Attached files

file filename
EX-99.1 - EXHIBIT 99.1 ALJ FINANCIAL STATEMENTS - Delek US Holdings, Inc.dk-10kxex991xaljfinancials.htm
EX-32.2 - EXHIBIT 32.2 CFO CERTIFICATION - Delek US Holdings, Inc.dk-ex322xcfocertificationx.htm
EX-32.1 - EXHIBIT 32.1 CEO CERTIFICATION - Delek US Holdings, Inc.dk-ex321xceocertificationx.htm
EX-31.2 - EXHIBIT 31.2 CFO CERTIFICATION - Delek US Holdings, Inc.dk-ex312xcfocertificationx.htm
EX-31.1 - EXHIBIT 31.1 CEO CERTIFICATION - Delek US Holdings, Inc.dk-ex311xceocertificationx.htm
EX-24.1 - EXHIBIT 24.1 POA - Delek US Holdings, Inc.dk-10kxex241xpoax123116.htm
EX-23.2 - EXHIBIT 23.2 KPMG CONSENT - Delek US Holdings, Inc.dk-10kxex232xkpmgconsentx1.htm
EX-23.1 - EXHIBIT 23.1 EY CONSENT - Delek US Holdings, Inc.dk-10kxex231xeyconsentx123.htm
EX-21.1 - EXHIBIT 21.1 SUBSIDIARIES - Delek US Holdings, Inc.dk-10kxex211xsubsidiariesx.htm
EX-10.29(D) - EXHIBIT 10.29(D) 2016 PLAN RSU AGREEMENT - Delek US Holdings, Inc.dk-10kxex1029drsuagreement.htm
EX-10.29(C) - EXHIBIT 10.29(C) 2016 PLAN PRSU AGREEMENT - Delek US Holdings, Inc.dk-10kxex1029cformofprsuag.htm
EX-10.40 - EXHIBIT 10.40 COX EMPLOYMENT AGREEMENT - Delek US Holdings, Inc.dk-10kxex1040xcoxemploymen.htm
EX-10.39 - EXHIBIT 10.39 SOREQ EMPLOYMENT AGREEMENT - Delek US Holdings, Inc.dk-10kxex1039xsoreqemploym.htm
EX-2.6 - EXHIBIT 2.6 AMENDMENT TO MERGER AGREEMENT - Delek US Holdings, Inc.dk-10kxex26amendmenttomerg.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
þ
 
ANNUAL REPORT PURSUANT TO SECTION 18 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
 
 
 
 
 
For the Fiscal Year Ended December 31, 2016
OR
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
 
 
 
 
 
For the transition period from                      to                     

Commission file number 001-32868
DELEK US HOLDINGS, INC.
(Exact name of registrant as specified in its charter)
Delaware
 
52-2319066
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
 
 
 
7102 Commerce Way
 
 
Brentwood, Tennessee
 
37027
(Address of principal executive offices)
 
(Zip Code)
(615) 771-6701
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
 
 
 
Common Stock, $.01 par value
 
New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes  o No  þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes  þ No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  þ   No  o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (section 232.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendments of this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
    
Large accelerated filer þ    Accelerated filer o         Non-accelerated filer o    Smaller reporting company o
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  o  No þ

The aggregate market value of the common stock held by non-affiliates as of June 30, 2016 was approximately $805,158,800, based upon the closing sale price of the registrant's common stock on the New York Stock Exchange on that date. For purposes of this calculation only, all directors, officers subject to Section 16(b) of the Securities Exchange Act of 1934, and 10% stockholders are deemed to be affiliates.

At February 17, 2017, there were 61,970,962 shares of the registrant's common stock, $.01 par value, outstanding (excluding securities held by, or for the account of, the Company or its subsidiaries).

Documents incorporated by reference
Portions of the registrant's definitive Proxy Statement to be delivered to stockholders in connection with the 2017 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2016, are incorporated by reference into Part III of this Form 10-K.




TABLE OF CONTENTS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2



Unless otherwise indicated or the context requires otherwise, the terms "Delek," "we," "our," "Company" and "us" are used in this report to refer to Delek US Holdings, Inc. and its consolidated subsidiaries. See also "Glossary of Terms" included in Item 1, Business, of this Annual Report on Form 10-K for definitions of certain business and industry terms used herein.

Statements in this Annual Report on Form 10-K, other than purely historical information, including statements regarding our plans, strategies, objectives, beliefs, expectations and intentions are forward-looking statements. These forward-looking statements generally are identified by the words "may," "will," "should," "could," "would," "predicts," "intends," "believes," "expects," "plans," "scheduled," "goal," "anticipates," "estimates" and similar expressions. Forward-looking statements are based on current expectations and assumptions that are subject to risks and uncertainties, including those discussed below and in Item 1A, Risk Factors, which may cause actual results to differ materially from the forward-looking statements. See also "Forward-Looking Statements" included in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, of this Annual Report on Form 10-K.

PART I

ITEMS 1 and 2.        BUSINESS and PROPERTIES

Company Overview

We are an integrated downstream energy business focused on petroleum refining and the transportation, storage and wholesale distribution of crude oil, intermediate and refined products. Delek US Holdings, Inc. ("Holdings"), a Delaware corporation formed in 2001, is the sole shareholder or owner of membership interests of Delek Refining, Inc. ("Refining"), Delek Finance, Inc., Delek Marketing & Supply, LLC, Lion Oil Company ("Lion Oil"), Delek Renewables, LLC, Delek Rail Logistics, Inc., Delek Logistics Services Company, Delek Helena, LLC, and Delek Land Holdings, LLC. In addition, as of December 31, 2016, we owned a 60.7% limited partner interest in Delek Logistics Partners, LP ("Delek Logistics"), a publicly traded master limited partnership that we formed in April 2012, and a 94.9% interest in Delek Logistics GP, LLC ("Logistics GP"), which owns the entire 2.0% general partner interest in Delek Logistics. Unless otherwise indicated or the context requires otherwise, the terms "we," "our," "us," "Delek" and the "Company" are used in this report to refer to Delek US Holdings, Inc. and its consolidated subsidiaries. Our business consists of two operating segments: refining and logistics.

Our refining segment operates independent refineries in Tyler, Texas (the "Tyler refinery") and El Dorado, Arkansas (the "El Dorado refinery") with a combined design crude throughput capacity of 155,000 bpd. The Tyler refinery sells the majority of its production over a refinery truck rack owned and operated by our logistics segment to supply the local market in the east Texas area. The El Dorado refinery sells a portion of its production at the refinery truck rack, which is owned and operated by our logistics segment, but the majority of the refinery's production is shipped into the Enterprise Pipeline System and our logistics segment's El Dorado Pipeline system to supply a combination of pipeline bulk sales and wholesale rack sales at terminal locations along the pipeline, including Shreveport, Louisiana, North Little Rock, Arkansas, Memphis, Tennessee, and Cape Girardeau, Missouri. Our refining segment also includes two biodiesel facilities we own and operate that are involved in the production of biodiesel fuels and related activities, located in Crossett, Arkansas and Cleburne, Texas.

Our logistics segment gathers, transports and stores crude oil and markets, distributes, transports and stores refined products in select regions of the southeastern United States and west Texas for both our refining segment and third parties. The logistics segment owns or leases capacity on approximately 400 miles of crude oil transportation pipelines, approximately 366 miles of active refined product pipelines, an approximately 600-mile crude oil gathering system and associated crude oil storage tanks with an aggregate of approximately 7.3 million barrels of active shell capacity. Our logistics segment owns and operates nine light product terminals and markets light products using third-party terminals.



3



The following map outlines the geography of our integrated downstream energy structure:


a2015armapadjustedfornoretai.jpg
Corporate Headquarters

We lease our corporate headquarters at 7102 Commerce Way, Brentwood, Tennessee. The lease is for 54,000 square feet of office space. The lease term expires in April 2022.

Liens and Encumbrances

The majority of the assets described in this Form 10-K are pledged under and encumbered by certain of our debt facilities. See Note 11 of the consolidated financial statements included in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K for further information.

Business Strategy

Historically, we have grown through acquisitions in both of our segments. This is exemplified by the acquisitions of the Tyler refinery and El Dorado refinery in 2005 and 2011, respectively. Our business strategy is focused on growing our integrated business model that allows us to participate in all phases of the downstream production process, from transporting crude oil to our refineries for processing into refined products to selling fuel to customers. This growth may come from acquisitions as well as investments in our existing businesses, as we continue to broaden our existing geographic presence and integrated business model. Below is a tabular summary of our acquisitions over the last five years.

4




Date
 
Acquired Company/Assets
 
Acquired From
 
Approximate
Purchase Price(1)
 
 
 
 
 
 
 
January 2012
 
The Nettleton Pipeline, a 35-mile long pipeline system used to transport crude oil from Nettleton, Texas to the Bullard Junction in Tyler, Texas
 
Plains Marketing, L.P.
 
 $12.3 million
 
 
 
 
 
 
 
February 2012
 
The Big Sandy Terminal, a light petroleum products terminal and the Hopewell - Big Sandy Pipeline originating at Hopewell Junction, Texas and terminating at the Big Sandy Station in Big Sandy, Texas
 
Sunoco Pipeline L.P. and Sunoco Partners Marketing & Terminals, L.P.
 
$11.0 million
January 2013
 
The Beacon Facility, a biodiesel facility in Cleburne, Texas, involved in the production of biodiesel fuels and related activities.
 
Beacon Energy (Texas) Corp.
 
$5.3 million
July 2013
 
The Hopewell Pipeline, a 13.5-mile pipeline that originates at the Tyler refinery and terminates at the Hopewell delivery yard.
 
Enterprise TE Products Pipeline Company, LLC
 
$5.7 million
October 2013
 
The North Little Rock terminal, a refined products terminal in Little Rock, Arkansas
 
Enterprise Refined Products Pipeline Company, LLC
 
$7.2 million, including $2.2 million of refined product inventory
December 2013
 
The Helena Assets, a 149-mile pipeline that connects El Dorado, Arkansas to Helena, Arkansas and a crude oil and/or refined products terminal located on the Mississippi River in Helena, Arkansas
 
Enterprise Product Partners L.P.
 
$5.0 million
February 2014
 
The Crossett Facility, a biodiesel plant in Crossett, Arkansas
 
Pinnacle Biofuels, Inc.
 
$11.1 million
October 2014
 
The Greenville-Mount Pleasant Assets, a light products terminal in Mount Pleasant, Texas, a light products storage facility in Greenville, Texas and a 76-mile pipeline connecting the locations.
 
An affiliate of Magellan Midstream Partners, L.P.
 
$11.1 million, including $1.1 million of product inventory
December 2014
 
FTT, a transport company that primarily hauls crude oil and asphalt by truck, including 130 trucks and 210 trailers.
 
Frank Thompson Transport, Inc.
 
$12.0 million, including $0.5 million working capital
May 2015
 
33.7 million shares of common stock of Alon USA, representing approximately 48% of the outstanding common stock of Alon USA at the time of investment.
 
Alon Israel Oil Company, Ltd.
 
$575.8 million, including cash, Delek stock, a promissory note and contingent consideration
(1) 
Excludes transaction costs

2016 Strategic Developments
Retail Divestiture
In August 2016, we entered into a definitive equity purchase agreement (the "Purchase Agreement") with Compañía de Petróleos de Chile COPEC S.A. and its subsidiary, Copec Inc., a Delaware corporation (collectively, "COPEC"). Under the terms of the Purchase Agreement, Delek agreed to sell, and COPEC agreed to purchase, 100% of the equity interests in Delek's wholly-owned subsidiaries MAPCO Express, Inc. ("MAPCO Express"), MAPCO Fleet, Inc., Delek Transportation, LLC, NTI Investments, LLC and GDK Bearpaw, LLC (collectively, the “Retail Entities”) for cash consideration of $535 million, subject to customary adjustments (the “ Retail Transaction”).
In November 2016, the Retail Transaction closed, and, at closing, $156.0 million of debt associated with the Retail Entities was repaid, along with a debt prepayment fee of $13.4 million and $4.6 million of transaction related costs. Net cash proceeds before taxes related to the Retail Transaction were $378.9 million.
As a result of the Purchase Agreement, we met the requirements under the provisions of Accounting Standards Codification ("ASC") 205-20, Presentation of Financial Statements - Discontinued Operations and ASC 360, Property, Plant and Equipment ("ASC 360"), to report the results of the Retail Entities as discontinued operations and to classify the Retail Entities as a group of assets held for sale. See Note 5, Discontinued Operations and Assets Held for Sale, of our consolidated financial statements included in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K for further information.

5



Alon Merger
In January 2017, we announced that Delek, Alon USA Energy, Inc. (NYSE: ALJ) ("Alon USA"), Delek Holdco, Inc., a Delaware corporation and wholly owned subsidiary of Delek (“Holdco”), Dione Mergeco, Inc., a Delaware corporation and wholly owned subsidiary of Holdco ("Parent Merger Sub"), and Astro Mergeco, Inc., a Delaware corporation and wholly owned subsidiary of Holdco (“Astro Merger Sub” and, together with Holdco and Parent Merger Sub, the “Holdco Parties”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which (i) Parent Merger Sub will, upon the terms and subject to the conditions thereof, merge with and into Delek (the “Parent Merger”), with Delek surviving as a wholly owned subsidiary of Holdco and (ii) Astro Merger Sub will, upon the terms and subject to the conditions thereof, merge with and into Alon USA (the “Alon Merger” and, together with the Parent Merger, the “Mergers”) with Alon USA surviving as a wholly owned subsidiary of Holdco. 
In the Parent Merger, each issued and outstanding share of common stock of Delek, par value $0.01 per share (“Delek common stock”), or fraction thereof, will be converted into the right to receive one validly issued, fully paid and non-assessable share of Holdco common stock, par value $0.01 per share (“Holdco common stock”), or such fraction thereof equal to the fractional share of Delek common stock, upon the terms and subject to the conditions set forth in the Merger Agreement. In the Alon Merger, each issued and outstanding share of common stock of Alon, par value $0.01 per share (“Alon common stock”), other than Alon USA common stock held by Delek or any subsidiary of Delek, will be converted into the right to receive 0.504 shares of Holdco common stock, upon the terms and subject to the conditions set forth in the Merger Agreement. 
Pursuant to the Merger Agreement, Delek must take all action necessary to elect as directors of Holdco the directors of Delek immediately prior to the effective time of the Parent Merger; provided, that within thirty days after the closing date, Delek and Holdco must take all action necessary to increase the size of the board of directors of Holdco by one seat and to appoint an individual to fill the resulting vacancy as designated by the special committee of the board of directors of Alon USA.  Additionally, pursuant to the Merger Agreement, the special committee of the board of Alon USA will nominate one new director that will be appointed to the board of the general partner of Delek Logistics.
The mergers remain subject to the approval of the stockholders of Delek and Alon USA, along with certain other closing conditions as set forth in the Merger Agreement. Concurrently with the execution of the Merger Agreement, Alon, Delek and each of David Wiessman, D.B.W. Holdings (2005) Ltd. (an entity controlled by David Wiessman), Jeff Morris, and Karen Morris entered into Voting, Irrevocable Proxy and Support Agreements (the “Voting Agreements”) in connection with the Merger Agreement. Delek, David Wiessman, D.B.W. Holdings (2005) Ltd., Jeff Morris and Karen Morris are each individually referred to herein as an “Alon Stockholder” and collectively as the “Alon Stockholders.”
The Voting Agreements generally require that the Alon Stockholders vote or cause to be voted all Alon USA common stock owned by the Alon Stockholders at the Alon USA stockholders’ meeting in favor of (1) the Mergers and the Merger Agreement and any other transactions or matters contemplated by the Merger Agreement and (2) any proposal to adjourn or postpone the Alon USA Stockholders Meeting to a later date if there are not sufficient votes to adopt the Merger Agreement or if there are not sufficient shares present in person or by proxy at such meeting to constitute a quorum. In the case of the Alon Stockholders other than Delek, the Voting Agreements also require that they vote in favor of any other matter necessary to consummate the transactions contemplated by the Merger Agreement, in each case at every meeting (or in connection with any action by written consent) of the Alon Stockholders at which such matters are considered and at every adjournment or postponement thereof, and vote against (1) any Company Acquisition Proposal (as defined in the Merger Agreement), (2) any action, proposal, transaction or agreement that could reasonably be expected to result in a breach of any covenant, representation or warranty or any other obligation or agreement of Alon USA under the Merger Agreement or of the Alon Stockholders under the Voting Agreements and (3) any action, proposal, transaction or agreement that could reasonably be expected to impede, interfere with, frustrate, delay, discourage, adversely affect or inhibit the timely consummation of the Merger or the fulfillment of conditions under the Merger Agreement or change in any manner the voting rights of any class of shares of Alon USA.
Subject to certain exceptions, the Voting Agreements prohibit certain sales, transfers, offers, exchanges, and dispositions of Alon USA common stock owned by the Alon Stockholders, the granting of any proxies or powers of attorney that is inconsistent with the Voting Agreements, and the depositing of Alon USA common stock owned by the Alon Stockholders into a voting trust or entering into a voting agreement or arrangement with respect to the voting of shares of Alon USA common stock owned by the Alon Stockholders during the term of the Voting Agreements.
Alon USA is an independent refiner and marketer of petroleum products, operating primarily in the south central, southwestern and western regions of the United States. Alon USA owns 100% of the general partner and 81.6% of the limited partner interests in Alon USA Partners, LP (NYSE: ALDW), which owns a crude oil refinery in Big Spring, Texas with a crude oil throughput capacity of 73,000 bpd and an integrated wholesale marketing business. In addition, Alon USA directly owns a crude oil refinery in Krotz Springs, Louisiana with a crude oil throughput capacity of 74,000 bpd. Alon USA also owns crude oil refineries in California, which have not processed crude oil since 2012. Alon USA is a marketer of asphalt, which it distributes primarily through asphalt terminals located predominantly in the southwestern and western United States. Alon USA is the largest 7-Eleven licensee in the United States and operates approximately 300 convenience stores which market motor fuels in central and west Texas and New Mexico. Our current investment in Alon USA is accounted for as an equity method investment and the earnings from this equity method investment reflected in our consolidated statements of income include our share of net earnings directly attributable to this equity method investment and amortization of the excess of our investment balance over the underlying net assets of Alon USA.


6



Information About Our Segments
Prior to August 2016, we aggregated our operating units into three reportable segments: refining, logistics and retail. However, in August 2016, Delek entered into the Purchase Agreement pursuant to which it agreed to sell the Retail Entities, which consisted of all of the retail segment and a portion of the corporate, other and eliminations segment, to COPEC and in November 2016, the Retail Transaction closed. As a result of the Purchase Agreement, we met the requirements of ASC 205-20 and ASC 360 to report the results of the Retail Entities as discontinued operations and to classify the Retail Entities as a group of assets held for sale. The operating results for the Retail Entities, in all periods presented, have been reclassified to discontinued operations.
Additional segment and financial information is contained in our segment results included in Item 6, Selected Financial Data, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, and in Note 14, Segment Data, of our consolidated financial statements included in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.

Refining Segment

Overview

We own and operate two independent refineries located in Tyler, Texas and El Dorado, Arkansas, currently representing a combined 155,000 bpd of crude throughput capacity. Our refining system produces a variety of petroleum-based products used in transportation and industrial markets, which are sold to a wide range of customers located principally in inland, domestic markets.

Both of our refineries are located in the U.S. Gulf Coast Region (PADD 3), which is one of the five PADD regional zones established by the U.S. Department of Energy where refined products are produced and sold. Refined product prices generally differ among each of the five PADDs.

Our refining segment also includes two biodiesel facilities we own and operate that are engaged in the production of biodiesel fuels and related activities, located in Crossett, Arkansas and Cleburne, Texas.

Refining System Feedstock Purchases
Our refining system purchases crude oil and other feedstocks through short term agreements, some of which may include renewal provisions, and through spot market transactions. The majority of the crude oil we purchase is sourced from inland domestic sources, primarily originating in areas of Texas and Arkansas. We also have the ability to purchase crude delivered by rail car that originates primarily in other parts of the United States and Canada. A large portion of the crude oil currently purchased at both the Tyler and El Dorado refineries is priced at a differential to the price per barrel of WTI. In most cases, this differential is established during the month prior to the month in which the crude oil is processed at our refineries.

Refining System Production Slate
Our refining system processes a combination of light sweet and medium sour crude oils, which, when refined, results in a product mix consisting principally of higher-value transportation fuels such as gasoline, distillate and jet fuel. A lesser portion of our overall production consists of residual products, including paving asphalt, roofing flux and other products with industrial applications.

Refined Product Sales and Distribution

Our refining segment sells products on a wholesale basis to inter-company and third-party customers located around east Texas, Arkansas, Tennessee and the Ohio River Valley, including gulf coast markets and areas along the Enterprise Pipeline System and along the Colonial Pipeline System, through exchanges.

Refining Segment Seasonality

Demand for gasoline and asphalt products is generally higher during the summer months than during the winter months due to seasonal increases in motor vehicle traffic and road and home construction. Varying vapor pressure requirements between the summer and winter months also tighten summer gasoline supply. As a result, the operating results of our refining segment are generally lower for the first and fourth quarters of the calendar year.


7



Refining Segment Competition

The refining industry is highly competitive and includes fully integrated national and multinational oil companies engaged in many segments of the petroleum business, including exploration, production, transportation, refining, marketing and retail fuel and convenience stores. Our principal competitors are petroleum refiners in the Mid-Continent and Gulf Coast regions, in addition to wholesale distributors operating in these markets.

The principal competitive factors affecting our refinery operations are crude oil and other feedstock costs, the differential in price between various grades of crude oil, refinery product margins, refinery reliability and efficiency, refinery product mix, and distribution and transportation costs.

Refining Segment - Tyler Refinery

Our Tyler refinery has a nameplate crude throughput capacity of 75,000 bpd. The refinery is situated on approximately 100, out of a total of approximately 600, contiguous acres of land (excluding pipelines) that we own in Tyler, Texas and adjacent areas.

The Tyler refinery is currently the only major distributor of a full range of refined petroleum products within a radius of approximately 100 miles of its location. The Tyler refinery is designed to process mainly light, sweet crude oil, which is typically of a higher quality than heavier sour crudes. The Tyler refinery has access to crude oil pipeline systems that allow us access to East Texas, West Texas and limited Gulf of Mexico and foreign crude oils. Most of the crude supplied to the Tyler refinery is delivered by third-party pipelines and through pipelines owned by our logistics segment.

The charts below set forth information concerning crude oil received at the Tyler refinery for the years ended December 31, 2016 and 2015:

dk-10kx1231_chartx02483.jpgdk-10kx1231_chartx03367.jpg


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The table below sets forth information concerning the Tyler refinery's units and capacities:

Unit
 
Capacity (bpd)
Crude processing unit - atmospheric column
 
75,000

Crude processing unit - vacuum tower
 
24,000

Distillate hydrotreating unit
 
36,000

Naphtha hydrotreating unit
 
28,000

Fluid catalytic cracking unit
 
20,200

Continuous catalyst regeneration reforming unit
 
17,500

Gasoline hydrotreating unit
 
13,500

Delayed coking unit
 
7,500

Sulfuric alkylation unit (alkylate production capacity)
 
4,720


The Tyler refinery has a Complexity Index of 8.7. The fluid catalytic cracking unit and delayed coker enabled us to produce approximately 97.8% light products in 2016, including primarily a full range of gasoline, diesel, jet fuels, liquefied petroleum gas and natural gas liquids.

The chart below sets forth information concerning the throughput at the Tyler refinery:

dk-10kx1231_chartx04544.jpg
            
* In the first quarter of 2015, we completed a scheduled turnaround and an expansion project at the Tyler refinery. Total throughputs for the period from April 1, 2015 through December 31, 2015 were 75,058 bpd.

The Tyler refinery primarily produces two grades of gasoline (E10 premium - 93 octane and E10 regular - 87 octane), as well as aviation gasoline. Diesel and jet fuel products produced at the Tyler refinery include military specification jet fuel, commercial jet fuel and ultra-low sulfur diesel. The Tyler refinery offers both E-10 and biodiesel blended products. In addition to higher-value gasoline and distillate fuels, the Tyler refinery produces small quantities of propane, refinery grade propylene and butanes, petroleum coke, slurry oil, sulfur and other blendstocks.


9



The chart below sets forth information concerning the Tyler refinery's production slate:
dk-10kx1231_chartx06378.jpg

The vast majority of our transportation fuels and other products produced at the Tyler refinery are sold directly from a refined products terminal owned by Delek Logistics and located at the refinery. We believe this allows our customers to benefit from lower transportation costs compared to alternative sources. Our customers include major oil companies, independent refiners and marketers, jobbers, distributors, utility and transportation companies, the U.S. government and independent retail fuel operators.

Taking into account the Tyler refinery's crude and refined product slate, as well as the refinery's location near the Gulf Coast region, we apply the U.S. Gulf Coast 5-3-2 crack spread ("Gulf Coast crack spread") to calculate the approximate gross margin resulting from processing one barrel of crude oil into three-fifths of a barrel of gasoline and two-fifths of a barrel of high sulfur diesel. We calculate the Gulf Coast crack spread using the market values of U.S. Gulf Coast Pipeline CBOB and U.S. Gulf Coast Pipeline No. 2 Heating Oil (high-sulfur diesel) and the market value of WTI crude oil. U.S. Gulf Coast Pipeline CBOB and U.S. Gulf Coast Pipeline No. 2 Heating Oil are prices for which the products trade in the Gulf Coast region.

Refining Segment - El Dorado Refinery
Our El Dorado refinery has a crude throughput capacity of 80,000 bpd. The El Dorado site consists of approximately 460 acres, of which the main plant and associated tank farms adjacent to the refinery sit on approximately 335 acres. The El Dorado refinery is the largest refinery in Arkansas, and represents more than 90% of state-wide refining capacity.

The El Dorado refinery is designed mainly to process a wide variety of crude oil, ranging from light sweet to heavy sour. The refinery receives crude by several delivery points, including local crude and other third-party pipelines that connect directly into Delek Logistics' El Dorado Pipeline System, which runs from Magnolia, Arkansas, to the El Dorado refinery (the "El Dorado Pipeline System"), and rail at third-party terminals.


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In 2016, we purchased crude oil for the El Dorado refinery from inland sources in east and west Texas, south Arkansas and north Louisiana through a crude oil gathering system owned and operated by Delek Logistics (the "SALA Gathering System"), via rail and from the Gulf Coast. At present, J. Aron and Company ("J. Aron"), through arrangements with various oil companies, supplies a substantial portion of the El Dorado refinery's crude oil input requirements pursuant to an amended and restated Master Supply and Offtake Agreement (the "S&O Agreement").

The charts below set forth information concerning crude oil received at the El Dorado refinery for the years ended December 31, 2016 and 2015:

dk-10kx1231_chartx10407.jpgdk-10kx1231_chartx11287.jpg

The table below sets forth information concerning the El Dorado refinery's units and capacities:

Unit
 
Capacity
 (bpd, except as noted)
Crude processing unit - atmospheric column
 
80,000

Crude processing unit - vacuum tower
 
55,000

Distillate hydrotreating unit
 
35,000

Fluid catalytic cracking unit
 
20,140

Naphtha hydrotreating unit
 
17,900

LSR naphtha hydrotreating unit
 
7,750

Gas oil hydrotreating unit
 
20,900

Hydrogen steam methane reforming unit (in MScf/d)
 
10,000

Gasoline hydrotreating unit
 
8,500

Continuous catalyst regeneration reforming unit
 
15,300

Isomerization unit
 
7,500

Sulfuric alkylation unit (alkylate production capacity)
 
5,000


The actual average annual crude unit throughput will vary based on economics and market requirements, as well as other physical limitations that affect the daily throughput or the utilization rate of the refinery. Due to constraints in downstream conversion, the operable capacity of the El Dorado refinery is estimated at approximately 80,000 bpd. The El Dorado refinery has a Complexity Index of 10.2.


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The chart below sets forth information concerning the throughput at the El Dorado refinery:
dk-10kx1231_chartx12267.jpg
            
* In the first quarter of 2014, we completed a scheduled turnaround and certain other discretionary capital projects at the El Dorado refinery. Total throughputs for the period from April 1, 2014 through December 31, 2014 were 82,151 bpd.

The El Dorado refinery produces a wide range of refined products, from multiple grades of gasoline and ultra-low sulfur diesel fuels, LPGs, refinery grade propylene and a variety of asphalt products, including paving grade asphalt and roofing flux. The El Dorado refinery produces both low-sulfur gasoline and ultra-low sulfur diesel fuel, in compliance with current clean fuels standards. The El Dorado refinery offers both E-10 and biodiesel blended products.

In 2016, gasoline, diesel, liquefied petroleum gas and natural gas liquids accounted for approximately 91.7% of the El Dorado refinery's production, while 8.3% of the product slate included various grades of asphalt, black oils and other residual products.


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The chart below sets forth information concerning the El Dorado refinery's production slate:

dk-10kx1231_chartx14508.jpg

Products manufactured at the El Dorado refinery are sold to wholesalers and retailers through spot sales, commercial contracts and exchange agreements in markets in Arkansas, Memphis, Tennessee and north into the Ohio River Valley region. The El Dorado refinery connection via the logistics segment to the Enterprise Pipeline System is a key means of product distribution for the refinery, because it provides access to third-party terminals in multiple Mid-Continent markets located adjacent to the system. The El Dorado refinery also supplies products to these markets through product exchanges on the Colonial pipeline system.

Logistics Segment

Overview

Our logistics segment consists of Delek Logistics, a publicly traded master limited partnership, and its subsidiaries. Our consolidated financial statements include its consolidated financial results. As of December 31, 2016, we owned a 60.7% limited partner interest in Delek Logistics, and a 94.9% interest in Logistics GP, which owns both the entire 2.0% general partner interest in Delek Logistics and all of the incentive distribution rights.

Our logistics segment generates revenue and contribution margin, which we define as net sales less cost of goods sold and operating expenses, by charging fees for gathering, transporting and storing crude oil and intermediate product and for marketing, distributing, transporting and storing refined products. A substantial majority of the logistics segment's existing assets are both integral to and dependent upon the successful operation of our refining segment's assets, as the logistics segment gathers, transports and stores crude oil and markets, distributes, transports

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and stores refined products in select regions of the southeastern United States and east Texas in support of the Tyler and El Dorado refineries. In addition to intercompany services, the logistics segment also provides some crude oil and refined product transportation services for, and terminalling and wholesale marketing services to, third parties in Texas, Tennessee and Arkansas.

The logistics segment owns nine light product distribution terminals, one in each of Nashville and Memphis, Tennessee; Tyler, Big Sandy, San Angelo, Abilene and Mount Pleasant, Texas; and North Little Rock and El Dorado, Arkansas. All of the above properties are located on real property owned by Delek and its subsidiaries. The logistics segment also owns the El Dorado Pipeline System, the Magnolia Pipeline System and 600 miles of crude oil gathering lines, which are located in Louisiana and Arkansas. The logistics segment owns the McMurrey Pipeline System, the Nettleton Pipeline, the Tyler-Big Sandy Pipeline, the Paline Pipeline System and the Greenville-Mount Pleasant Pipeline, which are located in Texas. All of the pipeline systems set forth above run across fee owned land, leased land, easements and rights-of-way. The logistics segment also owns storage tanks in El Dorado and North Little Rock, Arkansas; Memphis and Nashville, Tennessee; and Tyler, Greenville, Big Sandy, San Angelo, Abilene and Mount Pleasant, Texas and a fleet of trucks and trailers used to transport crude oil, asphalt and other hydrocarbon products.

The following provides an overview of our logistics segment assets and operations:

dklregionalmap5112015a03.jpg

Logistics Segment - Wholesale Marketing and Terminalling

The logistics segment's wholesale marketing and terminalling business provides wholesale marketing and terminalling services to the refining segment and to independent third parties from whom it receives fees for marketing, transporting, storing and terminalling refined products. It generates revenue by (i) providing marketing services for the refined products output of the Tyler refinery, (ii) engaging in wholesale activity at owned terminals in Abilene and San Angelo, Texas, as well as at terminals owned by third parties in Texas, whereby it purchases light products for sale and exchange to third parties, and (iii) providing terminalling services to independent third parties and the refining segment. Three terminals, located in El Dorado, Arkansas, Memphis, Tennessee and North Little Rock, Arkansas, throughput refined product produced at the El Dorado refinery. Three terminals, located in Tyler, Big Sandy and Mount Pleasant Texas, throughput refined product produced at the Tyler refinery.

Logistics Segment - Pipelines and Transportation
The logistics segment's pipelines and transportation business owns or leases capacity on approximately 401 miles of crude oil transportation pipelines, approximately 366 miles of refined product pipelines, an approximately 600-mile crude oil gathering system and associated crude oil

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storage tanks with an aggregate of approximately 7.3 million barrels of active shell capacity. These assets are primarily divided into the following operating systems:
the Lion Pipeline System, which transports crude oil to, and refined products from, the El Dorado refinery (the "Lion Pipeline System");
the SALA Gathering System, which gathers and transports crude oil production in southern Arkansas and northern Louisiana, primarily for the El Dorado refinery;
the Paline Pipeline System, which primarily transports crude oil from Longview, Texas to third-party facilities in Nederland, Texas;
the East Texas Crude Logistics System, which currently transports a portion of the crude oil delivered to the Tyler refinery (the "East Texas Crude Logistics System");
the Tyler-Big Sandy Pipeline, which is a pipeline link between the Tyler refinery and the Big Sandy Terminal;
the Tyler Tank Assets;
the El Dorado Tank Assets; and
the Greenville-Mount Pleasant Pipeline and Greenville Storage Facility.

In addition to these operating systems, the logistics segment owns approximately 123 trucks and 205 trailers used to haul primarily crude oil and other hydrocarbon products for us and for third parties.
Joint Ventures

The logistics segment owns a portion of two joint ventures that have constructed logistics assets, which serve third parties and the refining segment. These assets include the following:

a 50% interest in an 80-mile crude oil pipeline with a capacity of 80,000 bpd that originates in Longview, Texas, with destinations in the Shreveport, Louisiana area (the "Caddo Pipeline") and;
a 33% interest in a 107-mile crude oil pipeline with an initial capacity of 55,000 bpd, with the capability to expand to 85,000 bpd, that originates in north Loving County, Texas near the Texas-New Mexico border and terminates in Midland, Texas ("the RIO Pipeline").
The RIO Pipeline project has been completed and began operations in September 2016. The Caddo Pipeline has been substantially completed and operations began in January 2017.

Logistics Segment Supply Agreement
Approximately 59.7% of the petroleum products for sale by the logistics segment in west Texas are purchased from Noble Petro, Inc. ("Noble Petro"). Under the terms of a supply contract (the "Abilene Contract") with Noble Petro, we have the right to purchase up to 20,350 bpd of petroleum products. Under the Abilene Contract, we purchase petroleum products based on monthly average prices from Noble Petro immediately prior to our resale of such products to customers at our San Angelo and Abilene, Texas terminals, which we lease to Noble Petro. Under this arrangement, we have limited direct exposure to risks associated with fluctuating prices for these refined products due to the short period of time between the purchase and resale of these refined products. The Abilene Contract expires in December 2017 and does not have a renewal option. We also purchase finished products from the refining segment and from other third parties.

Logistics Segment Operating Agreements With Delek

Delek Logistics has various long-term, fee-based commercial agreements with Delek and its subsidiaries that, among other things, establish fees for certain administrative and operational services provided by Delek and its subsidiaries to Delek Logistics, provide certain indemnification obligations and establish terms for fee-based commercial agreements for Delek Logistics to provide certain pipeline transportation, terminal throughput, finished product marketing and storage services to Delek. These agreements have various initial terms which expire, depending on the specific contracts, at different times from 2017 through 2022. Delek has opted to renew the agreements expiring in November 2017 for subsequent five-year terms. Each of these agreements requires Delek or a Delek subsidiary to pay for certain minimum volume commitments or certain minimum storage capacities. Delek Logistics is a variable interest entity as defined under United States generally accepted accounting principles ("GAAP") and is consolidated into our consolidated financial statements. Intercompany transactions with Delek Logistics and its subsidiaries are eliminated in our consolidated financial statements.

Logistics Segment Customers

In addition to certain of our subsidiaries, our logistics segment has various types of customers, including major oil companies, independent refiners and marketers, jobbers, distributors, utility and transportation companies and independent retail fuel operators.


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Logistics Segment Seasonality

The volume and throughput of crude oil and refined products transported through our pipelines and sold through our terminals and to third parties is directly affected by the level of supply and demand for all of such products in the markets served directly or indirectly by our assets. Supply and demand for such products fluctuates during the calendar year. Demand for gasoline, for example, is generally higher during the summer months than during the winter months due to seasonal increases in motor vehicle traffic. Varying vapor pressure requirements between the summer and winter months also tighten summer gasoline supply. In addition, our refining segment often performs planned maintenance during the winter, when demand for their products is lower. Accordingly, these factors can diminish the demand for crude oil or finished products by our customers, and therefore limit our volumes or throughput during these periods, and we expect that our operating results will generally be lower during the first and fourth quarters of the calendar year.

Logistics Segment Competition

Our logistics segment faces competition for the transportation of crude oil from other pipeline owners whose pipelines (i) may have a location advantage over our pipelines, (ii) may be able to transport more desirable crude oil to third parties, or (iii) may be able to transport crude oil or finished product at a lower tariff. In addition, the wholesale marketing and terminalling business in general is also very competitive. Our owned refined product terminals, as well as the other third-party terminals we use to sell refined products, compete with other independent terminal operators as well as integrated oil companies on the basis of terminal location, price, versatility and services provided. The costs associated with transporting products from a loading terminal to end users limit the geographic size of the market that can be competitively served by any terminal. Two key markets in west Texas that we serve from our company-owned facilities are Abilene and San Angelo, Texas. We have direct competition from an independent refinery that markets through another terminal in the Abilene market. There are no competitive fuel loading terminals within approximately 90 miles of our San Angelo terminal.

Logistics Segment Activity

The following table summarizes our activity in the wholesale marketing and terminalling portion of our logistics segment:

 
 
Year Ended December 31,
 
 
2016

2015

2014
Operating Information:
 
 
 
 
 
 
West Texas marketing throughputs (average bpd)
 
13,257

 
16,357

 
16,707

Terminalling throughputs (average bpd) (1)
 
122,350

 
106,514

 
96,801

East Texas marketing throughputs (average bpd)
 
68,131

 
59,174

 
61,368

            
(1) 
Consists of terminalling throughputs at our Tyler, Big Sandy and Mount Pleasant, Texas, El Dorado and North Little Rock, Arkansas and Memphis and Nashville, Tennessee terminals. Throughputs at the El Dorado, Arkansas terminal for the year ended December 31, 2014 are for the 324 days from February 10, 2014 through December 31, 2014. Throughputs for the Mount Pleasant, Texas terminal for the year ended December 31, 2014 are for the 92 days from October 1, 2014 through December 31, 2014. Barrels per day are calculated for only the days we operated each terminal.

The following table summarizes our activity in the pipelines and transportation portion of our logistics segment:
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
Throughputs (average bpd)
 
 
 
 
 
 
 Lion Pipeline System:
 
 
 
 
 
 
          Crude pipelines (non-gathered)
 
56,555

 
54,960

 
47,906

          Refined products pipelines to Enterprise Systems
 
52,071

 
57,366

 
53,461

SALA Gathering System
 
17,756

 
20,673
 
22,656

East Texas Crude Logistics System
 
12,735

 
18,828

 
7,361



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Information Technology

We believe that investments in information technology ("IT") are strategic to the success of our various business units. In 2016, we continued our efforts to improve several areas of IT, including infrastructure, security and enterprise software systems. Capital investments in infrastructure involved the continued migration of on-premise data center hardware to multiple off-site data center locations to improve the reliability and availability of IT services to our corporate and refinery locations. In addition, we migrated our Enterprise Resource Planning architecture to the cloud and deployed the SAP HANA database, which allowed us to take advantage of available real-time reporting and analytics features. A new HR information system was also implemented, taking advantage of cloud technology and providing an improved, self-service approach to managing human capital utilized by management and employees alike. Also, additional security technologies and enhancements were deployed to harden our existing infrastructure in the corporate environment, as well as the control systems at our refineries. The energy sector continues to be the target of cyber attack perpetrators, and we believe the steps we have taken, and continue to take, will help us maintain adequate data security in an environment of increasing risk of cyber attacks, hacks and other threats.

Governmental Regulation and Environmental Matters
Rate Regulation of Petroleum Pipelines

The rates and terms and conditions of service on certain of our pipelines are subject to regulation by the FERC, under the Interstate Commerce Act (“ICA”), and by the state regulatory commissions in the states in which we transport crude oil, intermediate and refined products, including the Railroad Commission of Texas, the Louisiana Public Service Commission and the Arkansas Public Service Commission. Certain of our pipeline systems are subject to such regulation and have filed tariffs with the appropriate authorities. We also comply with the reporting requirements for these pipelines. Other of our pipelines have received a waiver from application of the FERC's tariff requirements, but comply with other applicable regulatory requirements.

The FERC regulates interstate transportation under the ICA, the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. The ICA, and its implementing regulations, require that tariff rates for interstate service on oil pipelines, including pipelines that transport crude oil, intermediate and refined products in interstate commerce (collectively referred to as “petroleum pipelines”), be just and reasonable and non-discriminatory, and that such rates and terms and conditions of service be filed with the FERC. Under the ICA, shippers may challenge new or existing rates or services. The FERC is authorized to suspend the effectiveness of a challenged rate for up to seven months, though rates are typically not suspended for the maximum allowable period. Our tariff rates are typically contractually subject to increase or decrease on July 1 of each year, by the amount of any change in various inflation-based indices, including the FERC oil pipeline index, the consumer price index and the producer price index; provided, however, that in no event will the fees be adjusted below the amount initially set forth in the applicable agreement.
While FERC regulates rates for shipments of crude oil or refined products in interstate commerce, state agencies may regulate rates and services for shipments in intrastate commerce. We own pipeline assets in Texas, Arkansas, and Louisiana; accordingly, such assets may be subject to additional regulation by the applicable governmental authorities in those states.
Environmental Health and Safety
We are subject to extensive federal, state and local environmental and safety laws and regulations enforced by various agencies, including the EPA, the United States Department of Transportation, the Occupational Safety and Health Administration, the Texas Commission on Environmental Quality, the Railroad Commission of Texas, the Arkansas Department of Environmental Quality (the "ADEQ"), the Tennessee Department of Environment and Conservation and the Louisiana Department of Natural Resources, as well as other state and federal agencies. These laws and regulations govern the discharge of materials into the environment, waste management practices, pollution prevention measures and the composition of the fuels we produce, as well as the safe operation of our plants and pipelines and the safety of our workers and the public. Numerous permits or other authorizations are required under these laws and regulations for the operation of our refineries, biodiesel facilities, terminals, pipelines, trucks, rail cars and related operations, and may be subject to revocation, modification and renewal.
These laws and permits raise potential exposure to future claims and lawsuits involving environmental and safety matters, which could include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of, transported, or that relate to pre-existing conditions for which we have assumed responsibility. We believe that our current operations are in substantial compliance with existing environmental and safety requirements. However, there have been and will continue to be ongoing discussions about environmental and safety matters between us and federal and state authorities, including notices of violations, citations and other enforcement actions, some of which have resulted, or may result in, changes to operating procedures and in capital expenditures. While it is often difficult to quantify future environmental or safety related expenditures, we anticipate that continuing capital investments and changes in operating procedures will be required for the foreseeable future to comply with existing and new requirements, as well as evolving interpretations and more strict enforcement of existing laws and regulations. We anticipate that compliance with environmental, health and safety regulations will require us to spend approximately $17.6 million in capital costs in 2017 and approximately $57.7 million during the next five years.

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These estimates do not include amounts related to capital investments that management has deemed to be strategic investments. These amounts could materially change as a result of governmental and regulatory actions.
We generate wastes that may be subject to the RCRA and comparable state and local requirements. The EPA and various state agencies have limited the approved methods of managing, transporting, recycling and disposal of hazardous and certain non-hazardous wastes. Our refineries are large quantity generators of hazardous waste and require hazardous waste permits issued by EPA or state agencies. Other of our facilities, such as terminals and biodiesel plants, generate lesser quantities of hazardous wastes.
The Comprehensive Environmental Response, Compensation and Liability Act, also known as Superfund, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Analogous state laws impose similar responsibilities and liabilities on responsible parties. In the course of our ordinary operations, our various businesses generate waste, some of which falls within the statutory definition of a hazardous substance and some of which may have been disposed of at sites that may require future cleanup under Superfund. At this time, our El Dorado refinery has been named as a minor potentially responsible party at one site, for which we believe future costs will not be material.
As of December 31, 2016, we have recorded an environmental liability of approximately $7.2 million, primarily related to the estimated probable costs of remediating, or otherwise addressing, certain environmental issues of a non-capital nature at the Tyler and El Dorado refineries. This liability includes estimated costs for ongoing investigation and remediation efforts, which were already being performed by the former operators of the Tyler and El Dorado refineries prior to our acquisition of those facilities, for known contamination of soil and groundwater, as well as estimated costs for additional issues which have been identified subsequent to the acquisitions. We expect approximately $0.4 million of this amount to be reimbursable by a prior owner of the El Dorado refinery, which we have recorded in other current assets in our consolidated balance sheet as of December 31, 2016. Approximately $1.0 million of the total liability is expected to be expended over the next 12 months, with most of the balance expended by 2022. In the future, we could be required to extend the expected remediation period or undertake additional investigations of our refineries, pipelines and terminal facilities, which could result in additional remediation liabilities.
The EPA issued final rules for gasoline formulation that required the reduction of average benzene content by January 1, 2011 and the reduction of maximum annual average benzene content by July 1, 2012. It is necessary for us to purchase credits to fully comply with these content requirements for the Tyler refinery. Although credits have been acquired that should be sufficient to cover our obligations through 2019, there can be no assurance that such credits will be available in the future or that we will be able to purchase available credits at reasonable prices. Additional benzene reduction projects may be implemented to reduce or eliminate our need to purchase benzene credits, depending on the availability and cost of such credits. Future capital projects at the Tyler refinery may also impact our need to purchase benzene credits.
In recent years, various legislative and regulatory measures to address climate change and greenhouse gas ("GHG") emissions (including carbon dioxide, methane and nitrous oxides) have been discussed or implemented. They include proposed and enacted federal regulation and state actions to develop statewide, regional or nationwide programs designed to control and reduce GHG emissions from fixed sources, such as our refineries, power plants and oil and gas production operations, as well as mobile transportation sources and fuels. We are not aware of any state or regional initiatives for controlling existing GHG emissions that would affect our refineries. Although it is not possible to predict the requirements of any GHG legislation that may be enacted, any laws or regulations that may be adopted to restrict or reduce GHG emissions will likely require us to incur increased operating and capital costs and result in decreased demand for our petroleum fuels. In August 2015, the EPA finalized the “Clean Power Plan” requiring states to reduce carbon dioxide emissions from coal fired power plants through a combination of plant closures, switching to renewable energy and natural gas and demand reduction. The Clean Power Plan is currently being litigated in various courts, and the U.S. Supreme Court has stayed implementation pending the outcome of those legal challenges. If upheld, this rule will not directly affect our operations. The EPA has indicated that it intends to regulate refinery GHG emissions from new and existing sources through a New Source Performance Standard ("NSPS"), although there is no firm proposal or date for such regulation, and the EPA has said that such a performance standard is not imminent.
Our operations are subject to certain requirements of the Federal Clean Air Act (“CAA”), as well as related state and local laws and regulations governing air emission. Certain CAA regulatory programs applicable to our refineries, terminals and other operations require capital expenditures for the installation of air pollution control devices, operational procedures to minimize emissions and monitoring and reporting of emissions. In mid-2012, the EPA announced an industry-wide enforcement initiative directed at flaring operations and performance at refineries and petrochemical plants. In September 2012, the EPA finalized revisions to the NSPS for Petroleum Refineries ("NSPS Subpart Ja") that primarily affects flares and process heaters. The NSPS impacted the way some flares at our Tyler and El Dorado refineries are designed and/or operated, and capital projects were completed at our Tyler refinery in 2015 related to meeting this NSPS. We believe our flares and process heaters meet the applicable requirements, and our refineries have not received any associated inquiries or requests for information, nor are they a party to any associated enforcement action at this time.
In 2015, EPA finalized reductions in the National Ambient Air Quality Standard (NAAQS) for ozone, from 75 ppb to 70 ppb. Our Tyler refinery is located in an area reclassified as non-attainment with the new standard. While we do not yet know what specific actions we will be required to take or when, it is possible we will have to install additional air pollution control equipment for ozone forming emissions or change the formulation

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of gasoline we make for use in some areas. We do not believe such capital expenditures, or the changes in our operation, will result in a material adverse effect on our business, financial condition or results of operations.
On December 1, 2015, the EPA published final rules under the Risk and Technology Review provisions of the Clean Air Act to further regulate refinery air emissions through additional NSPS and Maximum Achievable Control Technology requirements (the “Refinery Sector Rules”). The final rules will require capital expenditures for additional controls on the Tyler refinery’s coker and for the relief systems, flares, tanks and other sources at both refineries, as well as requiring changes to the way we operate, start up and maintain some process units. The final rule also requires that we monitor property line benzene concentrations beginning in January 2018 and provide the results to the EPA quarterly, which will make the results available to the public beginning in 2019. Even though the concentrations are not expected to exceed regulatory or health based standards, the availability of such data may increase the likelihood of lawsuits against our refineries by the local public or organized public interest groups. We do not anticipate that the required capital and operating costs will be material, and do not believe compliance will affect our production capacities or have a material adverse effect upon our business, financial condition or results of operations.
On November 30, 2015, EPA finalized the renewable fuel volume obligations for 2014, 2015 and 2016 that represented year-over-year changes of -1.6%, +4.0% and +7.0%, respectively. On November 23, 2016, the EPA finalized the renewable fuel obligation for 2017 at 6.5% over the 2016 volume. The 2016 and 2017 ethanol volumes exceed the 10% ethanol “blendwall,” requiring increased usage of higher ethanol blends such as E15 and E85. The EPA has historically used its waiver authority to establish volumes lower than the statutory volumes required by the Energy Independence and Security Act, with the exception of the volumes for biomass-based diesel and for ethanol in 2017, but the EPA's interpretation of its waiver authority has been challenged in federal court.
Although our refineries have met and retired their 2014 and 2015 obligations, we were unable to blend sufficient quantities of ethanol and biodiesel to meet our 2016 obligation, and had to purchase RINs. On a consolidated basis, we purchased approximately 43 million RINs to meet our 2016 obligation. For our refineries' 2017 obligation, we estimate we will have to purchase approximately 40 million to 50 million RINs. It is not possible at this time to predict with certainty what those volumes or costs may be, but given the increase in required volumes and the volatile price of RINs, the increase in renewable volume requirements for 2017 could have an adverse impact on our results of operations if we are unable to recover those costs in the price of our refined products.
The EPA finalized Tier 3 gasoline rules in March 2014. The final Tier 3 rule requires a reduction in annual average gasoline sulfur content from 30 ppm to 10 ppm and retains the current maximum per-gallon sulfur content of 80 ppm. Larger refineries must comply with the 10 ppm sulfur standard by January 1, 2017, but the final rule provides a three-year waiver period, to January 1, 2020, for small volume refineries that processed less than 75,000 bpd in 2012. Both of our refineries meet this waiver provision. We anticipate that the Tyler refinery will meet these new limits when they become effective, with only minor operational changes, and that a capital project will be required for additional sulfur removal capacity at the El Dorado refinery.  Some loss of octane may occur as a result of changes in operation of the gasoline desulfurization units but we anticipate this loss will be mitigated through operational adjustments and modifications to other gasoline processes in the refineries.   Compliance is not expected to have a material adverse effect on our business, financial condition or results of operations. In April 2016, the EPA issued a final rule requiring small volume refineries that increase their annual average crude processing rate above 75,000 bpd to meet the Tier 3 sulfur limits 30 months from that “disqualifying” date. We do not anticipate that this rule will affect our refineries.

Our operations are also subject to the Federal Clean Water Act (“CWA”), the Oil Pollution Act of 1990 (“OPA-90”) and comparable state and local requirements. The CWA, and similar laws, prohibit any discharge into surface waters, ground waters, injection wells and publicly-owned treatment works, except as allowed by pre-treatment permits and National Pollutant Discharge Elimination System (“NPDES”) permits issued by federal, state and local governmental agencies. The OPA-90 prohibits the discharge of oil into "Waters of the U.S." and requires that affected facilities have plans in place to respond to spills and other discharges. The CWA also regulates filling or discharges to wetlands and other "Waters of the U.S." In 2015, the EPA, in conjunction with the Army Corps of Engineers, issued a final rule regarding the definition of “Waters of the U.S.,” which expanded the regulatory reach of the existing clean water regulations. Although the final rule is currently stayed pending litigation, if the rule becomes enforceable, it could increase costs for expanding our facilities or constructing new facilities, including pipelines.
We have experienced several crude oil releases from pipelines owned by our logistics segment, including, but not limited to, a release at Magnolia Station in March 2013, a release near Fouke, Arkansas in April 2015 and a release near Woodville, Texas in January 2016. In June 2015, the United States Department of Justice notified Delek Logistics that they were evaluating an enforcement action on behalf of the EPA with regard to potential CWA violations arising from the March 2013 Magnolia Station release. We are currently attempting to negotiate a resolution to this matter with the EPA and the ADEQ, which may include monetary penalties and/or other relief. Based on current information available to us, we do not believe the total costs associated with these events, whether alone or in the aggregate, including any fines or penalties, will have a material adverse effect upon our business, financial condition or results of operations.

Employees

As of December 31, 2016, we had 1,326 employees, of whom 650 were employed in our refining segment, 475 were employed by Delek for the benefit of our logistics segment and 201 were employed at our corporate office. As of December 31, 2016, 177 operations and maintenance hourly employees and 39 truck drivers at the Tyler refinery were represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union and its Local 202. The Tyler operations and maintenance hourly employees are

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currently covered by a collective bargaining agreement that expires January 31, 2019. The Tyler truck drivers are currently covered by a collective bargaining agreement that expires March 1, 2018. As of December 31, 2016, 192 operations and maintenance hourly employees at the El Dorado refinery were represented by the International Union of Operating Engineers and its Local 381. These employees are covered by a collective bargaining agreement which expires on August 1, 2017. None of our employees in our logistics segment or in our corporate office are represented by a union. We consider our relations with our employees to be satisfactory.

Available Information

Our Internet website address is www.DelekUS.com. Information contained on our website is not part of this Annual Report on Form 10-K. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to such reports filed with or furnished to the Securities and Exchange Commission ("SEC") are available on our Internet website in the "Investor Relations" section, free of charge, as soon as reasonably practicable after we file or furnish such material to the SEC. We also post our Corporate Governance Guidelines, Code of Business Conduct & Ethics and the charters of our Board of Directors' committees in the "Corporate Governance" section of our website, accessible by navigating to the "About Us" section on our Internet website. Our governance documents are available in print to any stockholder that makes a written request to the Secretary, Delek US Holdings, Inc., 7102 Commerce Way, Brentwood, Tennessee 37027.


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Glossary of Terms
The following are definitions of certain industry terms used in this Annual Report on Form 10-K:
Alkylation Unit - A refinery unit utilizing an acid catalyst to combine smaller hydrocarbon molecules to form larger molecules in the gasoline boiling range to produce a high octane gasoline blendstock, which is referred to as alkylate.
Barrel - A unit of volumetric measurement equivalent to 42 U.S. gallons.
Biodiesel - A renewable fuel produced from vegetable oils or animal fats that can be blended with petroleum-derived diesel to produce biodiesel blends for use in diesel engines. Pure biodiesel is referred to as B100, whereas blends of biodiesel are referenced by how much biodiesel is in the blend (e.g., a B5 blend contains five volume percent biodiesel and 95 volume percent ULSD).
Blendstocks - Various products or intermediate streams that are combined with other components of similar type and distillation range to produce finished gasoline, diesel fuel or other refined products. Blendstocks may include natural gasoline, hydrotreated Fluid Catalytic Cracking Unit gasoline, alkylate, ethanol, reformate, butane, diesel, biodiesel, kerosene, light cycle oil or slurry, among others.
Bpd/bpd - Barrels per calendar day.
Brent Crude (Brent) - a light, sweet crude oil, though not as light as WTI. Brent is the leading global price benchmark for Atlantic basin crude oils.
CBOB - Motor gasoline blending components intended for blending with oxygenates, such as ethanol, to produce finished conventional motor gasoline.
CERCLA - Comprehensive Environmental Response, Compensation and Liability Act
Complexity Index - A measure of secondary conversion capacity of a refinery relative to its primary distillation capacity. Generally, more complex refineries have a higher index number.
Crude Distillation Capacity, Nameplate Capacity or Production Capacity - The maximum sustainable capacity for a refinery or process unit for a given feedstock quality and severity level, measured in barrels per day.
Delayed Coking Unit (Coker) - A refinery unit that processes ("cracks") heavy oils, such as the bottom cuts of crude oil from the crude or vacuum units, to produce blendstocks for light transportation fuels or feedstocks for other units and petroleum coke.
Direct operating expenses - operating expenses attributed to the respective segment.
EISA - Energy Independence and Security Act of 2007.
Enterprise Pipeline System - a major product pipeline transport system that reaches from the Gulf Coast into the northeastern United States.
EPA - The Environmental Protection Agency.
Ethanol - An oxygenated blendstock that is blended with sub-grade (CBOB) or conventional gasoline to produce a finished gasoline.
E-10 - A 90% gasoline-10% ethanol blend.
E-15 - An 85% gasoline-15% ethanol blend.
E-85 - A blend of gasoline and 70%-85% ethanol.
FERC - The Federal Energy Regulatory Commission.
FIFO - First-in, first-out inventory accounting method.
Fluid Catalytic Cracking Unit or FCC Unit - A refinery unit that uses fluidized catalyst at high temperatures to crack large hydrocarbon molecules into smaller, higher-valued molecules (LPG, gasoline, LCO, etc.).

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Feedstocks - Crude oil and petroleum products used as inputs in refining processes.
Gulf Coast 5-3-2 crack spread or Gulf Coast crack spread - A crack spread reflecting the approximate gross margin resulting from processing one barrel of crude oil into three-fifths of a barrel of gasoline and two-fifths of a barrel of high sulfur diesel, utilizing the market prices of WTI crude oil, U.S. Gulf Coast Pipeline CBOB and U.S. Gulf Coast Pipeline No. 2 Heating Oil.
Gulf Coast Region - Commonly referred to as PADD III, includes the states of Texas, Arkansas, Louisiana, Mississippi, Alabama and New Mexico.
Hydrotreating Unit - A refinery unit that removes sulfur and other contaminants from hydrocarbons at high temperatures and moderate to high pressure in the presence of catalysts and hydrogen. When used to process fuels, this unit reduces the sulfur dioxide emissions from these fuels.
Isomerization Unit - A refinery unit altering the arrangement of a molecule in the presence of a catalyst and hydrogen to produce a more valuable molecule, typically used to increase the octane of gasoline blendstocks.
Jobbers - Retail stations owned by third parties that sell products purchased from or through us.
LPG - Liquefied petroleum gas.
Light/Medium/Heavy Crude Oil - Terms used to describe the relative densities of crude oil, normally represented by their API gravities. Light crude oils (those having relatively high API gravities) may be refined into a greater amount of valuable products and are typically more expensive than a heavier crude oil.
LSR - Light straight run naphtha.
LIFO - Last-in, first-out inventory accounting method.
Mid-Continent Region - Commonly referred to as PADD II, includes the states of North Dakota, South Dakota, Nebraska, Kansas, Oklahoma, Minnesota, Iowa, Missouri, Wisconsin, Illinois, Michigan, Indiana, Ohio, Kentucky and Tennessee.
MSCF/d - Abbreviation for a thousand standard cubic feet per day, a common measure for volume of gas.
Naphtha - A hydrocarbon fraction that is used as a gasoline blending component, a feedstock for reforming and as a petrochemical feedstock.
NGL - Natural gas liquids.
New York Mercantile Exchange (NYMEX) - A commodities futures exchange.
Operating margin - net sales less cost of goods sold.
OSHA - the Occupational Safety and Health Administration.
Petroleum Administration for Defense District (PADD) - Any of five regions in the United States as set forth by the Department of Energy and used throughout the oil industry for geographic reference. Our refineries operate in PADD III, commonly referred to as the Gulf Coast region.
Petroleum Coke - A coal-like substance produced as a byproduct during the Delayed Coking refining process.
Per barrel of sales - calculated by dividing the applicable income statement line item (operating margin or operating expenses) by the total barrels sold during the period.
PPB - parts per billion.
PPM - parts per million.
RCRA - Resource Conservation and Recovery Act.

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Refining margin, refined product margin or crack spread - A metric used in the refining industry to assess a refinery's product margins by comparing the difference between the price of refined products produced at the refinery and the price of crude oil required to produce those products.
Reforming Unit - A refinery unit that uses high temperature, moderate pressure and catalyst to create petrochemical feedstocks, high octane gasoline blendstocks and hydrogen.
Renewable Fuels Standard 2 (RFS-2) - An EPA regulation promulgated pursuant to the EISA, which requires most refineries to blend increasing amounts of renewable fuels (including biodiesel and ethanol) with refined products.
Renewable Identification Number (RIN) - a renewable fuel credit used to satisfy requirements for blending renewable fuels under RFS-2.
Roofing flux - An asphalt-like product used to make roofing shingles for the housing industry.
Straight run - product produced off of the crude or vacuum unit and not further processed.
Sweet/Sour crude oil - Terms used to describe the relative sulfur content of crude oil. Sweet crude oil is relatively low in sulfur content; sour crude oil is relatively high in sulfur content. Sweet crude oil requires less processing to remove sulfur and is typically more expensive than sour crude oil.
Throughput - The quantity of crude oil and feedstocks processed through a refinery or a refinery unit.
Turnaround - A periodic shutdown of refinery process units to perform routine maintenance to restore the operation of the equipment to its former level of performance. Turnaround activities normally include cleaning, inspection, refurbishment, and repair and replacement of equipment and piping. It is also common to use turnaround periods to change catalysts or to implement capital project improvements.
Ultra-Low Sulfur Diesel (ULSD) - Diesel fuel produced with a lower sulfur content (15 ppm) to reduce sulfur dioxide emissions. ULSD is the only diesel fuel that may be used for on-road and most other applications in the U.S.
U.S. Gulf Coast Pipeline CBOB - A grade of gasoline blendstock that must be blended with 10% biofuels in order to be marketed as Regular Unleaded at retail locations.
U.S. Gulf Coast Pipeline No. 2 Heating Oil - A petroleum distillate that can be used as either a diesel fuel or a fuel oil. This is the standard by which other Gulf Coast distillate products (such as ultra-low sulfur diesel) are priced.
Vacuum Distillation Unit - A refinery unit that distills heavy crude oils under deep vacuum to allow their separation without coking.
West Texas Intermediate Crude Oil (WTI) - A light, sweet crude oil characterized by an API gravity between 38 and 44 and a sulfur content of less than 0.4 weight percent that is used as a benchmark for other crude oils.

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ITEM 1A.    RISK FACTORS

We are subject to numerous known and unknown risks, many of which are presented below and elsewhere in this Annual Report on Form 10-K. You should carefully consider each of the following risks and all of the other information contained in this Annual Report on Form 10-K in evaluating us and our common stock. Any of the risk factors described below, or additional risks and uncertainties not presently known to us, or that we currently deem immaterial, could have a material adverse effect on our business, financial condition and results of operations. The headings provided in this Item 1A are for convenience and reference purposes only and shall not limit or otherwise affect the extent or interpretation of the risk factors.

Risks Relating to Our Industries

Our refining margins have been volatile and are likely to remain volatile, which may have a material adverse effect on our earnings and cash flows.

Our earnings, cash flow and profitability from our refining operations are substantially determined by the difference between the market price of refined products and the market price of crude oil, which is referred to as the crack spread, refining margin or refined products margin. Refining margins historically have been volatile, and are likely to continue to be volatile, as a result of numerous factors beyond our control, including volatility in the prices of the various types of crude oil and other feedstocks purchased by our refineries, volatility in the costs of natural gas and electricity used by our refineries, and volatility in the prices of gasoline and other refined petroleum products sold by our refineries. Although we monitor our refinery operating margins and seek to optimize results by adjusting throughput volumes, throughput types and product slates, there are inherent limitations on our ability to offset the effects of adverse market conditions.

For example, although there are differences between published prices and margins and those experienced in our operations, certain published data illustrate the volatility we encounter. The NYMEX price for domestic light sweet crude oil (NYMEX: CL), the Argus price for WTI Midland crude oil, the U.S. Gulf Coast price for unleaded gasoline (Platts U.S. Gulf Coast CBOB), the U.S. Gulf Coast price for high sulfur diesel (Platts U.S. Gulf Coast Pipeline High Sulfur No. 2 Diesel), the Gulf Coast 5-3-2 crack spread and the differential between the price of NYMEX crude oil and Intercontinental Exchange ("ICE") Brent Crude Oil (ICE: B) have fluctuated between the following daily highs and lows during the preceding three calendar years:
 
Year Ended
 
December 31, 2016
December 31, 2015
December 31, 2014
Low
High
Low
High
Low
High
 
 
 
 
 
 
 
NYMEX crude oil (per barrel)
$
26.21

$
54.06

$
34.73

$
61.43

$
53.27

$
107.26

WTI — Midland crude oil (per barrel)
$
27.07

$
54.81

$
34.78

$
61.42

$
49.15

$
100.66

U.S. Gulf Coast CBOB (per gallon)
$
0.78

$
1.65

$
1.05

$
2.12

$
1.08

$
2.99

U.S. Gulf Coast High Sulfur Diesel (per gallon)
$
0.74

$
1.52

$
0.84

$
1.84

$
1.22

$
2.98

U.S. Gulf Coast crack spread (per barrel)
$
4.52

$
13.60

$
3.93

$
24.91

$
(3.91
)
$
21.36

WTI — Cushing/Brent crude oil differential (per barrel)
$
(0.87
)
$
3.95

$
(0.21
)
$
12.82

$
1.77

$
14.95


Such volatility is affected by, among other things:

changes in global and local economic conditions;
domestic and foreign supply and demand for crude oil and refined products;
the level of foreign and domestic production of crude oil and refined petroleum products;
increased regulation of feedstock production activities such as hydraulic fracturing;
infrastructure limitations that restrict, or events that disrupt, the distribution of crude oil, other feedstocks and refined petroleum products;
an increase or decrease of infrastructure limitations (or the perception that such an increase or decrease could occur) on the distribution of crude oil, other feedstocks or refined products;
investor speculation in commodities;
worldwide political conditions, particularly in significant oil producing regions such as the Middle East, Africa, the former Soviet Union, and South America;
the ability of the members of the Organization of Petroleum Exporting Countries to maintain oil price and production controls;
pricing and other actions taken by competitors that impact the market;
the level of crude oil, other feedstocks and refined petroleum products imported into and exported out of the United States;
excess capacity and utilization rates of refineries worldwide;

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development and marketing of alternative and competing fuels, such as ethanol and biodiesel;
changes in fuel specifications required by environmental and other laws, particularly with respect to oxygenates and sulfur content;
local factors, including market conditions, adverse weather conditions and the level of operations of other refineries and pipelines in our markets;
accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our refineries or the supply and delivery of crude oil from third parties; and
United States government regulations.

The crude oil we purchase, and the refined products we sell, are commodities whose prices are mainly determined by market forces beyond our control. While an increase or decrease in the price of crude oil will often result in a corresponding increase or decrease in the wholesale price of refined products, a change in the price of one commodity does not always result in a corresponding change in the other. A substantial or prolonged increase in crude oil prices without a corresponding increase in refined product prices, or a substantial or prolonged decrease in refined product prices without a corresponding decrease in crude oil prices, could also have a significant negative effect on our results of operations and cash flows. This is especially true for non-transportation refined products, such as asphalt, butane, coke, sulfur, propane and slurry, whose prices are less likely to correlate to fluctuations in the price of crude oil, all of which we produce at our refineries.

Also, the price for a significant portion of the crude oil processed at our refineries is based upon the WTI benchmark for such oil rather than the Brent benchmark. While the prices for WTI and Brent historically corresponded to one another, elevated supply of WTI-priced crude oil in the Mid-Continent region has caused WTI prices to fall significantly below Brent prices at different points in time in recent years. During the years ended December 31, 2015 and December 31, 2016, this daily differential ranged from highs of $12.82 and $3.95, respectively, to lows of $(0.21) and $(0.87), respectively. Our ability to purchase and process favorably priced crude oils has allowed us to achieve higher net income and cash flow in recent years; however, we cannot assure you that these favorable conditions will continue. A substantial or prolonged narrowing in (or inversion to) the price differential between the WTI and Brent benchmarks for any reason, including, without limitation, increased crude oil distribution capacity from the Permian Basin, crude oil exports from the United States or actual or perceived reductions in Mid-Continent crude oil inventories, could negatively impact our earnings and cash flows. In addition, because the premium or discount we pay for a portion of the crude oil processed at our refineries is established based upon this differential during the month prior to the month in which the crude oil is processed, rapid decreases in the differential may negatively affect our results of operations and cash flows.

We operate in a highly regulated industry and increased costs of compliance with, or liability for violation of, existing or future laws, regulations and other requirements could significantly increase our costs of doing business, thereby adversely affecting our profitability.

Our industry is subject to extensive laws, regulations, permits and other requirements including, but not limited to, those relating to the environment, fuel composition, safety, transportation, pipeline tariffs, employment, labor, immigration, minimum wages, overtime pay, health care benefits, working conditions, public accessibility, and other requirements. These permits, laws and regulations are enforced by federal agencies including the EPA, United States Department of Transportation, Pipeline and Hazardous Materials Safety Administration, Federal Motor Carrier Safety Administration, Federal Railroad Administration, OSHA, National Labor Relations Board, Equal Employment Opportunity Commission, Federal Trade Commission and FERC, and state agencies such as the Texas Commission on Environmental Quality, Arkansas Department of Environmental Quality, Railroad Commission of Texas and Tennessee Department of Environment and Conservation, as well as numerous other state and federal agencies. We anticipate that compliance with environmental, health and safety regulations will require us to spend approximately $17.6 million in capital costs in 2017 and approximately $57.7 million during the next five years. These estimates do not include amounts related to capital investments that management has deemed to be strategic investments. These amounts could materially change as a result of governmental and regulatory actions.

Various permits, licenses, registrations and other authorizations are required under these laws for the operation of our refineries, terminals, pipelines and related operations, and these permits are subject to renewal and modification that may require operational changes involving significant costs. If key permits cannot be renewed or are revoked, the ability to continue operation of the affected facilities could be threatened.

Ongoing compliance with, or violation of, laws, regulations and other requirements could also have a material adverse effect on our business, financial condition and results of operations. We face potential exposure to future claims and lawsuits involving environmental matters, including, but not limited to, soil, groundwater and waterway contamination, air pollution, personal injury and property damage allegedly caused by substances we manufactured, handled, used, released or disposed. We are, and have been, the subject of various state, federal and private proceedings relating to environmental regulations, conditions and inquiries.

In addition, new legal requirements, new interpretations of existing legal requirements, increased legislative activity and governmental enforcement and other developments could require us to make additional unforeseen expenditures. Companies in the petroleum industry, such as us, are often the target of activist and regulatory activity regarding pricing, safety, environmental compliance, derivatives trading and other business practices, which could result in price controls, fines, increased taxes or other actions affecting the conduct of our business. For example, consumer activists are lobbying various authorities to enact laws and regulations mandating the removal of tetra-ethyl lead from aviation gasoline

25



and efforts are underway by the Federal Aviation Administration to find a suitable replacement fuel, which could affect production of aviation gasoline at our Tyler refinery. Other activists seek to require reductions in GHG emissions from our refineries and fuel products and are increasingly protesting new energy infrastructure projects such as pipelines and crude by rail facilities. The specific impact of laws and regulations or other actions may vary depending on a number of factors, including the age and location of operating facilities, marketing areas, crude oil and feedstock sources and production processes.

We generate wastes that may be subject to the RCRA and comparable state and local requirements. The EPA and various state agencies have limited the approved methods of managing, transporting, recycling and disposal of hazardous and certain non-hazardous wastes. Our refineries are large quantity generators of hazardous waste and require hazardous waste permits issued by the EPA or state agencies. Additionally, certain of our other facilities, such as terminals and biodiesel plants, generate lesser quantities of hazardous wastes.

Ongoing compliance with laws, regulations and other requirements could also have a material adverse effect on our business, financial condition and results of operations. Under RCRA and the CERCLA and other federal, state and local environmental requirements, as the owner or operator of refineries, biodiesel plants, bulk terminals, pipelines, tank farms, rail cars and trucks, we may be liable for the costs of removal or remediation of contamination at our existing or former locations, whether we knew of, or were responsible for, the presence of such contamination. We have incurred such liability in the past and several of our current and former locations are the subject of ongoing remediation projects. The failure to timely report and properly remediate contamination may subject us to liability to third parties and may adversely affect our ability to sell or rent our property or to borrow money using our property as collateral. Additionally, persons who arrange for the disposal or treatment of hazardous substances also may be liable for the costs of removal or remediation of these substances at sites where they are located, regardless of whether the site is owned or operated by that person. We typically arrange for the treatment or disposal of hazardous substances in our refining and other operations. Therefore, we may be liable for removal or remediation costs, as well as other related costs, including fines, penalties and damages resulting from injuries to persons, property and natural resources. Our El Dorado refinery is a minor potentially responsible party at a Superfund site, for which we expect our costs to be immaterial. In the future, we may incur substantial expenditures for investigation or remediation of contamination that has not been discovered at our current or former locations or locations that we may acquire.

Our operations are subject to certain requirements of the federal Clean Air Act (“CAA”) as well as related state and local laws and regulations governing air emissions. Certain CAA regulatory programs applicable to our refineries, terminals and other operations require capital expenditures for the installation of air pollution control devices, operational procedures to minimize emissions and monitoring and reporting of emissions. In 2012, the EPA announced an industry-wide enforcement initiative directed at flaring operations and performance at refineries and petrochemical plants and finalized revisions to NSPS Subpart Ja that primarily affects flares and process heaters. We completed capital projects at our refineries related to flare compliance with NSPS Ja in 2015. We believe our existing process heaters meet the applicable NSPS Ja requirements, and our refineries have not received any inquiries or requests for information from the EPA regarding flaring operations and are not a party to any associated enforcement action at this time.

In 2015, EPA finalized reductions in the National Ambient Air Quality Standard (NAAQS) for ozone, from 75 ppb to 70 ppb. Our Tyler refinery is located in an area reclassified as non-attainment with the new standard. While we do not yet know what specific actions we will be required to take or when, it is possible we will have to install additional air pollution control equipment for ozone forming emissions or change the formulation of gasoline we make for use in some areas. We do not believe such capital expenditures or the changes in our operation will result in a material adverse effect on our business.

In late 2015, the EPA finalized additional rules regulating refinery air emissions from a variety of sources (such as cokers, flares, tanks and other process units) through additional NSPS and National Emission Standards for Hazardous Air Pollutants and changing the way emissions from startup, shutdown and malfunction operations are regulated (the "Refinery Risk and Technology Review Rules" or “RTR”). The RTR rule also requires that, starting in January 2018, we monitor property line benzene concentrations at our refineries and, starting in 2019, report those concentrations quarterly to EPA, which will make the results available to the public. Even though the concentrations are not expected to exceed regulatory or health based standards, the availability of such data may increase the likelihood of lawsuits against our refineries by the local public or organized public interest groups. Compliance with the rules will require additional capital projects and changes in the way we operate some equipment over the next three years, but is not expected to have a material adverse effect on our business, financial condition or results of operations.

In addition to our operations, many of the fuel products we manufacture are subject to requirements of the CAA, as well as related state and local laws and regulations. The EPA has the authority under the CAA to modify the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with their final use. In 2007, the EPA issued final Mobile Source Air Toxic II rules for gasoline formulation that required the reduction of average benzene content beginning January 1, 2011 and the reduction of maximum annual average benzene content by July 1, 2012. We currently purchase credits to comply with these content requirements for one of our refineries. Although credits have been readily available, there can be no assurance that such credits will continue to be available for purchase at reasonable prices ,or at all, and we could have to implement capital projects in the future to reduce benzene levels.


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In March 2014, the EPA issued final Tier 3 gasoline rules that require a reduction in annual average gasoline sulfur content from 30 ppm to 10 ppm by January 1, 2017 for "large refineries" and retains the current maximum per-gallon sulfur content limit of 80 ppm. Under the final rules, both our refineries are considered “small refineries” and are exempt from complying with the rules' requirements until January 1, 2020. We anticipate that the Tyler refinery will meet these new limits when they become effective, with only minor operational changes, and that a capital project will be required for additional sulfur removal capacity at the El Dorado refinery.  Some loss of octane may occur as a result of changes in operation of the gasoline desulfurization units but we anticipate this loss will be mitigated through operational adjustments and modifications to other gasoline processes in the refineries.   Compliance is not expected to have a material adverse effect on our business, financial condition or results of operations. In April 2016, the EPA finalized a change to the Tier 3 standard requiring small volume refineries that increase their annual average crude processing rate above 75,000 bpd to meet the Tier 3 sulfur limits 30 months from that “disqualifying” date. We do not anticipate that this rule change will affect our refineries.

Our operations are also subject to the Federal Clean Water Act (“CWA”), the Oil Pollution Act of 1990 (“OPA-90”) and comparable state and local requirements. The CWA and similar laws prohibit any discharge into surface waters, ground waters, injection wells and publicly-owned treatment works except as allowed by pre-treatment permits and National Pollutant Discharge Elimination System (“NPDES”) permits, issued by federal, state and local governmental agencies. The OPA-90 prohibits the discharge of oil into "Waters of the U.S." and requires that affected facilities have plans in place to respond to spills and other discharges. The CWA also regulates filling or discharges to wetlands and other "Waters of the U.S." In 2015, the EPA, in conjunction with the Army Corps of Engineers, issued a final rule regarding the definition of “Waters of the U.S.,” which expanded the regulatory reach of the existing clean water regulations. Although the final rule is currently stayed pending litigation, if the rule becomes enforceable, it could increase costs for expanding our facilities or constructing new facilities, including pipelines.

We are subject to regulation by the United States Department of Transportation and various state agencies in connection with our pipeline, trucking and rail transportation operations. These regulatory authorities exercise broad powers, governing activities, such as the authorization to operate hazardous materials pipelines and engage in motor carrier operations. There are additional regulations specifically relating to the transportation industry, including integrity management of pipelines, testing and specification of equipment, product handling and labeling requirements and personnel qualifications. The transportation industry is subject to possible regulatory and legislative changes that may affect the economics of our business by requiring changes in operating practices or pipeline construction or by changing the demand for common or contract carrier services or the cost of providing trucking services. Possible changes include, among other things, increasingly stringent environmental regulations, increased frequency and stringency for testing and repairing pipelines, replacement of older pipelines, changes in the hours of service regulations that govern the amount of time a driver may drive in any specific period, on-board black box recorder devices or limits on vehicle weight and size and properties of the materials that can be shipped. Required changes to the specifications governing rail cars carrying crude oil will eliminate the most commonly used tank car or require that such cars be upgraded. In January 2017, PHMSA announced they were considering limits on the volatility of crude oil that could be shipped by rail and other modes of transportation. These rules could limit the availability of tank cars to transport crude to our refineries and increase the cost of crude oil transported by rail or truck. In addition to the substantial remediation costs that could be caused by leaks or spills from our pipelines, regulators could prohibit our use of affected portions of the pipeline for extended periods, thereby interrupting the delivery of crude oil to, or the distribution of refined products from, our refineries.

Our operations are subject to various laws and regulations relating to occupational health and safety and process safety administered by OSHA, EPA and various state equivalent agencies. We maintain safety, training, design standards, mechanical integrity and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations and protect the safety of our workers and the public. More stringent laws or regulations or adverse changes in the interpretation of existing laws or regulations by government agencies could have an adverse effect on our financial position and the results of our operations and could require substantial expenditures for the installation and operation of systems and equipment.

Health and safety legislation and regulations change frequently. We cannot predict what additional health and safety legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. Compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures. Future process safety rules could also mandate changes to the way we operate, the processes and chemicals we use and the materials from which our process units are constructed. Such regulations could have a significant negative effect on our operations and profitability. For example, in response to Executive Order 13650, Improving Chemical Facility Safety and Security, OSHA announced it intends to propose comprehensive changes to the process safety requirements. In January 2017, the EPA finalized changes to process safety requirements in its Risk Management Program rules that require evaluation of safer alternatives and technologies, expanded routine audits, independent third-party audits following certain process safety events and increased sharing of information with the public and emergency response organizations.

Environmental regulations are becoming more stringent, and new environmental and safety laws and regulations are continuously being enacted or proposed. Compliance with any future legislation or regulation of our produced fuels, including renewable fuel or carbon content; GHG emissions; sulfur, benzene or other toxic content; vapor pressure; octane; or other fuel characteristics, may result in increased capital and operating costs and may have a material adverse effect on our results of operations and financial condition. While it is impractical to predict the impact that potential regulatory and activist activity may have, such future activity may result in increased costs to operate and maintain our facilities, as well

27



as increased capital outlays to improve our facilities. Such future activity could also adversely affect our ability to expand production, result in damaging publicity about us, or reduce demand for our products. Our need to incur costs associated with complying with any resulting new legal or regulatory requirements, that are substantial and not adequately provided for, could have a material adverse effect on our business, financial condition and results of operations.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") is comprehensive financial reform legislation that, among other things, establishes comprehensive federal oversight and regulation of over-the-counter derivatives and many of the entities that participate in that market. Although the Dodd-Frank Act was enacted on July 21, 2010, the Commodity Futures Trading Commission, or CFTC, and the SEC, along with certain other regulators, must promulgate final rules and regulations to implement many of the Dodd-Frank Act's provisions relating to over-the-counter derivatives. While some of these rules have been finalized, others have not; and, as a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.

Finally, the Patient Protection and Affordable Care Act (the “ACA”) as well as other health care reform legislation being considered by Congress and state legislatures may have an impact on our business. As of December 31, 2016, we had 1,326 employees, of whom 650 were employed in our refining segment, 475 were employed by Delek for the benefit of our logistics segment and 201 were employed by Holdings. Although many of the rules, reforms and regulations required to implement the ACA have not yet been adopted, and consequently the precise costs of complying with the ACA remain unknown, an increase in our employee health care related costs appears likely and that increase could be extensive and changes to our health care cost structure could have a significant, negative impact on our business.

Increased supply of and demand for alternative transportation fuels, increased fuel economy standards and increased use of alternative means of transportation could lead to a decrease in transportation fuel prices and/or a reduction in demand for petroleum-based transportation fuels. A shortage of RINs could require that our refineries operate at reduced production rates or require us to incur a high cost to meet our RINs obligations that might not be recoverable in the price of our products.

Pursuant to the EISA, the EPA promulgated RFS-2 requiring refiners to blend "renewable fuels", such as ethanol, biodiesel and other advanced biofuels, with their petroleum fuels or purchase RINs in lieu of blending. The volume of renewable fuels required by the EISA increased from 9 billion gallons in 2008 to 22 billion gallons in 2016 and will increase to 36 billion gallons in 2022. The EPA has set annual volumes beneath the statutory levels each year because of the unavailability of certain advanced biofuels and to avoid exceeding 10% ethanol in the gasoline supply (the "blendwall"), but this decision has been challenged in federal court. Annually, the EPA establishes the volume of renewable fuels that refineries must blend into their finished petroleum fuels as a percentage of their domestic gasoline and diesel sales based on estimated demand for gasoline and diesel and the final biofuel volumes established by the EPA each year. Meeting RFS-2 requires displacing increasing amounts of petroleum-based transportation fuels with biofuels, beginning with approximately 7.8% in 2011, 10.1% in 2016 and 10.7% in 2017.

While we are able to obtain many of the RINs required for compliance by blending renewable fuels manufactured by third parties or by our own biodiesel plants, we must also purchase RINs on the open market. If we are unable to pass the costs of compliance with RFS-2 on to our customers, our profits will be adversely impacted. Moreover, the market prices for RINs have been volatile. If we have to pay a significantly higher price for RINs, if sufficient RINs are unavailable for purchase or if we are otherwise unable to meet the RFS-2 mandates, our business, financial condition and results of operations could be materially adversely affected.

Meeting the RFS-2 volume requirements will require more ethanol to be blended than can be achieved with 10% ethanol gasoline blends (E-10). The volumes of ethanol required to meet the 2016 and 2017 requirements exceed 10% ethanol in the nationwide gasoline pool. In 2011, the EPA approved E-15 for use in model year 2001 and later vehicles. However, studies show that E-15 may cause engine and fuel system damage, and most vehicle manufacturers do not recommend using E-15 in vehicles manufactured prior to 2013 or 2014 other than "Flex Fuel" vehicles. In addition, most existing underground storage tanks ("UST") and retail dispenser systems are not certified by Underwriters Laboratory, local fire codes or the EPA for use with gasoline blends containing more than 10% ethanol. Flex Fuel vehicles can utilize higher ethanol blends up to E-85, but there are relatively few such vehicles on the road, there are few E-85 retail locations and the use of E-85 results in significant reductions in fuel economy. These and other impediments may present challenges to blending the required volumes of ethanol. If adequate supplies of the required types of biofuels are unavailable in volumes sufficient to meet our requirement, if we are unable to physically blend the required biofuel volumes without exceeding 10% ethanol or if RINs are not available in sufficient volumes or at economical prices, refinery production or profitability could be negatively affected.

In addition, as regulatory initiatives have required an increase in the consumption of renewable transportation fuels, such as ethanol and biodiesel, consumer acceptance of electric, hybrid and other alternative vehicles is increasing. Increased use of renewable fuels and alternative vehicles may result in a decrease in demand for petroleum-based transportation fuels. Increased use of renewable fuels may also result in an increase in transportation fuel supply relative to decreased demand and a corresponding decrease in margins. A significant decrease in transportation fuel margins or demand for petroleum-based transportation fuels could have an adverse impact on our financial results. As described above, RFS-2 requires replacement of increasing amounts of petroleum-based transportation fuels with biofuels through 2022. RFS-2 and widespread

28



use of E-15 or E-85 could cause decreased crude runs and materially affect our profitability, unless fuel demand rises at a comparable rate or other outlets are found for the displaced petroleum products.

Finally, the EPA and the National Highway Traffic Safety Administration ("NHTSA") finalized new standards that raised the required Corporate Average Fuel Economy ("CAFE") of the nation's passenger fleet to approximately 35 mpg by 2016 and imposed the first-ever federal GHG emissions standards on cars and light trucks. In September 2011, the EPA and the Department of Transportation finalized first-time standards for fuel economy of medium and heavy duty trucks. In September 2012, the EPA and NHTSA finalized rules raising the CAFE and GHG standards for passenger vehicles beginning with 2017 model year vehicles and increasing to the equivalent of 54.5 mpg by 2025. These standards were reaffirmed by the EPA in January 2017. Additional increases in fuel efficiency standards for medium and heavy duty vehicles were finalized in August 2016. Such increases in fuel economy standards and potential electrification of the vehicle fleet, along with mandated increases in use of renewable fuels discussed above, could result in decreasing demand for petroleum fuels, which, in turn, could materially affect profitability at our refineries.

To meet higher fuel efficiency and GHG emission standards for passenger vehicles, automobile manufacturers are increasingly using technologies, such as turbocharging, direct injection and higher compression ratios, that require high octane gasoline. Many auto manufactures have expressed a desire that only a high-octane grade of gasoline be allowed in order to maximize fuel efficiency, rather than the three octane grades common now. Regulatory changes allowing only one high-octane grade, or significant increases in market demand for high-octane fuel, could result in a shift to high-octane ethanol blends containing 25% - 30% ethanol, the need for capital expenditures at our refineries to increase octane or reduced demand for petroleum fuels, which could materially affect profitability of our refineries.

We operate independent refineries which may not be able to withstand volatile market conditions, compete on the basis of price or obtain sufficient quantities of crude oil in times of shortage to the same extent as integrated, multinational oil companies.

We compete with a broad range of companies in our refining and petroleum product marketing operations. Many of these competitors are integrated, multinational oil companies that are substantially larger than us. Because of their diversity, integration of operations, larger capitalization, larger and more complex refineries and greater resources, these companies may be better able to withstand volatile market conditions relating to crude oil and refined product pricing, to compete on the basis of price and to obtain crude oil in times of shortage.

We do not engage in petroleum exploration or production, and therefore do not produce any of our crude oil feedstocks. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production activities. Competitors that have their own crude oil production are at times able to offset losses from refining operations with profits from producing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. If we are unable to compete effectively with these competitors, there could be a material adverse effect on our business, financial condition and results of operations.

Decreases in commodity prices may lessen our borrowing capacities, increase collateral requirements for derivative instruments or cause a write-down of inventory.

The nature of our business requires us to maintain substantial quantities of crude oil, refined petroleum product and blendstock inventories. Because these inventories are commodities, we have no control over their changing market value. For example, reductions in the value of our inventories or accounts receivable as a result of lower commodity prices could result in a reduction in our borrowing base calculation under the Tyler refinery's revolving credit facility and a reduction in the amount of financial resources available to meet the Tyler and El Dorado refineries' credit requirements. Further, if at any time our availability under the revolving credit facility falls below certain thresholds, we may be required to take steps to reduce our utilization under the credit facility. In addition, changes in commodity prices may require us to utilize substantial amounts of cash to settle or cash collateralize some or all of our existing commodity hedges. Finally, because our inventory is valued at the lower of cost or market value, we would record a write-down of inventory and a non-cash charge to cost of sales if the market value of the inventory were to decline to an amount below our cost.

A terrorist attack on our assets, or threats of war or actual war, may hinder or prevent us from conducting our business.

Terrorist attacks (including cyber-attacks) in the United States, as well as events occurring in response to or in connection with them, including political instability in various Middle Eastern countries, may harm our business. Energy-related assets (which could include refineries, pipelines and terminals such as ours) may be at greater risk of future terrorist attacks than other possible targets in the United States.

A direct attack on our assets, or the assets of others used by us, could have a material adverse effect on our business, financial condition and results of operations. In addition, any terrorist attack or continued political instability in the Middle East could have an adverse impact on energy prices, including prices for crude oil, other feedstocks and refined petroleum products, and an adverse impact on the margins from our refining and petroleum product marketing operations. Disruption or significant increases in energy prices could also result in government-imposed price controls.


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Legislative and regulatory measures to address climate change and GHG emissions could increase our operating costs or decrease demand for our refined products.

Various legislative and regulatory measures to address climate change and GHG emissions (including carbon dioxide, methane and nitrous oxides) are in various phases of discussion or implementation and could affect our operations. They include proposed and recently enacted federal regulation and state actions to develop statewide, regional or nationwide programs designed to control and reduce GHG emissions from fixed sources, such as our refineries, coal-fired power plants and oil and gas production operations, as well as mobile transportation sources and fuels. Many states and regions have implemented, or are in the process of implementing, measures to reduce emissions of GHGs, primarily through cap and trade programs or low carbon fuel standards, but we do not currently operate in states that have their own GHG reduction programs.

On an international level, in April 2016, the United States became a signatory to the 2015 Paris UN Climate Change Conference Agreement (the "Paris Climate Agreement"), which aims to hold the increase in the global average temperature to well below two degrees Celsius above pre-industrial levels. The Paris Climate Agreement requires participating countries to review and "represent a progression" in their intended nationally determined contributions to GHG emission reduction goals every five years beginning in 2020. The Paris Climate Agreement does not legally require parties to the agreement to reduce greenhouse gas emissions, but the U.S.'s future activities in response to the Paris Climate Agreement may result in regulations to further reduce greenhouse gas emissions.

Although it is not possible to predict the requirements of any GHG legislation that may be enacted, any laws or regulations that have been or may be adopted to restrict or reduce GHG emissions will likely require us to incur increased operating and capital costs and/or increased taxes on GHG emissions and petroleum fuels and result in reduced demand for our petroleum fuels. If we are unable to maintain sales of our refined products at a price that reflects such increased costs, there could be a material adverse effect on our business, financial condition and results of operations. Further, any increase in the prices of refined products resulting from such increased costs, GHG cap and trade programs or taxes on GHGs, could have a material adverse effect on our business, financial condition or results of operations. GHG regulation, including taxes on the GHG content of fuels, could also impact the consumption of refined products, thereby affecting our refinery operations.

Risks Relating to Our Business

We are particularly vulnerable to disruptions to our refining operations because our refining operations are concentrated in two facilities.

Because all of our refining operations are concentrated in the Tyler and El Dorado refineries, significant disruptions at either facility could have a material adverse effect on our business, financial condition or results of operations. Refining segment contribution margin comprised approximately 53.0%, 70.1% and 84.9% of our consolidated contribution margin for the 2016, 2015 and 2014 fiscal years, respectively.

Our refineries consist of many processing units, a number of which have been in operation for many years. These processing units undergo periodic shutdowns, known as turnarounds, during which routine maintenance is performed to restore the operation of the equipment to its former level of performance. Depending on which units are affected, all or a portion of a refinery's production may be halted or disrupted during a maintenance turnaround. We completed maintenance turnarounds at our El Dorado refinery in 2014 and our Tyler refinery in 2015. In addition, even if properly maintained, equipment may require significant capital expenditures to maintain desired efficiencies. One or more of the units may require additional unscheduled down time for unanticipated maintenance or repairs that are more frequent than our scheduled turnarounds.

Refinery operations may also be disrupted by external factors, such as a suspension of feedstock deliveries or an interruption of electricity, natural gas, water treatment or other utilities. Other potentially disruptive factors discussed elsewhere in these risk factors include natural disasters, severe weather conditions, workplace or environmental accidents, interruptions of supply, work stoppages, losses of permits or authorizations or acts of terrorism. Disruptions to our refining operations could reduce our revenues during the period of time that our processing units are not operating.

The dangers inherent in transporting, storing and processing crude oil and intermediate and finished petroleum products could cause disruptions and expose us to potentially significant costs and liabilities.

Our refining and logistics operations are subject to significant hazards and risks inherent in transporting, storing and processing crude oil and intermediate and finished petroleum products. These hazards and risks include, but are not limited to, natural or weather-related disasters, fires, explosions, pipeline ruptures and spills, trucking accidents, train derailments, third-party interference, mechanical failure of equipment and other events beyond our control. The occurrence of any of these events could result in production and distribution difficulties and disruptions, personal injury or death, environmental pollution and other damage to our properties and the properties of others. For example, we have experienced several crude oil releases from pipelines owned by our logistics segment. Each of these releases resulted in the need for clean-up and remediation efforts.


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Because of these inherent dangers, our refining and logistics operations are subject to various laws and regulations relating to occupational health and safety, process and operating safety, environmental protection and transportation safety. Continued efforts to comply with applicable laws and regulations related to health, safety and the environment, or a finding of non-compliance with current regulations, could result in additional capital expenditures or operating expenses, as well as fines and penalties.

In addition, our refineries, pipelines and terminals are located in populated areas and any release of hazardous material, or catastrophic event, could affect our employees and contractors as well as persons outside our property. Our pipelines, trucks and rail cars carry flammable and toxic materials on public railways and roads and across populated and/or environmentally sensitive areas, and waterways that could be severely impacted in the event of a release. An accident could result in significant personal injuries and/or cause a release that results in damage to occupied areas, as well as damage to natural resources. It could also affect deliveries of crude oil to our refineries, resulting in a curtailment of operations. The costs to remediate such an accidental release and address other potential liabilities, as well as the costs associated with any interruption of operations, could be substantial. Although we maintain significant insurance coverage for such events, it may not cover all potential losses or liabilities.

In the event that personal injuries or deaths result from such events, or there are natural resource damages, we would likely incur substantial legal costs and liabilities. The extent of these costs and liabilities could exceed the limits of our available insurance. As a result, any such event could have a material adverse effect on our business, results of operations and cash flows.

The costs, scope, timelines and benefits of our refining projects may deviate significantly from our original plans and estimates.

We may experience unanticipated increases in the cost, scope and completion time for our improvement, maintenance and repair projects at our refineries. Refinery projects are generally initiated to increase the yields of higher-value products, increase our ability to process a variety of crude oils, increase production capacity, meet new regulatory requirements or maintain the safe and reliable operations of our existing assets. Equipment that we require to complete these projects may be unavailable to us at expected costs or within expected time periods. Additionally, employee or contractor labor expense may exceed our expectations. Due to these or other factors beyond our control, we may be unable to complete these projects within anticipated cost parameters and timelines.

In addition, the benefits we realize from completed projects may take longer to achieve and/or be less than we anticipated. Large-scale capital projects are typically undertaken in anticipation of achieving an acceptable level of return on the capital to be employed in the project. We base these forecasted project economics on our best estimate of future market conditions that are not within our control. Most large-scale projects take many years to complete, and during this multi-year period, market and other business conditions can change from those we forecast. Our inability to complete, and/or realize the benefits of refinery projects in a cost-efficient and timely manner, could have a material adverse effect on our business, financial condition and results of operations.

We depend upon our logistics segment for a substantial portion of the crude oil supply and refined product distribution networks that serve our refineries.

Our logistics segment consists of Delek Logistics, a publicly traded master limited partnership, and our consolidated financial statements include its consolidated financial results. As of December 31, 2016, we owned a 60.7% limited partner interest in Delek Logistics, and a 94.9% interest in Logistics GP, which owns the entire 2.0% general partner interest in Delek Logistics. Delek Logistics operates a system of crude oil and refined product pipelines, distribution terminals and tankage in Arkansas, Louisiana, Tennessee and Texas. Delek Logistics generates revenues by charging tariffs for transporting crude oil and refined products through its pipelines, by leasing pipeline capacity to third parties, by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at its terminals.

Our refineries are substantially dependent upon Delek Logistics' assets and services under several long-term pipeline and terminal, tankage and throughput agreements expiring in 2017 through 2030. Delek Logistics is subject to its own operating and regulatory risks, including, but not limited to:

its reliance on significant customers, including us;
macroeconomic factors, such as commodity price volatility that could affect its customers' utilization of its assets;
its reliance on us for near-term growth;
sufficiency of cash flow for required distributions;
counterparty risks, such as creditworthiness and force majeure;
competition from third-party pipelines and terminals and other competitors in the transportation and marketing industries;
environmental regulations;
operational hazards and risks;
pipeline tariff regulations;
limitations on additional borrowings and other restrictions in its debt agreements; and

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other financial, operational and legal risks.

The occurrence of any of these risks could directly or indirectly affect Delek Logistics' financial condition, results of operations and cash flows. Because Delek Logistics is our consolidated subsidiary, the occurrence of any of these risks could also affect our financial condition, results of operations and cash flows. Additionally, if any of these risks affect Delek Logistics' viability, its ability to serve our supply and distribution needs may be jeopardized.

For additional information about Delek Logistics, see "Logistics Segment" under Item 1 & 2, Business and Properties, of this Annual Report on Form 10-K.

Interruptions or limitations in the supply and delivery of crude oil, or the supply and distribution of refined products, may negatively affect our refining operations and inhibit the growth of our refining operations.

We rely on Delek Logistics and third-party transportation systems for the delivery of crude oil to our refineries. For example, during the year ended December 31, 2016, we relied upon the West Texas Gulf pipeline for the delivery of approximately 77.0% of the crude oil processed by our refineries. We could experience an interruption or reduction of supply and delivery, or an increased cost of receiving crude oil, if the ability of these systems to transport crude oil is disrupted because of accidents, adverse weather conditions, governmental regulation, terrorism, maintenance or failure of pipelines or other delivery systems, other third-party action or other events beyond our control. The unavailability for our use, for a prolonged period of time, of any system of delivery of crude oil could have a material adverse effect on our business, financial condition or results of operations. For example, on two separate occasions since we assumed control of the El Dorado refinery in April 2011, a third-party pipeline operator has temporarily suspended crude oil shipments on a pipeline system that has historically supplied significant amounts of crude oil to the refinery. In May 2011, the suspension resulted from flooding along the Mississippi River and lasted approximately five weeks. In April 2012, the suspension resulted from a pipeline rupture and lasted approximately ten months. Pipeline suspensions like these could require us to operate at reduced throughput rates.

Moreover, interruptions in delivery or limitations in delivery capacity may not allow our refining operations to draw sufficient crude oil to support current refinery production or increases in refining output. In order to maintain or materially increase refining output, existing crude delivery systems may require upgrades or supplementation, which may require substantial additional capital expenditures.

In addition, the El Dorado refinery distributes most of its light product production through a third-party pipeline system. An interruption to, or change in, the operation of the third-party pipeline system may result in a material restriction to our distribution channels. Because demand in the El Dorado market is limited, a material restriction to the El Dorado refinery's distribution channels may cause us to reduce production and may have a material adverse effect on our business, financial condition and results of operations.

Finally, our West Texas terminals sell refined products produced by refineries owned mostly by third parties. In 2016, these terminals received a majority of their supply of refined products from a single supplier. We could experience an interruption or reduction of supply or delivery of refined products if our suppliers partially or completely ceased operations, temporarily or permanently. The ability of these refineries and our suppliers to supply refined products to us could be temporarily disrupted by anticipated events such as scheduled upgrades or maintenance, as well as events beyond their control, such as unscheduled maintenance, fires, floods, storms, explosions, power outages, accidents, acts of terrorism or other catastrophic events, labor difficulties and work stoppages, governmental or private party litigation, or legislation or regulation that adversely impacts refinery operations. In addition, any reduction in capacity of other pipelines that connect with our suppliers' pipelines or our pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes of refined product supplied to our West Texas terminals. A reduction in the volume of refined products supplied to our West Texas terminals could adversely affect our sales and earnings.

General economic conditions may adversely affect our business, operating results and financial condition.

Economic slowdowns may have serious negative consequences for our business and operating results, because our performance is subject to domestic economic conditions and their impact on levels of consumer spending. Some of the factors affecting consumer spending include general economic conditions, unemployment, consumer debt, reductions in net worth based on declines in equity markets and residential real estate values, adverse developments in mortgage markets, taxation, energy prices, interest rates, consumer confidence and other macroeconomic factors. During a period of economic weakness or uncertainty, current or potential customers may travel less, reduce or defer purchases, go out of business or have insufficient funds to buy or pay for our products and services. Moreover, a financial market crisis may have a material adverse impact on financial institutions and limit access to capital and credit. This could, among other things, make it more difficult for us to obtain (or increase our cost of obtaining) capital and financing for our operations. Our access to additional capital may not be available on terms acceptable to us or at all.

Also, because both of our refineries are located in the Gulf Coast Region, we primarily market our refined products in a relatively limited geographic area. As a result, we are more susceptible to regional economic conditions compared to our more geographically diversified competitors,

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and any unforeseen events or circumstances that affect the Gulf Coast Region could also materially and adversely affect our revenues and cash flows. The primary factors include, among other things, changes in the economy, weather conditions, demographics and population, increased supply of refined products from competitors and reductions in the supply of crude oil or other feedstocks. In the event of a shift in the supply/demand balance in the Gulf Coast Region due to changes in the local economy, an increase in aggregate refining capacity or other reasons, resulting in supply exceeding the demand in the region, our refineries may have to deliver refined products to more customers outside of the Gulf Coast Region and thus incur considerably higher transportation costs, resulting in lower refining margins, if any.

From time to time, our cash and credit needs may exceed our internally generated cash flow and available credit, and our business could be materially and adversely affected if we are not able to obtain the necessary cash or credit from financing sources.

We have significant short-term cash needs to satisfy working capital requirements, such as crude oil purchases which fluctuate with the pricing and sourcing of crude oil. We rely in part on our access to credit to purchase crude oil for our refineries. If the price of crude oil increases significantly, we may not have sufficient available credit, and may not be able to sufficiently increase such availability, under our existing credit facilities or other arrangements to purchase enough crude oil to operate our refineries at desired capacities. Our failure to operate our refineries at desired capacities could have a material adverse effect on our business, financial condition and results of operations. We also have significant long-term needs for cash, including any capital expenditures for refinery expansion and upgrade projects, as well as projects necessary for regulatory compliance.

Depending on the conditions in credit markets, it may become more difficult to obtain cash or credit from third-party sources. If we cannot generate cash flow or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to comply with regulatory deadlines or pursue our business strategies, in which case our operations may not perform as well as we currently expect.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

As of December 31, 2016, we had total debt of $832.9 million, including current maturities of $84.4 million. In addition to our outstanding debt, as of December 31, 2016, our letters of credit issued under our various credit facilities were $102.3 million. Our borrowing availability under our various credit facilities as of December 31, 2016 was $503.4 million.

Our level of debt could have important consequences for us. For example, it could:

increase our vulnerability to general adverse economic and industry conditions;
require us to dedicate a substantial portion of our cash flow from operations to service our debt and lease obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate purposes;
limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
place us at a disadvantage relative to our competitors that have less indebtedness or better access to capital by, for example, limiting our ability to enter into new markets, upgrade our refining assets or pursue acquisitions or other business opportunities;
limit our ability to borrow additional funds in the future; and
increase interest costs for our borrowed funds and letters of credit.

In addition, a substantial portion of our debt has a variable rate of interest, which increases our exposure to interest rate fluctuations, to the extent we elect not to hedge such exposures.

If we are unable to meet our principal and interest obligations under our debt and lease agreements, we could be forced to restructure or refinance our obligations, seek additional equity financing or sell assets, which we may not be able to do on satisfactory terms or at all. Our default on any of those agreements could have a material adverse effect on our business, financial condition and results of operations. In addition, if new debt is added to our current debt levels, the related risks that we now face could intensify.

Our debt agreements contain operating and financial restrictions that might constrain our business and financing activities.

The operating and financial restrictions and covenants in our credit facilities and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage in, expand or pursue our business activities. For example, to varying degrees our credit facilities restrict our ability to:

declare dividends and redeem or repurchase capital stock;
prepay, redeem or repurchase debt;
make loans and investments, issue guaranties and pledge assets;
incur additional indebtedness or amend our debt and other material agreements;
make capital expenditures;
engage in mergers, acquisitions and asset sales; and

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enter into certain intercompany arrangements or make certain intercompany payments, which in some instances could restrict our ability to use the assets, cash flows or earnings of one operating segment to support another operating segment or Holdings.

Other restrictive covenants require that we meet certain financial covenants, including leverage coverage, fixed charge coverage and net worth tests as described in the applicable credit agreements. In addition, the covenant requirements of our various credit agreements require us to make many subjective determinations pertaining to our compliance thereto and exercise good faith judgment in determining our compliance.

Our ability to comply with the covenants and restrictions contained in our debt instruments may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants and restrictions may be impaired. If we breach any of the restrictions or covenants in our debt agreements, a significant portion of our indebtedness may become immediately due and payable, and our lenders' commitments to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these immediate payments. In addition, our obligations under our credit facilities are secured by substantially all of our assets. If we are unable to timely repay our obligations under our credit facilities, the lenders could seek to foreclose on the assets or we may be required to contribute additional capital to our subsidiaries. Any of these outcomes could have a material adverse effect on our business, financial condition and results of operations.

Changes in our credit profile could affect our relationships with our suppliers, which could have a material adverse effect on our liquidity and our ability to operate our refineries at full capacity.

Changes in our credit profile could affect the way crude oil, feedstock and refined product suppliers view our ability to make payments. As a result, suppliers could shorten the payment terms of their invoices with us or require us to provide significant collateral to them that we do not currently provide. Due to the large dollar amounts and volume of our crude oil and other petroleum product purchases, as well as the historical volatility of crude oil pricing, any imposition by our suppliers of more burdensome payment terms or collateral requirements may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could cause us to be unable to operate our refineries at desired capacities. A failure to operate our refineries at desired capacities could adversely affect our profitability and cash flows.

The termination or expiration of our Amended and Restated Master Supply and Offtake Agreement could have a material adverse effect on our liquidity.

Our S&O Agreement with J. Aron expires on April 30, 2017. Pursuant to the agreement, J. Aron purchases a substantial portion of the crude oil and refined products in Lion Oil’s inventory at market prices. Upon any termination of the agreement, including at expiration or in connection with a force majeure or default, the parties are required to negotiate with third parties for the assignment to us of certain contracts, commitments and arrangements, including procurement contracts, commitments for the sale of product and pipeline, terminalling, storage and shipping arrangements. Additionally, upon any termination, we will be required to repurchase or refinance the consigned crude oil and refined products from J. Aron at then market prices, which may have a material impact on our working capital needs. At December 31, 2016, we had approximately 2.6 million barrels of inventory consigned to J. Aron, and we had recorded a liability associated with this consigned inventory of $124.6 million.

Our insurance policies do not cover all losses, costs or liabilities that we may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.

We carry property, business interruption, pollution and casualty insurance, but we do not maintain insurance coverage against all potential losses, costs or liabilities. We could suffer losses for uninsurable, or uninsured, risks or in amounts in excess of existing insurance coverage. In addition, we purchase insurance programs with large self-insured retentions and large deductibles. For example, we retain a short period of our business interruption losses. Therefore, a significant part or all of a business interruption loss or other types of loss could be retained by us. The occurrence of a loss that is retained by us, or not fully covered by insurance, could have a material adverse effect on our business, financial condition and results of operations.

The energy industry is highly capital intensive, and the entire or partial loss of individual facilities or multiple facilities can result in significant costs to both industry companies, such as us, and their insurance carriers. Historically, large energy industry claims have resulted in significant increases in the level of premium costs and deductible periods for participants in the energy industry. For example, hurricanes have caused significant damage to energy companies operating along the Gulf Coast, in addition to numerous oil and gas production facilities and pipelines in that region. Insurance companies that have historically participated in underwriting energy-related risks may discontinue that practice, may reduce the insurance capacity they are willing to offer or demand significantly higher premiums or deductible periods to cover these risks. If significant changes in the number, or financial solvency, of insurance underwriters for the energy industry occur, or if other adverse conditions over which we have no control prevail in the insurance market, we may be unable to obtain and maintain adequate insurance at reasonable cost.


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In addition, we cannot assure you that our insurers will renew our insurance coverage on acceptable terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. The unavailability of full insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results of operations.

We may not be able to successfully execute our strategy of growth through acquisitions.

A significant part of our growth strategy is to acquire assets such as refineries, pipelines and terminals that complement our existing assets and/or broaden our geographic presence. If attractive opportunities arise, we may also acquire assets in new lines of business that are complementary to our existing businesses. From our inception in 2001 through December 2016, we acquired the Tyler and El Dorado refineries, developed our logistics segment through the acquisition of transportation and marketing assets and purchased approximately 48% of the issued and outstanding common stock of Alon USA. We expect to continue to acquire assets that complement our existing assets and/or broaden our geographic presence as a major element of our growth strategy. However, the occurrence of any of the following factors could adversely affect our growth strategy:

We may not be able to identify suitable acquisition candidates or acquire additional assets on favorable terms;
We usually compete with others to acquire assets, which competition may increase, and any level of competition could result in decreased availability or increased prices for acquisition candidates;
We may experience difficulty in anticipating the timing and availability of acquisition candidates;
We may not be able to obtain the necessary financing, on favorable terms or at all, to finance any of our potential acquisitions; and
As a public company, we are subject to reporting obligations, internal controls and other accounting requirements with respect to any business we acquire, which may prevent or negatively affect the valuation of some acquisitions we might otherwise deem favorable or increase our acquisition costs.

Acquisitions involve risks that could cause our actual growth or operating results to differ adversely compared with our expectations.

Due to our emphasis on growth through acquisitions, we are particularly susceptible to transactional risks that could cause our actual growth or operating results to differ adversely compared with our expectations. For example:

during the acquisition process, we may fail, or be unable, to discover some of the liabilities of companies or businesses that we acquire;
we may assume contracts or other obligations in connection with particular acquisitions on terms that are less favorable or desirable than the terms that we would expect to obtain if we negotiated the contracts or other obligations directly;
we may fail to successfully integrate or manage acquired assets;
acquired assets may not perform as we expect, or we may not be able to obtain the cost savings and financial improvements we anticipate;
acquisitions may require us to incur additional debt or issue additional equity;
acquired assets may suffer a diminishment in fair value as a result of which we may need to record a write-down or impairment;
we may fail to grow our existing systems, financial controls, information systems, management resources and human resources in a manner that effectively supports our growth;
to the extent that we acquire assets in new lines of business, we may become subject to additional regulatory requirements and additional risks that are characteristic or typical of these lines of business; and
to the extent that we acquire equity interests in entities that control assets (rather than acquiring the assets directly), we may become subject to liabilities that predate our ownership and control of the assets.

The occurrence of any of these factors could adversely affect our business, financial condition or results of operations.

Failure to complete, or delays in completing, the Mergers may reduce or eliminate the expected benefits from the transactions and could negatively impact our stock price and future business and financial results.

The Mergers are subject to a number of conditions beyond Delek’s and Alon USA’s control that may prevent, delay or otherwise materially adversely affect their completion. We cannot predict whether and when these other conditions will be satisfied. There can be no assurance that either Delek or Alon USA or both parties will waive any condition to closing that is not satisfied. Furthermore, the requirements for obtaining the required clearances and approvals and the time required to satisfy any other conditions to the closing could delay the completion of the Mergers for a significant period of time or prevent the transaction from occurring. Any delay in completing the Mergers could cause us not to realize some or all of the benefits that we expect to achieve if the Mergers are successfully completed within the expected timeframe. In addition, if the Mergers are not completed by October 2, 2017, either Delek or Alon USA may choose not to proceed with the Mergers, and the parties can mutually decide to terminate the Merger Agreement at any time prior to the consummation of the Mergers, before or after stockholder approval. In addition, Delek or Alon USA may elect to terminate the Merger Agreement in certain other circumstances.


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If the Mergers are not completed, our ongoing business may be adversely affected and we will be subject to several risks, including the following:

being required, under certain circumstances, to pay a termination fee of $20 million to Alon USA;
having to pay certain costs relating to the proposed Mergers, such as legal, accounting, financial advisor, filing, printing and mailing fees; and
the focus of management on the Mergers instead of our ongoing business operations or pursuing other opportunities that may be beneficial to Delek.

If the Mergers do not occur, we may incur these costs without realizing any of the benefits of the Mergers being completed. In addition, if the Mergers are not completed, we may experience negative reactions from the financial markets and from its customers and employees. We could also be subject to litigation related to any failure to complete the Mergers or to potential enforcement proceedings seeking to compel the performance of our obligations under the Merger Agreement. There can be no assurance that the Mergers will be completed within the expected timeframe, or at all, and the occurrence of any of these factors could adversely affect our business, financial condition or results of operations.

Pending litigation against Delek or Alon USA could result in an injunction preventing the completion of the Mergers or a judgment requiring the payment of damages.

Our directors and officers may be subject to lawsuits challenging the proposed Mergers and other additional lawsuits that may be filed.  The outcome of any such litigation is uncertain.  If any litigation challenging the Mergers is not resolved, the lawsuits could prevent or delay completion of the Mergers and result in substantial costs to us, including any costs associated with the indemnification of our directors and officers. One condition to closing the Mergers is that no order, decree or injunction of any court or agency of competent jurisdiction be in effect that enjoins, prohibits or makes illegal consummation of any of the transactions, and no legal proceeding by any governmental authority with respect to the Mergers or other transactions be pending that seeks to restrain, enjoin, prohibit or delay consummation of the Mergers or imposes any material restrictions on the transactions contemplated by the Merger Agreement. Accordingly, any pending litigation with respect to the Mergers will threaten to delay or prevent the closing of the Mergers, particularly if any plaintiffs are successful in obtaining an injunction prohibiting the consummation of the Mergers. Additionally, if the Mergers are completed, HoldCo would assume the risks and liabilities associated with litigation that Alon USA and all members of the Alon USA board are party to, and we have agreed to indemnify the directors and officers of Alon USA following the completion of the Mergers for liability arising out of the fact that each such person was a director or officer of Alon USA prior to the date of the Merger Agreement.

The defense or settlement of these legal proceedings and any future additional litigation could be time-consuming and expensive, divert the attention of our management away from their regular business, and, if the resolution of any one of these legal proceedings or any future litigation is adverse to us or otherwise threatens the consummation of the Mergers, could have a material adverse effect on the financial condition, results of operations or liquidity of Delek or the combined company if resolved after the Mergers are completed.

The Merger Agreement contains provisions that could discourage a potential acquiror of Delek or could result in any potential acquisition proposal being offered at a lower price than might otherwise be offered.

The Merger Agreement contains “no shop” provisions that, subject to limited exceptions, restrict our ability to initiate, solicit, knowingly encourage or facilitate third-party proposals of offers to acquire all or a significant part of Delek. Further, even if our board withdraws or modifies its recommendation with respect to the issuance of Holdco common stock to the stockholders of Alon USA as consideration for the Alon Merger contemplated by the Merger Agreement, it will still be required to submit the matter to a vote of our stockholders at the special meeting unless the Merger Agreement is terminated in accordance with its terms. In addition, Alon USA generally has an opportunity to offer to modify the terms of the Merger Agreement in response to any competing acquisition proposals (as defined in the Merger Agreement) that may be made before our board may withdraw or modify its recommendation. In some circumstances, upon termination of the Merger Agreement, either of the parties to the Merger Agreement may be required to pay a termination fee to the other party.

These provisions could discourage a potential acquiror from considering or proposing an acquisition, even if it were prepared to pay consideration with a higher per share cash or market value than that market value proposed to be received or realized in the Mergers, or might result in a potential acquiror proposing to pay a lower price than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances.

If we complete the Mergers, we may face risks in connection with our planned integration of Alon USA. 
 
Risks we face in connection with our planned integration of Alon USA include but are not limited to: 
 
the risk that the proposed transaction and its announcement could have an adverse effect on the ability of Delek and Alon USA to retain customers and retain and hire key personnel and maintain relationships with their suppliers and customers and on their operating results and businesses generally; 

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the risk that problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected; 
the risk that the combined company may be unable to achieve cost-cutting synergies or it may take longer than expected to achieve those synergies; 
uncertainty related to timing and amount of future share repurchases and dividend payments; 
risks and uncertainties with respect to the quantities and costs of crude oil we are able to obtain and the price of the refined petroleum products we ultimately sell; 
gains and losses from derivative instruments;  
management's ability to execute its strategy of growth through acquisitions and the transactional risks associated with acquisitions and dispositions;  
acquired assets may suffer a diminishment in fair value as a result of which we may need to record a write-down or impairment in carrying value of the asset;  
changes in the scope, costs, and/or timing of capital and maintenance projects;  
operating hazards inherent in transporting, storing and processing crude oil and intermediate and finished petroleum products;  
our competitive position and the effects of competition;  
the projected growth of the industries in which we operate;  
general economic and business conditions affecting the southern United States;  and
other risks contained Alon USA’s filings with the SEC. 
 
The occurrence of any of these factors could adversely affect our business, financial condition or results of operations. 
 
Our sale of the Retail Entities to COPEC involves risks related to our continuing obligations under the Purchase Agreement and the effect of the disposition of the Retail Entities.  
 
In November 2016, we closed the Retail Transaction, pursuant to which we sold the Retail Entities to COPEC, which comprised our retail segment and a portion of our corporate, other and eliminations segment. In connection with the closing of the Retail Transaction, we and our stockholders are subject to several risks, including the following: 
 
the effect of the sale of the Retail Entities may adversely affect our relationships with our employees, customers, suppliers and other persons with whom we have business relationships;  
any event that results in a right for COPEC to seek indemnity from us could result in a substantial payment from us to COPEC and could adversely affect our business, financial condition, and results of operations; 
certain terms of the Purchase Agreement may preclude us from engaging in or pursuing certain business opportunities; and  
our revenues will decrease accordingly and our business will be subject to an increased concentration of the risks that affect our refining and logistics segments. 

We may incur significant costs and liabilities with respect to investigation and remediation of environmental conditions at our refineries.

Prior to our purchase of our refineries and terminals, the previous owners had been engaged for many years in the investigation and remediation of hydrocarbons and other materials which contaminated soil and groundwater at the purchased facilities. Upon purchase of the facilities, we became responsible and liable for certain costs associated with the continued investigation and remediation of known and unknown impacted areas at the refineries. In the future, it may be necessary to conduct further assessments and remediation efforts at impacted areas at our refinery, pipeline, tank, terminal locations and elsewhere. In addition, we have identified and self-reported certain other environmental matters subsequent to our purchase of the refineries.

Based upon environmental evaluations performed internally and by third parties subsequent to the purchase of our refineries and other properties, we recorded and periodically update environmental liabilities and accrued amounts we believe are sufficient to complete remediation. We expect remediation of soil, sediment and groundwater at some properties to continue for the foreseeable future. The need to make future expenditures for these purposes that exceed the amounts we estimated and accrued for could have a material adverse effect on our business, financial condition and results of operations.

In the future, we may incur substantial expenditures for investigation or remediation of contamination that has not been discovered at our current or former locations or locations that we may acquire. In addition, new legal requirements, new interpretations of existing legal requirements, increased legislative activity and governmental enforcement and other developments could require us to make additional unforeseen expenditures. Liabilities for future remediation costs are recorded when environmental assessments and/or remedial efforts are probable and the costs can be reasonably estimated as material. Other than for assessments, the timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action.


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We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.

Our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification, and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any, or all, of these matters could have a negative effect on our business, results of operations and cash flows.

Our Tyler refinery currently has limited ability to economically distribute refined petroleum products outside the northeast Texas market.

In recent years, we have expanded our refined product distribution capacities in northeast Texas with our acquisition of refined product terminals located in Big Sandy, Texas and Mount Pleasant, Texas. However, unlike most other refineries, the Tyler refinery currently has a limited ability to distribute refined products outside the northeast Texas market. For the year ended December 31, 2016, nearly all of the refinery sales volume in Tyler was completed through a rack system located at the Tyler refinery, which is owned by our logistics segment. The Tyler refinery's limited distribution capabilities may continue to limit its ability to increase its production, attract new customers for its refined petroleum products or increase sales of the Tyler refinery products. In addition, if demand for the Tyler refinery's products diminishes within the northeast Texas market, its production may be reduced and our financial results would be adversely affected, unless additional distribution capabilities are identified.

An increase in competition, and/or reduction in demand in the markets in which we purchase feedstocks and sell our refined products, could increase our costs and/or lower prices and adversely affect our sales and profitability.

Our Tyler refinery is currently the only supplier of a full range of refined petroleum products within a radius of approximately 100 miles of its location, and there are no competitive fuel loading terminals within approximately 90 miles of our San Angelo terminal. If competitors commence operations within these niche markets, we could lose our niche market advantage, which could have a material adverse effect on our business, financial condition and results of operations.

Our El Dorado refinery's profitability may be impacted by increased competition from refineries that operate in different regions that have access to Canadian and domestic crudes, which, from time to time may be discounted from crudes available to our El Dorado refinery. For example, third-party pipelines are currently in operation and have increased the supply of third-party refined products in Little Rock, Arkansas.

In addition, the maintenance, or replacement, of our existing customers depends on a number of factors outside of our control, including increased competition from other suppliers and demand for refined products in the markets we serve. The market for distribution of wholesale motor fuel is highly competitive and fragmented. Some of our competitors have significantly greater resources and name recognition than us. The loss of major customers, or a reduction in amounts purchased by major customers, could have an adverse effect on us to the extent that we are not able to correspondingly increase sales to other purchasers.

Compliance with and changes in tax laws could adversely affect our performance.

We are subject to extensive tax liabilities, including federal and state income taxes and transactional taxes, such as excise, sales/use, payroll, franchise, withholding and ad valorem taxes. New tax laws and regulations, and changes in existing tax laws and regulations, are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. Certain of these liabilities are subject to periodic audits by the respective taxing authority, which could increase or otherwise alter our tax liabilities. Subsequent changes to our tax liabilities as a result of these audits may also subject us to interest and penalties and could have a material adverse effect on our business, financial condition and results of operations.

For example, the tax treatment of our logistics segment depends on its status as a partnership for federal income tax purposes. If a change in law, our failure to comply with existing law or other factors were to cause our logistics segment to be treated as a corporation for federal income tax purposes, it would become subject to entity-level taxation. As a result, our logistics segment would pay federal income tax on all of its taxable income at regular corporate income tax rates (subject to corporate alternative minimum tax), would likely pay additional state and local income taxes at varying rates, and distributions to unitholders, including us, would be generally treated as taxable dividends from a corporation. In such case, the logistics segment would likely experience a material reduction in its anticipated cash flow and after-tax return to its unitholders and we would likely experience a substantial reduction in its value.

In addition, recent regulatory proposals in the United States could effectively limit, or even eliminate, use of the LIFO inventory method for financial and income tax purposes. Although the final outcome of these proposals cannot be ascertained at this time, the ultimate impact to us of the transition from LIFO to another inventory method could be material. We use the LIFO method with respect to our inventories at the Tyler

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refinery. A change to the FIFO inventory method could result in a material increase/decrease in the tax basis of our inventory at the Tyler refinery. This increase/decrease in inventory value could impact our taxable income in the year of change or ratably over several tax years.

Our commodity and interest rate derivative activity may limit potential gains, increase potential losses, result in earnings volatility and involve other risks.
At times, we enter into commodity derivative contracts to manage our price exposure to our inventory positions, future purchases of crude oil, ethanol and other feedstocks, future sales of refined products, manage our RINs exposure or to secure margins on future production. We have used interest rate swap and cap agreements to manage our market exposure to changes in interest rates related to our floating rate borrowings. We expect to continue to enter into these types of transactions from time to time and have increased our use of these risk management activities in recent years.

While these transactions are intended to limit our exposure to the adverse effects of fluctuations in crude oil prices, refined products prices, RIN prices and interest rates, they may also limit our ability to benefit from favorable changes in market conditions and may subject us to period-by-period earnings volatility in the instances where we do not seek hedge accounting for these transactions. Further, because the volume of derivative activity is less than our actual use of crude oil, production of refined products or total RINs exposure, our risk management activity does not completely limit our exposure to market volatility. Also, in connection with such derivative transactions, we may be required to make cash payments to maintain margin accounts and to settle the contracts at their value upon termination. Finally, this activity exposes us to potential risk of counterparties to our derivative contracts failing to perform under the contracts. As a result, the effectiveness of our risk management policies could have a material adverse impact on our business, results of operations and cash flows. For additional information about the nature and volume of these transactions, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk, of this Annual Report on Form 10-K.

We are exposed to certain counterparty risks which may adversely impact our results of operations.

We evaluate the creditworthiness of each of our various counterparties, but we may not always be able to fully anticipate or detect deterioration in a counterparty's creditworthiness and overall financial condition. The deterioration of creditworthiness or overall financial condition of a material counterparty (or counterparties) could expose us to an increased risk of nonpayment or other default under our contracts with them. If a material counterparty (or counterparties) defaults on their obligations to us, this could materially adversely affect our financial condition, results of operations or cash flows. For example, under the terms of the S&O Agreement with J. Aron, we granted J. Aron the exclusive right to store and withdraw crude and certain products in the tanks associated with the El Dorado refinery. The S&O Agreement also provides that the ownership of substantially all crude oil and certain other refined products in the tanks associated with the refinery will be retained by J. Aron, and that J. Aron will purchase substantially all of the specified refined products processed at the El Dorado refinery. An adverse change in J. Aron's business, results of operations, liquidity or financial condition could adversely affect its ability to timely discharge its obligations to us, which could consequently have a material adverse effect on our business, results of operations or liquidity.

Adverse weather conditions or other unforeseen developments could damage our facilities and impair our ability to produce and deliver refined petroleum products.

The regions in which we operate are susceptible to severe storms, including hurricanes, thunderstorms, tornadoes, floods, extended periods of rain, ice storms and snow, all of which we have experienced in the past few years. In addition, for a variety of reasons, many members of the scientific community believe that climate changes are occurring that could have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.

Inclement weather conditions could damage our facilities, interrupt production, adversely impact consumer behavior, travel and retail fuel demand or interrupt or impede our ability to operate our locations. If such conditions prevail near our refineries, they could interrupt or undermine our ability to produce and transport products from our refineries and receive and distribute products at our terminals. Regional occurrences, such as energy shortages or increases in energy prices, fires and other natural disasters, could also hurt our business. The occurrence of any of these developments could have a material adverse effect on our business, financial condition and results of operations.

Our operating results are seasonal and generally lower in the first and fourth quarters of the year for our refining and logistics segments. We depend on favorable weather conditions in the spring and summer months.

Demand for gasoline and asphalt products is generally higher during the summer months than during the winter months due to seasonal increases in motor vehicle traffic and road and home construction. Varying vapor pressure requirements between the summer and winter months also tighten summer gasoline supply. As a result, the operating results of our refining segment and logistics segment are generally lower for the first and fourth quarters of each year.


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A substantial portion of the workforce at our refineries is unionized, and we may face labor disruptions that would interfere with our operations.

As of December 31, 2016, we employed 274 and 330 people in our Tyler and El Dorado operations, respectively. From among these employees, 177 operations and maintenance hourly employees and 39 truck drivers at the Tyler refinery were represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union and its Local 202 at year end. The Tyler operations and maintenance hourly employees are currently covered by a collective bargaining agreement that expires January 31, 2019. The Tyler truck drivers are currently covered by a collective bargaining agreement that expires March 1, 2018. As of December 31, 2016, 192 operations and maintenance hourly employees at the El Dorado refinery were represented by the International Union of Operating Engineers and its Local 381. These employees are covered by a collective bargaining agreement which expires on August 1, 2017. Although these collective bargaining agreements contain provisions to discourage strikes or work stoppages, we cannot assure you that strikes or work stoppages will not occur. A strike or work stoppage could have a material adverse effect on our business, financial condition and results of operations.

We rely on information technology in our operations, and any material failure, inadequacy, interruption or security failure of that technology could harm our business.

We rely on information technology systems across our operations, including management of our supply chain, including various processes and transactions. We rely on commercially available systems, software, tools and monitoring to provide security for processing, transmission and storage of confidential customer information.

Any compromise or breach of our internal data network at any of our refining or terminal locations could cause interruptions in our operations. These disruptions could range from inconvenience in accessing business information to a disruption in our refining and/or logistics operations. The landscape of cyber threats is continuously changing and we combat this threat by undertaking continuous improvement opportunities within our security systems. Cost increases may be incurred in this area to combat the continued escalation of cyber attacks and/or disruptive criminal activity.

Also, we utilize information technology systems and controls that monitor the movement of petroleum products through our pipelines and terminals. An undetected failure of these systems could result in environmental damage, operational disruptions, regulatory enforcement or private litigation. Further, the failure of any of our systems to operate effectively, or problems we may experience with transitioning to upgraded or replacement systems, could significantly harm our business and operations and cause us to incur significant costs to remediate such problems.

If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively impacted.

Our future performance depends to a significant degree upon the continued contributions of our senior management team and key technical personnel. We do not currently maintain key person life insurance policies for any of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of members of our senior management team and key technical personnel would be unavailable to us for any reason, we would be required to hire other personnel to manage and operate our company and to develop our products and technology. We cannot assure you that we would be able to locate or employ such qualified personnel on acceptable terms or at all.

If we are, or become, a United States real property holding corporation, special tax rules may apply to a sale, exchange or other disposition of common stock and non-U.S. holders may be less inclined to invest in our stock, as they may be subject to United States federal income tax in certain situations.

A non-U.S. holder of our common stock may be subject to United States federal income tax with respect to gain recognized on the sale, exchange or other disposition of our common stock if we are, or were, a "U.S. real property holding corporation" ("USRPHC") at any time during the shorter of the five-year period ending on the date of the sale or other disposition and the period such non-U.S. holder held our common stock (the shorter period referred to as the "lookback period"). In general, we would be a USRPHC if the fair market value of our "U.S. real property interests," as such term is defined for United States federal income tax purposes, equals or exceeds 50% of the sum of the fair market value of our worldwide real property interests and our other assets used or held for use in a trade or business. The test for determining USRPHC status is applied on certain specific determination dates and is dependent upon a number of factors, some of which are beyond our control (including, for example, fluctuations in the value of our assets). If we are or become a USRPHC, so long as our common stock is regularly traded on an established securities market such as the NYSE, only a non-U.S. holder who, actually or constructively, holds or held during the lookback period more than five percent of our common stock will be subject to United States federal income tax on the disposition of our common stock.


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Risks Related to Our Common Stock

The price of our common stock may fluctuate significantly, and you could lose all or part of your investment.

The market price of our common stock may be influenced by many factors, some of which may be beyond our control, including:

our quarterly or annual earnings or those of other companies in our industry;
inaccuracies in, and changes to, our previously published quarterly or annual earnings;
changes in accounting standards, policies, guidance, interpretations or principles;
economic conditions within our industry, as well as general economic and stock market conditions;
the failure of securities analysts to cover our common stock or the cessation of such coverage;
changes in financial estimates by securities analysts and the frequency and accuracy of such reports;
future issuance or sales of our common stock;
announcements by us or our competitors of significant contracts or acquisitions;
sales of common stock by our senior officers or our affiliates; and
the other factors described in these "Risk Factors."

In recent years, the stock market has experienced extreme price and volume fluctuations. This volatility has had a significant impact on the market price of securities issued by many companies, including companies in our industry. The changes often occur without any apparent regard to the operating performance of these companies. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company performance, and these fluctuations could materially reduce our stock price. In addition, recent distress in the credit and financial markets resulted in extreme volatility in trading prices of securities and diminished liquidity, and we cannot assure you that our liquidity will not be affected by changes in the financial markets and the global economy.

In the past, some companies that have experienced volatile market prices for their securities have been subject to securities class action suits filed against them. The filing of a lawsuit against us, regardless of the outcome, could have a material adverse effect on our business, financial condition and results of operations, as it could result in substantial legal costs and a diversion of our management's attention and resources.

We do not have the ability to control the operations or policies of Alon USA for so long as we do not control a majority of Alon USA common stock.

As of December 31, 2016, we owned approximately 47% of the issued and outstanding common stock of Alon USA (the “Alon Investment”) and five of our employees served on the 11-member Alon USA board of directors, including Mr. Yemin who serves as the chairman of the Alon USA board of directors. However, as a result of our minority ownership position in Alon USA common stock and our minority position on the Alon USA board of directors, we are unable to control the operations or policies of Alon USA.

So long as we maintain a minority ownership position in Alon USA common stock and a minority position on the Alon USA board of directors, we may be unable to control, among other things, (i) the election of members of the Alon USA board of directors; (ii) the corporate and management policies of Alon USA (including the declaration of dividends and the timing and preparation of its financial statements); and/or (iii) the outcome of any corporate transaction or other matter submitted to shareholders of Alon USA for approval, including potential mergers or acquisitions, asset sales or other significant corporate transactions. See Note 23 of the consolidated financial statements included in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K for further information regarding a definitive agreement under which Delek will acquire all of the outstanding shares of Alon USA common stock which Delek does not already own in an all-stock transaction.

Because we account for the Alon Investment under the equity method of accounting, the earnings or losses reported by Alon USA will have a direct effect upon our earnings.

Due to our ownership percentage in Alon USA, we account for the Alon Investment using the equity method of accounting. As a result, the earnings or losses reported by Alon USA will have a direct impact on our earnings or losses per share. Alon USA is an independent refiner and marketer of petroleum products subject to many of the same risk factors affecting us, as described this Annual Report on Form 10-K, as well as other risk factors. To the extent that these factors adversely impact Alon USA’s earnings, our earnings per share would be adversely affected as well. For example, for the quarter ended December 31, 2015, Alon USA reported a goodwill impairment in the amount of approximately $39.0 million that adversely impacted Alon USA's pre-tax earnings. Because we account for the Alon Investment using the equity method of accounting, this impairment adversely impacted our pre-tax earnings for the quarter ended December 31, 2015 by approximately $18.7 million. For additional information regarding the risks to Alon USA's business, please see those identified in Alon USA's annual, quarterly and current reports, including those identified in Alon USA's Annual Report on Form 10-K for the year ended December 31, 2016.


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Stockholder activism may negatively impact the price of our common stock.

Our stockholders may from time to time engage in proxy solicitations, advance stockholder proposals or otherwise attempt to effect changes or acquire control over us. The Alon Investment and recent decline in the price of our common stock increase this risk. Campaigns by stockholders to effect changes at publicly traded companies are sometimes led by investors seeking to increase short-term stockholder value through actions such as financial restructuring, increased debt, special dividends, stock repurchases or sales of assets or the entire company. Responding to proxy contests and other actions by activist stockholders can be costly and time-consuming, disrupting our operations and diverting the attention of our Board of Directors and senior management from the pursuit of business strategies. As a result, stockholder campaigns could adversely affect our results of operations, financial condition and cash flows.

Future sales of shares of our common stock could depress the price of our common stock.

The market price of our common stock could decline as a result of the introduction of a large number of shares of our common stock into the market or the perception that these sales could occur. For example, we issued six million shares of our common stock to Alon Israel Oil Company, Ltd. in connection with the Alon Investment, and upon the closing of the proposed merger with Alon USA, a significant number of shares of Holdco common stock would be issued to the stockholders of Alon USA in consideration for their Alon USA shares. The introduction of these shares into the market (or the perception that sales of these shares could occur) could have an adverse impact on the market price of our common stock. Sales of a large number of shares of our common stock, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.

Our stockholders may suffer substantial dilution.

We may sell securities in the public or private equity markets if and when conditions are favorable, even if we do not have an immediate need for capital. In addition, if we have an immediate need for capital, we may sell securities in the public or private equity markets even when conditions are not otherwise favorable. Our stockholders will suffer dilution if we issue currently unissued shares of our stock or sell our treasury holdings in the future. Our stockholders will also suffer dilution as stock, restricted stock units, stock options, stock appreciation rights, warrants or other equity awards, whether currently outstanding or subsequently granted, are exercised.

We depend upon our subsidiaries for cash to meet our obligations and pay any dividends.

We are a holding company. Our subsidiaries conduct substantially all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations or pay dividends to our stockholders depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of dividends, tax sharing payments or otherwise. Our subsidiaries' ability to make any payments will depend on many factors, including their earnings, cash flows, the terms of their credit facilities, tax considerations and legal restrictions.

We may be unable to pay future regular dividends in the anticipated amounts and frequency set forth herein.

We will only be able to pay regular dividends from our available cash on hand and funds received from our subsidiaries. Our ability to receive dividends and other cash payments from our subsidiaries is restricted under the terms of their respective credit facilities. For example, under the terms of their credit facilities, our subsidiaries are subject to certain customary covenants that limit their ability to, subject to certain exceptions as defined in their respective credit agreements, remit cash to, distribute assets to, or make investments in us as the parent company. Specifically, these covenants limit the payment, in the form of cash or other assets, of dividends or other cash payments to us. The declaration of future regular dividends on our common stock will be at the discretion of our Board of Directors and will depend upon many factors, including our results of operations, financial condition, earnings, capital requirements, restrictions in our debt agreements and legal requirements. Although we currently intend to pay regular quarterly cash dividends on our common stock at an annual rate of $0.60 per share, we cannot provide any assurances that any regular dividends will be paid in the anticipated amounts and frequency set forth herein, if at all.

Provisions of Delaware law and our organizational documents may discourage takeovers and business combinations that our stockholders may consider in their best interests, which could negatively affect our stock price.

Provisions of Delaware law, our Second Amended and Restated Certificate of Incorporation and our Third Amended and Restated Bylaws may have the effect of delaying or preventing a change in control of our company or deterring tender offers for our common stock that other stockholders may consider in their best interests. For example, our Second Amended and Restated Certificate of Incorporation provides that:

stockholder actions may only be taken at annual or special meetings of stockholders;
members of our Board of Directors can be removed with or without cause by a supermajority vote of stockholders;
the Court of Chancery of the State of Delaware is, with certain exceptions, the exclusive forum for certain legal actions;
our bylaws, as may be in effect from time to time, can be amended only by a supermajority vote of stockholders; and

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certain provisions of our certificate of incorporation, as may be in effect from time to time, can be amended only by a supermajority vote of stockholders.

In addition, the certificate of incorporation authorizes us to issue up to 10,000,000 shares of preferred stock in one or more different series, with terms to be fixed by our Board of Directors. Stockholder approval is not necessary to issue preferred stock in this manner. Issuance of these shares of preferred stock could have the effect of making it more difficult and more expensive for a person or group to acquire control of us and could effectively be used as an anti-takeover device. On the date of this report, no shares of our preferred stock are outstanding.

Finally, our Third Amended and Restated Bylaws provide for an advance notice procedure for stockholders to nominate director candidates for election or to bring business before an annual meeting of stockholders and require that special meetings of stockholders be called only by our chairman of the Board of Directors, president or secretary after written request of a majority of our Board of Directors. The advance notice provision requires disclosure of derivative positions, hedging transactions, short interests, rights to dividends and other similar positions of any stockholder proposing a director nomination, in order to promote full disclosure of such stockholder's economic interest in us.

The anti-takeover provisions of Delaware law and provisions in our organizational documents may prevent our stockholders from receiving the benefit from any premium to the market price of our common stock offered by a bidder in a takeover context. Even in the absence of a takeover attempt, the existence of these provisions may adversely affect the prevailing market price of our common stock if they are viewed as discouraging takeover attempts in the future.

We are exposed to risks relating to evaluations of internal controls required by Section 404 of Sarbanes-Oxley.

To comply with the management certification and auditor attestation requirements of Section 404 of Sarbanes-Oxley, we are required to evaluate our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. During this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board rules and regulations that remain unremediated. As a public company, we are required to report, among other things, control deficiencies that constitute a "material weakness" or changes in internal controls that, or are reasonably likely to, materially affect internal controls over financial reporting. A "material weakness" is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company's annual or interim financial statements will not be prevented or detected on a timely basis.

If we fail to comply with the requirements of Section 404, we may be subject to sanctions or investigation by regulatory authorities such as the SEC or the NYSE. Additionally, failure to comply with Section 404 or the report by us of a material weakness may cause investors to lose confidence in our financial statements and our stock price may be adversely affected. If we fail to remedy any material weakness, our financial statements may be inaccurate, we may face restricted access to the capital markets and our stock price may decline.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

None.

ITEM 3.    LEGAL PROCEEDINGS

In the ordinary conduct of our business, we are from time to time subject to lawsuits, investigations and claims, including, environmental claims and employee-related matters.

Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, including civil penalties or other enforcement actions, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, financial condition or results of operations.

ITEM 4.    MINE SAFETY DISCLOSURES

Not applicable.



43



PART II

ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information and Dividends

Our common stock is traded on the New York Stock Exchange under the symbol "DK." The following table sets forth the quarterly high and low sales prices of our common stock for each quarterly period indicated and dividends issued since January 1, 2015:

Period
 
High Sales Price
 
Low Sales Price
 
Regular Dividends
Per Common Share
 
Special Dividends
Per Common Share
2015
 
 
 
 
 
 
 
 
First Quarter
 
$
40.22

 
$
25.38

 
$
0.15

 
$

Second Quarter
 
$
41.15

 
$
34.96

 
$
0.15

 
$

Third Quarter
 
$
40.47

 
$
27.32

 
$
0.15

 
$

Fourth Quarter
 
$
29.90

 
$
22.11

 
$
0.15

 
$

2016
 
 
 
 
 
 
 
 
First Quarter
 
$
24.74

 
$
12.54

 
$
0.15

 
$

Second Quarter
 
$
17.39

 
$
11.41

 
$
0.15

 
$

Third Quarter
 
$
18.57

 
$
11.66

 
$
0.15

 
$

Fourth Quarter
 
$
25.14

 
$
14.76

 
$
0.15

 
$


The dividends paid in 2016 and 2015 totaled approximately $37.5 million and $37.1 million, respectively. As of the date of this filing, we intend to continue to pay regular quarterly cash dividends on our common stock at the annual rate of $0.60 per share. The declaration and payment of future regular and/or special dividends to holders of our common stock will be at the discretion of our Board of Directors and will depend upon many factors, including our financial condition, earnings, legal requirements, restrictions in our debt agreements and other factors our Board of Directors deems relevant. Except as represented in the table above, we have paid no other cash dividends on our common stock during the two most recent fiscal years.

Holders

As of February 17, 2017, there were approximately eight common stockholders of record. This number does not include beneficial owners of our common stock whose stock is held in nominee or "street name" accounts through brokers.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers
In 2016, the Company's Board of Directors authorized a share repurchase program to purchase up to $125.0 million of the Company’s common stock in the aggregate. Any share repurchases under the repurchase program were implemented through open market transactions or in privately negotiated transactions, in accordance with applicable securities laws. The timing, price, and size of repurchases were made at the discretion of management and depended on prevailing market prices, general economic and market conditions and other considerations. The repurchase program did not obligate the Company to acquire any particular amount of stock, and the unused portion of the authorization under the repurchase program expired on December 31, 2016. There were no purchases of shares of our common stock made during the three months ended December 31, 2016 by or on behalf of us or any “affiliated purchaser,” as defined by Rule 10b-18 of the Exchange Act.
A new $150.0 million stock repurchase program was authorized by the Board on December 29, 2016. The 2017 stock repurchase authorization has no expiration date and, as of February 27, 2017, this repurchase authorization had not been utilized.

44



Performance Graph

The following Performance Graph and related information shall not be deemed "soliciting material" or to be "filed" with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that we specifically incorporate it by reference into such filing.

The following graph compares cumulative total returns for our stockholders to the Standard and Poor's 500 Stock Index and a market capitalization weighted peer group selected by management for the five-year period commencing December 31, 2011 and ending December 31, 2016.  The graph assumes a $100 investment made on December 31, 2011.  Each of the three measures of cumulative total return assumes reinvestment of dividends.  The peer group is comprised of Alon USA Energy, Inc. (NYSE: ALJ), CVR Energy, Inc. (NYSE: CVI), HollyFrontier Corporation (NYSE: HFC), Marathon Petroleum Corporation (NYSE: MPC), Phillips 66 (NYSE: PSX), Tesoro Corporation (NYSE: TSO), Valero Energy Corporation (NYSE: VLO) and Western Refining, Inc (NYSE: WNR).  The stock performance shown on the graph below is not necessarily indicative of future price performance.

a2016graphimage.jpg

45



ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data should be read in conjunction with Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, and Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.
 
 
Year Ended December 31,
 
 
2016
 
2015(1)
 
2014(1)
 
2013(1)
 
2012(1)
Statement of Operations Data:
 
 
 
(In millions, except share and per share data)
 
 
Net sales
 
$
4,197.9

 
$
4,782.0

 
$
7,019.2

 
$
7,184.2

 
$
6,977.0

Operating costs and expenses:
 
 
 
 
 
 
 
 
 
 
Cost of goods sold
 
3,812.9

 
4,236.9

 
6,213.3

 
6,536.9

 
6,132.8

Operating expenses
 
249.3

 
270.3

 
258.7

 
257.5

 
235.6

Insurance proceeds — business interruption
 
(42.4
)
 

 

 

 

General and administrative expenses
 
106.1

 
100.6

 
105.2

 
86.2

 
79.8

Depreciation and amortization
 
116.4

 
106.0

 
83.2

 
64.6

 
57.9

Other operating expense (income), net
 
4.8

 
(0.5
)
 
0.1

 
1.7

 
0.1

Total operating costs and expenses
 
4,247.1

 
4,713.3

 
6,660.5

 
6,946.9

 
6,506.2

Operating (loss) income
 
(49.2
)
 
68.7

 
358.7


237.3


470.8

Interest expense
 
54.4

 
52.1

 
33.5

 
31.4

 
38.8

Interest income
 
(1.5
)
 
(1.1
)
 
(0.8
)
 
(0.3
)
 
(0.2
)
Loss (income) from equity method investments
 
43.4

 
(2.0
)
 

 

 

Loss on impairment of equity method investment
 
245.3

 

 

 

 

Other expense (income), net
 
0.4

 
(1.6
)
 
(0.9
)
 
(6.3
)
 

Total non-operating expenses, net
 
342.0

 
47.4

 
31.8

 
24.8

 
38.6

(Loss) income from continuing operations before income tax expense
 
(391.2
)
 
21.3

 
326.9

 
212.5

 
432.2

Income tax (benefit) expense
 
(171.5
)
 
(15.8
)
 
101.6

 
76.1

 
152.7

(Loss) income from continuing operations

(219.7)

 
37.1

 
225.3

 
136.4

 
279.5

Discontinued operations
 
 
 
 
 
 
 
 
 
 
Income from discontinued operations
 
144.2

 
5.7

 
0.6

 
(5.9
)
 
(4.8
)
Income tax expense (benefit)
 
57.9

 
(0.9
)
 
(0.1
)
 
(5.2
)
 
(1.3
)
Income (loss) from discontinued operations, net of tax
 
86.3

 
6.6

 
0.7

 
(0.7
)
 
(3.5
)
Net (loss) income
 
(133.4
)
 
43.7

 
226.0

 
135.7

 
276.0

Net income attributed to non-controlling interest
 
20.3

 
24.3

 
27.4

 
18.0

 
3.2

Net (loss) income attributable to Delek

$
(153.7
)
 
$
19.4


$
198.6


$
117.7


$
272.8

 
 
 
 
 
 
 
 
 
 
 
Basic (loss) earnings per share:
 
 
 
 
 
 
 
 
 
 
(Loss) income from continuing operations
 
$
(3.88
)
 
$
0.21

 
$
3.37

 
$
2.00

 
$
4.71

Income (loss) from discontinued operations
 
$
1.39

 
$
0.11

 
$
0.01

 
$
(0.01
)
 
$
(0.06
)
Total basic (loss) earnings per share
 
$
(2.49
)
 
$
0.32

 
$
3.38

 
$
1.99

 
$
4.65

 
 
 
 
 
 
 
 
 
 
 
Diluted earnings per share:
 
 
 
 
 
 
 
 
 
 
(Loss) income from continuing operations
 
$
(3.88
)
 
$
0.21

 
$
3.33

 
$
1.97

 
$
4.63

Income (loss) from discontinued operations
 
$
1.39

 
$
0.11

 
$
0.01

 
$
(0.01
)
 
$
(0.06
)
Total diluted (loss) earnings per share
 
$
(2.49
)
 
$
0.32

 
$
3.34

 
$
1.96

 
$
4.57

Weighted average common shares outstanding:
 
 
 
 
 
 
 
 
 
 
Basic
 
61,921,787

 
60,819,771

 
58,780,947

 
59,186,921

 
58,719,968

Diluted
 
61,921,787

 
61,320,570

 
59,355,120

 
60,047,138

 
59,644,798



46



 
 
Year Ended December 31,
 
 
2016
 
2015(1)
 
2014(1)
 
2013(1)
 
2012(1)
Balance Sheet Data:
 
 
 
(In millions)
 
 
Cash and cash equivalents
 
$
689.2

 
$
287.2

 
$
429.8

 
$
383.2

 
$
589.6

Assets of discontinued operations held for sale
 

 
478.8

 
485.9

 
480.6

 
437.9

Total current assets
 
1,402.2

 
1,397.5

 
1,656.0

 
1,810.3

 
1,715.0

Property, plant and equipment, net
 
1,103.3

 
1,177.4

 
1,099.2

 
944.3

 
834.2

Total assets
 
2,985.1

 
3,324.9

 
2,888.7

 
2,840.4

 
2,623.7

Liabilities of discontinued operations held for sale
 

 
302.8

 
259.1

 
235.5

 
266.4

Total current liabilities
 
940.5

 
1,004.1

 
1,057.5

 
1,250.3

 
1,168.3

Total debt, including current maturities
 
832.9

 
805.2

 
464.8

 
313.1

 
249.7

Total non-current liabilities
 
862.1

 
966.9

 
632.8

 
469.7

 
377.4

Total shareholders' equity
 
1,182.5

 
1,353.9

 
1,198.4

 
1,120.4

 
1,078.0

Total liabilities and shareholders' equity
 
2,985.1

 
3,324.9

 
2,888.7

 
2,840.4

 
2,623.7

(1) 
In August 2016, Delek entered into the Purchase Agreement to sell the Retail Entities, which consist of all of the retail segment and a portion of the corporate, other and eliminations segment, to COPEC. As a result of the Purchase Agreement, we met the requirements of ASC 205-20, Presentation of Financial Statements - Discontinued Operations and ASC 360, Property, Plant and Equipment, to report the results of the Retail Entities as discontinued operations and to classify the Retail Entities as a group of assets held for sale. The operating results for the Retail Entities have been reclassified to discontinued operations.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
This Annual Report contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements reflect our current estimates, expectations and projections about our future results, performance, prospects and opportunities. Forward-looking statements include, among other things, the information concerning our possible future results of operations, business and growth strategies, financing plans, expectations that regulatory developments or other matters will or will not have a material adverse effect on our business or financial condition, our competitive position and the effects of competition, the projected growth of the industry in which we operate, and the benefits and synergies to be obtained from our completed and any future acquisitions, statements of management’s goals and objectives, and other similar expressions concerning matters that are not historical facts. Words such as "may," "will," "should," "could," "would," "predicts," "potential," "continue," "expects," "anticipates," "future," "intends," "plans," "believes," "estimates," "appears," "projects" and similar expressions, as well as statements in future tense, identify forward-looking statements.
Forward-looking statements should not be read as a guarantee of future performance or results, and will not necessarily 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. Important factors that, individually or in the aggregate, could cause such differences include, but are not limited to:
volatility in our refining margins or fuel gross profit as a result of changes in the prices of crude oil, other feedstocks and refined petroleum products;
our ability to execute our strategy of growth through acquisitions and the transactional risks inherent in such acquisitions;
acquired assets may suffer a diminishment in fair value, which may require us to record a write-down or impairment;
liabilities related to, and the effects of, the sale of the Retail Entities (as defined below);
a delay in or failure to close the Mergers (as defined below);
reliability of our operating assets;

47



competition;
changes in, or the failure to comply with, the extensive government regulations applicable to our industry segments;
diminution in value of long-lived assets may result in an impairment in the carrying value of the assets on our balance sheet and a resultant loss recognized in the statement of operations;
general economic and business conditions affecting the southern United States;
volatility under our derivative instruments;
deterioration of creditworthiness or overall financial condition of a material counterparty (or counterparties);
unanticipated increases in cost or scope of, or significant delays in the completion of, our capital improvement and periodic turnaround projects;
risks and uncertainties with respect to the quantities and costs of refined petroleum products supplied to our pipelines and/or held in our terminals;
operating hazards, natural disasters, casualty losses and other matters beyond our control;
increases in our debt levels or costs;
changes in our ability to continue to access the credit markets;
compliance, or failure to comply, with restrictive and financial covenants in our various debt agreements;
the inability of our subsidiaries to freely make dividends, loans or other cash distributions to us;
seasonality;
acts of terrorism aimed at either our facilities or other facilities that could impair our ability to produce or transport refined products or receive feedstocks;
changes in the cost or availability of transportation for feedstocks and refined products; and
other factors discussed under Item 1A, Risk Factors and Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and in our other filings with the SEC.
In light of these risks, uncertainties and assumptions, our actual results of operations and execution of our business strategy could differ materially from those expressed in, or implied by, the forward-looking statements, and you should not place undue reliance upon them. In addition, past financial and/or operating performance is not necessarily a reliable indicator of future performance, and you should not use our historical performance to anticipate future results or period trends. We can give no assurances that any of the events anticipated by any forward-looking statements will occur or, if any of them do, what impact they will have on our results of operations and financial condition.
Forward-looking statements speak only as of the date the statements are made. We assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking information except to the extent required by applicable securities laws. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect thereto or with respect to other forward-looking statements.
Executive Summary and Strategic Overview
Business Overview
We are an integrated downstream energy business focused on petroleum refining and the transportation, storage and wholesale distribution of crude oil, intermediate and refined products and, prior to August 2016, convenience store retailing. Prior to August 2016, we aggregated our operating units into three reportable segments: refining, logistics and retail. However, in August 2016, we entered into a definitive equity purchase agreement (the "Purchase Agreement") with COPEC. Under the terms of the Purchase Agreement, Delek agreed to sell, and COPEC agreed to purchase, 100% of the equity interests in Delek's wholly-owned subsidiaries MAPCO Express, Inc., MAPCO Fleet, Inc., Delek Transportation, LLC, NTI Investments, LLC and GDK Bearpaw, LLC (collectively, the “Retail Entities”) for cash consideration of $535 million, subject to certain customary adjustments (the “Transaction”). In November 2016, the Retail Transaction closed. As a result of the Purchase Agreement, we met the requirements of ASC 205-20, Presentation of Financial Statements - Discontinued Operations and ASC 360, Property, Plant and Equipment, to report the results of the Retail Entities as discontinued operations and to classify the Retail Entities as a group of assets held for sale.

48



We own a 60.7% limited partner interest in Delek Logistics Partners, LP ("Delek Logistics") and a 94.9% interest in the entity that owns the entire 2.0% general partner interest in Delek Logistics and all of the income distribution rights. Delek Logistics was formed by Delek in 2012 to own, operate, acquire and construct crude oil and refined products logistics and marketing assets. Delek Logistics' initial assets were contributed by us and included certain assets formerly owned or used by certain of our subsidiaries. A substantial majority of Delek Logistics' assets are currently integral to our refining and marketing operations.
Our profitability in the refining segment is substantially determined by the difference between the cost of the crude oil feedstocks we purchase and the price of the refined products we sell, referred to as the "crack spread, refining margin or refined product margin." The cost to acquire feedstocks and the price of the refined petroleum products we ultimately sell from our refineries depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined petroleum products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions such as hurricanes or tornadoes, local, domestic and foreign political affairs, global conflict, production levels, the availability of imports, the marketing of competitive fuels and government regulation. Other significant factors that influence our results in the refining segment include operating costs (particularly the cost of natural gas used for fuel and the cost of electricity), seasonal factors, refinery utilization rates and planned or unplanned maintenance activities or turnarounds. Moreover, while the fluctuations in the cost of crude oil typically influence the prices of light refined products, such as gasoline and diesel fuel, the price of other residual products, such as asphalt, coke, carbon black oil and LPG are less likely to move in parallel with crude cost. This causes additional pressure on our realized margin in periods of rising crude oil prices and, during periods of falling crude oil prices, margins may benefit from these economics. Additionally, our margins are impacted by the pricing differentials of the various types and sources of crude oil we use at our two refineries and their relation to product pricing, such as the differentials between Midland WTI and Cushing WTI or Cushing WTI and Brent crude oil.
For our Tyler refinery, we compare our per barrel refined product margin to a well-established industry metric: the Gulf Coast crack spread. The Gulf Coast crack spread is used as a benchmark for measuring a refinery's product margins by measuring the difference between the market price of light products and crude oil. It represents the approximate gross margin resulting from processing one barrel of crude oil into three-fifths of a barrel of gasoline and two-fifths of a barrel of high-sulfur diesel. We calculate the Gulf Coast crack spread using the market value of U.S. Gulf Coast Pipeline CBOB and U.S. Gulf Coast Pipeline No. 2 Heating Oil (high sulfur diesel) and the first month futures price of WTI on the NYMEX. U.S. Gulf Coast Pipeline CBOB is a grade of gasoline commonly blended with biofuels and marketed as Regular Unleaded at retail locations. U.S. Gulf Coast Pipeline No. 2 Heating Oil is a petroleum distillate that can be used as either a diesel fuel or a fuel oil. This is the standard by which other distillate products (such as ultra low sulfur diesel) are priced. The NYMEX is the commodities trading exchange where contracts for the future delivery of petroleum products are bought and sold.
The crude oil and product slate flexibility of the El Dorado refinery allows us to take advantage of changes in the crude oil and product markets; therefore, we anticipate that the quantities and varieties of crude oil processed and products manufactured at the El Dorado refinery will continue to vary. Thus, we do not believe that it is possible to develop a reasonable refined product margin benchmark that would accurately portray our refined product margins at the El Dorado refinery.
The cost to acquire the refined fuel products we sell to our wholesale customers in our logistics segment depends on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined petroleum products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation.
We also own a non-controlling equity interest of approximately 47% of the outstanding shares (the "ALJ Shares") in Alon USA Energy, Inc. (NYSE: ALJ) ("Alon USA"). Alon USA is an independent refiner and marketer of petroleum products, operating primarily in the south central, southwestern and western regions of the United States. Alon USA owns 100% of the general partner and 81.6% of the limited partner interests in Alon USA Partners, LP (NYSE: ALDW), which owns a crude oil refinery in Big Spring, Texas with a crude oil throughput capacity of 73,000 bpd and an integrated wholesale marketing business. In addition, Alon USA directly owns a crude oil refinery in Krotz Springs, Louisiana with a crude oil throughput capacity of 74,000 bpd. Alon USA also owns crude oil refineries in California, which have not processed crude oil since 2012. Alon USA is a marketer of asphalt, which it distributes through asphalt terminals located predominately in the southwestern and western United States. Alon USA is the largest 7-Eleven licensee in the United States and operates approximately 300 convenience stores which market motor fuels in central and west Texas and New Mexico. Our investment in Alon USA is accounted for as an equity method investment and the earnings from this equity method investment reflected in our consolidated statements of income include our share of net earnings directly attributable to this equity method investment, and amortization of the excess of our investment balance over the underlying net assets of Alon USA. In January 2017, we announced a definitive agreement under which Delek will acquire all of the outstanding shares of Alon USA common stock which Delek does not already own in an all-stock transaction. See 2016 Strategic Developments - Alon Merger below for further information.
Due to the decline in the quoted market price of Alon USA below the carrying amount of our investment, we evaluated our investment in Alon USA for potential impairment. As of September 30, 2016, we determined that the decline in the market value of the ALJ Shares is other than temporary and, therefore, it was necessary to record an impairment charge of $245.3 million on our investment in the year ended December 31, 2016. Our decision that the decline in market value of the ALJ shares is other than temporary was primarily based on the following factors: the duration of the period in which the fair market value had been below our investment balance and the decreased possibility of a recovery in the

49



near term as a result of Alon USA's recent financial performance, as well as expectations of Alon USA's future operating performance. Future conditions in the industry, operating performance and performance in relation to peers and the future economic environment may continue to decline. Such future conditions could cause us to determine that any further decline in fair value is also other than temporary. If we determine that further decline is other than temporary, we will record additional write-downs in the carrying value of our asset to the then-current fair market value.
As part of our overall business strategy, we regularly evaluate opportunities to expand our portfolio of businesses and may at any time be discussing or negotiating a transaction that, if consummated, could have a material effect on our business, financial condition, liquidity or results of operations.
2017 Strategic Goals
Maintain and continue to enhance our safe operations. As we invest in and grow our business, we remain focused on operating safe and compliant operations for the benefit of our employees, communities, customers and our shareholders.
Successful completion and integration of the Alon Merger. This transaction marks our next step in our growth. We will be focused on the successful integration of the companies to capitalize on synergies, utilize the expertise from both companies to apply best practices to improve the performance of a larger asset base and unlock logistics value from the refining assets.
Utilize our position in the Permian Basin. A successful combination with Alon will create a Permian Basin focused organization as it expands our refining, logistics and retail presence in the area. The combined refining system should have approximately 300,000 barrels per day of crude throughput capacity and access to approximately 200,000 barrels per day of Permian Basin sourced crude. We believe our logistics assets are well positioned to support this larger refining system and we will gain a retail presence in west Texas through the combination. We intend to direct our efforts at exploring opportunities to utilize our Permian Basin position to create additional growth across our businesses.
Build on a winning culture. In 2016, our team implemented strategies across our operating platforms that improved our cost structure, unlocked the value of our assets and managed our operations during a challenging refining environment.  If we successfully complete the Alon Merger, we will become a larger and more diverse company, and our focus will be to foster a culture where we have the ability to act quickly in a changing environment to take advantage of opportunities. The foundation of this effort is our focus on expanding our team, developing systems and providing the resources to support a growing organization.
Focus on continued improvements in optimization of our refining system. The market environment for refining is dynamic and we strive to improve the factors within our control to create long term value. This includes a continued focus on reliability, efficiencies and yields in our refining system to improve cost, and aligning operations with commercial demand to maximize margins. We believe this will enhance our competitive position and provide free cash flow potential. As we grow, we intend to apply this focus to a larger refining platform.
Enhance our logistics assets. If we successfully complete the Alon Merger, we will look for opportunities to capitalize on increased access to the Permian Basin to increase our crude gathering operations and grow our logistics assets to support our operations as well as third parties. This will include continued development of our RIO joint venture crude oil pipeline in the Delaware Basin. In addition, our focus will be to increase our product marketing capabilities in our logistics segment to support our growing refining system.
Grow through opportunistic acquisitions. This growth platform has been a central part of the development of our integrated business model. We will be focused on the successful completion and integration of the Alon Merger, but we will continue to explore opportunities to provide long-term growth across our business platforms.
Use our financial flexibility and cash flow to create shareholder value. We are focused on managing the cash flow in our business to support our capital allocation program that includes: 1) investing in our business, 2) growing through acquisitions, and 3) returning cash to shareholders through dividends and share repurchases - all of which support our central theme of increasing long-term value for our shareholders.
2016 Strategic Developments
Retail Divestiture
In August 2016, we entered into a definitive equity purchase agreement (the "Purchase Agreement") with Compañía de Petróleos de Chile COPEC S.A. and its subsidiary, Copec Inc., a Delaware corporation (collectively, "COPEC"). Under the terms of the Purchase Agreement, Delek agreed to sell, and COPEC agreed to purchase, 100% of the equity interests in Delek's wholly-owned subsidiaries MAPCO Express, Inc., MAPCO Fleet, Inc., Delek Transportation, LLC, NTI Investments, LLC and GDK Bearpaw, LLC (collectively, the “Retail Entities”) for cash consideration of $535 million, subject to customary adjustments (the “ Retail Transaction”).

50



In November 2016, the Retail Transaction closed and, at closing, $156.0 million of debt associated with the Retail Entities was repaid, along with a debt prepayment fee of $13.4 million and $4.6 million of transaction related costs. Net cash proceeds before taxes related to the Retail Transaction are $378.9 million.
As a result of the Purchase Agreement, we met the requirements under the provisions of Accounting Standards Codification ("ASC") 205-20, Presentation of Financial Statements - Discontinued Operations and ASC 360, Property, Plant and Equipment, to report the results of the Retail Entities as discontinued operations and to classify the Retail Entities as a group of assets held for sale. See Note 5, Discontinued Operations and Assets Held for Sale, of our consolidated financial statements included in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K for further information.
Alon Merger
In January 2017, we announced that Delek, Alon USA Energy, Inc. (NYSE: ALJ) ("Alon USA"), Delek Holdco, Inc., a Delaware corporation and wholly owned subsidiary of Delek (“Holdco”), Dione Mergeco, Inc., a Delaware corporation and wholly owned subsidiary of Holdco ("Parent Merger Sub"), and Astro Mergeco, Inc., a Delaware corporation and wholly owned subsidiary of Holdco (“Astro Merger Sub” and, together with Holdco and Parent Merger Sub, the “Holdco Parties”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which (i) Parent Merger Sub will, upon the terms and subject to the conditions thereof, merge with and into Delek (the “Parent Merger”), with Delek surviving as a wholly owned subsidiary of Holdco and (ii) Astro Merger Sub will, upon the terms and subject to the conditions thereof, merge with and into Alon USA (the “Alon Merger” and, together with the Parent Merger, the “Mergers”) with Alon USA surviving as a wholly owned subsidiary of Holdco.  On February 27, 2017, Delek, Alon USA and the Holdco Parties entered into a First Amendment to Agreement and Plan of Merger (the “Amendment”). The Amendment sets forth technical amendments.
In the Parent Merger, each issued and outstanding share of common stock of Delek, par value $0.01 per share (“Delek common stock”), or fraction thereof, will be converted into the right to receive one validly issued, fully paid and non-assessable share of Holdco common stock, par value $0.01 per share (“Holdco common stock”), or such fraction thereof equal to the fractional share of Delek common stock, upon the terms and subject to the conditions set forth in the Merger Agreement. In the Alon Merger, each issued and outstanding share of common stock of Alon, par value $0.01 per share (“Alon common stock”), other than Alon USA common stock held by Delek or any subsidiary of Delek, will be converted into the right to receive 0.504 shares of Holdco common stock, upon the terms and subject to the conditions set forth in the Merger Agreement. 
Pursuant to the Merger Agreement, Delek must take all action necessary to elect as directors of Holdco the directors of Delek immediately prior to the effective time of the Parent Merger; provided, that within thirty days after the closing date, Delek and Holdco must take all action necessary to increase the size of the board of directors of Holdco by one seat and to appoint an individual to fill the resulting vacancy as designated by the special committee of the board of directors of Alon USA to fill the resulting vacancy.  Additionally, pursuant to the Merger Agreement, the special committee of the board of Alon USA will nominate one new director that will be appointed to the board of the general partner of Delek Logistics.
The mergers remain subject to the approval of the stockholders of Delek and Alon USA, along with certain other closing conditions as set forth in the Merger Agreement. Concurrently with the execution of the Merger Agreement, Alon, Delek and each of David Wiessman, D.B.W. Holdings (2005) Ltd. (an entity controlled by David Wiessman), Jeff Morris, and Karen Morris entered into Voting, Irrevocable Proxy and Support Agreements (the “Voting Agreements”) in connection with the Merger Agreement. Delek, David Wiessman, D.B.W. Holdings (2005) Ltd., Jeff Morris and Karen Morris are each individually referred to herein as an “Alon Stockholder” and collectively as the “Alon Stockholders.”
The Voting Agreements generally require that the Alon Stockholders vote or cause to be voted all Alon USA common stock owned by the Alon Stockholders at the Alon USA stockholders’ meeting in favor of (1) the Mergers and the Merger Agreement and any other transactions or matters contemplated by the Merger Agreement and (2) any proposal to adjourn or postpone the Alon USA Stockholders Meeting to a later date if there are not sufficient votes to adopt the Merger Agreement or if there are not sufficient shares present in person or by proxy at such meeting to constitute a quorum. In the case of the Alon Stockholders other than Delek, the Voting Agreements also require that they vote in favor of any other matter necessary to consummate the transactions contemplated by the Merger Agreement, in each case at every meeting (or in connection with any action by written consent) of the Alon Stockholders at which such matters are considered and at every adjournment or postponement thereof, and vote against (1) any Company Acquisition Proposal (as defined in the Merger Agreement), (2) any action, proposal, transaction or agreement that could reasonably be expected to result in a breach of any covenant, representation or warranty or any other obligation or agreement of Alon USA under the Merger Agreement or of the Alon Stockholders under the Voting Agreements and (3) any action, proposal, transaction or agreement that could reasonably be expected to impede, interfere with, frustrate, delay, discourage, adversely affect or inhibit the timely consummation of the Merger or the fulfillment of conditions under the Merger Agreement or change in any manner the voting rights of any class of shares of Alon USA.
Subject to certain exceptions, the Voting Agreements prohibit certain sales, transfers, offers, exchanges, and dispositions of Alon USA common stock owned by the Alon Stockholders, the granting of any proxies or powers of attorney that is inconsistent with the Voting Agreements, and the depositing of Alon USA common stock owned by the Alon Stockholders into a voting trust or entering into a voting agreement or arrangement with respect to the voting of shares of Alon USA common stock owned by the Alon Stockholders during the term of the Voting Agreements.

51




Return Capital to Shareholders

Dividends
We paid regular quarterly dividends of $0.15 per share, totaling $0.60 per share, during the year ended December 31, 2016. Total dividends declared during the year ended December 31, 2016 equaled $37.5 million.

Stock Repurchase Program

In February 2016, the Board of Directors authorized a share repurchase program to purchase up to $125.0 million of our common stock in the aggregate. Any share repurchases under the repurchase program were implemented through open market transactions or in privately negotiated transactions, in accordance with applicable securities laws. The timing, price, and size of repurchases were made at the discretion of management and depended on prevailing market prices, general economic and market conditions and other considerations. The repurchase program did not obligate us to acquire any particular amount of stock, and the unused portion of the authorization expired on December 31, 2016. During the year ended December 31, 2016, we repurchased 386,090 shares of our common stock under the repurchase authorization, for a total expenditure of approximately $6.0 million.

A new $150.0 million stock repurchase program was authorized by the Board of Directors on December 29, 2016. The 2017 stock repurchase authorization has no expiration date and, as of February 27, 2017, this repurchase authorization had not been utilized.



52



Market Trends
Our results of operations are significantly affected by fluctuations in the prices of certain commodities, including, but not limited to, crude oil, gasoline, distillate fuel, biofuels and natural gas and electricity, among others. Historically, our profitability has been affected by commodity price volatility, specifically as it relates to the price of crude oil and refined products.
The table below reflects the quarterly high, low and 5-3-2 crack spread over the past three years.
dk-10kx1231_chartx03894.jpg
The average Gulf Coast 5-3-2 crack spread declined to $9.12 in 2016 from $14.68 in 2015. The price of Cushing WTI crude oil declined 11.1%, from an average of $48.84 in 2015, to $43.41 in 2016. The wholesale price of refined products declined further, resulting in the decline in the Gulf Coast 5-3-2 crack spread in the year ended December 31, 2016, with the U.S. Gulf Coast price of gasoline declining 16.1%, from an average of $1.55 per gallon in 2015 to $1.30 per gallon in 2016 and the U.S. Gulf Coast price of High Sulfur Diesel declining 18.6%, from an average of $1.45 per gallon in 2015 to $1.18 per gallon in 2016. The charts below illustrate the the quarterly high, low and average prices of Cushing WTI crude oil U.S. Gulf Coast Gasoline and U.S. High Sulfur Diesel over the past three years.
dk-10kx1231_chartx05804.jpg
We believe that the fluctuation in the price of Cushing WTI crude oil in 2015 and 2016 is primarily attributable to local and global oversupply, driven by an increase in foreign exports. Fluctuations in the price of Cushing WTI crude oil impact the cost of raw materials processed at our refineries, as well as the price of finished products sold by both of our operating segments.

53




dk-10kx1231_chartx08004.jpg

dk-10kx1231_chartx10027.jpg

54



Our Tyler and El Dorado refineries both continue to have greater access to Midland WTI and Midland WTI-linked crude feedstocks compared to certain of our competitors. A combination of the addition of new pipelines, which have increased the ability to ship price-advantaged crude oil supplies to and from the mid-continent region, and a low crude oil price environment were factors in a decline in certain crude oil price differentials favorable to us. As these price differentials decrease, so does our competitive advantage created by our access to Midland WTI-linked crude oil. The chart below illustrates the differentials of both Brent crude oil and Midland WTI crude oil as compared to Cushing WTI crude oil.
dk-10kx1231_chartx12347.jpg

55



Environmental regulations continue to affect our margins in the form of the increasing cost of RINs. On a consolidated basis, we work to balance our RINs obligations in order to minimize the effect of RINs on our results. While we generate RINs in both of our operating segments through our ethanol blending and biodiesel production, our refining segment needs to purchase additional RINs to satisfy its obligations. As a result, increases in the price of RINs generally adversely affect our results of operations. It is not possible at this time to predict with certainty what future volumes or costs may be, but given the increase in required volumes and the volatile price of RINs, the cost of purchasing sufficient RINs could have an adverse impact on our results of operations if we are unable to recover those costs in the price of our refined products. The chart below illustrates the volatile nature of the price for RINs over the past three years.
dk-10kx1231_chartx14319.jpg




56



Results of Operations
The table below sets forth certain information concerning our consolidated operations:
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
Net sales
 
$
4,197.9

 
$
4,782.0

 
$
7,019.2

Operating costs and expenses:
 
 
 
 
 
 
Cost of goods sold
 
3,812.9

 
4,236.9

 
6,213.3

Operating expenses
 
249.3

 
270.3

 
258.7

Insurance proceeds — business interruption
 
(42.4
)
 

 

General and administrative expenses
 
106.1

 
100.6

 
105.2

Depreciation and amortization
 
116.4

 
106.0

 
83.2

Other operating expense (income), net
 
4.8

 
(0.5
)
 
0.1

Total operating costs and expenses
 
4,247.1

 
4,713.3

 
6,660.5

Operating (loss) income
 
(49.2
)
 
68.7

 
358.7

Interest expense
 
54.4

 
52.1

 
33.5

Interest income
 
(1.5
)
 
(1.1
)
 
(0.8
)
Loss (income) from equity method investments
 
43.4

 
(2.0
)
 

Loss on impairment of equity method investment
 
245.3

 

 

Gain on sale of Retail Entities
 

 

 

Other expense (income), net
 
0.4

 
(1.6
)
 
(0.9
)
Total non-operating expenses, net
 
342.0

 
47.4

 
31.8

(Loss) income from continuing operations before income tax (benefit) expense
 
(391.2
)
 
21.3

 
326.9

Income tax (benefit) expense
 
(171.5
)
 
(15.8
)
 
101.6

(Loss) income from continuing operations
 
(219.7
)
 
37.1

 
225.3

Discontinued operations
 
 
 
 
 
 
Income from discontinued operations
 
144.2

 
5.7

 
0.6

Income tax expense (benefit)
 
57.9

 
(0.9
)
 
(0.1
)
Income from discontinued operations, net of tax
 
86.3

 
6.6

 
0.7

Net (loss) income
 
(133.4
)
 
43.7

 
226.0

Net income attributed to non-controlling interest
 
20.3

 
24.3

 
27.4

Net (loss) income attributable to Delek
 
$
(153.7
)
 
$
19.4

 
$
198.6



57



Consolidated Results of Operations — Comparison of the Year Ended December 31, 2016 versus the Year Ended December 31, 2015 and the Year Ended December 31, 2015 versus the Year Ended December 31, 2014
Net Sales
We generated net sales of $4,197.9 million and $4,782.0 million during the years ended December 31, 2016 and 2015, respectively, a decrease of $584.1 million, or 12.2%. The decrease in net sales was primarily attributable to decreases in refined product sales prices across both operating segments, as well as decreased sales volumes attributed to our west Texas operations in the logistics segment for 2016, as compared to 2015. These decreases were partially offset by an increase in sales volumes at the Tyler refinery, attributable to lower volumes in 2015 due to downtime at the Tyler refinery related to the turnaround and expansion project completed in the first quarter of 2015.
We generated net sales of $4,782.0 million and $7,019.2 million during the years ended December 31, 2015 and 2014, respectively, a decrease of $2,237.2 million, or 31.9%. The decrease in net sales was primarily attributable to decreases in refined product sales prices across both operating segments, as well as a decrease in sales volumes at the Tyler refinery due to the downtime associated with the turnaround and expansion projects completed in the first quarter of 2015, as well as decreased sales volumes attributed to our west Texas operations in the logistics segment for 2015, as compared to 2014. These decreases were partially offset by an increase in sales volumes at the El Dorado refinery.
Cost of Goods Sold
Cost of goods sold was $3,812.9 million for the year ended December 31, 2016, compared to $4,236.9 million for 2015, a decrease of $424.0 million, or 10.0%. The decrease in cost of goods sold was primarily due to a decrease in the average cost of refined products in the logistics segment, a decrease in the cost of crude oil in the refining segment and a decrease in sales volumes in the west Texas operations in the logistics segment and a decrease in throughputs at the El Dorado refinery. Partially offsetting these decreases were losses associated with our hedging program of $45.6 million for the year ended December 31, 2016, compared to losses of $10.2 million for the year ended December 31, 2015.
Cost of goods sold was $4,236.9 million for the year ended December 31, 2015, compared to $6,213.3 million for 2014, a decrease of $1,976.4 million, or 31.8%. The decrease in cost of goods sold was primarily due to a decrease in the average cost of refined products in the logistics segment, a decrease in the cost of crude oil in the refining segment and a decrease in sales volumes in the west Texas operations in the logistics segment and at the Tyler refinery. Partially offsetting these decreases were losses associated with our hedging program of $10.2 million for the year ended December 31, 2015, compared to gains of $131.7 million for the year ended December 31, 2014.
 
Operating Expenses
Operating expenses were $249.3 million for the year ended December 31, 2016 compared to $270.3 million in 2015, a decrease of $21.0 million, or 7.8%. The decrease in operating expenses is primarily attributable to decreases in utilities and oil spill remediation expenses in the refining segment, reduced maintenance expenses in the logistics segment and cost reduction initiatives at both the refining and logistics segments. These decreases were partially offset by a full year of operating expenses at the Tyler refinery for the year ended December 31, 2016, as compared to reduced expenses resulting from the downtime associated with the turnaround and an expansion project during the first quarter of 2015, and increased expenses associated with an internal tank contamination at one of our terminal locations in the logistics segment.
Operating expenses were $270.3 million for the year ended December 31, 2015 compared to $258.7 million in 2014, an increase of $11.6 million, or 4.5%. The increase in operating expenses is primarily attributable to various maintenance initiatives in the logistics segment and increases in labor, electricity, catalyst and outside services expenses at the El Dorado refinery. These were partially offset by the downtime associated with the turnaround and expansion projects completed at the Tyler refinery in the first quarter of 2015, as well as a decline in insurance expenses at the Tyler refinery.
Insurance proceeds — business interruption
We recognized proceeds from business interruption insurance claims of $42.4 million for the year ended December 31, 2016, associated with a litigation settlement. We did not record any insurance proceeds for the years ended December 31, 2015 or 2014.
General and Administrative Expenses
General and administrative expenses were $106.1 million for the year ended December 31, 2016 compared to $100.6 million in 2015, an increase of $5.5 million, or 5.5%. The overall increase was primarily due to expenses associated with the Retail Transaction and the Mergers, as well as a decrease in expenses in 2015 due to a reimbursement of expenses associated with the insurance proceeds mentioned above. These increases were partially offset by a decrease in expenses associated with a new payroll system project initiated in 2015.
General and administrative expenses were $100.6 million for the year ended December 31, 2015 compared to $105.2 million in 2014, a decrease of $4.6 million, or 4.4%. The overall decrease was primarily due to a decrease in outside services, as well as lower employee related expenses due to lower earnings in the year ended December 31, 2015, as compared to 2014. These decreases were partially offset by an increase in acquisition related expenses and expenses associated with a new payroll system project initiated in 2015.
Depreciation and Amortization
Depreciation and amortization was $116.4 million and $106.0 million for the years ended December 31, 2016 and 2015, respectively, an increase of $10.4 million, or 9.8%. This increase was


58



primarily attributable to the turnaround and expansion of the Tyler refinery completed in the first quarter of 2015, as well as other capital expenditures and acquisitions completed in 2015.
Depreciation and amortization was $106.0 million and $83.2 million for the years ended December 31, 2015 and 2014, respectively, an increase of $22.8 million, or 27.4%. This increase was primarily due to the completion of capital projects in the refining segment and accelerated depreciation of assets replaced in the turnaround and expansion of the Tyler refinery completed in the first quarter of 2015.
Other Operating (Income) Expense, Net
Other operating expense, net for the year ended December 31, 2016 was $4.8 million and primarily related to losses on asset disposals in 2016. Other operating income, net for the year ended December 31, 2015 was $0.5 million and primarily related to settlement of certain sales and use tax overpayments from prior years, partially offset by a $2.2 million impairment of certain equipment assets in our refining segment. Other operating expense, net for the year ended December 31, 2014 was 0.1 million.
Interest Expense
Interest expense was $54.4 million in the year ended December 31, 2016, compared to $52.1 million for 2015, an increase of $2.3 million, or 4.4%. The increase was primarily attributable to interest costs associated with increased debt levels related to the investment in Alon USA. The increase was partially offset by $3.9 million in one-time fees associated with the amendment of the Lion Term Loan in the second quarter of 2015.
Interest expense was $52.1 million in the year ended December 31, 2015, compared to $33.5 million for 2014, an increase of $18.6 million, or 55.5%. The increase was primarily attributable to $3.9 million of one-time fees associated with the amendment to the Lion Term Loan and interest costs associated with increased debt levels related to the Alon Acquisition in the second quarter of 2015.
Loss (Income) from Equity Method Investments
Loss from equity method investments was $43.4 million in the year ended December 31, 2016, compared to income of $2.0 million for 2015. The change was primarily attributable to our proportionate share of the net (loss) income from our investment in Alon USA of $(39.6) million in the year ended December 31, 2016 compared to $4.1 million for 2015, which included a reduction of $18.7 million associated with an impairment of goodwill taken by Alon USA in the fourth quarter of 2015. (Loss) income from equity method investments is net of $2.6 million and $1.5 million in amortization of the excess of our investment over our equity in the underlying net assets of Alon USA for the years ended December 31, 2016 and 2015, respectively. We did not hold any equity method investments
 
in 2014.
Other Expense (Income), Net
Other expense (income), net was $0.4 million, $(1.6) million and $(0.9) million in the years ended December 31, 2016, 2015 and 2014, respectively, and was primarily attributable to changes in foreign currency gains/losses and miscellaneous other income/expense in all three years.
Income Taxes (Benefit) Expense
Income tax benefit was $171.5 million and $15.8 million during the years ended December 31, 2016 and 2015, respectively, an increase of $155.7 million. Our effective tax rate was 43.8% for 2016, compared to (74.2)% for 2015. The change in our effective tax rate for 2016 was primarily due to a decrease in state income taxes and lower pre-tax income for 2016 as compared to 2015.
Income tax (benefit) expense was $(15.8) million and $101.6 million during the years ended December 31, 2015 and 2014, respectively, a decrease of $117.4 million. Our effective tax rate was (74.2)% for 2015, compared to 31.1% for 2014. The decrease in our effective tax rate for 2015 was primarily due to an increase in tax credits and incentives and lower pre-tax income for 2015, as compared to 2014.







59



Operating Segments
We report operating results in two reportable segments: refining and logistics. Decisions concerning the allocation of resources and assessment of operating performance are made based on this segmentation. Management measures the operating performance of each of our reportable segments based on the segment contribution margin.
Refining Segment
The tables and charts below set forth certain information concerning our refining segment operations ($ in millions, except per barrel information):
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
Net sales
 
$
3,923.2

 
$
4,440.2

 
$
6,350.5

Cost of goods sold
 
3,658.8

 
4,022.2

 
5,664.8

Gross Margin
 
264.4

 
418.0

 
685.7

Operating expenses
 
212.4

 
225.4

 
221.0

Insurance proceeds - business interruption
 
(42.4
)
 

 

Contribution margin
 
$
94.4

 
$
192.6

 
$
464.7

dk-10kx1231_chartx02768.jpg

 
dk-10kx1231_chartx04588.jpg
1 
Sales volume includes 622 bpd, 3,693 bpd and 1,096 bpd of finished product sold to the logistics segment during the years ended December 31, 2016, 2015 and 2014, respectively. Sales volume also includes sales of 510 bpd, 1,800 bpd and 3,324 bpd of intermediate and finished products to the El Dorado refinery during the years ended December 31, 2016, 2015 and 2014, respectively. Sales volume excludes 1,008 bpd and 1,635 bpd of wholesale activity during the years ended December 31, 2016 and 2015, respectively. There was no wholesale activity during the year ended December 31, 2014.
dk-10kx1231_chartx05753.jpg


60



dk-10kx1231_chartx06589.jpg
dk-10kx1231_chartx08567.jpg
1 
Sales volume includes 102 bpd, 1,744 bpd and 1,609 bpd of produced finished product sold to the Tyler refinery during the years ended December 31, 2016, 2015 and 2014, respectively. Sales volume excludes 20,465 bpd, 28,057 bpd and 13,842 bpd of wholesale activity during the years ended December 31, 2016, 2015 and 2014, respectively.
 

dk-10kx1231_chartx09627.jpg
Refining Segment Operational Comparison of the Year Ended December 31, 2016 versus the Year Ended December 31, 2015 and the Year Ended December 31, 2015 versus the Year Ended December 31, 2014
Net Sales
dk-10kx1231_chartx10525.jpg
Net sales for the refining segment were $3,923.2 million and $4,440.2 million during the years ended December 31, 2016 and 2015, respectively, a decrease of $517.0 million, or 11.6%. The decrease in net sales was primarily due to declines in the average price of U.S. Gulf Coast gasoline and diesel and a 4.3% decrease in sales volumes at the El Dorado refinery. These declines were partially offset by a 18.1% increase in net sales volume at the Tyler refinery. The increase in sales volume at the Tyler refinery was attributable to lower volumes in 2015 due to downtime at the Tyler refinery related to the turnaround and an expansion project completed in the first quarter of 2015.
Net sales for the refining segment were $4,440.2 million and $6,350.5 million during the years ended December 31, 2015 and 2014, respectively, a decrease of $1,910.3 million, or 30.1%. The


61



decrease in net sales was primarily due to declines in the average price of U.S. Gulf Coast gasoline and diesel and a decrease in sales volumes at the Tyler refinery due to downtime at the Tyler refinery related to the turnaround and an expansion project completed in the first quarter of 2015. These declines were partially offset by a 5.4% increase in net sales volume at the El Dorado refinery. During the years ended December 31, 2015 and 2014, the refining segment sold $619.4 million and $622.1 million, or 26,683 and 17,490 bpd, respectively, of finished product to the logistics segment. These sales are eliminated in consolidation.
Cost of Goods Sold
dk-10kx1231_chartx11646.jpg
Cost of goods sold for the year ended December 31, 2016 was $3,658.8 million compared to $4,022.2 million for the year ended December 31, 2015, a decrease of $363.4 million, or 9.0%. The decrease in cost of goods sold was primarily a result of the decrease in the cost of WTI crude oil, as well as the decrease in throughputs at the El Dorado refinery. These decreases were partially offset by an increase in throughputs at the Tyler refinery, as well as hedging losses associated with our hedging program of $43.5 million in 2016, compared to losses of $10.7 million in 2015.
Cost of goods sold for the year ended December 31, 2015 was $4,022.2 million compared to $5,664.8 million for the year ended December 31, 2014, a decrease of $1,642.6 million, or 29.0%. The decrease in cost of goods sold was primarily a result of the decrease in the cost of WTI crude oil, as well as the decrease in throughputs at the Tyler refinery. These decreases were partially offset by an increase in throughputs at the El Dorado refinery, as well as hedging losses associated with our hedging program of $10.7 million in 2015, compared to gains of $128.6 million in 2014.
Our refining segment has multiple service agreements with our logistics segment, which, among other things, require the refining segment to pay terminalling and storage fees based on the throughput volume of crude and finished product in the logistics segment pipelines and the volume of crude and finished product stored in the logistics segment storage tanks. These fees were $123.2 million, $121.6 million and $95.0 million during the years ended December 31, 2016, 2015 and 2014, respectively, and are
 
included in cost of goods sold for the refining segment. We eliminate these intercompany fees in consolidation.
Operating Expenses
Operating expenses were $212.4 million for the year ended December 31, 2016, compared to $225.4 million in 2015, a decrease of $13.0 million, or 5.8%. The decrease in operating expenses was primarily due to decreases in utilities expenses, primarily due to a reduction in natural gas prices and consumption, a decrease in oil spill remediation costs and certain cost reduction initiatives at both refineries. These were partially offset by a full year of operating expenses at the Tyler refinery for the year ended December 31, 2016, as compared to reduced expenses resulting from downtime associated with the turnaround and an expansion project completed in the first quarter of 2015.
Operating expenses were $225.4 million for the year ended December 31, 2015, compared to $221.0 million in 2014, an increase of $4.4 million, or 2.0%. The increase in operating expenses was primarily due to increases in labor, electricity, catalyst and outside services expenses at the El Dorado refinery, which were partially offset by the downtime associated with the turnaround and expansion projects completed at the Tyler refinery in the first quarter of 2015, as well as a decline in insurance expenses at the Tyler refinery.
Contribution Margin
dk-10kx1231_chartx12546.jpg
Contribution margin for the refining segment for the year ended December 31, 2016 was $94.4 million, or 53.0% of our consolidated contribution margin, compared to $192.6 million, or 70.1% of our consolidated segment contribution margin, for the year ended December 31, 2015. The decrease to the refining segment contribution margin was primarily attributable to a decline in operating margins at both refineries, which were partially offset by business interruption insurance proceeds of $42.4 million associated with a settlement of litigation received in the first quarter of 2016, as well as an increase in sales volumes at the Tyler refinery in the year ended December 31, 2016, attributable to lower volumes in 2015 due to


62



downtime at the Tyler refinery related to the turnaround and an expansion project completed in the first quarter of 2015.
Contribution margin for the refining segment for the year ended December 31, 2015 was $192.6 million, or 70.1% of our consolidated contribution margin, compared to $464.7 million, or 84.9% of our consolidated segment contribution margin, for the year ended December 31, 2014. The decrease to the refining segment contribution margin was primarily attributable to a decrease in sales volumes at the Tyler refinery, as a result of the downtime at the Tyler refinery associated with the turnaround and expansion projects completed in the first quarter of 2015 and a decline in margins at both refineries. This was partially offset by subsequent volume increases at the Tyler refinery as a result of the expansion project as well as an increase in sales volumes at the El Dorado refinery.
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Margins at both refineries were negatively impacted by the decline in the average differential between WTI Midland crude oil and WTI Cushing crude oil and a decline in the Gulf Coast 5-3-2 crack spread, which was driven by declines in the US Gulf Coast price of gasoline and High Sulfur Diesel of 16.1% and 18.6%, respectively, coupled with a lower decline in the cost of WTI crude oil of 11.1%. In the Tyler refinery, Midland crude oil accounted for 81.7% and 77.5% of the crude slate in 2016 and 2015, respectively. In the El Dorado refinery, Midland crude oil accounted for 70.6% and 62.8% of the crude slate in 2016 and 2015, respectively. Further contributing to the decline in margins was an increase in consolidated RINs costs, net of benefits from our biodiesel facilities, for the refining segment, to $40.4 million in 2016, from $19.6 million in 2015.
The decrease in margins from 2015, as compared to 2014, primarily resulted from the decreased differential between WTI crude oil and Midland crude oil. In the Tyler refinery, Midland crude oil accounted for 77.5% and 90.5% of the crude slate in 2015 and 2014, respectively. In the El Dorado refinery, Midland crude oil accounted for 62.8% and 49.5% of the crude slate in 2015 and 2014, respectively. This was partially offset by an increase in the benchmark Gulf Coast crack spread, which was driven by a 47.4% decline in the cost of WTI crude oil, coupled with smaller declines in the US Gulf Coast price of gasoline and high sulfur diesel of 37.8% and 44.0%, respectively.
 




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Logistics Segment
The table below sets forth certain information concerning our logistics segment operations:
 
 
Year Ended December 31,