Alon USA Partners, LP (NYSE:ALDW) (“Alon Partners”) today announced
results for the third quarter of 2017. Net income for the third
quarter of 2017 was $29.2 million, or $0.47 per unit, compared to
net income of $2.1 million, or $0.03 per unit, for the same period
last year. Included in the third quarter 2017 results was an
approximately $22.0 million, or $0.35 per common unit charge
for inventory fair value adjustment entries at Delek US Holdings,
Inc. (NYSE:DK) (“Delek US”) related to its acquisition of Alon USA
Energy, Inc. on July 1, 2017 that were recorded at Alon Partners
through push down accounting.
On November 8, 2017, Delek US and Alon Partners
announced the execution of a definitive merger agreement under
which Delek US will acquire all of the outstanding Alon Partners
common units representing limited partner interests of Alon
Partners which Delek US and its affiliates do not already own in an
all-stock for common units merger transaction. Delek US and its
affiliates currently own approximately 51.0 million common units of
Alon Partners, or approximately 81.6 percent of the outstanding
units. Under the terms of the merger agreement, the owners of the
outstanding common units in Alon Partners that Delek US and its
affiliates do not currently own will receive a fixed exchange ratio
of 0.49 shares of Delek US common stock for each common unit of
Alon Partners. This implies a 5.0 percent premium to the 30
trading day volume weighted average ratio through and including
November 7, 2017, of .4666 and a 2.9 percent premium to the ratio
on November 7, 2017, which was the day before the parties announced
this transaction. This transaction was approved by all voting
members of the board of directors of Alon Partners’ general
partner, upon the recommendation from its conflicts committee and
by the board of directors of Delek US. This transaction is expected
to close in the first quarter 2018 and is subject to customary
closing conditions.
Fred Green, Chief Executive Officer of our
general partner, commented, “Our third quarter 2017 results
benefited from an improvement in our benchmark Gulf Coast crack
spread and discounts in Midland-sourced crude oil relative to WTI
Cushing. Our operations were unaffected by Hurricane Harvey and
during late August and September we remained focused on supplying
our customers as the hurricane reduced product supply on the Gulf
Coast during that time period. During the third quarter 2017,
we continued to increase the amount of WTI crude oil that we
processed and our wholesale business performed well. The
combination with Delek US in an all-equity transaction will provide
our public unit holders with the opportunity to be a part of a
larger, more diverse and growing company.”
On November 8, 2017, 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 2017 of $0.43
per unit payable on November 22, 2017 to common unitholders of
record at the close of business on November 13, 2017, based on
cash available for distribution of $26.9 million. During the
quarter, capital expenditures included $9.2 million to buyout an
operating lease, which reduced the distribution by approximately
$0.14 per unit.
Effective July 1, 2017, with the completion of
the merger between Delek US and Alon USA Energy, Delek US
indirectly owns 100% of our General Partner and 81.6% of our
limited partner interest. As a result of these transactions, Alon
Partners became a consolidated subsidiary of Delek US Holdings,
Inc. and elected to apply “push down” accounting which required its
assets and liabilities to be adjusted to fair value on the
effective date. Due to the application of push-down accounting,
Alon Partners’ consolidated financial statements are presented in
two distinct periods to indicate the application of two different
basis of accounting between the periods presented. The periods
prior to the merger effective date, July 1, 2017, are identified as
“Predecessor” and the period from July 1, 2017 forward is
identified as “Successor”. Because of this change the periods are
not directly comparable.
THIRD QUARTER 2017
Refinery operating margin was $12.49 per barrel
for the third quarter of 2017, which included approximately $22.0
million, or a $3.43 per barrel charge for inventory fair
value adjustment at Delek US related to its acquisition of Alon USA
on July 1, 2017 that were recorded at Alon Partners through push
down accounting. Excluding this amount, the operating margin in the
third quarter 2017 would have been $15.92 per barrel compared to
$9.22 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 the
WTI Cushing to WTI Midland spread and a stronger wholesale
marketing environment, partially offset by a reduced benefit from
the contango environment which increased the cost of crude oil. The
third quarter 2016 operating margin was negatively affected by
costs associated with the reformer generation. Refinery average
throughput for the third quarter of 2017 was 69,723 bpd compared to
average throughput of 70,063 bpd for the same period in 2016.
The average Gulf Coast 3/2/1 crack spread was
$20.16 per barrel for the third quarter of 2017 compared to $13.31
per barrel for the third quarter of 2016. The average WTI Cushing
to WTI Midland spread for the third quarter of 2017 was $0.79 per
barrel compared to $0.31 per barrel for the third quarter of 2016.
The average WTI Cushing to WTS spread for the third quarter of 2017
was $0.97 per barrel compared to $1.47 per barrel for the third
quarter of 2016. The average Brent to WTI Cushing spread for the
third quarter of 2017 was $4.04 per barrel compared to $2.05 per
barrel for the same period in 2016. The contango environment in the
third quarter of 2017 created an average cost of crude benefit of
$0.24 per barrel compared to an average cost of crude benefit of
$0.84 per barrel for the same period in 2016. The average RINs cost
effect on refinery operating margin was $1.14 per barrel in the
third quarter of 2017, compared to $0.58 per barrel for the same
period in 2016.
Third Quarter 2017 Results | Conference
Call Information
Alon Partners has scheduled a conference call,
which will be broadcast live over the Internet on Thursday,
November 9, 2017 at 7:30 a.m. Central Time, to discuss the third
quarter 2017 financial results. Investors may 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 February 9, 2017 and may be accessed by
calling 855-859-2056 and using the passcode 99812665. A webcast
archive will also be available at www.alonpartners.com shortly
after the call and will be accessible for approximately 90
days.
Tax Considerations
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.
Safe Harbor Provisions Regarding
Forward-Looking Statements
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. These forward-looking statements include, but are
not limited to, statements regarding the potential merger between
Alon Partners and Delek US including the closing, timeline and
benefits relating thereto; crude oil slates; crude oil and product
costs, netbacks and margins; opportunities; anticipated performance
and financial position; continued safe and reliable operations; and
other factors. Forward-looking statements should not be read
as a guarantee of future performance or results and will not be
accurate indications of the times at or by which such performance
or results will be achieved. Forward-looking information is
based on information available at the time and/or management's good
faith belief with respect to future events, and is subject to risks
and uncertainties that could cause actual performance or results to
differ materially from those expressed in the statements.
Alon Partners undertakes no obligation to update or revise any such
forward-looking statements, except as required by applicable law or
regulation. Additional information regarding these and other
risks is contained in our filings with the Securities and Exchange
Commission.
About Alon USA Partners, LP
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.
No Offer or SolicitationThis communication
relates to a proposed business combination between Delek US and
Alon Partners. This announcement is for informational purposes only
and is neither an offer to purchase, nor a solicitation of an offer
to sell, any securities or the solicitation of any vote in any
jurisdiction pursuant to the proposed transactions or otherwise,
nor shall there be any sale, issuance or transfer of securities in
any jurisdiction in contravention of applicable law. No offer of
securities shall be made except by means of a prospectus meeting
the requirements of Section 10 of the Securities Act of 1933, as
amended.
Additional Information and Where to Find ItThis
press release does not constitute an offer to sell or the
solicitation of an offer to buy any securities or a solicitation of
any vote or approval.
In connection with the proposed acquisition
transaction, a registration statement on Form S-4 will be filed
with the SEC that will include a consent statement of Alon
Partners. Delek US also plans to file other relevant materials with
the SEC. UNITHOLDERS OF ALON PARTNERS ARE ENCOURAGED TO READ THE
REGISTRATION STATEMENT AND ANY OTHER RELEVANT DOCUMENTS FILED WITH
THE SEC, INCLUDING THE CONSENT STATEMENT/PROSPECTUS THAT WILL BE
PART OF THE REGISTRATION STATEMENT, BECAUSE THEY WILL CONTAIN
IMPORTANT INFORMATION ABOUT THE PROPOSED ACQUISITION. The final
consent solicitation /prospectus will be mailed to unitholders of
Alon Partners. Investors and security holders will be able to
obtain the documents, and any other documents that Delek US has
filed with the SEC, free of charge at the SEC's website,
www.sec.gov. In addition, documents filed with the SEC by Delek US
will be available free of charge by (1) accessing Delek US’ website
at www.delekus.com under the "Investor Relations" link and then
under the heading "SEC Filings"; (2) writing Delek US at 7102
Commerce Way, Brentwood, TN 37027, Attention: Investor Relations;
or (3) writing Alon Partners at 7102 Commerce Way, Brentwood, TN
37027, Attention: Investor Relations.
Participants in the SolicitationDelek US, Alon
Partners and their respective directors and executive officers may
be deemed to be participants in the solicitation of consents in
favor of the acquisition from the unitholders of Alon Partners.
Additional information regarding the interests of those
participants and other persons who may be deemed participants in
the transaction may be obtained by reading the consent
statement/prospectus regarding the proposed acquisition when it
becomes available. Free copies of this document may be obtained as
described in the preceding paragraph.
|
ALON USA PARTNERS, LP AND
SUBSIDIARIESCONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)(In thousands, except share and per
share data) |
|
|
Successor |
|
|
Predecessor |
|
September 30, 2017 |
|
|
December 31, 2016 |
ASSETS |
|
|
|
|
Current assets: |
|
|
|
|
Cash and
cash equivalents |
$ |
268,572 |
|
|
|
$ |
73,524 |
|
Accounts
receivables, net |
83,781 |
|
|
|
82,292 |
|
Accounts
receivables from related parties |
— |
|
|
|
11,425 |
|
Inventories |
99,802 |
|
|
|
49,682 |
|
Prepaid
expenses and other current assets |
4,877 |
|
|
|
4,949 |
|
Total
current assets |
457,032 |
|
|
|
221,872 |
|
Property, plant and
equipment, net |
418,106 |
|
|
|
420,554 |
|
Goodwill |
568,541 |
|
|
|
— |
|
Other non-current
assets |
54,031 |
|
|
|
53,211 |
|
Total
assets |
$ |
1,497,710 |
|
|
|
$ |
695,637 |
|
LIABILITIES AND PARTNERS’ EQUITY |
|
|
|
|
Current
liabilities: |
|
|
|
|
Accounts
payable |
$ |
101,588 |
|
|
|
$ |
249,835 |
|
Accounts
payable to related parties, net of related receivables |
84,631 |
|
|
|
— |
|
Accrued
expenses and other current liabilities |
181,820 |
|
|
|
43,100 |
|
Current
portion of long-term debt |
2,500 |
|
|
|
2,500 |
|
Obligation under Supply and Offtake Agreement |
99,108 |
|
|
|
— |
|
Total
current liabilities |
469,647 |
|
|
|
295,435 |
|
Non-Current
Liabilities: |
|
|
|
|
Other non-current
liabilities |
27,381 |
|
|
|
62,880 |
|
Long-term debt, net of
current portion |
335,625 |
|
|
|
233,819 |
|
Deferred income tax
liability |
2,374 |
|
|
|
— |
|
Total
non-current liabilities |
365,380 |
|
|
|
296,699 |
|
|
|
|
|
|
Partners’ equity: |
|
|
|
|
General
Partner |
— |
|
|
|
— |
|
Common
unit interest - 62,529,328 and 62,520,220 units issued and
outstanding at September 30, 2017 and December 31, 2016,
respectively |
662,683 |
|
|
|
103,503 |
|
Total
partners’ equity |
662,683 |
|
|
|
103,503 |
|
Total
liabilities and partners’ equity |
$ |
1,497,710 |
|
|
|
$ |
695,637 |
|
ALON USA PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATEDEARNINGS RELEASE |
|
|
Successor |
|
|
Predecessor |
RESULTS OF
OPERATIONS - FINANCIAL DATA (UNAUDITED) |
Three Months Ended September 30,
2017 |
|
|
Three Months Ended September 30,
2016 |
Net sales: |
|
|
|
|
Affiliate |
$ |
94,536 |
|
|
|
$ |
82,717 |
|
Third party |
400,942 |
|
|
|
379,540 |
|
Net sales |
495,478 |
|
|
|
462,257 |
|
Operating costs and
expenses: |
|
|
|
|
Cost of
goods sold |
415,386 |
|
|
|
404,207 |
|
Operating
expenses |
26,548 |
|
|
|
25,125 |
|
Selling,
general and administrative expenses |
7,741 |
|
|
|
8,153 |
|
Depreciation and amortization |
7,620 |
|
|
|
14,581 |
|
Loss on
disposition of assets |
— |
|
|
|
— |
|
Total
operating costs and expenses |
457,295 |
|
|
|
452,066 |
|
Operating income |
38,183 |
|
|
|
10,191 |
|
Interest expense,
net |
8,817 |
|
|
|
8,144 |
|
Other expense (income),
net |
5 |
|
|
|
(353 |
) |
Total non-operating
expense |
8,822 |
|
|
|
7,791 |
|
Income before income
tax expense |
29,361 |
|
|
|
2,400 |
|
Income tax expense |
125 |
|
|
|
317 |
|
Net income attributable
to partners |
$ |
29,236 |
|
|
|
$ |
2,083 |
|
Comprehensive income
attributable to partners |
$ |
29,236 |
|
|
|
$ |
2,083 |
|
Net income per unit -
(basic and diluted) |
$ |
0.47 |
|
|
|
$ |
0.03 |
|
Weighted average common
units outstanding (in thousands) - (basic and diluted) |
62,529 |
|
|
|
62,520 |
|
Cash distribution per
unit |
$ |
0.35 |
|
|
|
$ |
0.14 |
|
CASH FLOW
DATA: |
|
|
|
|
Net cash provided by
(used in): |
|
|
|
|
Operating
activities |
$ |
94,574 |
|
|
|
$ |
11,870 |
|
Investing
activities |
(17,738 |
) |
|
|
(5,954 |
) |
Financing
activities |
24,497 |
|
|
|
36,027 |
|
OTHER
DATA: |
|
|
|
|
Adjusted EBITDA
(1) |
$ |
67,798 |
|
|
|
$ |
25,125 |
|
Capital
expenditures |
12,681 |
|
|
|
4,499 |
|
Capital expenditures
for turnarounds and catalysts |
— |
|
|
|
1,455 |
|
Capital expenditure for
operating lease purchase |
$ |
9,200 |
|
|
|
$ |
— |
|
Key Operating
Statistics: |
|
|
|
|
Per barrel of
throughput: |
|
|
|
|
Refinery operating
margin (2) |
$ |
12.49 |
|
|
|
$ |
9.22 |
|
Refinery direct
operating expense (3) |
4.14 |
|
|
|
3.90 |
|
|
Successor |
|
|
Predecessor |
|
Predecessor |
RESULTS OF
OPERATIONS - FINANCIAL DATA (UNAUDITED) |
Period fromJuly 1, 2017 to September 30,
2017 |
|
|
Period from January 1, 2017 to June 30,
2017 |
|
Nine Months Ended September 30,
2016 |
Net sales: |
|
|
|
|
|
|
Affiliate |
$ |
94,536 |
|
|
|
$ |
185,760 |
|
|
$ |
222,711 |
|
Third party |
400,942 |
|
|
|
880,523 |
|
|
1,076,012 |
|
Net sales |
495,478 |
|
|
|
1,066,283 |
|
|
1,298,723 |
|
Operating costs and
expenses: |
|
|
|
|
|
|
Cost of
goods sold |
415,386 |
|
|
|
911,366 |
|
|
1,134,275 |
|
Operating
expenses |
26,548 |
|
|
|
52,638 |
|
|
73,424 |
|
Selling,
general and administrative expenses |
7,741 |
|
|
|
14,156 |
|
|
24,264 |
|
Depreciation and amortization |
7,620 |
|
|
|
28,691 |
|
|
43,454 |
|
Loss on
disposition of assets |
— |
|
|
|
23 |
|
|
— |
|
Total
operating costs and expenses |
457,295 |
|
|
|
1,006,874 |
|
|
1,275,417 |
|
Operating income |
38,183 |
|
|
|
59,409 |
|
|
23,306 |
|
Interest expense,
net |
8,817 |
|
|
|
16,497 |
|
|
28,651 |
|
Other expense (income),
net |
5 |
|
|
|
554 |
|
|
(550 |
) |
Total non-operating
expense |
8,822 |
|
|
|
17,051 |
|
|
28,101 |
|
Income (loss) before
income tax expense |
29,361 |
|
|
|
42,358 |
|
|
(4,795 |
) |
Income tax expense |
125 |
|
|
|
566 |
|
|
493 |
|
Net income (loss)
attributable to partners |
$ |
29,236 |
|
|
|
$ |
41,792 |
|
|
$ |
(5,288 |
) |
Comprehensive income
(loss) attributable to partners |
$ |
29,236 |
|
|
|
$ |
41,792 |
|
|
$ |
(5,288 |
) |
Net income (loss) per
unit - (basic and diluted) |
$ |
0.47 |
|
|
|
$ |
0.67 |
|
|
$ |
(0.08 |
) |
Weighted average common
units outstanding (in thousands) - (basic and diluted) |
62,529 |
|
|
|
62,523 |
|
|
62,515 |
|
Cash distribution per
unit |
$ |
0.35 |
|
|
|
$ |
0.49 |
|
|
$ |
0.22 |
|
CASH FLOW
DATA: |
|
|
|
|
|
|
Net cash provided by
(used in): |
|
|
|
|
|
|
Operating
activities |
$ |
94,574 |
|
|
|
$ |
77,145 |
|
|
$ |
58,457 |
|
Investing
activities |
(17,738 |
) |
|
|
(13,191 |
) |
|
(26,878 |
) |
Financing
activities |
24,497 |
|
|
|
29,761 |
|
|
39,231 |
|
OTHER
DATA: |
|
|
|
|
|
|
Adjusted EBITDA
(1) |
$ |
67,798 |
|
|
|
$ |
87,569 |
|
|
$ |
67,310 |
|
Capital
expenditures |
12,681 |
|
|
|
12,175 |
|
|
17,199 |
|
Capital expenditures
for turnarounds and catalysts |
— |
|
|
|
1,016 |
|
|
9,679 |
|
Capital expenditure for
operating lease purchase |
$ |
9,200 |
|
|
|
$ |
— |
|
|
$ |
— |
|
Key Operating
Statistics: |
|
|
|
|
|
|
Per barrel of
throughput: |
|
|
|
|
|
|
Refinery operating
margin (2) |
$ |
12.49 |
|
|
|
$ |
11.47 |
|
|
$ |
8.52 |
|
Refinery direct
operating expense (3) |
4.14 |
|
|
|
3.86 |
|
|
3.85 |
|
PRICING
STATISTICS: |
For the Three Months Ended September
30, |
|
Nine Months Ended September 30, |
|
2017 |
|
2016 |
|
2017 |
|
|
2016 |
|
|
|
|
|
|
|
|
|
Crack spreads (per
barrel): |
|
|
|
|
|
|
|
|
Gulf
Coast 3/2/1 (4) |
$ |
20.16 |
|
|
$ |
13.31 |
|
|
$ |
16.20 |
|
|
|
$ |
12.25 |
|
WTI Cushing crude oil
(per barrel) |
$ |
48.16 |
|
|
$ |
44.88 |
|
|
$ |
49.31 |
|
|
|
$ |
41.40 |
|
Crude oil differentials
(per barrel): |
|
|
|
|
|
|
|
|
WTI
Cushing less WTI Midland (5) |
$ |
0.79 |
|
|
$ |
0.31 |
|
|
$ |
0.53 |
|
|
|
$ |
0.18 |
|
WTI
Cushing less WTS (5) |
0.97 |
|
|
1.47 |
|
|
1.15 |
|
|
|
0.82 |
|
Brent
less WTI Cushing (5) |
4.04 |
|
|
2.05 |
|
|
3.18 |
|
|
|
1.81 |
|
Product price (dollars
per gallon): |
|
|
|
|
|
|
|
|
Gulf
Coast unleaded gasoline |
$ |
1.63 |
|
|
$ |
1.39 |
|
|
$ |
1.57 |
|
|
|
$ |
1.29 |
|
Gulf
Coast ultra-low sulfur diesel |
1.62 |
|
|
1.37 |
|
|
1.55 |
|
|
|
1.25 |
|
Natural
gas (per MMBtu) |
2.95 |
|
|
2.79 |
|
|
3.05 |
|
|
|
2.35 |
|
SALES, THROUGHPUT AND PRODUCTION DATA: |
For the Three Months Ended |
|
For the Nine Months Ended |
September 30, |
|
September 30, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
bpd |
|
% |
|
bpd |
|
% |
|
bpd |
|
% |
|
bpd |
|
% |
Sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery
throughput: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTS
crude |
17,016 |
|
|
24.4 |
|
|
34,292 |
|
|
48.9 |
|
|
21,617 |
|
|
29.5 |
|
|
32,189 |
|
|
46.3 |
|
WTI
crude |
52,101 |
|
|
74.7 |
|
|
32,503 |
|
|
46.4 |
|
|
49,095 |
|
|
66.9 |
|
|
34,428 |
|
|
49.4 |
|
Blendstocks |
606 |
|
|
0.9 |
|
|
3,268 |
|
|
4.7 |
|
|
2,672 |
|
|
3.6 |
|
|
2,969 |
|
|
4.3 |
|
Total refinery
throughput (6) |
69,722 |
|
|
100.0 |
|
|
70,063 |
|
|
100.0 |
|
|
73,384 |
|
|
100.0 |
|
|
69,586 |
|
|
100.0 |
|
Refinery
production: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline |
35,990 |
|
|
51.9 |
|
|
33,637 |
|
|
48.1 |
|
|
36,052 |
|
|
49.4 |
|
|
33,826 |
|
|
48.7 |
|
Diesel/jet |
27,001 |
|
|
38.9 |
|
|
26,004 |
|
|
37.2 |
|
|
27,912 |
|
|
38.3 |
|
|
25,108 |
|
|
36.1 |
|
Asphalt |
1,213 |
|
|
1.7 |
|
|
2,818 |
|
|
4.0 |
|
|
2,036 |
|
|
2.8 |
|
|
2,846 |
|
|
4.1 |
|
Petrochemicals |
2,956 |
|
|
4.3 |
|
|
3,861 |
|
|
5.5 |
|
|
3,765 |
|
|
5.2 |
|
|
3,611 |
|
|
5.2 |
|
Other |
2,196 |
|
|
3.2 |
|
|
3,661 |
|
|
5.2 |
|
|
3,193 |
|
|
4.4 |
|
|
4,084 |
|
|
5.9 |
|
Total refinery
production (7) |
69,356 |
|
|
100.0 |
|
|
69,981 |
|
|
100.0 |
|
|
72,958 |
|
|
100.0 |
|
|
69,475 |
|
|
100.0 |
|
Refinery utilization
(8) |
|
|
94.7 |
% |
|
|
|
99.1 |
% |
|
|
|
96.9 |
% |
|
|
|
95.5 |
% |
|
Successor |
|
|
Predecessor |
|
Three Months Ended September 30,
2017 |
|
|
Three Months Ended September 30,
2016 |
Reconciliation
of Adjusted EBITDA to net income: |
|
|
|
|
Net
income |
$ |
29,236 |
|
|
|
$ |
2,083 |
|
Add: |
|
|
|
|
Interest
Expense |
8,817 |
|
|
|
8,144 |
|
State
income tax expense |
125 |
|
|
|
317 |
|
Depreciation and amortization |
7,620 |
|
|
|
14,581 |
|
Inventory
fair value adjustment |
22,000 |
|
|
|
— |
|
Adjusted EBITDA
(1) |
$ |
67,798 |
|
|
|
$ |
25,125 |
|
Maintenance/growth
capital expenditures |
21,881 |
|
|
|
4,499 |
|
Turnaround and catalyst
replacement capital expenditures |
— |
|
|
|
1,455 |
|
Major turnaround
reserve for future years (a) |
3,500 |
|
|
|
1,500 |
|
Principal payments |
625 |
|
|
|
625 |
|
Income tax
payments |
310 |
|
|
|
317 |
|
Gain (loss) on asset
disposals |
— |
|
|
|
— |
|
Interest paid in
cash |
8,314 |
|
|
|
7,337 |
|
Cash available for
distribution before special expenses |
33,168 |
|
|
|
9,392 |
|
Special reserve for
cost increase in capital expenditures associated with the consent
decree (b) |
6,300 |
|
|
|
— |
|
Cash available for
distribution |
$ |
26,868 |
|
|
|
$ |
9,392 |
|
|
|
|
|
|
|
Successor |
|
|
Predecessor |
|
Predecessor |
|
Period from July 1, 2017 to September 30,
2017 |
|
|
Period from January 1, 2017 to June 30,
2017 |
|
Nine Months Ended September 30,
2016 |
Reconciliation
of net income to EBITDA, Adjusted EBITDA (1) and cash available for
distribution: |
|
|
|
|
|
|
Net income |
$ |
29,236 |
|
|
|
41,792 |
|
|
$ |
(5,288 |
) |
Add: |
|
|
|
|
|
|
Interest
Expense |
8,817 |
|
|
|
16,497 |
|
|
28,651 |
|
Income
tax expense |
125 |
|
|
|
566 |
|
|
493 |
|
Depreciation and amortization |
7,620 |
|
|
|
28,691 |
|
|
43,454 |
|
Inventory
fair value adjustment |
22,000 |
|
|
|
— |
|
|
— |
|
Adjusted EBITDA
(2) |
$ |
67,798 |
|
|
|
$ |
87,546 |
|
|
$ |
67,310 |
|
Maintenance/growth
capital expenditures |
21,881 |
|
|
|
12,175 |
|
|
17,199 |
|
Turnaround and catalyst
replacement capital expenditures |
— |
|
|
|
1,016 |
|
|
4,616 |
|
Major turnaround
reserve for future years (a) |
3,500 |
|
|
|
7,000 |
|
|
4,500 |
|
Principal payments |
625 |
|
|
|
1,250 |
|
|
1,875 |
|
Income tax
payments |
310 |
|
|
|
566 |
|
|
493 |
|
Less: Gain (loss) on
asset disposals |
— |
|
|
|
23 |
|
|
— |
|
Interest paid in
cash |
8,314 |
|
|
|
16,155 |
|
|
27,219 |
|
Cash available
for distribution before special expenses |
33,168 |
|
|
|
49,407 |
|
|
11,408 |
|
Special reserve for
cost increase in capital expenditures associated with the consent
decree (b) |
6,300 |
|
|
|
4,000 |
|
|
— |
|
Cash available
for distribution |
$ |
26,868 |
|
|
|
$ |
45,407 |
|
|
$ |
11,408 |
|
|
- 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.
- 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 $6.3 million from cash available for
distribution each quarter through the fourth quarter of 2018 to
cover a $28 million increase in the expected costs.
________________
- To supplement our financial information presented in accordance
with United States generally accepted accounting principles
(“GAAP”), management uses additional measures that are known as
“non-GAAP financial measures” in its evaluation of past performance
and prospectus for the future. The primary measures used by
management are Adjusted EBITDA, Earnings Before Interest, Taxes,
Depreciation and Amortization (“EBITDA”) and cash available for
distribution.EBITDA and Adjusted EBITDA represent earnings before
income tax expense, interest expense, depreciation and amortization
and in the case of Adjusted EBITDA, the inventory fair value
adjustment. Neither EBITDA nor Adjusted EBITDA is a recognized
measurement under GAAP; however, the amounts included in EBITDA and
Adjusted EBITDA are derived from amounts included in our
consolidated financial statements. Our management believes that the
presentation of EBITDA and 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 EBITDA and
Adjusted EBITDA are useful in evaluating our operating performance
compared to that of other companies in our industry because the
calculation of EBITDA and Adjusted EBITDA generally eliminates the
effects of 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.Cash available for distribution is derived
from net income plus or minus all adjustments to arrive at Adjusted
EBITDA, less cash needed for maintenance capital expenditures, debt
service and other contractual obligations, and reserves for future
operating or capital needs that the board of directors of our
general partner deems necessary or appropriate, including reserves
for our expenses in the quarters in which our planned turnarounds
and catalyst replacement occur and special reserve for cost
increase in capital expenditures associated with the consent
decree.We believe that the presentation of EBITDA, Adjusted EBITDA
and cash available for distribution provides useful information to
investors in assessing our financial condition and results of
operations. EBITDA, Adjusted EBITDA and cash available for
distribution should not be considered alternatives to net income,
operating income, cash flow from operating activities or any other
measure of financial performance or liquidity presented in
accordance with U.S. GAAP. EBITDA, Adjusted EBITDA and cash
available for distribution have important limitations as analytical
tools because they exclude some but not all items that affect net
income and net cash provided by operating activities.
Additionally, because EBITDA, Adjusted EBITDA and cash available
for distribution may be defined differently by other companies in
our industry, our definition of EBITDA, Adjusted EBITDA and cash
available for distribution may not be comparable to similarly
titled measures of other companies, thereby diminishing its
utility. Because of these limitations, EBITDA, Adjusted
EBITDA and cash available for distribution 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 EBITDA, Adjusted
EBITDA and cash available for distribution only
supplementally.
- 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 total throughput. 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
Successor three-month period ended September 30, 2017 and
Predecessor six-month period ended June 30, 2017 excludes gains
(losses) related to inventory adjustments of $0 and $1,264,
respectively. Refinery operating margin for the Predecessor three-
and nine-month periods ended September 30, 2016 excludes gains
(losses) related to inventory adjustments of $1,419 and $2,046,
respectively.
- Refinery direct operating expense is a per barrel
measurement calculated by dividing direct operating expenses by
total throughput.
- 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.
- 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.
- Total refinery throughput represents the total barrels per day
of crude oil and blendstock inputs in the refinery production
process.
- 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. Effective July 1, 2017, with the completion of the merger
between Delek US and Alon USA Energy, Delek US indirectly owns 100%
of our General Partner and 81.6% of our limited partner interest.
As a result of these transactions, Alon Partners became a
consolidated subsidiary of Delek US Holdings, Inc. As a result of
throughput and yield methodologies be conformed to Delek US in the
third quarter 2017, the current period and prior year periods are
not directly comparable.
- Refinery utilization represents average daily crude oil
throughput divided by crude oil capacity, excluding planned periods
of downtime for maintenance and turnarounds.
U.S. Investor / Media Relations Contact:Keith
JohnsonVice President of Investor Relations615-435-1366
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