Product price (dollars
per gallon):
Gulf Coast unleaded
gasoline $1.39 $1.61 $1.30 $1.66
Gulf Coast ultra-low
sulfur diesel 1.37 1.52 1.25 1.68
Natural gas (per MMBtu) 2.79 2.73 2.34 2.76
September 30, December 31,
2016 2015
---- ----
BALANCE SHEET DATA (end of period): (dollars in thousands)
Cash and cash equivalents $203,763 $132,953
Working capital 10,460 (53,804)
Total assets 825,050 748,584
Total debt 291,486 292,082
Total debt less cash and cash equivalents 87,723 159,129
Total partners' equity 111,968 130,957
THROUGHPUT AND PRODUCTION
DATA: For the Three Months Ended For the Nine Months Ended
September 30, September 30,
------------- -------------
2016 2015 2016 2015
---- ---- ---- ----
bpd % bpd % bpd % bpd %
Refinery throughput:
WTS crude 34,292 48.9 30,810 40.6 32,189 46.3 35,041 47.0
WTI crude 32,503 46.4 42,503 56.1 34,428 49.4 36,834 49.4
Blendstocks 3,268 4.7 2,484 3.3 2,969 4.3 2,687 3.6
----- --- ----- --- ----- --- ----- ---
Total refinery throughput
(7) 70,063 100.0 75,797 100.0 69,586 100.0 74,562 100.0
====== ===== ====== ===== ====== ===== ====== =====
Refinery production:
Gasoline 33,637 48.1 37,503 49.5 33,826 48.7 37,155 49.6
Diesel/jet 26,004 37.2 28,623 37.8 25,108 36.1 27,596 36.9
Asphalt 2,818 4.0 2,452 3.2 2,846 4.1 2,733 3.7
Petrochemicals 3,861 5.5 4,588 6.1 3,611 5.2 4,770 6.4
Other 3,661 5.2 2,595 3.4 4,084 5.9 2,510 3.4
----- --- ----- --- ----- --- ----- ---
Total refinery production
(8) 69,981 100.0 75,761 100.0 69,475 100.0 74,764 100.0
====== ===== ====== ===== ====== ===== ====== =====
Refinery utilization (9) 99.1% 100.4% 95.5% 98.5%
CASH AVAILABLE FOR DISTRIBUTION DATA: For the Three
Months Ended
September 30, 2016
------------------
(dollars in
thousands, except
per unit data)
Net sales (1) $462,257
Operating costs and expenses:
Cost of sales 404,207
Direct operating expenses 25,125
Selling, general and administrative
expenses 8,153
Depreciation and amortization 14,581
------
Total operating costs and expenses 452,066
Operating income 10,191
Interest expense (8,144)
Other income, net 353
---
Income before state income tax expense 2,400
State income tax expense 317
Net income 2,083
Adjustments to reconcile net loss to
Adjusted EBITDA:
Interest expense 8,144
State income tax expense 317
Depreciation and amortization 14,581
Adjusted EBITDA (2) 25,125
Adjustments to reconcile Adjusted EBITDA
to cash available for distribution:
less: Maintenance/growth capital
expenditures 4,499
less: Turnaround and catalyst replacement
capital expenditures 1,455
less: Major turnaround reserve for future
years 1,500
less: Principal payments 625
less: State income tax payments 317
less: Interest paid in cash 7,337
-----
Calculated cash available for
distribution $9,392
======
Common units outstanding (in 000's) 62,520
Cash available for distribution per unit $0.15
=====
________________
(1) Includes sales to
related parties
of $82,717 and
$97,014 for the
three months
ended September
30, 2016 and
2015,
respectively, and
$222,711 and
$281,136 for the
nine months ended
September 30,
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 and nine
months ended
September 30,
2016 and 2015:
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
------------- -------------
2016 2015
2016 2015
---- ----
(dollars in thousands)
Net income
(loss) $2,083 $53,776 $(5,288) $149,653
State income
tax expense 317 525 493 480
Interest
expense 8,144 11,505 28,651 34,045
Depreciation
and
amortization 14,581 13,697 43,454 41,281
------ ------ ------ ------
Adjusted
EBITDA $25,125 $79,503 $67,310 $225,459
======= ======= ======= ========
(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,
2016 excludes
gains
(losses)
related to
inventory
adjustments
of $(1,419)
and $2,046,
respectively.
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.
To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/alon-usa-partners-lp-reports-third-quarter-2016-results-and-declares-quarterly-cash-distribution-300352102.html
SOURCE Alon USA Partners, LP
