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Alon USA Partners, LP Reports Third Quarter 2017 Results and Declares Quarterly Cash Distribution

BRENTWOOD, Tenn., Nov. 08, 2017 (GLOBE NEWSWIRE) -- 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 Solicitation
This 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 It
This 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 Solicitation
Delek 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 SUBSIDIARIES
CONDENSED 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, net83,781 82,292
Accounts receivables from related parties 11,425
Inventories99,802 49,682
Prepaid expenses and other current assets4,877 4,949
Total current assets457,032 221,872
Property, plant and equipment, net418,106 420,554
Goodwill568,541
Other non-current assets54,031 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 receivables84,631
Accrued expenses and other current liabilities181,820 43,100
Current portion of long-term debt2,500 2,500
Obligation under Supply and Offtake Agreement99,108
Total current liabilities469,647 295,435
Non-Current Liabilities:
Other non-current liabilities27,381 62,880
Long-term debt, net of current portion335,625 233,819
Deferred income tax liability2,374
Total non-current liabilities365,380 296,699
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, respectively662,683 103,503
Total partners’ equity662,683 103,503
Total liabilities and partners’ equity$1,497,710 $695,637


ALON USA PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED
EARNINGS 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 party400,942 379,540
Net sales495,478 462,257
Operating costs and expenses:
Cost of goods sold415,386 404,207
Operating expenses26,548 25,125
Selling, general and administrative expenses7,741 8,153
Depreciation and amortization7,620 14,581
Loss on disposition of assets
Total operating costs and expenses457,295 452,066
Operating income38,183 10,191
Interest expense, net8,817 8,144
Other expense (income), net5 (353)
Total non-operating expense8,822 7,791
Income before income tax expense29,361 2,400
Income tax expense125 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 activities24,497 36,027
OTHER DATA:
Adjusted EBITDA (1)$67,798 $25,125
Capital expenditures12,681 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 from
July 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 party400,942 880,523 1,076,012
Net sales495,478 1,066,283 1,298,723
Operating costs and expenses:
Cost of goods sold415,386 911,366 1,134,275
Operating expenses26,548 52,638 73,424
Selling, general and administrative expenses7,741 14,156 24,264
Depreciation and amortization7,620 28,691 43,454
Loss on disposition of assets 23
Total operating costs and expenses457,295 1,006,874 1,275,417
Operating income38,183 59,409 23,306
Interest expense, net8,817 16,497 28,651
Other expense (income), net5 554 (550)
Total non-operating expense8,822 17,051 28,101
Income (loss) before income tax expense29,361 42,358 (4,795)
Income tax expense125 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 activities24,497 29,761 39,231
OTHER DATA:
Adjusted EBITDA (1)$67,798 $87,569 $67,310
Capital expenditures12,681 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 diesel1.62 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 crude17,016 24.4 34,292 48.9 21,617 29.5 32,189 46.3
WTI crude52,101 74.7 32,503 46.4 49,095 66.9 34,428 49.4
Blendstocks606 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:
Gasoline35,990 51.9 33,637 48.1 36,052 49.4 33,826 48.7
Diesel/jet27,001 38.9 26,004 37.2 27,912 38.3 25,108 36.1
Asphalt1,213 1.7 2,818 4.0 2,036 2.8 2,846 4.1
Petrochemicals2,956 4.3 3,861 5.5 3,765 5.2 3,611 5.2
Other2,196 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 Expense8,817 8,144
State income tax expense125 317
Depreciation and amortization7,620 14,581
Inventory fair value adjustment22,000
Adjusted EBITDA (1)$67,798 $25,125
Maintenance/growth capital expenditures21,881 4,499
Turnaround and catalyst replacement capital expenditures 1,455
Major turnaround reserve for future years (a)3,500 1,500
Principal payments625 625
Income tax payments310 317
Gain (loss) on asset disposals
Interest paid in cash8,314 7,337
Cash available for distribution before special expenses33,168 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 Expense8,817 16,497 28,651
Income tax expense125 566 493
Depreciation and amortization7,620 28,691 43,454
Inventory fair value adjustment22,000
Adjusted EBITDA (2)$67,798 $87,546 $67,310
Maintenance/growth capital expenditures21,881 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 payments625 1,250 1,875
Income tax payments310 566 493
Less: Gain (loss) on asset disposals 23
Interest paid in cash8,314 16,155 27,219
Cash available for distribution before special expenses33,168 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

  1. 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.

  2. 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.

________________

  1. 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.
  1. 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.
  1. Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses by total throughput.

  2. 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.

  3. 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.

  4. Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.

  5. 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.

  6. 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 Johnson
Vice President of Investor Relations
615-435-1366

Source:Alon USA Partners, LP