10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Fiscal Year Ended December 31, 2017

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 001-35721

DELEK LOGISTICS PARTNERS, LP

(Exact name of registrant as specified in its charter)

Delaware	45-5379027
(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 Units Representing Limited Partner Interests	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. YesoNoþ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  YesoNoþ

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. YesþNoo

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).  Yesþ Noo

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. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer    oAccelerated filer  þNon-accelerated filero Smaller reporting company o Emerging growth company ¨

(Do not check if a smaller reporting company)

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes oNoþ

The aggregate market value of the registrant's common limited partner units held by non-affiliates as of June 30, 2017 was approximately $296,957,710, based upon the closing price of its common units on the New York Stock Exchange on that date.

At February 26, 2018, there were 24,382,633common limited partner units and 497,604 general partner units outstanding.

Documents incorporated by reference: None

TABLE OF CONTENTS

	PART I
Item 1.	Business	3
Item 1A.	Risk Factors	20
Item 1B.	Unresolved Staff Comments	45
Item 2.	Properties	45
Item 3.	Legal Proceedings	46
Item 4.	Mine Safety Disclosures	46
	PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	46
Item 6.	Selected Financial Data	49
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	50
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	75
Item 8.	Financial Statements and Supplementary Data	76
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	76
Item 9A.	Controls and Procedures	76
Item 9B.	Other Information	77
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	78
Item 11.	Executive Compensation	84
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	90
Item 13.	Certain Relationships and Related Transactions, and Director Independence	91
Item 14.	Principal Accountant Fees and Services	94
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	94
Item 16.	Form 10-K Summary	98
	Signatures

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Unless otherwise indicated or the context requires otherwise, the terms "Delek Logistics Partners, LP," the "Partnership," “we,” “us,” or “our” may refer to Delek Logistics Partners, LP, one or more of its consolidated subsidiaries or all of them taken as a whole.

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 included in Item 1, Business, of this Annual Report on Form 10-K.

PART I

ITEM 1.  BUSINESS

General

Delek Logistics Partners, LP is a Delaware limited partnership formed in April 2012 by Old Delek (as defined below) and its subsidiary Delek Logistics GP, LLC, our general partner (our "general partner"). In November 2012, the Partnership completed its initial public offering (the "Offering").

In January 2017, Delek US Holdings, Inc. ("Old Delek") (and various related entities) entered into an Agreement and Plan of Merger with Alon USA Energy, Inc. (NYSE: ALJ) ("Alon USA"), as subsequently amended on February 27 and April 21, 2017 (as so amended, the "Merger Agreement"). The related merger (the "Delek/Alon Merger") was effective July 1, 2017 (the “Effective Time”), resulting in a new post-combination consolidated registrant renamed Delek US Holdings, Inc. (“New Delek”), with Alon USA and Old Delek surviving as wholly-owned subsidiaries. New Delek is the successor issuer to Old Delek and Alon USA pursuant to Rule 12g-3(c) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Unless the context otherwise requires, references in this report to "Delek" refer collectively to Old Delek with respect to periods prior to July 1, 2017, or New Delek, with respect to periods on or after July 1, 2017, and any of Old Delek's or New Delek's, as applicable, subsidiaries, other than the Partnership and its subsidiaries and its general partner.

The Partnership's business primarily consists of certain crude oil, intermediate and refined products pipelines and transportation, storage, wholesale marketing, terminalling and offloading assets which were previously owned, operated or held by Delek and assets acquired from unrelated third parties. Irrespective of the party from whom we acquired our assets, Delek is our primary or sole customer for a substantial majority of our assets and is responsible, directly or indirectly, for the majority of our gross margin (as defined below).

Overview

The Partnership primarily owns and operates logistics and marketing assets for crude oil and intermediate and refined products. We generate revenue and contribution margin, which we define as net sales less cost of goods sold and operating expenses, by charging fees for gathering, transporting, offloading and storing crude oil; for storing intermediate products and feed stocks; for distributing, transporting and storing refined products; and for wholesale marketing. A substantial majority of our existing assets are both integral to and dependent on the success of Delek's refining operations and most of our assets are contracted exclusively to Delek in support of Delek's refineries in Tyler, Texas (the "Tyler Refinery") and El Dorado, Arkansas (the "El Dorado Refinery"). See "—Commercial Agreements—Commercial Agreements with Delek" and Note 4 to the consolidated financial statements in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K, for a discussion of our material commercial agreements with Delek. In addition to the services we provide to Delek, we also provide, and generate substantial revenue and contribution margin from, crude oil, intermediate and refined products transportation services for, and terminalling and marketing services to, third parties primarily in Texas, Tennessee and Arkansas. Certain of these services are provided pursuant to contractual agreements with such third parties. See "—Commercial Agreements—Other Agreements with Third Parties."

We are not a taxable entity for federal income tax purposes or the income taxes of those states that follow the federal income tax treatment of partnerships. Instead, for purposes of such income taxes, each partner of the Partnership is required to take into account

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its share of items of income, gain, loss and deduction in computing its federal and state income tax liabilities, regardless of whether cash distributions are made to such partner by the Partnership. The taxable income reportable to each partner takes into account differences between the tax basis and the fair market value of our assets and financial reporting bases of assets and liabilities, the acquisition price of the partner's units and the taxable income allocation requirements under the Partnership's First Amended and Restated Agreement of Limited Partnership (the "Partnership Agreement").

Recent Developments

Big Spring Asset Dropdown. On February 26, 2018, a definitive agreement was entered into between the Partnership and Delek to acquire certain logistics assets primarily located adjacent to Delek's Big Spring, Texas refinery. In connection with the closing of the transaction, Delek, the Partnership and various of their subsidiaries expect to enter into a new wholesale and marketing agreement and amend certain existing contracts, such as new throughput and tankage agreement for the Big Spring Logistics Assets. See Note 21 to the consolidated financial statements in Item 8. Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.

Formation of Green Plains Joint Venture.On February 20, 2018, the Partnership and Green Plains Partners LP ("Green Plains") announced the companies have formed DKGP Energy Terminals, LLC ("DKGP Energy"), a joint venture engaging in the light products terminalling business. The Partnership and Green Plains will each own a 50% membership interest in DKGP Energy. DKGP Energy signed a membership interest purchase agreement to acquire two light products terminals located in Caddo Mills, Texas and North Little Rock, Arkansas from an affiliate of American Midstream Partners, L.P. ("American Midstream"). Subject to customary closing conditions and regulatory approvals, this transaction is expected to close in the first half of 2018. DKGP Energy will consist of the assets purchased from the affiliate of American Midstream and assets contributed by the Partnership. Immediately prior to the closing of the acquisition by the joint venture of the two terminals from American Midstream, the Partnership will contribute to the joint venture its North Little Rock, Arkansas terminal and its Greenville tank farm located in Caddo Mills, Texas. The DKGP Energy board will oversee the newly formed joint venture and will appoint an affiliate of the Partnership as the operator with day-to-day operational responsibilities of the four terminals.

Acquisition of Non-controlling Interest in Alon Partnership.On November 8, 2017, Delek and Alon USA Partners, LP (the "Alon Partnership") entered into a definitive merger agreement under which Delek agreed to acquire all of the outstanding limited partner units of the Alon Partnership that Delek did not already own in an all-equity transaction (the "Alon Partnership Transaction"). The Alon Partnership Transaction was approved by the board of directors of Delek and by all voting members of the board of directors of the general partner of the Alon Partnership upon the recommendation from its conflicts committee. As a result of the Alon Partnership Transaction, we anticipate additional growth opportunities through subsequent dropdowns of logistics assets acquired by Delek through the transaction. The Alon Partnership Transaction closed on February 7, 2018.

Big Spring Pipeline Acquisition.  On September 15, 2017, the Partnership, through its wholly owned subsidiary, Delek Marketing & Supply, LP, acquired from Plains Pipeline, L.P. an approximately 40-mile pipeline and related ancillary assets (the "Big Spring Pipeline") (such transaction, the "Big Spring Acquisition") for approximately $9.0 million to complement our existing asset base. The Big Spring Pipeline originates in Big Spring, Texas and terminates in Midland, Texas.

Delek/Alon Merger. In January 2017, Old Delek, New Delek and various related entities entered into the Merger Agreement with Alon USA. The transactions contemplated by the Merger Agreement became effective on July 1, 2017, and, among other things, resulted in Alon USA and Old Delek surviving as wholly-owned subsidiaries of New Delek. The Delek/Alon Merger did not affect the Partnership's commercial agreements with Delek discussed in Note 4 to the consolidated financial statements in Item 8. Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.

Inflation Adjustments.  On July 1, 2017, the tariffs on our Federal Energy Regulatory Commission ("FERC") regulated pipelines and the throughput fees and storage fees under certain of our agreements with Delek and third parties that are subject to adjustment using FERC indexing increased by approximately 0.2%, the amount of the change in the FERC oil pipeline index. Under certain of our other agreements with Delek and third parties, the fees increased based on the consumer price index or the producer price index, which increased approximately 1.8% and 1.6%, respectively. Any applicable decreases to such fees in the future will not result in a reduction to an amount below the fee initially set forth in such agreements.

6.750% Senior Notes Due 2025. On May 23, 2017, the Partnership and Delek Logistics Finance Corp., a Delaware corporation and a wholly owned subsidiary of the Partnership (“Finance Corp.” and together with the Partnership, the “Issuers”), issued $250.0 million in aggregate principal amount of 6.750% senior notes due 2025 (the “2025 Notes”). The 2025 Notes are general unsecured senior obligations of the Issuers. The net proceeds from the issuance of the 2025 Notes totaled approximately $242.3 million, after deducting the initial

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purchasers' discount, commissions and offering expenses. The Partnership used substantially all of the net proceeds to pay down a portion of the outstanding balance under the Partnership's revolving credit facility. See Note 11 to the consolidated financial statements in Item 8. Financial Statements and Supplementary Data, of this Annual Report on Form 10-K for further discussion.

Caddo Pipeline. In March 2015, we entered into a joint venture to construct a crude oil pipeline system and related ancillary assets (the "Caddo Pipeline"), which is serving third parties and subsidiaries of Delek. We own a 50% membership interest in the entity formed with an affiliate of Plains All American Pipeline, L.P. to construct the Caddo Pipeline. Operations on the Caddo Pipeline began in January 2017.

Assets and Operations

We prepare segment information on the same basis that we review financial information for operational decision-making purposes. Currently, our business consists of two operating segments: (i) pipelines and transportation and (ii) wholesale marketing and terminalling. 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 Note 15, Segment Data, of our consolidated financial statements included in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K. Our principal assets, as of December 31, 2017, are described below under the segment that uses such assets.

The following provides an overview of our assets and operations:

Pipelines and Transportation Segment

Our pipelines and transportation segment consists of assets, including pipelines and trucks and ancillary assets, that provide crude oil gathering and crude oil, intermediate and finished products transportation and storage services primarily in support of the Tyler and El Dorado Refineries. Additionally, this segment provides crude oil and other products transportation services to certain unrelated third parties. In providing these services, we do not take ownership of the products or crude oil that we transport or store; and, therefore, the results of our pipelines and transportation segment are not directly exposed to changes in commodity prices. Our pipeline assets include approximately 460 miles of operable crude oil transportation pipelines, approximately 406 miles of refined product pipelines and approximately 600 miles of crude oil gathering and trunk lines. Associated with and currently used in connection with the operation of these lines are crude oil, intermediate and refined products storage tanks with an aggregate of approximately 7.3 million barrels of active shell capacity. We also own 95 tractors and 231 trailers used to haul primarily crude oil, finished products and other hydrocarbon products for unrelated and related third parties.

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The discussion and tables below describe the operating results for each of our operating systems within this segment for the years ended December 31, 2017, 2016 and 2015.

Lion Pipeline System. Our Lion Pipeline System is a system of common carrier pipelines that transport crude oil to, and refined products from, Delek's El Dorado Refinery. The Lion Pipeline System consists primarily of:

• the Magnolia Pipeline system;

• the El Dorado Pipeline system;

• multiple short crude oil pipelines located at the El Dorado Refinery and our Sandhill Station;

• the Magnolia Station located west of the El Dorado Refinery;

• the Refined Products Pipeline system; and

• certain related crude oil pipelines.

The Magnolia Pipeline is an approximately 77-mile crude oil pipeline, with a capacity of approximately 68,500 bpd, which runs from a connection with ETP/ExxonMobil’s LOLA System near Shreveport, Louisiana to our Magnolia Station, where the crude oil is then stored and transferred to our El Dorado Pipeline. In addition, third-party pipelines connect to the Magnolia Pipeline near Haynesville, Louisiana, which allows for the receipt of crude oil transported from Longview, Texas. The service provided on the Magnolia Pipeline is regulated by the FERC and is subject to FERC tariffs.     

The El Dorado Pipeline is a 28-mile, 12-inch crude oil pipeline, with a capacity of approximately 22,000 bpd, which transports crude oil from our Magnolia Station to Delek's Sandhill Station adjacent to the El Dorado Refinery. The service provided on the El Dorado Pipeline is regulated by the FERC and is subject to FERC tariffs. Upon reaching Sandhill Station, the crude oil from the El Dorado Pipeline is transported, via multiple short crude oil pipelines owned by us, to Tank 192, a 150,000 barrel capacity storage tank ("Tank 192") or to Tank 120, an 80,000 barrel capacity storage tank ("Tank 120"), which receives heavier asphaltic crudes. At present, substantially all crude oil that enters the El Dorado Refinery, including the crude oil gathered on the SALA Gathering System, is routed through Sandhill Station. Through our SALA subsidiary, we own Tank 192 and Tank 120 and lease the underlying ground from Lion Oil under a long-term ground lease.

The Magnolia Station is a location, owned by us, where the Magnolia and Lion Pipelines and SALA Gathering System have origination and destination points, as the case may be. In addition, the Magnolia Station has storage facilities with approximately 220,000 barrels of active shell capacity, which includes the addition of an 85,000 barrel crude oil storage tank in the fourth quarter of 2016.

We also own two refined product pipelines that transport gasoline and diesel from the El Dorado Refinery to the nearby Enterprise TE Products Pipeline El Dorado Station (the “Refined Products Pipelines”). Pursuant to a capacity lease with Enterprise dated October 24, 2013, we also lease capacity of approximately 11,000 bpd on the approximately 240-mile Enterprise Products Pipeline from Enterprise's El Dorado Station to our refined products terminal in Memphis, Tennessee. The Refined Products Pipelines along with the leased capacity are collectively referred to as the "Refined Products Pipeline System." The service provided on the Refined Products Pipelines is regulated by the FERC and is subject to a FERC tariff. The diesel line is approximately eight miles and is 12 inches in diameter, while the gasoline line is approximately eight miles and is 10 inches in diameter. These two lines commence at the El Dorado Refinery.

The pipelines in the Lion Pipeline System also have injection points where crude oil gathered from the SALA Gathering System can be injected and then transported to the El Dorado Refinery. Movements from the SALA Gathering System onto the Lion Pipeline System to the El Dorado Refinery are subject to a joint tariff for the transportation of these volumes that is on file with the FERC for both the SALA Gathering System and the El Dorado Pipeline; the joint rate for these movements is equal to the rate that would apply for movements only on the SALA Gathering System to the connection point with the Lion Pipeline System. The Lion Pipeline System has crude oil storage tanks and facilities ancillary to the operation of the pipeline system. The Lion Pipeline System is capable of transporting crude oil offloaded from rail cars at or near the El Dorado Refinery, including at the two crude oil rail offloading racks we acquired in March 2015. See "El Dorado Rail Offloading Racks" below.

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The table below details certain operating data for our Lion Pipeline System.

	Average Daily Throughput (bpd)
	Year Ended
	December 31,
	2017	2016	2015
Lion Pipeline System:
Crude Oil Pipelines (Non-gathered) (1)	59,362	56,555	54,960
Refined Products Pipelines to Enterprise System	51,927	52,071	57,366

⁽¹⁾  Excludes crude oil gathered on our SALA Gathering System and injected into our Lion Pipeline System.

SALA Gathering System. The SALA Gathering System is a system of common carrier pipelines that primarily gathers and transports crude oil and condensate that is purchased from various crude oil producers in Arkansas, Texas and Louisiana by Delek or a third party to whom Delek has assigned certain of its rights. Service on the SALA Gathering System is regulated by the FERC and is subject to tariffs on file with the FERC. The SALA Gathering System includes approximately 600 miles of two- to eight-inch crude oil gathering and transportation lines in southern Arkansas and northern Louisiana, located primarily within a 60-mile radius of the El Dorado Refinery. In addition, the gathering system transports small volumes of crude oil that are received from other sources and condensate that is purchased from a third party in east Texas. All such crude oil and other products are ultimately transported to the El Dorado Refinery for processing. In addition, a pipeline within the SALA Gathering System transports minimal crude oil for third party shippers pursuant to a common carrier tariff.

The SALA Gathering System includes 53 crude oil storage tanks and breakout tanks with a total combined active shell capacity of approximately 0.8 million barrels (including Tank 120, Tank 192 and approximately 37,000 barrels of capacity we lease to an unrelated third party), 14 truck receipt locations, approximately 500 pipeline gathering and receiving stations and 17 relay stations to deliver crude oil to the Magnolia Station, the El Dorado Pipeline System or directly to the El Dorado Refinery. We also have approximately 0.5 million barrels of combined shell capacity that is currently not in service. The table below sets forth historical throughput information for the SALA Gathering System.

	Average Daily Throughput (bpd)
	Year Ended
	December 31,
	2017	2016	2015
SALA Gathering System:
Throughput (average bpd):	15,871	17,756	20,673

Paline Pipeline System. Our Paline Pipeline System is primarily a 195-mile, 10-inch crude oil pipeline, with a capacity of approximately 36,000 bpd, running from Longview, Texas to the Phillips 66-operated Beaumont terminal in Nederland, Texas. It includes a three-mile section that runs north from Kilgore, Texas. Our Paline Pipeline System is operated as a common carrier pipeline and the service is regulated by the FERC. See "—Commercial Agreements—Other Agreements with Third Parties—Paline Pipeline System Capacity Reservation" for additional information on the use of our Paline Pipeline System.  

East Texas Crude Logistics System. Our East Texas Crude Logistics System includes two owned and operated crude oil pipeline systems and their related tank farms, which serve the Tyler Refinery: (i) the Nettleton pipeline, a bi-directional 36-mile pipeline, with a capacity of approximately 38,000 bpd, that is capable of transporting crude oil from our tank farms in and around Longview, Texas to (a) the Bullard Junction at the Tyler Refinery and (b) other of our tank farms in and around Longview, Texas, and (ii) the McMurrey Pipeline System, a 65-mile pipeline system, with a capacity of approximately 28,000 bpd, that transports crude oil from our tank farms in and around Longview, Texas and runs roughly parallel to the Nettleton Pipeline. While service on the East Texas Crude Logistics System may otherwise constitute transportation in interstate commerce and may be subject to the common carrier regulation and jurisdiction of the FERC, it is currently subject to a temporary waiver issued by the FERC on October 23, 2012, waiving the otherwise applicable tariff filing and reporting requirements for common carrier interstate service providers (the “East Texas Waiver Order”). The continuing

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effectiveness of the East Texas Waiver Order depends upon the continuation in effect of the following conditions: (1) our affiliates continuing to own 100% of the throughput; (2) there being no demonstrated third party interest in shipping on the system; (3) our not anticipating any such interest materializing; and (4) there remaining no demonstrated opposition to the continuing effectiveness of the East Texas Waiver Order.

Our East Texas Crude Logistics System also includes five owned or leased crude oil storage terminals, at which we store crude oil owned by Delek for the Tyler Refinery. The LaGloria Station consists of two tanks with an active shell capacity of approximately 450,000 barrels. The Nettleton Station consists of five tanks with an active shell capacity of approximately 222,000 barrels. It is located on property that we lease from a third party, as described in more detail in Item 2, Properties. In addition to the active shell capacity, the Nettleton Station includes approximately 55,000 barrels of shell capacity that is currently not in service. The Bradford Station consists of two tanks with an active shell capacity of approximately 65,000 barrels. The Arp Station consists of two tanks with an active shell capacity of approximately 110,000 barrels. The Big Sandy Station consists of seven tanks with an active shell capacity of approximately 248,000 barrels.

The table below sets forth historical average daily throughput for the East Texas Crude Logistics System.

	Average Daily Throughput (bpd)
	Year Ended
		December 31,
	2017	2016	2015
East Texas Crude Logistics System (average bpd)	15,780	12,735	18,828

We have a pipelines and tankage agreement with Delek to provide throughput on the East Texas Crude Logistics System. However, in April 2013, a reconfigured pipeline system that is owned and operated by third parties began transporting crude oil to the Tyler Refinery from west Texas. Delek has a 10-year agreement, with an initial term expiring in 2023, with such third parties to transport a substantial majority of the Tyler Refinery’s crude oil requirements on this reconfigured pipeline system. As a result of the third parties' ability to transport crude oil on the reconfigured pipeline system directly to the Tyler Refinery, the crude oil supplied through the Nettleton and McMurrey Pipelines fell below the minimum aggregate throughput requirements of our pipelines and tankage agreement with Delek during the second quarter of 2013 and has remained below the minimum aggregate throughput requirements since that time. We expect crude oil volumes transported on our East Texas Crude Logistics System to continue to be below the minimum throughput requirement of 35,000 bpd for the foreseeable future. However, Delek is required under its commercial agreement with us, to pay us throughput fees in an amount equal to the fees it would pay were we to throughput 35,000 bpd, based on the per barrel fees in our agreement. The current term of this agreement expires in November 2022.

Tyler-Big Sandy Product Pipeline. The Tyler-Big Sandy Product Pipeline is a pipeline that runs between the Tyler Refinery and the Partnership's terminal at Big Sandy, Texas. The line consists of two segments: (i) the Hopewell Pipeline, an approximately 13-mile pipeline with a capacity of approximately 26,000 bpd, whichoriginates at the Tyler Refinery and terminates at the Hopewell Station, and (ii) the Big Sandy Pipeline, a 19-mile pipeline with a capacity of approximately 26,000 bpd, which originates at the Hopewell Station and terminates at the Big Sandy Terminal. The Big Sandy Terminal has 13 tanks with an aggregate shell capacity of approximately 177,000 barrels. Service on the Tyler-Big Sandy Product Pipeline is not provided to third parties, and is classified as private intrastate carrier service.

Tyler Tank Assets. The Tyler Tank Assets consist of 96 storage tanks and certain ancillary assets (such as pumps and piping) located at and adjacent to the Tyler Refinery with an aggregate shell capacity of approximately 2.0 million barrels.

El Dorado Tank Assets. The El Dorado Tank Assets consist of 158 storage tanks and certain ancillary assets (such as pumps and piping) located at and adjacent to the El Dorado Refinery with an aggregate shell capacity of approximately 2.5 million barrels.

Greenville-Mount Pleasant Pipeline and Greenville Storage Facility. The Greenville-Mount Pleasant Pipeline is a 76-mile pipeline, connecting the Greenville Storage Facility and the Mount Pleasant Terminal. The service provided on the Greenville-Mount Pleasant Pipeline is regulated by the Texas Railroad Commission, subject to a tariff on file with the Texas Railroad Commission. The Greenville Storage Facility has four tanks with an aggregate shell capacity of approximately 330,000 barrels and is connected to the Explorer Pipeline System.

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North Little Rock Tanks. Our terminal in North Little Rock, Arkansas has five tanks with an aggregate shell capacity of approximately 180,000 barrels.

FTT Trucking Assets. We own 95 tractors and 231 trailers used primarily to haul crude oil and other products for third parties and Delek.

El Dorado Rail Offloading Racks. The El Dorado Rail Offloading Racks consist of two crude oil rail offloading racks, which are designed to receive up to 25,000 bpd of light crude oil or 12,000 bpd of heavy crude oil, or any combination of the two, delivered by rail to the El Dorado Refinery and related ancillary assets.

Tyler Crude Tank. The Tyler Crude Tank is a crude oil storage tank and certain ancillary assets located adjacent to the Tyler Refinery. The Tyler Crude Tank has approximately 350,000 barrels of shell capacity and primarily supports the Tyler Refinery.

Talco Crude Pipeline. The Talco crude pipeline is an approximately 60-mile pipeline that transports crude oil from the Exxon Talco field to the ETP/ExxonMobil LOLA pipeline injection point in the East Texas Longview Station.

Big Spring Truck Unloading Station.  The Big Spring Truck Unloading Station is located at Delek's Big Spring, Texas Refinery (the "Big Spring Refinery"). The Big Spring Truck Unloading Station is designed to receive up to 10,000 bpd of crude oil.

Big Spring Pipeline. The Big Spring Pipeline is an approximately 40-mile pipeline, which includes related ancillary assets. The Big Spring Pipeline originates in Big Spring, Texas and terminates in Midland, Texas.

Wholesale Marketing and Terminalling Segment

Our wholesale marketing and terminalling segment provides wholesale marketing and terminalling services to Delek’s refining operations and to independent third parties from whom we receive fees for marketing, transporting, storing and terminalling refined products and to whom we wholesale market refined products. In providing certain of these services, we take ownership of the products and are therefore exposed to market risks related to the volatility of refined product prices in our west Texas operations, which depend on many factors, including demand and supply of refined products in the west Texas market, the timing of refined product deliveries and downtime at refineries in the surrounding area. As of December 31, 2017, we generated revenue in our wholesale marketing and terminalling segment by (i) providing marketing services for the refined products output of the Tyler Refinery, (ii) engaging in wholesale activity at our Abilene and San Angelo, Texas terminals, as well as at terminals owned by third parties, whereby we purchase light products for sale and exchange to third parties, and (iii) providing terminalling services to independent third parties and Delek. See “—Commercial Agreements—Other Agreements with Third Parties—West Texas." Also see Note 4 to the consolidated financial statements in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K, for a discussion of our material commercial agreements with Delek. The tables below show the operating results for the wholesale marketing and terminalling segment. For the years ended December 31, 2017, 2016 and 2015, we present the results for the period during which we owned the assets, as delineated in any notes accompanying the tables.

Wholesale Marketing

East Texas.Pursuant to a marketing agreement with Delek, we market 100% of the refined products output of the Tyler Refinery, other than jet fuel and petroleum coke. See Note 4 to the consolidated financial statements in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K for additional information. The table below sets forth the historical sales volumes under this marketing agreement.

		Year Ended
		December 31,
	2017	2016	2015
Sales volumes (average bpd):	73,655	68,131	59,174

West Texas.In our west Texas marketing operations, we generate revenue by purchasing refined products from independent third-party suppliers and from Delek for sale and exchange to third parties at our Abilene and San Angelo, Texas terminals and at third-party

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terminals located elsewhere in Texas. Our terminals in Abilene and San Angelo, Texas were leased for nominal consideration to Noble Petro, Inc. ("Noble Petro") pursuant to a terminal and pipeline lease and operating agreement, which expired on December 31, 2017.

We own approximately 104 miles of product pipelines in west Texas that connect our Abilene and San Angelo, Texas terminals to the Magellan Orion Pipeline. These pipelines were leased to Noble Petro until December 31, 2017. At these terminals, Noble Petro also regularly sold petroleum products to us that we then marketed to third parties. As of January 1, 2018, these regular sales of product by Noble Petro to us concluded. We are currently purchasing products from Delek and third parties at our Abilene and San Angelo terminals. To facilitate these purchases, we have constructed a pipeline into our Abilene Terminal to receive product from the pipeline owned by Holly Energy Partners, L.P. (NYSE: HEP) through which Delek ships product that is produced at the Big Spring Refinery. We also have active connections to the Magellan Orion Pipeline that enable us to ship product to our terminals and to acquire product from other shippers. The table below provides the location of the Abilene and San Angelo terminals associated with our marketing activities and the number of tanks, their storage capacities, number of truck loading lanes and maximum daily available truck loading capacity for the year ended December 31, 2017.

Terminal Location	Number of Tanks	Active Aggregate Shell Capacity (bbls)	Number of Truck Loading Lanes	Maximum Daily Available Truck Loading Capacity (bpd)
Abilene, TX (1)	9	368,000	2	15,000
San Angelo, TX	5	93,000	2	15,000
Total	14	461,000	4	30,000

⁽¹⁾  Excludes approximately 545,530 barrels of shell capacity that is out of service.

Substantially all of our product sales in west Texas are on a wholesale basis. While we purchase finished products from Delek and from other third parties, a large portion of the products we sold in west Texas were purchased from Noble Petro during the year ended December 31, 2017 pursuant to the terms of a supply contract with Noble Petro that expired in December 2017 (the "Abilene Contract"). Under the Abilene Contract, we had the right to purchase up to 20,350 bpd of petroleum products for sale at our Abilene and San Angelo, Texas terminals. As of January 2018, we began replacing the product supplied under the Abilene Contract with product purchased from Delek, which is produced by the Big Spring Refinery and from third parties that may continue to include Noble Petro. See “—Commercial Agreements—Other Agreements with Third Parties—West Texas."

The table below details the average aggregate daily number of barrels of refined products, and the margins associated with such products, that we sold in our west Texas wholesale operations for the periods indicated.

	Year Ended
			December 31,
	2017		2016		2015
Throughput (average bpd)	13,817		13,257		16,357
Gross margin (in thousands)	$	20,320	$	6,929	$	7,984
Gross margin per barrel	$	4.03	$	1.43	$	1.35

Terminalling

We provide terminalling services for products to independent third parties and Delek through light products terminals we own in Nashville, Tennessee and to Delek, or certain third parties to whom Delek has assigned its rights, through our light products terminals in Memphis, Tennessee; Tyler, Texas; Big Sandy, Texas; Mount Pleasant, Texas; El Dorado, Arkansas; and North Little Rock, Arkansas. See Note 4 to the consolidated financial statements in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K for additional information pertaining to our material agreements. See "—Commercial Agreements—Delek's Crude Oil and Refined Products Supply and Offtake Arrangement" for a description of a third party's involvement in certain agreements.

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The table below provides the locations of our refined product terminals associated with our terminalling activities and their storage capacities, number of truck loading lanes, average truck loading volume and maximum daily available truck loading capacity for the year ended December 31, 2017.

				Maximum
				Daily
		Active		Available
		Aggregate	Number of	Truck
		Shell	Truck	Loading
	Number	Capacity	Loading	Capacity
Terminal Location	of Tanks	(bbls)	Lanes	(bpd)
Big Sandy, TX (1)			3	25,000
El Dorado, AR (1)			3	35,000
Memphis, TN	12	126,000	3	20,000
Mount Pleasant, TX	7	175,000	3	10,000
Nashville, TN (2)	10	128,000	2	15,000
North Little Rock, AR (1)			2	17,100
Tyler, TX (1)			11	91,000
Total	29	429,000	27	213,100

⁽¹⁾  See "—Pipelines and Transportation Segment—Tyler-Big Sandy Product Pipeline," "—Pipelines and Transportation Segment—Tyler Tank Assets," "—Pipelines and Transportation Segment—North Little Rock Tanks" and "—Pipelines and Transportation Segment—El Dorado Tank Assets," above for a discussion of the storage tanks associated with these terminals.

⁽²⁾  Excludes approximately 10,000 barrels of shell capacity that is currently not in service.

The table below sets forth historical average daily throughput for each of our terminals.

	Year Ended
	December 31,
	2017	2016	2015
Throughput (average bpd):
Big Sandy, TX	6,878	7,025	7,135
El Dorado, AR	14,149	17,040	10,363
Memphis, TN	7,112	7,982	7,616
Mount Pleasant, TX	5,202	2,746	1,056
Nashville, TN	7,292	6,939	9,440
North Little Rock, AR	8,848	10,174	9,853
Tyler, TX	75,007	70,444	61,051
Total (average bpd)	124,488	122,350	106,514

Commercial Agreements

Commercial Agreements with Delek

The Partnership has a number of long-term, fee-based commercial agreements with Delek under which we provide various services, including crude oil gathering; crude oil, intermediate and refined products transportation and storage services; and marketing, terminalling and offloading services to Delek. Most of these agreements have an initial term ranging from five to ten years, which may be extended for various renewal terms at the option of Delek. The initial term of certain of these agreements expired in November 2017. Delek opted

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to renew these agreements for subsequent five-year terms expiring in November 2022. In the case of our marketing agreement with Delek, the initial term has been extended through 2026. These agreements typically include minimum quarterly volume, revenue or throughput commitments. Fees under each agreement are payable to us monthly by Delek or certain third parties to whom Delek has assigned certain of its rights. For a discussion of a third party's involvement in certain agreements, see "Delek's Crude Oil and Refined Products Supply and Offtake Arrangement." In most circumstances, if Delek or the applicable third party assignee fails to meet or exceed the minimum volume, throughput or other commitment during any calendar quarter, Delek, and not any third party assignee, will be required to make a quarterly shortfall payment to us equal to the volume or amount of the shortfall multiplied or increased by the applicable fee, subject to certain exceptions as specified in the applicable agreement. Carry-over of any volumes or revenue in excess of such commitment to any subsequent quarter is not permitted.

The tariffs and throughput and storage fees under our agreements with Delek are 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 or various iterations of 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.

See Note 4 to the consolidated financial statements in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K, for a complete discussion of our material commercial agreements with Delek.

Other Agreements with Delek

In addition to the commercial agreements described above, the Partnership has entered into an omnibus agreement with Delek, our general partner, Delek Logistics Operating LLC ("OpCo") and certain of the Partnership’s and Delek’s other subsidiaries on November 7, 2012, which was subsequently amended and restated on July 26, 2013, February 10, 2014 and March 31, 2015 and further amended on August 3, 2015 (collectively, as amended, the "Omnibus Agreement"). The Omnibus Agreement governs the provision of certain operational services and reimbursement obligations, among other matters, between the Partnership and Delek.

Other Agreements with Third Parties

Paline Pipeline System Capacity Reservation. We previously had separate agreements with two unrelated third parties for such parties to reserve certain capacity on the Paline Pipeline System. Pursuant to the terms of these agreements, each unrelated third party paid a fixed monthly fee for the exclusive right to use its respective reserved capacity on the pipeline, which together accounted for a combined 35,000 bpd. The initial term of each agreement ran through June 30, 2016. We extended one of the agreements through December 31, 2016, for a total reservation of 10,000 bpd. We currently maintain a tariff on file with the FERC for service provided on the Paline Pipeline System, which allows for third parties to ship on the available capacity of the pipeline.

West Texas. In our west Texas marketing operations, we generate revenue by purchasing refined products from independent third-party suppliers and Delek for sale and exchange to third parties at our Abilene and San Angelo, Texas terminals and at third-party terminals located elsewhere in Texas. Substantially all of our product sales in west Texas are on a wholesale basis. We purchase finished products from Delek and from third parties. During the year ended December 31, 2017, a large portion of the petroleum products we sold in west Texas were purchased from Noble Petro. Under the terms of the Abilene Contract with Noble Petro, which expired in December 2017, we purchased petroleum products based on monthly average prices from Noble Petro immediately prior to our resale of such products to customers at our Abilene and San Angelo, Texas terminals, which we leased to Noble Petro. Under this arrangement, we had 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. As of January 2018, we began replacing the product supplied under the Abilene Contract with product purchased from Delek, which is produced by the Big Spring Refinery and from third parties that may continue to include Noble Petro. Products purchased from Delek or other third parties are generally based on daily market prices at the time of purchase requiring price hedging risk management activities between the time of purchase and sale. Existing price risk hedging programs have been expanded to correspond to the higher volume of product purchased from Delek and third parties.

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Delek's Crude Oil and Refined Products Supply and Offtake Arrangement

Pursuant to an arrangement with Delek and Lion Oil, to which we are not a party, J. Aron & Company ("J. Aron") acquires and holds either title to or a lien on substantially all crude oil, intermediate and refined products transported on our Lion Pipeline System, SALA Gathering System and on pipeline capacity we lease from Enterprise TE Products Pipeline Company LLC on a pipeline that runs from the El Dorado Refinery to our Memphis Terminal (the "Memphis Pipeline"). J. Aron is therefore considered the shipper for the liquid it owns on the Lion Pipeline System, the SALA Gathering System and the Memphis Pipeline. J. Aron also has title to the refined products stored at our Memphis, North Little Rock and El Dorado terminals and in the El Dorado storage tanks. Under (i) our pipelines and storage agreement with Lion Oil relating to the Lion Pipeline System and the SALA Gathering System, (ii) our terminalling agreements with Lion Oil relating to the Memphis and North Little Rock terminals, and (iii) our throughput and tankage agreement relating to the terminal and tank assets at and adjacent to the El Dorado Refinery, Lion Oil has assigned to J. Aron certain of its rights under these agreements, including the right to have J. Aron's crude oil and intermediate and refined products stored in or transported on or through these systems, the Memphis and North Little Rock terminals and the terminal and tank assets at and adjacent to the El Dorado Refinery, with Lion Oil acting as J. Aron's agent for scheduling purposes. Accordingly, even though this is effectively a financing arrangement for Delek whereby J. Aron sells the product back to Delek, J. Aron is technically our primary customer under each of these agreements. J. Aron retains these storage and transportation rights for the term of its arrangement with Delek and Lion Oil, which currently runs through April 30, 2020, and J. Aron pays us for the transportation, throughput and storage services we provide to it. The rights assigned to J. Aron do not alter Lion Oil's obligations to meet certain throughput minimum volumes under our agreements with respect to the transportation, throughputting and storage of crude oil and refined products through our facilities, but J. Aron's throughput is credited toward Lion Oil's minimum throughput commitments. Accordingly, Lion Oil is responsible for making any shortfall payments incurred under the pipelines and storage agreement or the terminalling agreement which may result from minimum throughputs or volumes not being met.

Customers

We are dependent upon Delek as our primary customer, and the loss of Delek as a customer would have a material adverse effect on both of our operating segments. We derive a substantial majority of our gross margin, which is defined as net sales less cost of goods sold, from fee-based commercial agreements with Delek or as a direct result of its operations. For more information pertaining to these agreements, please see "—Commercial Agreements." We also have other customers, including major oil companies, independent refiners and marketers, jobbers, distributors, utility and transportation companies and independent retail fuel operators.

Major Customers

Delek, directly or indirectly, accounted for 28.9%, 32.8% and 24.2% of our total revenues for the years ended December 31, 2017, 2016 and 2015, respectively. Sunoco LP accounted for 9.0%, 10.5% and 16.2% of our total revenues for the years ended December 31, 2017, 2016 and 2015, respectively. However, we believe that gross margin is a better measure of performance of our business on a customer specific basis than revenue, particularly in our wholesale marketing and terminalling segment, as total revenue varies with the price of the underlying product, such as a gallon of finished product. Delek, directly or indirectly, accounted for 85.8%, 90.5% and 90.0% of our gross margin for the years ended December 31, 2017, 2016 and 2015, respectively.

Competition

Pipelines and Transportation

Our business in this segment primarily consists of gathering, transporting and storing crude oil, intermediate and finished products for Delek and third parties, especially other refiners. We face competition for the transportation and storage of crude oil from other pipeline owners whose pipelines or storage facilities (i) may have a location advantage over our pipelines or storage facilities, (ii) may be able to transport or store more desirable crude oil or finished products to Delek or to third parties, (iii) may be able to transport or store crude oil or finished product at a lower rate, or (iv) may be able to store more crude oil or finished product. Any or all such factors could cause Delek, or our third-party customers, to reduce throughput to a level that is below the minimum throughput commitments established in any contracts we may have with them or determine not to renew such contracts when the term expires.

As a result of our physical integration with Delek's El Dorado Refinery, and our contractual relationships with Delek relative to the El Dorado Refinery, we do not believe that we will face significant competition for the transportation of crude oil or refined products to or from the El Dorado Refinery, particularly during the term of our Lion Pipeline System, SALA Gathering System, El Dorado Tank Assets

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and El Dorado Assets agreements with Delek. See Note 4 to the consolidated financial statements in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K, for a discussion of our material commercial agreements with Delek.

Wholesale Marketing and Terminalling

The wholesale marketing and terminalling business is generally very competitive. Our owned refined product terminals, as well as the other third-party terminals we use to sell refined product, 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 usually limit the geographic size of the market that can be served economically by any terminal. Two key markets in west Texas that we serve from our owned facilities are Abilene and San Angelo, Texas. However, there are no competitive fuel loading terminals in close proximity to our Abilene terminal or within approximately 90 miles of our San Angelo terminal. Our Nashville terminal competes with a significant number of other terminals located in the greater Nashville area. With respect to terminalling services we provide to Delek at our Memphis and North Little Rock terminals, as a result of our exclusive terminalling agreements, we do not believe we will face significant competition from third parties for these services.

Pursuant to an exclusive marketing agreement with Delek, the term of which currently expires in 2026, we market 100% of the refined products output of the Tyler Refinery (other than jet fuel and petroleum coke). As a result, we do not believe that we will face significant competition for these services from third parties. In addition, as a result of our physical integration with the Tyler Refinery and our contractual relationships with Delek relative to the Tyler Refinery, we do not believe that we will face significant competition for the storage or throughput of intermediate or refined products at the Tyler Refinery, particularly during the term of our agreements with Delek. See Note 4 to the consolidated financial statements in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K, for additional information. Should Delek's wholesale customers, however, reduce their purchases of refined products due to the increased availability of more competitively priced products from other suppliers or for other reasons, the volumes we sell under the aforementioned agreement could decrease below the minimum volume commitment under the contract. Delek's Tyler Refinery is the only full-range product supplier within 100 miles; therefore, we believe its location gives the Tyler Refinery a natural advantage over more distant competitors.

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 Texas Railroad Commission, 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. 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. In addition, on October 20, 2016, the FERC issued an Advance Notice of Proposed Rulemaking on Revisions to Indexing Policies and Page 700 of FERC Form No. 6, which could, if final rules are implemented as proposed, increase reporting burdens on interstate liquids transportation providers and, in some cases, prohibit pipelines, including ours, from increasing rates even if warranted by the annual index. See Item 1A, "Risk Factors—Risks Relating to Our Business."

While the FERC regulates rates for shipments of crude oil or refined products in interstate commerce, state agencies may regulate rates and service for shipments in intrastate commerce. We own pipeline assets in Texas, Arkansas, and Louisiana; accordingly, such

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assets may be subject to additional regulation by the applicable governmental authorities in those states. Without limitation, certain of our pipeline assets in Texas are operated under Texas Railroad Commission regulation and subject to filed tariffs with that agency. See "—Pipelines and Transportation Segment—Greenville-Mount Pleasant Pipeline and Greenville Storage Facility" for additional information on these tariffs. In Texas, a pipeline, with some exceptions, is required to operate as a common carrier by publishing tariffs and providing transportation without discrimination. Arkansas provides that all intrastate oil pipelines are common carriers. In Louisiana, all pipelines conveying petroleum from a point of origin within the state to a destination within the state are declared common carriers. The Louisiana Public Service Commission is empowered with the authority to establish reasonable rates and regulations for the transport of petroleum by a common carrier, mandating public tariffs and providing of transportation without discrimination. State commissions have generally not been aggressive in regulating common carrier pipelines, have generally not investigated the rates or practices of petroleum pipelines in the absence of shipper complaints and generally resolve shipper complaints informally.

Whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact-dependent and determined on a case-by-case basis. We cannot provide assurance that the FERC will not at some point assert that some or all of the transportation service we provide, for which we do not have a tariff on file at the FERC, is within its jurisdiction. If the FERC were successful with any such assertion, we may be required to pay refunds to customers and the FERC's ratemaking methodologies may subject us to potentially burdensome and expensive operational, reporting and other requirements. Service on the East Texas Crude Logistics System is currently subject to a temporary waiver issued by the FERC, as discussed above in "—Pipelines and Transportation Segment—East Texas Crude Logistics System." If the conditions to the continued effectiveness of that East Texas Waiver Order are no longer true at any point, service on that system would become fully subject to FERC tariff filing requirements and other regulatory requirements for the provision of transportation service.

Department of Transportation

The Pipeline and Hazardous Materials Safety Administration ("PHMSA") of the United States Department of Transportation ("DOT") regulates the design, construction, testing, operation, maintenance, reporting and emergency response of crude oil, petroleum products and other hazardous liquids pipelines and other facilities, including certain tank facilities used in the transportation of such liquids. These requirements are complex, subject to change and, in certain cases, can be costly to comply with. We believe our operations are in substantial compliance with these regulations, but cannot assure you that substantial expenditures on our part will not be required to remain in compliance. Moreover, certain of these rules are difficult to insure adequately, and we cannot assure you that we will have adequate insurance to address costs and damages from any noncompliance.

The United States Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (or the "Pipeline Safety Act") was enacted on January 3, 2012, pursuant to which the maximum civil penalties for certain violations were increased from $100,000 to $200,000 per violation per day and from a total cap of $1 million to $2 million. A number of the provisions of the Pipeline Safety Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs. We intend to work closely with our industry associations to participate with and monitor DOT-PHMSA's efforts.

In January 2017, PHMSA finalized a new regulation that, once effective, will impose additional responsibilities concerning the operation, maintenance, and inspection of hazardous liquid pipelines; the reporting of pipeline incidents; reference standards for in-line pipeline inspection and the direct assessment of stress corrosion cracking; and other requirements. We are reviewing the new regulations and intend to adjust our operations, to the extent necessary, in order to comply with the regulations upon their effective date.

The DOT has issued guidelines with respect to securing regulated facilities against terrorist attack. We have instituted security measures and procedures in accordance with such guidelines to enhance the protection of certain of our facilities. We cannot provide any assurance that these security measures would fully protect our facilities from an attack.

The Federal Motor Carrier Safety Administration of the DOT regulates safety standards and monitors drivers and equipment of commercial motor carrier fleets. Such standards include vehicle and maintenance inspection requirements, limitations on the number of hours drivers may operate vehicles and financial responsibility requirements. We believe that the operations of our fleet of crude oil and finished products truck transports are substantially in compliance with these regulations and safety requirements.

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Environmental, Health and Safety

We are subject to extensive and periodically changing federal, state and local laws and regulations relating to the protection of the environment, health and safety. Among other things, these laws and regulations govern the emission or discharge of pollutants into or onto the land, air and water, the handling and disposal of solid and hazardous wastes, the remediation of contamination and the protection of workers and the public. Compliance with environmental laws and regulations increases our overall cost of business, including our capital costs to develop, maintain, operate and upgrade equipment and facilities. Numerous permits or other authorizations are required under these laws for the operation of our terminals, pipelines, and related operations, and may be subject to revocation, modification and renewal. These laws and permits may become the basis for 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, or that relate to pre-existing conditions for which we have assumed or are assigned responsibility.

We believe that our current operations are in substantial compliance with existing environmental, health and safety requirements. However, these laws and regulations are subject to changes by governmental or judicial authorities. The legislative and regulatory trend in recent years has been to place increasingly stringent restrictions and limitations on activities that may affect the environment; however, the current administration has changed this trend at the federal level. Continued and future compliance with such laws and regulations may require us to incur significant expenditures. Violation of environmental laws, regulations and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions limiting our operations, investigatory or remedial liabilities or construction bans or delays in the construction of additional facilities or equipment. Additionally, a release of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expenses, including costs to respond to, contain and remediate a release, to comply with applicable laws and regulations and to resolve claims by third parties for personal injury, property damage, or natural resources damages. See "—Hazardous Substances and Waste" below for additional information on regulations pertaining to releases into the environment. These impacts could directly and indirectly affect our business. We cannot currently determine the amounts of such future impacts. 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.

Indemnification

Under the Omnibus Agreement, Delek has agreed to indemnify us for certain environmental matters associated with the ownership of our assets as specified therein, including matters arising from operations by Delek, at or before the time of our acquisition of these assets from Delek.

Air Emissions and Climate Change

Our operations are subject to the Clean Air Act and its regulations and comparable state and local statutes. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources that are already constructed. These permits may require controls on our air emission sources, and we may become subject to more stringent regulations requiring the installation of additional emission control technologies. Any such future obligations may require us to incur significant additional capital or operating costs. These air emissions requirements also affect Delek's refineries, from which we receive a substantial portion of our revenues. In the future, Delek may be required to incur significant capital expenditures to comply with new legislative and regulatory requirements relating to its operations. To the extent these capital expenditures have a material effect on Delek, they could have a material effect on our business and results of operations.    

Environmental advocacy groups and regulatory agencies in the United States and other countries have focused considerable attention on the emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") and their potential role in climate change. Developments in GHG initiatives that result in GHG-related requirements that disproportionately affect the cost of energy from oil in comparison to competing energy sources could affect demand for our services. Due to the uncertainties surrounding the risks and regulatory framework associated with greenhouse gas emissions, the financial impact of related developments cannot be estimated at this time.

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Renewable Fuel Standard

The Energy Independence and Security Act of 2007 ("EISA") was enacted into federal law in December 2007 creating the Renewable Fuel Standard - 2 ("RFS-2") rule, requiring the amounts of renewable fuel sold or introduced in the United States to increase each year, reaching 36 billion gallons by 2022. The Environmental Protection Agency (the "EPA") has the ability to alter annual blending volume requirements based on inadequate domestic supply and has chosen to do so most years for lack of cellulosic biofuels. For this reason, the EPA has finalized volume requirements for 2018 below the statutory level. Although Delek’s refineries are obligated parties under this rule, our entities are not obligated parties and have no requirement to blend specific volumes of renewable fuels. However, the requirements could reduce future demand for petroleum products and thereby have an indirect effect on certain aspects of our business, although it could increase demand for our ethanol and biodiesel fuel blending services at our truck loading racks.

Hazardous Substances and Waste

To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into water or soils, and include measures to control pollution of the environment. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste. They also require corrective action, including investigation and remediation, at a facility where such waste may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), which is also known as Superfund, and comparable state laws, impose liability without regard to fault or to the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In the course of our ordinary operations, we generate waste that falls within CERCLA’s definition of a “hazardous substance” and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up certain sites. However, we have not been identified as a potentially responsible party at any Superfund sites.

We also generate small quantities of solid wastes, including hazardous wastes that are subject to the requirements of the federal Resource Conservation and Recovery Act ("RCRA"), and comparable state laws. From time to time, the EPA considers the adoption of stricter disposal standards for non-hazardous wastes, including crude oil and refined products wastes. We are not currently required to comply with a substantial portion of the RCRA requirements, because our operations generate minimal quantities of hazardous wastes. However, it is possible that additional wastes, which could include wastes currently generated during operations, will in the future be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Any changes in the regulations could increase our, and our competitors’, maintenance capital expenditures and operating expenses.

We currently own and lease, and Delek has in the past owned and leased, properties where hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other waste may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.

Water

Our operations can result in the discharge of pollutants, including crude oil and refined products. Several of our pipelines and terminals are located near, or cross under or over, environmentally sensitive waters, such as streams, creeks, rivers, lakes and wetlands. The transportation and storage of crude oil and refined products over and adjacent to water involves risk and subjects us to the provisions of the Oil Pollution Act of 1990 (the "OPA"), the Water Pollution Control Act of 1972 (the "Clean Water Act") and related state requirements. These requirements subject owners of covered facilities to strict, joint and potentially unlimited liability for containment and removal costs, natural resource damages and certain other consequences of an oil spill where the spill is into navigable waters, along shorelines or in

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the exclusive economic zone of the United States. In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us. States in which we operate have also enacted similar and, in some cases, more stringent laws.

Regulations under the Clean Water Act, the OPA and state laws also impose additional regulatory burdens on our operations. Spill prevention control and countermeasure requirements of federal laws and some state laws require containment to mitigate or prevent contamination of navigable waters in the event of an oil overflow, rupture or leak. For example, the Clean Water Act requires us to maintain spill prevention control and countermeasure plans at many of our facilities. In addition, the OPA requires that most oil transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. We maintain such plans, and where required have submitted plans and received federal and state approvals necessary to comply with the OPA, the Clean Water Act and related regulations. We regularly review and modify our crude oil and refined product spill prevention plans and procedures to help prevent crude oil and refined product releases and to minimize potential impacts should a release occur.

The Clean Water Act also imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters. Our facilities contract with third parties for wastewater disposal, discharge to local Publicly Owned Treatment Works, or discharge under the terms of a National Pollutant Discharge Elimination System permit for wastewater and stormwater. In the event regulatory requirements change, or interpretations of current requirements change, and our facilities are required to undertake different wastewater management arrangements, we could incur substantial additional costs. The Clean Water Act imposes substantial potential liability for the violation of permits or permitting requirements and for the costs of removal, remediation, and damages resulting from such discharges. In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

Employees

We have no employees. Rather, all of the employees that conduct our business are employed by our general partner and its non-Partnership affiliates, and we believe that our general partner and its non-Partnership affiliates have a satisfactory relationship with those employees.

Seasonality and Customer Maintenance Programs

The volume and throughput of crude oil and refined products transported through our pipelines and sold through our terminals and to third parties are 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. While demand for asphalt products, which are a substantial portion of the El Dorado Refinery's product mix, is also lower in the winter months. In addition, our refining customers, such as Delek, occasionally reduce or suspend operations to perform planned maintenance, which is more typically scheduled during the winter, when demand for their products is lower. Accordingly, these factors affect the need for crude oil or finished products by our customers and therefore limit our volumes or throughput during these periods, and our operating results will generally be lower during the first and fourth quarters of the year. We believe, however, that many of the potential effects of seasonality on our revenues and contribution margin will be substantially mitigated due to our commercial agreements with Delek that include minimum volume and throughput commitments.

Working Capital

We primarily fund our business operations from operating cash flows, borrowings under our revolving credit facility and any potential future issuances of equity and debt securities. For additional information, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, of this Annual Report on Form 10-K.

Available Information

Our internet website address is www.DelekLogistics.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 and ethics and the charter of the audit committee of the board of directors of our general partner in the same website location. Our governance documents are available in print to any unitholder that

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makes a written request to Secretary, Delek Logistics, GP, LLC, general partner of Delek Logistics Partners, LP, 7102 Commerce Way, Brentwood, TN 37027.

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ITEM 1A.  RISK FACTORS

Limited partner interests are inherently different from shares of capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the following risks were to occur, our business, financial condition or results of operations could be materially and adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units or the trading price of our common units could decline.

Risks Relating to Our Business

Delek, directly or indirectly, accounts for a substantial majority of our gross and contribution margins. Therefore, we are indirectly subject to the business risks of Delek. If Delek changes their business strategy, fails to satisfy their obligations under our commercial agreements for any reason or significantly reduces the volumes transported through our pipelines or handled at our terminals or its use of our marketing services, then our revenues, and, consequently, our margins would decline and our financial condition, results of operations, cash flows and ability to make distributions to our unitholders could be adversely affected.

Delek, directly or indirectly, accounted for 85.8%, 90.5% and 90.0% of our gross margin for the years ended December 31, 2017, 2016 and 2015, respectively, and is the only customer for a substantial majority of our assets. In addition, Delek is, effectively, through its supply and offtake agreement with its assignee, the principal customer for our Lion Pipeline System, our SALA Gathering System and our El Dorado, Memphis and North Little Rock terminals. Please see Item 1. "Business—Delek's Crude Oil and Refined Products Supply and Offtake Arrangement." As we expect to continue to derive the substantial majority of our margins from Delek, either directly or indirectly, for the foreseeable future, we are subject to the risk of nonpayment, nonperformance or underperformance by Delek under our commercial agreements. In addition, we are subject to the risk of nonpayment, nonperformance or underperformance by Delek’s assignees. If Delek were to significantly decrease, or cause the significant decrease of, the materials transported on our pipelines or the volumes of refined products handled at our terminals, whether because of business or operational difficulties or strategic decisions by Delek’s management, it is unlikely that we would be able to utilize any additional capacity on our pipelines or terminal facilities to service third-party customers without substantial capital outlays and delays, if at all, which could materially and adversely affect our results of operations, financial condition and cash flows. Likewise, the terms of Delek's obligations under its agreements with us are for initial terms ranging from five years to ten years, with options to extend at the election of Delek. If Delek fails to renew these contracts as they come up for renewal, or if Delek fails to use our assets and services after the expiration of the agreements, or should our agreements be invalidated for any reason, and we are unable to generate revenue from third parties with respect to such assets, we could be materially and adversely affected. See Note 4 to the consolidated financial statements in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K, for a complete discussion of our material commercial agreements with Delek. Additionally, any event, whether in our areas of operation or otherwise, that materially and adversely affects Delek’s or its assignees' operations, financial condition, results of operations or cash flows may adversely affect us and our business and, therefore, our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are indirectly subject to the operational and business risks of Delek and its assignees, including, but not limited to, the following:

• the timing and extent of changes in the costs and availability of crude oil and other refinery feedstocks (including prolonged periods of low crude oil prices that could impact production of inland crude oil and reduce the amount of cost advantaged crude oil available and/or the discount of such crude oil as compared to other crude oil) and in the price and demand for Delek's refined products;

• the risk of contract cancellation, non-renewal or failure to perform by Delek’s suppliers or customers, and Delek’s inability to replace such suppliers, contracts, customers and/or revenues;

• disruptions due to equipment interruption or failure or other events at Delek’s facilities, or at third-party facilities on which Delek’s business is dependent;

• the effects of economic downturns on Delek’s business and the business of its suppliers, customers, business partners and lenders;

• Delek’s ability to remain in compliance with its contracts;

• Delek’s ability to remain in compliance with the terms of its outstanding and any future indebtedness;

• changes in the cost or availability of third-party pipelines, terminals and other means of delivering and transporting crude oil, feedstocks and refined products;

• state and federal environmental, economic, health and safety, energy and other policies and regulations, and any changes in those policies and regulations;

• environmental incidents and violations and related remediation costs, fines and other liabilities; and

• changes in crude oil and refined product inventory levels and carrying costs.

Additionally, Delek continually considers opportunities presented by third parties with respect to its refinery assets. These opportunities may include offers to purchase certain assets and joint venture propositions. Delek may also change its refineries’ operations by constructing new facilities, suspending or reducing certain operations, or modifying or closing facilities. Changes may be considered to meet market demands, to satisfy regulatory requirements or environmental and safety objectives, to improve operational efficiency or for other reasons.

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Delek actively manages its assets and operations, and, therefore, changes of some nature, possibly material to its business relationship with us, could occur in the future.

Furthermore, conflicts of interest may arise between Delek and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. We have no control over Delek or our general partner, and Delek may elect to pursue a business strategy or make other decisions that do not favor us or our business. Please see “—Risks Relating to Our Partnership Structure—Our general partner and its affiliates, including Delek and the Individual GP Owners, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.”

Delek may be unable to integrate successfully the businesses of Old Delek and Alon USA and realize the anticipated benefits of the Delek/Alon Merger.

The Delek/Alon Merger involves the combination of two companies which, prior to July 1, 2017, operated as independent public companies. Delek must devote significant management attention and resources to integrate the business practices and operations of Old Delek and Alon USA. Delek may fail to realize some or all of the anticipated benefits of the Delek/Alon Merger if the integration process takes longer than expected or is more costly than expected, which may adversely affect us. Potential difficulties Delek may encounter in the integration process include the following:

• an inability of Delek to grow as expected and realize the synergies and the other expected benefits of its merger with Alon USA, which became effective as of July 1, 2017, and Delek's acquisition of the remaining interest in Alon USA Partners, LP that Delek did not already own, which became effective as of February 7, 2018;

• as it relates to our potential future growth opportunities, including dropdowns, and other potential benefits, the ability to successfully integrate the businesses of Delek and Alon USA;

• lost sales and customers as a result of certain customers of either of the two companies deciding not to do business with Delek;

• complexities associated with managing the combined businesses;

• integrating personnel from the two companies;

• challenges in the creation of uniform standards, controls, procedures, policies and information systems;

• potential unknown liabilities and unforeseen increased expenses, delays, or regulatory conditions associated with the Delek/Alon Merger; and

• performance shortfalls as a result of the diversion of management's attention caused by integrating the companies' operations.

Our operations and Delek’s refining operations, some of which have been in service for decades, are subject to many risks and operational hazards, for which we may not be adequately insured, some of which may result in business interruptions and shutdowns of our or Delek’s facilities and liability for damages. If a significant accident or event occurs that results in a business interruption or shutdown, our operations and financial results could be adversely affected.

Our operations are subject to all of the risks and operational hazards inherent in gathering, transporting and storing crude oil and intermediate and refined and other products, including:

• business interruption due to maintenance and repairs or mechanical or structural failures with respect to our assets, or our facilities or with respect to third-party assets or facilities on which our operations are dependent, including Delek’s assets or facilities;

• operational errors that result in a loss of physical integrity or performance in our pipelines and facilities;

• deterioration of the condition of our pipelines and facilities through age, use and disuse;

• damages to our assets and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism;

• damages to and loss of availability of interconnecting third-party pipelines, terminals and other means of delivering crude oil, feedstocks and refined petroleum products;

• the inability of third-party facilities on which our operations are dependent, including Delek’s facilities, to complete capital projects and to restart timely refining operations following a shutdown;

• curtailments of operations as a result of severe seasonal weather;

• inadvertent damage to pipelines from construction, farm and utility equipment;

• constrained pipeline and storage infrastructure;

• disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attacks; and

• other hazards.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage, as well as business interruptions or shutdowns of our assets and facilities. Any such event or unplanned shutdown could have a material adverse effect on our business, financial condition and results of operations.

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In addition, Delek’s refining operations, on which our operations are substantially dependent and over which we have no control, are subject to these and other operational hazards and risks inherent in refining crude oil. A significant accident or event, such as described above at Delek’s facilities, could damage our assets, expose us to significant liability and could affect Delek’s ability and/or obligation to satisfy the minimum volume commitments under our commercial agreements with Delek, any of which could have a material adverse effect on our business, financial condition and results of operations.

Further, significant portions of our pipeline systems, including our gathering system, and storage and terminalling facilities have been in service for many decades, which could enhance the risks and operational hazards discussed above. The age and condition of our systems could also result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our systems could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.

Our insurance policies and other contractual protections from Delek 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 are insured under Delek's insurance policies, subject to the terms, retentions and limits under those policies. To the extent Delek experiences losses under the insurance policies, the limits of our coverage may be decreased. In addition, we are not insured 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, because Delek’s time element insurance has up to a 60 day waiting period, a significant part, or all, of a business interruption loss could be uninsured. The occurrence of an event that is 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 energy industry companies, such as us, and their insurance carriers. Large energy industry claims could result in significant increases in the level of premium costs and deductibles for participants in the energy industry. Insurance companies that have historically participated in underwriting energy-related facilities may discontinue that practice, may reduce the insurance coverage they are willing to offer or demand significantly higher premiums or deductibles. If significant changes occur in the number or financial solvency of insurance underwriters for the energy industry, 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 a reasonable cost.

Furthermore, any loss under the insurance policies experienced by Delek may impact our ability to obtain, renew or arrange for adequate alternative coverage. 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.

Under the Omnibus Agreement, Delek has also agreed to reimburse us for certain losses related to certain asset failures, which provisions expire at various times depending on the asset involved. See Item 1, "Business—Commercial Agreements—Other Agreements with Delek." However, upon such expiration, or if Delek were to default under the Omnibus Agreement or otherwise fail to satisfy its obligations to us and insurance coverage was not otherwise available or was otherwise available only at substantial retention levels or cost, we could suffer significant losses that could have a material adverse effect on our business, financial condition and results of operations.

If we are unable to generate sufficient cash flow, our ability to pay quarterly distributions to our common unitholders at all, at current levels or in an amount equal to the minimum quarterly distribution or our ability to increase our quarterly distributions in the future could be impaired materially.

Our ability to pay quarterly distributions (including distributions equal to, or in excess of, the minimum quarterly distribution) depends primarily on cash flow, including cash flow from operations, cash from financial reserves, cash from credit facilities and cash from the capital markets, and not solely on profitability, which is affected by non-cash items. As a result, we may pay cash distributions during periods of losses and may be unable to pay cash distributions during periods of income. Our ability to generate sufficient cash flow is largely dependent on our ability to manage our business successfully, but may also be affected by economic, financial, competitive, regulatory and other factors beyond our control. For example, we may not be able to obtain debt or equity financing on terms that are favorable to us, if at all, and we may be required to fund our working capital requirements principally with cash generated by our operations and borrowings under our credit facilities and not to increase or pay distributions.

We may not have sufficient available cash each quarter to enable us to pay distributions at current levels or at the minimum quarterly distribution. In addition, even if we are able to make distributions in excess of the minimum quarterly distribution, because the cash we generate will fluctuate from quarter to quarter, quarterly distributions, or any period over period growth in such distributions, may also

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fluctuate, or even decrease, from quarter to quarter. Any failure to pay distributions at expected levels could result in a loss of investor confidence and a decrease in the trading price of our units.

Our assets and operations are subject to federal, state and local laws and regulations relating to environmental protection, pipeline integrity and safety that could require us to make substantial expenditures. In addition, our business involves the risks of spills, releases and emissions from our facilities, which could require us to make substantial expenditures and subject us to fines and penalties.

Our assets and operations involve the transportation and storage of crude oil and products, which are subject to increasingly stringent and extensive federal, state and local laws and regulations related to the discharge and remediation of materials in the environment, greenhouse gas emissions, waste management, species and habitat preservation, pollution prevention, pipeline integrity and other safety-related regulations, and characteristics and composition of fuels. These laws and regulations require us to comply with various safety requirements regarding the design, installation, testing, construction and operational management of certain of our assets. These requirements have raised operating costs, and compliance with such laws and regulations may cause us to incur potentially material capital expenditures associated with the construction, maintenance and upgrading of equipment and facilities. Environmental laws and regulations, in particular, are subject to frequent change, and many of them have become and may continue to become more stringent.

Transportation and storage of crude oil and products involves inherent risks of spills and releases and emissions into the air from our facilities, and can subject us to various federal and state laws governing spills and releases, including reporting and remediation obligations. We have experienced multiple releases and spills from our facilities and are subject to ongoing remediation and/or monitoring projects and enforcement actions. The costs associated with such obligations can be substantial, as can costs associated with related enforcement matters, including possible fines and penalties. Transportation of crude oil and products over water, or proximate to navigable bodies of water, involves inherent risks (including risks of spills) and could subject us to the provisions of the OPA, the Clean Water Act and similar state environmental laws should a spill occur from our facilities. See Item 1. "Business—Governmental Regulation and Environmental Matters—Water." Among other things, the OPA requires us to prepare a facility response plan identifying the personnel and equipment necessary to remove, to the maximum extent practicable, a “worst case discharge.” While our plans are designed to mitigate environmental impacts, such plans may not protect us from all liability associated with the discharge of crude oil or products into navigable waters.

With respect to the releases that have occurred, or for an event that occurs or is discovered in the future, whether in connection with any of our assets or any other facility to which we send or have sent waste or by-products for treatment or disposal, or a facility or assets that we may acquire from time to time as part of our ongoing growth strategy, we could be liable for all costs and penalties associated with the remediation of such facilities under federal, state and local environmental laws or common law. We may also be liable for personal injury, property damage and natural resource damage claims from third parties alleging contamination from spills or releases from our facilities or operations. In addition, even if we are insured against such risks, we may be responsible for costs or penalties to the extent our insurers do not fulfill their obligations to us or our insurance policies do not cover such items. Our failure to comply with these, or any other environmental, pipeline integrity or safety-related laws or regulations, could result in the assessment of administrative, civil or criminal penalties, the imposition of investigatory and remedial liabilities and the issuance of injunctions that may subject us to additional operational constraints. At present, the United States Department of Justice is pursuing an enforcement action on behalf of the Environmental Protection Agency with regard to potential Clean Water Act violations arising from the 2013 release at our Magnolia Station. See Item 3. Legal Proceedings. In addition, we could incur potentially significant additional expenses should we determine that any of our assets are not in compliance with such laws or regulations in order to bring our assets into compliance. Any such expenses, penalties or liabilities could have a material adverse effect on our business, financial condition or results of operations. While we are entitled to reimbursement or indemnification from Delek for certain environmental liabilities under the Omnibus Agreement, such reimbursement or indemnification may not fully cover any damages we may incur, or Delek may default on or otherwise fail to satisfy its obligations to us, which could have a material adverse effect on our business, financial condition or results of operations.

Further, certain of our pipeline facilities are subject to the pipeline safety regulations of the PHMSA at the DOT. PHMSA regulates the design, construction, testing, operation, maintenance, reporting and emergency response of crude oil, petroleum products and other hazardous liquid pipeline facilities.

PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs for hazardous liquids pipelines located where a leak or rupture could affect “high consequence areas” that are populated or environmentally sensitive areas, although recent rulemaking is extending certain requirements beyond high consequence areas. PHMSA has also issued regulations that subject certain rural low-stress hazardous liquids pipelines to the integrity management requirements. The integrity management regulations require operators, including us, to:

• perform ongoing assessments of pipeline integrity;

• identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

• maintain processes for data collection, integration and analysis;

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• repair and remediate pipelines as necessary; and

• implement preventive and mitigating actions.

PHMSA also carries out the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the "2011 Pipeline Safety Act"), which increased penalties for safety violations, established additional safety requirements for newly constructed pipelines, imposed new emergency response and incident notification requirements and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The Protecting our Infrastructure of Pipelines and Enhancing Safety Act (the "PIPES Act") was finalized in 2016, reauthorizing PHMSA’s pipeline safety programs through 2019 and directing PHMSA to complete unfinished mandates of the 2011 Pipeline Safety Act. The PIPES Act also directs PHMSA to provide a report to Congress within eighteen months studying the risks and providing safety recommendations for existing hazardous liquid pipelines as well as giving the agency increased emergency order authority to shut down and restrict pipeline use for unsafe conditions or practices.

We may incur significant costs and liabilities associated with compliance with pipeline safety regulations, and any corresponding repair, remediation, preventive or mitigation measures required for our non-exempt pipeline facilities, including lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Moreover, changes to pipeline safety laws and regulations that result in more stringent or costly pipeline integrity management or safety standards could have a material adverse effect on us and similarly situated operators.

A material decrease in wholesale fuel margins or in the quantity of barrels sold to wholesale customers could adversely affect our financial condition, results of operations, cash flows and ability to service our indebtedness.

Our wholesale fuel sales in our west Texas business are made to third party customers. The margins we earn on these sales, and the quantity of barrels we sell, are dependent on a number of factors outside our control, including the overall supply of refined products, overall market conditions, the demand for these products, competition from third parties, the price of ethanol and the value of renewable identification numbers ("RINs") we receive from blending renewable fuels. Specifically, among other circumstances, the margins we earn through these activities may be adversely impacted in the event of excess supply of refined products or decreased customer demand. These supply and demand dynamics are subject to day-to-day variability and may result in volatility in the margins that we achieve. These, and other dynamics, may also result in our customers reducing their purchases of product from us in favor of purchasing more product from other refiners or suppliers. Further, decreases in the value of RINs could impact our margins in our wholesale business. In addition, our margins are affected by the price we pay for ethanol, which is blended into certain refined products. We occasionally lock in ethanol prices by committing to purchase ethanol in the future at a certain price. If the spot price for ethanol at the time we actually take delivery of such product is less than what we paid for it, our margins could be negatively impacted. With the expiration of the Abilene Contract, a greater portion of the product that we purchase and sell may be subject to price volatility between the time of purchase and the time of sale. Price risk management programs established to hedge price volatility may not perform as intended, which may negatively impact gross margins. Extended periods of market conditions that result in us earning margins lower than anticipated or in us selling fewer barrels of product to wholesale customers, for any of the reasons set forth above or otherwise, could adversely affect our financial condition, results of operations and cash flows.

Our contract counterparties may suspend, reduce or terminate their obligations under our various commercial agreements in certain circumstances, including events of force majeure, which could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to unitholders.

Our commercial agreements with Delek and third parties provide that the counterparty may, depending on the commercial agreement, suspend, reduce or terminate its obligations to us under the applicable agreement, including the requirement to pay the fees associated with the applicable minimum volume commitments, in the event of (i) a material breach of the agreement by us, (ii) in the case of Delek, Delek deciding to permanently or indefinitely suspend refining operations at one or more of its refineries, or (iii) the occurrence of certain force majeure events that would prevent us or the third party from performing our or its obligations under the applicable agreement. Force majeure events may include any acts or occurrences that prevent services from being performed either by us or such third party under the applicable agreement, such as:

• acts of God;

• strikes, lockouts or other industrial disturbances;

• acts of the public enemy, wars, blockades, insurrections, riots or civil disturbances;

• storms, floods or washouts;

• arrests or the order of any court or governmental authority having jurisdiction while the same is in force and effect;

• explosions, breakage or accident to machinery, storage tanks or lines of pipe;

• any inability to obtain, or unavoidable delay in obtaining, material or equipment;

• any inability to deliver crude oil or refined products because of a failure of third-party pipelines; and

• any other causes not reasonably within the control of the party claiming suspension and which by the exercise of due diligence such party is unable to prevent or overcome.

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Our counterparties have the discretion in certain circumstances to decide to suspend, reduce or terminate their obligations under our commercial agreements notwithstanding the fact that their decisions may significantly and adversely affect us.

Accordingly, there exists a broad range of events that could result in us being unable to utilize our assets, and Delek or its assignee or a third party, as the case may be, no longer having an obligation to meet its minimum volume commitments or pay the amounts otherwise owing under the applicable agreement. Furthermore, a single event relating to one of Delek’s refineries could have such an impact on multiple of our commercial agreements with Delek or its assignee. Any reduction, suspension or termination of any of our commercial agreements could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to unitholders.

If Delek satisfies only its minimum obligations under, or if we are unable to renew or extend, the various commercial agreements we have with Delek, our ability to make distributions to our unitholders may be impaired.

Delek is not obligated to use, or to pay us with respect to our services, for volumes of crude oil or refined products in excess of the minimum volume commitments under the various commercial agreements with us. During refinery turnarounds, which typically last 30 to 60 days and are performed every three to five years, and during other planned or unplanned maintenance periods, Delek may only satisfy its minimum volume commitments during such periods with respect to our assets that serve the refinery. In addition, the initial terms of Delek’s obligations under those agreements range from five to ten years, unless earlier terminated as described above, with Delek having the option to renew. If Delek fails to use our services for volumes of crude oil or refined products in excess of the minimum volume commitments or fails to use our facilities and services after expiration of those agreements, or if Delek terminates those agreements prior to their expiration, and we are unable to generate additional revenues from third parties, our ability to make cash distributions to unitholders may be impaired.

A material decrease in the refining margins at the Tyler Refinery or the El Dorado Refinery could materially reduce the volumes of crude oil or refined products that we handle, which could adversely affect our financial condition, results of operations, cash flows and ability to make distributions to unitholders.

The volumes of crude oil and refined products that we transport and refined products that we market depend substantially on Delek’s refining margins. Refining margins are dependent mostly upon the price of crude oil or other refinery feedstocks and the price of refined products. These prices are affected by numerous factors beyond our or Delek’s control, including the dynamics of global supply and demand for crude oil, gasoline and other refined products. The impact of low refined product demand may be further compounded by excess global refining capacity and high inventory levels.

If the demand for refined products, particularly in Delek’s primary market areas, decreases significantly, or if there were a material increase in the price of crude oil supplied to the Tyler Refinery or the El Dorado Refinery without an increase in the value of the refined products produced by those refineries, either temporary or permanent, which caused Delek to reduce production of refined products at its refineries, there would likely be a reduction in the volumes of crude oil and refined products we handle for Delek. Any such reduction could adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

A material decrease in the supply of attractively priced crude oil could materially reduce the volumes of crude oil and refined products that we transport and store, which could materially and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

The volumes of crude oil and refined products that we may transport on our pipelines will depend on the volumes of crude oil processed and refined products produced at Delek’s refineries that we serve, as well as third parties' desire to transport crude on our systems, including our Paline Pipeline. The volumes of crude oil processed and refined products produced depend, in part, on the availability of attractively priced crude oil. For example, if a shipper on one of our pipeline systems is unable to locate or purchase attractively priced crude, which could happen due to a large number of market factors, and their shipments on our system are made in large part because of the pipeline's proximity to such attractively priced crude, then our pipeline may not be utilized. If the capacity of such pipeline is not under contract, or the pipeline is not utilized at all or to its capacity, then our results may be adversely affected. Our Paline Pipeline is such a pipeline. If we are unable to secure capacity agreements on our Paline Pipeline, our Paline Pipeline may go unused or underused for a period of time, which could affect our operating results if third parties are no longer interested in transporting crude oil along that route for economic reasons associated with the price of crude or other reasons.

Further, in order to maintain or increase production levels at Delek’s refineries, Delek must continually contract for new crude oil supplies or consider connecting to alternative sources of crude oil. Adverse developments in major oil producing regions around the world could have a significant impact on our financial condition, results of operations and cash flows because of our lack of industry and geographic

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diversity and substantial reliance on Delek as a direct or indirect customer. Accordingly, in addition to risks related to accessing, transporting and storing crude oil and refined products, we are disproportionately exposed to risks inherent in the broader oil and gas industry, including:

• the volatility and uncertainty of regional pricing differentials for crude oil and refined products;

• the action by the members of the Organization of the Petroleum Exporting Countries, or OPEC, individually or in the aggregate, regarding production levels and prices;

• the nature and extent of governmental regulation and taxation; and

• the anticipated future prices of crude oil and refined products in markets served by Delek’s refineries.

If, as a result of any of these or other factors, the volumes of attractively priced crude oil available to Delek’s refineries are materially reduced for a prolonged period of time, the volumes of crude oil and refined products that we transport and store, and the related fees for those services, could be materially reduced, which could materially and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

A portion of our operations are conducted through joint ventures, over which we do not have full control and which have unique risks.

A portion of our operations are conducted through joint ventures, in which we have been making investments since 2015. We are able to appoint members to the managing boards of each of the joint ventures and maintain certain rights of approval over certain actions of our partners and/or their affiliates. However, our partners in each of our joint ventures, or their affiliates, serve as, or are responsible for, the contractor and the operator of the joint ventures' assets, and we have limited control over the same. In addition, we have limited control over the cash distribution policies of each of the joint ventures.

We share ownership in the joint ventures with partners that may not always share our goals and objectives. Differences in views among the partners may result in delayed decisions or failures to agree on major matters, such as large expenditures or contractual commitments, the construction of assets or borrowing money, among others. Delay or failure to agree may prevent action with respect to such matters, even though such action may not serve our best interest or that of the joint venture. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business and operations. From time to time, our joint ventures may be involved in disputes or legal proceedings which may negatively affect our investments. Accordingly, any such occurrences could adversely affect our financial condition, operating results and cash flows.

Our substantial dependence on Delek's Tyler and El Dorado Refineries, as well as the lack of diversification of our assets and geographic locations, could adversely affect our ability to make distributions to our common unitholders.

We believe that a substantial majority of our gross and contribution margins for the foreseeable future will be derived from the operation of our pipelines, gathering systems and terminal and storage facilities that support the Tyler and El Dorado Refineries and are primarily located in Arkansas and Texas and, to a lesser degree, Louisiana and Tennessee. Any event that renders either Delek refinery temporarily or permanently unavailable could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders. Due to our lack of diversification in assets and geographic location, an adverse development in our businesses or areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in demand for crude oil and refined products, could have a significantly greater impact on our results of operations and cash available for distribution to our common unitholders than if we maintained more diverse assets and locations. Such events may constitute force majeure events under our commercial agreements, potentially resulting in the suspension, reduction or termination of multiple commercial agreements in the affected geographic area. In addition, during planned maintenance periods or a refinery turnaround, we expect that Delek, or its assignee, may only satisfy its minimum volume commitments with respect to our assets that serve such refinery. Please see “—Our contract counterparties may suspend, reduce or terminate their obligations under our various commercial agreements in certain circumstances, including events of force majeure, which could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to unitholders” and “—If Delek satisfies only its minimum obligations under, or if we are unable to renew or extend, the various commercial agreements we have with Delek, our ability to make distributions to our unitholders may be impaired.”

We are exposed to direct commodity price risk and interest rate risk, both of which may increase in the future. We may incur losses as a result of our forward contract activities and derivative transactions.

We typically own and hold a certain amount of inventory of light products in our business with respect to our wholesale marketing business in west Texas. Depending on our ability to sell such inventory, and the timing in which we do so, we could be exposed to risks related to the volatility of commodity prices in west Texas. Such volatility depends on many factors, including general market conditions and prices, demand for refined products in the west Texas market, the timing of refined product deliveries and downtime at refineries in the surrounding area. In addition, our actual product acquisitions from suppliers versus the amount we nominated to acquire may result in us being effectively long or short with respect to a given product and thus subject to further commodity price risk. This exposure to the volatility

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of commodity prices could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

To partially mitigate the risk of various financial exposures inherent in our business, including commodity price risk and interest rate risk, we selectively use derivative financial instruments, such as fuel-related derivative transactions, and may use interest rate swaps and interest rate cap agreements. In connection with such derivative transactions, we may be required to make payments to maintain margin accounts and to settle the contracts at their value in accordance with their terms and upon termination. The maintenance of required margin accounts, and the settlement of derivative contracts, could cause us to suffer losses or limit gains. In particular, derivative transactions could expose us to the risk of financial loss upon unexpected or unusual variations in the sales prices of wholesale gasoline and diesel relative to the derivative instrument. We cannot assure you that the strategies underlying these transactions will be successful. If any of the instruments we utilize to manage our exposure to various types of risk is not effective, we may incur losses.

Our ability to expand may be limited if Delek’s business does not grow as expected.

Part of our growth strategy depends on the growth of Delek’s business. For example, in our terminals and storage business, we believe our growth will be driven in part by identifying and executing organic expansion or new construction projects that will result in increased or new throughput volumes from Delek, its assignees and third parties. Our organic growth opportunities will be limited if Delek is unable to acquire new assets for which our execution of organic projects is needed. Additionally, if Delek focuses on other growth areas that our business does not serve, or does not make capital expenditures to fund the organic growth of its operations, we may not be able to fully execute our growth strategy.

We may not be able to significantly increase or retain our third-party revenue due to competition and other factors, which could limit our ability to grow and may increase our dependence on Delek.

We can provide no assurance that we will be able to retain or attract third-party revenues, which could limit our ability to grow and increase our dependence on Delek. Our ability to increase our third-party revenue is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when third-party shippers require it. Further, under certain of our commercial agreements with Delek, we may not provide service to third parties with respect to certain assets without Delek’s consent, subject to limited exceptions. Furthermore, to the extent that we have capacity at our refined products terminals available for third-party volumes, competition from other existing or future refined products terminals owned by our competitors may limit our ability to utilize this available capacity.

The costs, scope, timelines and benefits of any construction projects we undertake may deviate significantly from our original plans and estimates.

One of our business strategies is to evaluate and make capital investments to expand our existing asset base through the development and construction of new or expanded logistics assets. At the same time, we also will need to devote significant resources to maintaining our asset base. However, in developing or maintaining such assets, we may experience unanticipated increases in the cost, scope and completion time for our construction or maintenance and repair projects. Equipment that we require to complete these projects may be unavailable to us at expected costs or within expected time periods. Additionally, 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 realize and/or be less than we anticipated. Our inability to complete and/or realize the benefits of construction and/or maintenance projects in a cost-efficient and timely manner could have a material adverse effect on our business, financial condition, results of operations and our ability to make distributions.

If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to make quarterly cash distributions may be diminished or our financial leverage could increase.

In order to expand our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash distributions. We will be required to use cash from our operations or incur borrowings or sell additional limited partner units or interests in order to fund our expansion capital expenditures. Using cash from operations will reduce cash available for distribution to our common unitholders. Our ability to obtain financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering, as well as the covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to pay distributions to our common unitholders. Moreover, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

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If third-party pipelines, terminals or other facilities interconnected to our pipeline systems or terminals become partially or fully unavailable, or if we are unable to fulfill our contractual obligations, our financial condition, results of operations, cash flows and ability to make distributions to our unitholders could be adversely affected.

Our pipelines and terminals connect to other pipelines, terminals and facilities owned and operated by unaffiliated third parties. Our shippers often need to use such pipelines, terminals and facilities; however, the continuing operation of such third-party pipelines, terminals and other facilities is not within our control.

These pipelines, terminals and other facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity, corporate business decisions or because of damage from hurricanes or other operational hazards. In addition, we do not have interconnect agreements with all of these pipelines, terminals and other facilities, and the interconnect agreements we do have may be terminated in certain circumstances, including circumstances beyond our control, and on short notice. If any of these pipelines, terminals or other facilities becomes unable to receive or transport crude oil or refined products, we may be unable to perform our obligations under our commercial agreements with Delek and third parties, and our financial condition, results of operations, cash flows and ability to make distributions to our unitholders could be adversely affected.

Similarly, if additional shippers begin transporting volumes of refined products or crude oil over interconnecting pipelines, the allocations to us and other existing shippers on these interconnecting pipelines could be reduced, which could also reduce volumes distributed through our terminals or transported through our crude oil pipelines. Allocation reductions of this nature are not infrequent and are beyond our control. Any significant reduction in volumes could adversely affect our revenues and cash flow and our ability to make distributions to our unitholders.

An interruption or reduction of supply and delivery of refined products to our wholesale marketing business could result in a decline in our sales and profitability.

In our west Texas wholesale marketing business, we sell refined products that we purchase from Delek and unaffiliated third parties. The contract under which we purchased the majority of the products we sold in west Texas expired in December 2017. We are now purchasing the majority of product we sell in west Texas from Delek. The remainder of the barrels we sell in west Texas are spot purchased from various suppliers or refiners. We could experience an interruption or reduction in the supply or delivery of refined products if our suppliers, the refineries who supply us or our suppliers, or the pipelines that deliver that product partially or completely ceased operations, temporarily or permanently, or ceased to supply us with refined products for any reason. The ability of these refineries and our suppliers to supply refined products to us could be 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. An interruption or reduction in the volume of refined products supplied to our wholesale business could adversely affect our sales and profitability.

We are exposed to the credit risks and certain other risks of our key customers and other contractual counterparties, including Delek and its assignees, and any material nonpayment or nonperformance by our key customers or other counterparties could adversely affect our business, financial condition, results of operations and our ability to make distributions to our unitholders.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other contractual counterparties. Any material nonpayment or nonperformance or default by our key customers or other contractual counterparties, including Delek or its assignees, could adversely affect our business, financial condition, results of operations and our ability to make distributions to our unitholders.Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. Any loss of our key customers, including Delek, could adversely affect our business, financial condition, results of operations and our ability to make distributions to our unitholders.

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Restrictions in our revolving credit facility and in the indenture governing the 2025 Notes could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

Our revolving credit facility and the indenture governing the 2025 Notes contain, and any future financing agreements may contain, operating and financial restrictions and covenants that could limit our ability to finance future operations or capital needs, or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders.

For example, our revolving credit facility limits our ability to, among other things:

• incur or guarantee additional debt;

• incur certain liens on assets;

• dispose of assets;

• make certain cash distributions or redeem or repurchase units;

• change the nature of our business;

• engage in certain mergers or acquisitions or make certain investments (including joint ventures); and

• enter into certain transactions with affiliates.

Our revolving credit facility contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios can be affected by events beyond our control, and we cannot assure you that we will meet those ratios. In addition, our revolving credit facility contains events of default customary for agreements of this nature, including the occurrence of a change of control (which will occur if, among other things, (i) Delek ceases to own and control legally and beneficially at least 51% of the equity interests of our general partner, (ii) Delek Logistics GP, LLC ceases to be our sole general partner, or (iii) we fail to own and control legally and beneficially 100% of the equity interests of any other borrower under our revolving credit facility, unless otherwise permitted thereunder).

Similarly, the indenture governing the 2025 Notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to (i) incur, assume or guarantee additional indebtedness or issue certain convertible or redeemable equity securities; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem subordinated securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of our properties to, another person; (vii) sell or otherwise dispose or assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates.

The provisions of our revolving credit facility and of the indenture governing the 2025 Notes may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility or the 2025 Notes could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest and certain other indebtedness and other outstanding amounts, to be immediately due and payable. Such event of default would also permit our lenders to foreclose on our assets serving as collateral for our obligations under the revolving credit facility. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. The revolving credit facility and the indenture governing the 2025 Notes also have cross-default provisions that will apply to certain other indebtedness we may have.

Our debt levels may limit our flexibility to obtain financing and to pursue other business opportunities.

As of December 31, 2017, we had approximately $422.6 million in debt outstanding. We have the ability to incur additional debt; however, such ability is subject to limitations under our revolving credit facility and the indenture governing the 2025 Notes. Our level of debt could have important consequences to us, including the following:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on favorable terms;

• our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flows required to make payments on our debt and any interest thereon;

• we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

• our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, which is within our control, or such as reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital, which actions we may not be able to effect on satisfactory terms or at all.

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Transportation on certain of our pipelines is subject to federal or state rate and service regulation, and the imposition and/or cost of compliance with such regulation could adversely affect our operations and cash flows available for distribution to our unitholders. In addition, certain of our other contracts are eligible for fee increases tied to other inflationary indexes, which could adversely affect our operations and cash flows available for distribution to our unitholders.

Certain of our pipelines provide services that may be subject to regulation by the FERC, under the ICA, the Energy Policy Act of 1992 and/or state regulators. The FERC uses prescribed rate methodologies for developing regulated tariff rates for interstate oil and product pipelines. The FERC's primary rate-making authority is currently price-indexing; if the methodology changes, the new methodology may result in tariffs that generate lower revenues and cash flows. The indexing method allows a pipeline to increase its rates based on a percentage change in the producer price index for finished goods and is not based on pipeline-specific costs. If the index falls, we will be required to reduce our rates that are based on the FERC's price indexing methodology if they exceed the new maximum available rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. The FERC's rate-making methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs. Any of the foregoing could adversely affect our revenues and cash flows. We note that the FERC index has been set at a level for the period from 2016-2021 that is lower than that which was in effect from 2010-2015; this is likely to result in lower annual rate increases for the coming 2018-2021 period for our transportation and other rates that are subject to the FERC index for annual adjustments, compared to the previous five-year period, and indeed the index level for the 2016 index rate adjustment required a decrease in certain of our interstate transportation rates to comply with the reduced ceiling level. Furthermore, on October 20, 2016, the FERC issued an Advance Notice of Proposed Rulemaking regarding Revisions to Indexing Policies and Page 700 of FERC Form No. 6, (the “ANOPR”). If final rules are implemented as proposed in that ANOPR, our reporting burdens for providing to FERC annual throughput, revenue and cost of service information would likely increase. In addition, if implemented as proposed, FERC regulations based on the ANOPR would create new tests for whether our pipelines providing service subject to FERC tariffs could increase rates in accordance with the FERC index in a given year and could restrict our ability to increase our rates as a result.

Shippers may protest, and the FERC may investigate, the lawfulness of new or changed tariff rates. The FERC can suspend those tariff rates for up to seven months. It can also require refunds of amounts collected, based on rates that are ultimately found to be unlawful, and prescribe new rates prospectively. The FERC and interested parties can also challenge tariff rates that have become final and effective.

The FERC can order new rates to take effect prospectively and order reparations for past rates that exceed the just and reasonable level for time periods up to two years prior to the date of a complaint. Due to the complexity of rate making, the lawfulness of any rate is never assured. A successful challenge of our rates could adversely affect our revenues. In addition, on December 15, 2016, the FERC issued a Notice of Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Costs, (the “NOI”). The NOI sought comments on how FERC should address any double recovery for partnership-owned pipelines resulting from FERC’s current income tax allowance and rate of return policies. If the NOI results in final regulations or policy changes that alter the FERC’s current approach to liquids pipeline ratemaking and the relevant components of our interstate pipeline transportation rates, those changes could require us to change our rate design and potentially lower our rates if they are challenged on a cost of service basis. The FERC also regulates the terms and conditions of service, including access rights, for interstate transportation on common carrier pipelines subject to its jurisdiction.

While the FERC regulates rates and terms and conditions of service for transportation of crude oil or refined products in interstate commerce by pipeline, state agencies may regulate rates and terms and conditions of service for petroleum pipeline transportation in intrastate commerce. Whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact-dependent and determined on a case-by-case basis. We cannot provide assurance that the FERC will not, at some point, assert that some or all of the transportation service we provide is within its jurisdiction. If the FERC were successful with any such assertion, we may be required to pay refunds to customers and the FERC's rate-making methodologies may limit our ability to set rates based on our actual costs, delay the use of rates that reflect increased costs and subject us to potentially burdensome and expensive operational, reporting and other requirements. Service on the East Texas Crude Logistics System is currently subject to a temporary waiver issued by the FERC. If the conditions to the continued effectiveness of that East Texas Waiver Order are no longer true at any point, service on that system would become fully subject to FERC tariff filing requirements and other regulatory requirements for the provision of transportation service. If we file tariffs, we may be required to provide a cost justification for the transportation charge. We would also be required to provide service to all prospective shippers making reasonable requests for service without undue discrimination and to operate in a manner that does not provide any undue preference to shippers. The rates under such tariffs may be insufficient to allow us to recover fully our cost of providing service on the affected pipelines, which could adversely affect our business, financial condition and results of operations. In addition, regulation by the FERC may subject us to potentially burdensome and expensive operational, reporting and other requirements. We own pipeline assets in Texas, Arkansas and Louisiana. In Texas, a pipeline, with some exceptions, is required to operate as a common carrier and provide transportation without discrimination. Arkansas provides that all intrastate oil pipelines are common carriers, but it exercises light-handed regulation over petroleum pipelines. In Louisiana, all pipelines conveying petroleum from a point of origin within the state to a destination within the state are declared common carriers. The Louisiana Public Service Commission is empowered with the authority to establish reasonable rates and regulations for the transport of petroleum by a common carrier, mandating public tariffs and providing of transportation without discrimination. State

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commissions have generally not been aggressive in regulating common carrier pipelines, have generally not investigated the rates or practices of petroleum pipelines in the absence of shipper complaints and generally resolve complaints informally. If the regulatory commissions in the states in which we operate change their policies and aggressively regulate the rates or terms of service of pipelines operating in those states, it could adversely affect our business, financial condition and results of operations.

The Federal Trade Commission, the FERC and the CFTC hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.

In addition, the fees we charge on certain of our other contracts not involving regulated or other pipelines are also subject to change based on inflation based indices, such as certain sub-indices of the producer price index or the consumer price index. If the index rises, we will be able to increase our rates. However, if the index falls, we will be required to reduce our rates.

Delek’s level of indebtedness, the terms of its borrowings and any future credit ratings could adversely affect our ability to grow our business, our ability to make cash distributions to our unitholders and our credit profile. Our current and future credit ratings may also be affected by Delek’s level of indebtedness and creditworthiness.

Delek must devote a substantial portion of its cash flows from operations to service its debt and lease obligations, thereby reducing the availability of its cash flows to fund its growth strategy, including capital expenditures, acquisitions and other business opportunities that would expand its needs for logistics operations. Furthermore, a higher level of indebtedness at Delek increases the risk that it may default on its obligations, including commercial agreements with us. The covenants contained in the agreements governing Delek’s outstanding and future indebtedness may limit its ability to borrow additional funds for development and make certain investments and may directly or indirectly impact our operations in a similar manner. For example, Delek’s indebtedness requires that any transactions it enters into with us must be on terms no less favorable to Delek than those that could have been obtained with an unrelated person. There is also the risk that if Delek were to default under certain of its debt obligations, Delek’s creditors would attempt to assert claims against our assets during the litigation of their claims against Delek. The defense of any such claims could be costly and could materially impact our financial condition, even absent any adverse determination. In the event these claims were successful, our ability to meet our obligations to our creditors, make distributions and finance our operations could be materially and adversely affected.

Although we are not contractually bound by and are not liable for Delek’s debt under its credit arrangements, we may be indirectly affected by certain prohibitions and limitations contained therein. Due to its ownership and control of our general partner, Delek has the ability to prevent us from taking actions that would cause Delek to violate any covenants in its credit arrangements, or otherwise to be in default under any of its credit arrangements. In deciding whether to prevent us from taking any such action, Delek will have no fiduciary duty to us or our unitholders. Delek’s compliance with the covenants in its credit arrangements may restrict our ability to undertake certain actions that might otherwise be considered beneficial, including borrowing under our revolving credit facility.

Any debt instruments that Delek or any of its affiliates enter into in the future, including any amendments to existing credit facilities, may include additional or more restrictive limitations on Delek that may impact our ability to conduct our business. These additional restrictions could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities.

Our current and future credit ratings may be adversely affected by the leverage or any future credit rating of Delek, as credit rating agencies may consider the leverage and credit profile of Delek and its affiliates, because of their ownership interest in and control of us and because Delek accounts for a substantial majority of our contribution margin. Any adverse effect on our current and future credit ratings could increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which could impair our ability to grow our business and make cash distributions to our unitholders.

Increases in interest rates could adversely impact the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Floating interest rates on our revolving credit facility, to the extent not hedged, and interest rates on future credit facilities and debt offerings, could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

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Fixed rate debt, such as the 2025 Notes, exposes us to changes in the fair value of our debt due to changes in market interest rates. Fixed rate debt also exposes us to the risk that we may need to refinance maturing debt with new debt at higher rates, or that we may be obligated to rates higher than the current market.

Our right of first offer to acquire certain of Delek’s existing logistics assets and certain assets that it may acquire or construct in the future is subject to risks and uncertainty, and ultimately we may not acquire any of those assets.

The Omnibus Agreement provides us with a right of first offer on certain of Delek’s existing logistics assets and certain assets that it may acquire or construct in the future, subject to certain exceptions and time limitations. The consummation and timing of any future acquisitions pursuant to this right will depend on, among other things, Delek’s willingness to offer such assets for sale and obtain any necessary consents, our ability to negotiate acceptable purchase agreements and commercial agreements with respect to such assets and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future acquisitions pursuant to our right of first offer, and Delek is under no obligation to accept any offer that we may choose to make. In addition, we may decide not to exercise our right of first offer, if and when any assets are offered for sale, and our decision will not be subject to unitholder approval. In addition, our right of first offer may be terminated by Delek at any time in the event that it no longer controls our general partner.

If we are unable to make investments in joint ventures or acquisitions on economically acceptable terms from Delek or third parties, our future growth could be limited, and any investments or acquisitions we may make may reduce, rather than increase, our cash flows and ability to make distributions to unitholders.

A portion of our strategy to grow our business and increase distributions to unitholders is dependent on our ability to make acquisitions or invest in joint ventures that result in an increase in cash flow. If we are unable to make acquisitions from Delek or third parties or invest in joint ventures, because we are unable to identify attractive acquisition or project candidates or negotiate acceptable purchase contracts, we are unable to obtain financing for these acquisitions or investments on economically acceptable terms, we are outbid by competitors or we or the seller are unable to obtain any necessary consents, our future growth and ability to increase distributions to unitholders may be limited. Furthermore, even if we do consummate acquisitions or investments in joint ventures that we believe will be accretive, they may in fact result in a decrease in cash flow. Any acquisition or investment involves potential risks, including, among other things:

• mistaken assumptions about revenues and costs, including synergies;

• the assumption of known or unknown liabilities;

• limitations on rights to indemnity from the seller;

• mistaken assumptions about the overall costs of equity or debt;

• the diversion of management’s attention from other business concerns;

• ineffective or poor integration of such acquisitions;

• unforeseen difficulties operating multi-customer and product assets in new product areas or new markets; and

• customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions or investments in joint ventures, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

We may be unsuccessful in integrating the operations of the assets we have acquired or of any future acquisitions with our existing operations and in realizing all or any part of the anticipated benefits of any such acquisitions.

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. Our capitalization and results of operations may change significantly as a result of future acquisitions. Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of improper assumptions regarding the new assets, unfamiliarity with new assets and the businesses associated with them and new geographic areas and the diversion of management’s attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition, if at all. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions.

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The expansion of existing assets and construction of new assets, including through joint venture investments, may not result in revenue increases and will be subject to regulatory, environmental, political, legal, economic and other risks, which could adversely affect our results of operations and financial condition.

A portion of our strategy to grow and increase distributions to unitholders is dependent on our ability to expand existing assets and to construct additional assets, including through investments in joint ventures. The construction of a new pipeline or terminal, or the expansion of an existing pipeline or terminal, involves numerous regulatory, environmental, political and legal uncertainties, most of which are beyond our control. If we, or joint ventures we invest in, undertake these types of projects, they may not be completed on schedule, or at all, or at the budgeted cost. Moreover, we, or the joint ventures we invest in, may not receive sufficient long-term contractual commitments from customers to provide the revenue needed to support such projects. Even if such commitments are received, an increase in revenue may not be realized for an extended period of time. For instance, if we build, or invest in a joint venture that builds, a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project, if at all. In addition, we, or the joint ventures we invest in, may construct facilities to capture anticipated future growth in production in a region or gain access to crude supplies at lower costs, and such growth or access may not materialize. As a result, new facilities may not be able to attract enough throughput to achieve the expected return on investment, which could adversely affect our results of operations and financial condition and our ability to make distributions to our unitholders.

We do not own all of the land on which most of our pipelines and several of our facilities are located, which could result in disruptions to our operations.

We do not own all of the land on which most of our pipelines, tank farms and terminal facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or leases, if such rights-of-way or leases lapse or terminate or if our facilities are not properly located within the boundaries of such leases or rights-of-way. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies, and some of those agreements may grant us those rights for only a specific period of time. Our loss of such rights, through our inability to renew any rights-of-way contracts, or a significant increase in the costs of these rights, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to make distributions to our unitholders.

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, material 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.

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating and capital costs and reduced demand for our products and services.

In December 2009, the EPA published its findings that emissions of greenhouse gases, or GHGs, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the Earth’s atmosphere and other climatic conditions. Based on these findings, the EPA adopted two sets of regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates GHG emissions from certain large stationary sources under the Clean Air Act Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. In addition, the EPA expanded its existing GHG emissions reporting rule to include onshore oil and natural gas processing, transmission, storage, and distribution activities, beginning in 2012 for emissions occurring in 2011. Congress has also from time to time considered legislation to reduce emissions of GHGs. Efforts have been made, and continue to be made, in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In April 2016, the United States became a signatory to the 2015 United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which became effective by its terms on November 4, 2016, will require countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years, beginning in 2020. On August 4, 2017, the United States formally communicated to the United Nations its intent to withdraw from participating in the Paris Agreement, which entails a four year process. In response to the announced withdrawal plan, a number of state and local governments in the United States have expressed intentions to take GHG-related actions. Although it is not possible to predict the requirements of any GHG legislation or regulations that may be enacted or promulgated, any laws or regulations that may be adopted to restrict or reduce GHG emissions may require us to incur increased operating costs. 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,

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any increase in the prices of refined products resulting from such increased costs could have a material adverse effect on our business, financial condition or results of operations. Moreover, GHG regulation could also impact the consumption of refined products, thereby affecting the demand for our services. Finally, some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets.

In 2010, the EPA and the National Highway Transportation Safety Administration ("NHTSA") finalized new standards, raising the required Corporate Average Fuel Economy, or CAFE, standard of the nation’s passenger fleet by 40% to approximately 35 miles per gallon by 2016 and imposing the first ever federal GHG emissions standards on cars and light trucks. In September 2011, the EPA and the DOT finalized first-time standards for fuel economy of medium and heavy duty trucks. On August 28, 2012, the EPA and NHTSA announced final regulations that mandated further decreases in passenger vehicle GHG emissions and increases in fuel economy beginning with 2017 model year vehicles and increasing to the equivalent of 54.5 miles per gallon by 2025. During 2016, the EPA conducted a mid-term evaluation of progress in meeting vehicle GHG standards and in January 2017 the EPA issued a determination to maintain the current GHG emissions standards for model year (MY) 2022-2025 vehicles. In March 2017, EPA announced its decision to reopen the mid-term evaluation process and reconsider the January 2017 determination. As a result, GHG emissions standards for MY 2022-2025 vehicles remain uncertain. In August 2016, the EPA and the NHTSA jointly finalized standards for medium- and heavy-duty vehicles regulating fuel efficiency and carbon pollution. 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. Decreasing demand for petroleum fuels could materially affect profitability at Delek’s refineries, which could adversely impact our business, results of operations and cash flows.

Our operations are subject to federal and state laws and regulations relating to product quality specifications, and we could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of products we distribute to meet certain quality specifications.

Various federal and state agencies prescribe specific product quality specifications for refined products, including vapor pressure, sulfur content, benzene content, ethanol content and biodiesel content. Changes in product quality specifications or blending requirements could reduce our throughput volume, require us to incur additional handling costs or require capital expenditures. For example, mandated increases in use of renewable fuels could require the construction of additional storage and blending equipment. If we are unable to recover these costs through increased revenues, our cash flows and ability to pay cash distributions to our unitholders could be adversely affected. Violations of product quality laws attributable to our operations could subject us to significant fines and penalties as well as negative publicity. In addition, changes in the product quality of the products we receive on our pipeline system could reduce or eliminate our ability to blend products.

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

Terrorist attacks in the United States, as well as events occurring in response or similar to or in connection with such attacks, including political instability in various Middle Eastern countries, may harm our business. Energy-related assets (which could include pipelines and terminals such as ours) may be at greater risk of future terrorist attacks than other possible targets in the United States. In addition, the State of Israel, where Delek Group, the former parent company of Delek, is based, has suffered armed conflicts and political instability in recent years. We may be more susceptible to terrorist attack as a result of our connection to Israel. In the future, certain of the directors of our general partner may reside in Israel.

A direct attack on our assets (including cyber attacks), Delek’s 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 the crude oil and other feedstocks we transport and refined petroleum products, and an adverse impact on the margins from our operations. Disruption or significant increases in energy prices could also result in government-imposed price controls.

Further, changes in the insurance markets attributable to terrorist attacks could make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital, including our ability to repay or refinance debt.

Our customers’ operating results are seasonal and generally lower in the first and fourth quarters of the year. Our customers depend on favorable weather conditions in the spring and summer months.

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 fluctuate during the calendar year. Demand for gasoline, for example, is generally higher

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during the summer months than during the winter months due to seasonal increases in motor vehicle traffic, while demand for asphalt products, which is a substantial product of Delek's El Dorado Refinery, is lower in the winter months. In addition, our refining customers, such as Delek, occasionally slow or shut down operations to perform planned maintenance during the winter, when demand for their products is lower. Accordingly, these factors can affect the need for crude oil or finished products by our customers, and therefore limit our volumes or throughput during these periods, and could adversely affect our customers’ business, financial condition and results of operations, which may adversely affect our business, financial condition and results of operations.

Regulations adopted by the Commodity Futures Trading Commission could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The U.S. Congress has adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which is comprehensive financial reform legislation that, among other things, establishes new federal oversight and regulation of over-the-counter derivatives and many of the entities that participate in that market. The Dodd-Frank Act was enacted in 2010, and the Commodity Futures Trading Commission (“CFTC”), and the SEC, along with certain other regulators, have promulgated final rules to implement many of the Dodd-Frank Act’s provisions relating to over-the-counter derivatives. Most of these rules have been finalized, while others have not; as a result, the final form and timing of the implementation of certain parts of the regulatory regime affecting commodity derivatives remains uncertain. Among other consequences of the new regulations, entities that enter into derivatives (including futures and exchange-traded and over-the-counter swaps) are expected to be subject to aggregate position limits for certain futures, options and swaps (under regulations re-proposed in December 2016 that have not been finalized and the ultimate form, timing and implementation of which remains uncertain), and are currently subject to recordkeeping and reporting requirements. There can be no assurance that, when fully implemented, this regulatory regime will not have a material adverse effect on our ability to hedge our exposure to commodity prices, interest rates and other risks to the extent that we use derivatives to do so.

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 are heavily dependent on technology infrastructure and rely upon certain critical information systems for the effective operation of our business. These information systems include data network and telecommunications, internet access and our websites, and various computer hardware equipment and software applications, including those that are critical to the safe operation of our pipelines and terminals. These information systems are subject to damage or interruption from a number of potential sources, including natural disasters, software viruses or other malware, power failures, cyber-attacks and other events to the extent that these information systems are under our or Delek’s control. Delek has implemented measures, such as virus protection software, intrusion detection systems, advanced monitoring and emergency recovery processes to address the outlined risks. However, security measures for information systems cannot be guaranteed to be failsafe. Any compromise of our data security, or our inability to use or access these information systems at critical points in time, could unfavorably impact the timely and efficient operation of our business and subject us to additional costs and liabilities, which could adversely affect our results of operations. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.

Risks Relating to Our Partnership Structure

Our general partner and its affiliates, including Delek and the Individual GP Owners, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.

Delek controls our general partner and appoints all of the officers and directors of our general partner. In addition, three members of the board of directors of our general partner, all of whom also serve as executive officers of Delek, own a small percentage of our general partner (the "Individual GP Owners"). See Item 10. Directors, Executive Officers and Corporate Governance. All of the officers and three of the directors of our general partner (who are also the Individual GP Owners) are also officers and/or directors of Delek. Although our general partner has a contractual obligation to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to Delek. Conflicts of interest will arise from time to time between Delek, the Individual GP Owners, and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Delek and the Individual GP Owners over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

• Our Partnership Agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.

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• Neither our Partnership Agreement nor any other agreement requires Delek to pursue a business strategy that favors us or utilizes our assets, including whether to increase or decrease refinery production, whether to shut down or reconfigure a refinery or what markets to pursue or grow. The directors and officers of Delek have a fiduciary duty to make these decisions in the best interests of the stockholders of Delek, which may be contrary to our interests. Delek may choose to shift the focus of its investment and growth to areas not served by our assets.

• Delek, as our primary customer, has an economic incentive to cause us not to seek higher service fees, even if such higher fees could be obtained in arm’s-length, third-party transactions. Furthermore, under many of our commercial agreements with them, Delek’s consent is required before we may enter into an agreement with any third party with respect to certain of our assets, including those that serve the El Dorado and Tyler Refineries, and Delek has an incentive to cause us not to pursue such third-party contracts in certain circumstances.

• Our general partner is allowed to take into account the interests of parties other than us, such as Delek, in resolving conflicts of interest.

• All of the officers and three of the directors of our general partner (who are also the three Individual GP Owners) are also officers and/or directors of Delek and owe fiduciary duties to Delek. These officers will also devote significant time to the business of Delek and will be compensated by Delek accordingly.

• Delek may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests.

• Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

• Disputes may arise under our commercial agreements with Delek.

• Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership units and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash available for distribution to our unitholders.

• Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders.

• Our general partner determines which costs incurred by it are reimbursable by us.

• Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on their common units or to make incentive distributions.

• Our Partnership Agreement permits us to classify up to $25.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our general partner units or to our general partner in respect of the incentive distribution rights.

• Our Partnership Agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

• Our general partner intends to limit its liability regarding our contractual and other obligations.

• Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.

• Our general partner controls the enforcement of the obligations that it and its affiliates owe to us, including Delek’s obligations under the Omnibus Agreement and its commercial agreements with us.

• Our general partner decides whether to retain separate counsel, accountants or other advisers to perform services for us.

• Our general partner may transfer its incentive distribution rights without unitholder approval.

• Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Our Partnership Agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties.

Our Partnership Agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our Partnership Agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the Partnership Agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

• how to allocate corporate opportunities among us and its other affiliates;

• whether to exercise its limited call right;

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• whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;

• how to exercise its voting rights with respect to the units it owns;

• whether to exercise its registration rights;

• whether to elect to reset target distribution levels;

• whether to transfer the incentive distribution rights to a third party; and

• whether or not to consent to any merger or consolidation of the Partnership or amendment to the Partnership Agreement.

Delek may compete with us.

Delek may compete with us. Under the Omnibus Agreement, Delek and its affiliates have agreed not to engage in, whether by acquisition or otherwise, the business of owning or operating crude oil or refined products pipelines, terminals or storage facilities in the United States that are not within, directly connected to, substantially dedicated to, or otherwise an integral part of, any refinery owned, acquired or constructed by Delek. This restriction, however, does not apply to:

• any assets that were owned by Delek upon the completion of the Offering (including replacements or expansions of those assets);

• any asset or business that Delek acquires or constructs that has a fair market value of less than $5.0 million; and

• any asset or business that Delek acquires or constructs that has a fair market value of $5.0 million or more if we have been offered the opportunity to purchase the asset or business for fair market value not later than six months after completion of such acquisition or construction, and we decline to do so.

As a result, Delek has the ability to construct assets which directly compete with our assets. The limitations on the ability of Delek to compete with us are terminable by either party if Delek ceases to control our general partner.

Pursuant to the terms of our Partnership Agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and Delek. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our common unitholders.

If unitholders are not eligible holders, their common limited partner units may be subject to redemption.

We have adopted certain requirements regarding those investors who may own our common units. Eligible holders are limited partners whose (i) federal income tax status is not reasonably likely to have a material adverse effect on the rates that can be charged by us on assets that provide services that are subject to regulation by the FERC or an analogous regulatory body and (ii) nationality, citizenship or other related status would not create a substantial risk of cancellation or forfeiture of any property in which we have an interest, in each case as determined by our general partner with the advice of counsel. If you are not an eligible holder, in certain circumstances as set forth in our Partnership Agreement, your units may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

Our Partnership Agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We expect that we will distribute all of our available cash quarterly to our unitholders and, to the extent not otherwise reserved for, will rely primarily upon cash flows from operations, borrowings under the Second Amended and Restated Credit Agreement (as defined below) and potential future issuances of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy could significantly impair our ability to grow.

In addition, because we intend to distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per-unit distribution level. There are no limitations in our Partnership Agreement, and we do not anticipate there being limitations in any of our credit facilities, on our ability to issue additional units, including units ranking senior to the common limited partner units. The incurrence of additional borrowings, or other debt, to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

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Our Partnership Agreement restricts the remedies available to holders of our common limited partner units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our Partnership Agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement provides that:

• whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of the Partnership, and, except as specifically provided by our Partnership Agreement, will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;

• our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

• our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission, unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

• our general partner will not be in breach of its obligations under the Partnership Agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:

◦ approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;

◦ approved by the vote of a majority of the outstanding common limited partner units, excluding any common units owned by our general partner and its affiliates;

◦ determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

◦ determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or its conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub bullets above, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. The general partner may still take action with respect to any affiliate transactions or the resolution of a conflict of interest without satisfying any of the sub bullets above. In such case, it is not entitled to the presumption of good faith discussed above.

The administrative services fee and reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce our cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making any distribution on our common limited partner units, we will reimburse our general partner and its affiliates, including Delek, for costs and expenses they incur and payments they make on our behalf. Under the Omnibus Agreement, we will pay Delek an annual fee and reimburse Delek and its subsidiaries for Delek’s provision of various centralized corporate services. Additionally, we will reimburse Delek for direct or allocated costs and expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business, and insurance expenses. We also expect to incur incremental annual general and administrative expense as a result of being a publicly traded partnership. Our Partnership Agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders.

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Holders of our common limited partner units have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. Rather, the board of directors of our general partner will be appointed by the members of the general partner, which currently consist of Delek and Messrs. Yemin, Ginzburg and Green. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common limited partner units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Even if holders of our common limited partner units are dissatisfied, they cannot remove our general partner without its consent.

Unitholders are unable to remove our general partner without its consent, because our general partner and its affiliates, including Delek, own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common limited partner units is required to remove our general partner. As of February 26, 2018, Delek owned 62.7% of our outstanding common limited partner units.

Our Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common limited partner units.

Unitholders’ voting rights are further restricted by a provision of our Partnership Agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.

Our Partnership Agreement does not restrict the ability of Delek to transfer all or a portion of its general partner interest or its ownership interest in our general partner to a third party. Our general partner, or the new owner of our general partner, would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers of our general partner.

The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of Delek selling or contributing additional assets to us, as Delek would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

We may issue additional units without unitholder approval, which would dilute unitholder interests.

Our Partnership Agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common limited partner units that we may issue at any time without the approval of our unitholders. The issuance by us of additional common limited partner units or other equity securities of equal or senior rank will have the following effects:

• our existing unitholders’ proportionate ownership interest in us will decrease;

• the amount of cash available for distribution on each unit may decrease;

• because the amount payable to holders of incentive distribution rights is based on a percentage of the total cash available for distribution, the distributions to holders of incentive distribution rights will increase even if the per-unit distribution on common limited partner units remains the same;

• the ratio of taxable income to distributions may increase;

• the relative voting strength of each previously outstanding unit may be diminished; and

• the market price of the common limited partner units may decline.

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Delek may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

Delek holds 15,294,046 common limited partner units. In addition, we have agreed to provide Delek with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements, so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our Partnership Agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our general partner has a limited call right that may require our unitholders to sell their units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of our common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our Partnership Agreement. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any positive return on their investment. Our unitholders may also incur a tax liability upon any such sale of their units to Delek. At February 26, 2018, Delek owned 15,294,046 common limited partner units, or 62.7% of our total outstanding common limited partner units.

Our general partner, or any transferee holding a majority of the incentive distribution rights, may elect to cause us to issue common limited partner units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to the incentive distribution rights, without the approval of the conflicts committee of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

The holder or holders of a majority of the incentive distribution rights, which is currently our general partner, have the right, at any time when there are no subordinated units outstanding and such holders have received incentive distributions at the highest level to which they are entitled (48.0%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for each such quarter), to reset the minimum quarterly distribution and the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. Our general partner has the right to transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights shall have the same rights as our general partner with respect to resetting target distributions.

In the event of a reset of the minimum quarterly distribution and the target distribution levels, the holders of the incentive distribution rights will be entitled to receive, in the aggregate, the number of common limited partner units equal to that number of common limited partner units which would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not otherwise be sufficiently accretive to cash distributions per common unit. It is possible, however, that our general partner or a transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights, and may therefore desire to be issued common limited partner units rather than retain the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common limited partner units to our general partner or its transferee in connection with resetting the target distribution levels.

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Our unitholders' liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. The Partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Our unitholders could be held liable for any and all of our obligations as if they were general partners if a court or government agency were to determine that:

• we were conducting business in a state but had not complied with that particular state’s partnership statute; or

• our unitholders' right to act with other unitholders to remove or replace our general partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common limited partner units are liable both for the obligations of the transferor to make contributions to the Partnership that were known to the transferee at the time of transfer and for those obligations that were unknown if the liabilities could have been determined from the Partnership Agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

Our common limited partner units are listed on the New York Stock Exchange ("NYSE"). Because we are a publicly traded limited partnership, the NYSE does not require us to have, and we do not intend to have, a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common limited partner units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (the "IRS") on this or any other tax matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 21.0%, and would likely pay state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to such unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be material reductions in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common limited partner units.

Our Partnership Agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

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If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such additional tax on us by a state will reduce the cash available for distribution to our unitholders. Our Partnership Agreement provides that, if a law is enacted or an existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common limited partner units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common limited partner units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, such a proposal could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for federal income tax purposes. We are unable to predict whether any changes or proposals will ultimately be enacted, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our common limited partner units.

Our unitholders are required to pay income taxes on their share of our taxable income even if they do not receive any cash distributions from us. A unitholder's share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, transactions in which we engage or changes in law and may be substantially different from any estimate we make in connection with a unit offering.

A unitholder’s allocable share of our taxable income will be taxable to it, which may require it to pay federal income taxes and, in some cases, state and local income taxes, even if it receives cash distributions from us that are less than the actual tax liability that results from that income or no cash distributions at all.

A unitholder's share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, which may be affected by numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control, and certain transactions in which we might engage. For example, we may engage in transactions that produce substantial taxable income allocations to some or all of our unitholders without a corresponding increase in cash distributions to our unitholders, such as a sale or exchange of assets, the proceeds of which are reinvested in our business or used to reduce our debt, or an actual or deemed satisfaction of our indebtedness for an amount less than the adjusted issue price of the debt. A unitholder's ratio of its share of taxable income to the cash received by it may also be affected by changes in law. For instance, under the recently enacted tax reform law known as the Tax Cuts and Jobs Act, the net interest expense deductions of certain business entities, including us, are limited to 30% of such entity's "adjusted taxable income", which is generally taxable income with certain modifications. If the limit applies, a unitholder's taxable income allocations will be more (or its net loss allocations will be less) than would have been the case absent the limitation.

From time to time, in connection with an offering of our units, we may state an estimate of the ratio of federal taxable income to cash distributions that a purchaser of units in that offering may receive in a given period. These estimates depend in part on factors that are unique to the offering with respect to which the estimate is stated, so the expected ratio applicable to other units will be different, and in many cases less favorable, than these estimates. Moreover, even in the case of units purchased in the offering to which the estimate relates, the estimate may be incorrect, due to the uncertainties described above, challenges by the IRS to tax reporting positions which we adopt, or other factors. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units.

If the IRS contests the federal income tax positions we take, the market for our common limited partner units may be adversely impacted and the cost of any IRS contest would likely reduce our cash available for distribution to unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the conclusions of our counsel or from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a material adverse effect on the market

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for our common limited partner units and the price at which they trade. In addition, our costs of any contest with the IRS would be borne indirectly by our unitholders and our general partner, because the costs would likely reduce our cash available for distribution.

Tax gain or loss on the disposition of our common limited partner units could be more or less than expected.

If any of our unitholders sells their common limited partner units, such unitholders must recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and such unitholder's tax basis in those common limited partner units. Because distributions in excess of such unitholder's allocable share of our net taxable income decrease such unitholder's tax basis in such unitholder's common limited partner units, the amount, if any, of such prior excess distributions with respect to the common limited partner units such unitholder sells will, in effect, become taxable income to such unitholder if it sells such common limited partner units at a price greater than its tax basis in those common limited partner units, even if the price such unitholder receives is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale or other disposition of such unitholder's common limited partner units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells their common limited partner units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common limited partner units that may result in adverse tax consequences to them.

Investment in our common limited partner units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income ("UBTI")and will be taxable to them. Under the recently enacted tax reform act known as the Tax Cuts and Jobs Act, an exempt organization will be required to independently compute its UBTI from each separate unrelated trade or business which may prevent an exempt organization from utilizing losses we allocate to the organization against the organization’s UBTI from other sources and vice versa. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common limited partner units.

Under the Tax Cuts and Jobs Act, if a unitholder sells or otherwise disposes of a common unit, the transferee is required to withhold 10.0% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. However, the Department of the Treasury and the IRS have determined that this withholding requirement should not apply to any disposition of a publicly traded interests in a publicly traded partnership (such as us) until regulations or other guidance have been issued clarifying the application of this withholding requirement to dispositions of interests in publicly traded partnerships. Accordingly, while this new withholding requirement does not currently apply to interests in the Partnership, there can be no assurance that such requirement will not apply in the future.

We treat each holder of common limited partner units as having the same tax benefits without regard to the actual common limited partner units held. The IRS may challenge this treatment, which could adversely affect the value of the common limited partner units.

Because we cannot match transferors and transferees of common limited partner units, and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder's sale of common limited partner units and could have a negative impact on the value of our common limited partner units or result in audit adjustments to such unitholder's tax returns.

We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of the Treasury adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such final regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Our counsel has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations.

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If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it (and some states) may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our general partner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (and will choose to do so) under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If we make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders would be reduced, perhaps substantially.

In the event the IRS makes an audit adjustment to our income tax returns and we do not or cannot shift the liability to our unitholders in accordance with their interests in us during the year under audit, we will generally have the ability to request that the IRS reduce the determined underpayment by reducing the suspended passive loss carryovers of our unitholders (without any compensation from us to such unitholders), to the extent such underpayment is attributable to a net decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected unitholders.

A unitholder whose common limited partner units are loaned to a “short seller” to cover a short sale of common limited partner units may be considered as having disposed of those common limited partner units. If so, such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common limited partner units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common limited partner units are loaned to a “short seller” to cover a short sale of common limited partner units may be considered as having disposed of the loaned common limited partner units, such unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common limited partner units during the period of the loan to the short seller and may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common limited partner units may not be reportable by the unitholder, and any cash distributions received by the unitholder as to those common limited partner units could be fully taxable as ordinary income. Therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common limited partner units.

We have adopted certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common limited partner units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common limited partner units may have a greater portion of their Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common limited partner units and could have a negative impact on the value of the common limited partner units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

As a result of investing in our common limited partner units, our unitholders may be subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders may be subject to other taxes, including state and local income, franchise, unincorporated business, estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if such unitholders do not live or otherwise do business in any of those jurisdictions. Our unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property and conduct

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business in Arkansas, Louisiana, Oklahoma, Tennessee and Texas. Many of these states impose a personal income tax on individuals, and each state imposes an income or similar tax on corporations and certain other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that may impose personal income taxes or other state or local taxes on our unitholders.

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

We are subject to extensive tax laws and regulations, including federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes, as well as interest and penalties.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Our principal assets, as of December 31, 2017, have been described in Item 1. "Business—Pipelines and Transportation Segment" and Item 1. "Business—Wholesale Marketing and Terminalling Segment." We believe that our assets are adequate for our operations and adequately maintained.

Title to Properties and Permits

While we own the physical improvements consisting of our pipelines, substantially all of these pipelines are constructed on rights-of-way granted by the apparent record owners of the property, and in some instances these rights-of-way are revocable at the election of the grantor. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets and state highways, and, in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our common carrier pipelines.

We believe that we are the owner of valid easement rights and rights-of-way or fee ownership or leasehold interests to the lands on which our assets are located. Under the Omnibus Agreement, Delek has agreed to indemnify us for certain title defects and for failures to obtain certain consents and permits necessary to conduct our business, in each case, that are identified prior to the relevant date in the Omnibus Agreement, subject to an annual deductible. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens, and easements, restrictions, and other encumbrances to which the underlying properties were subject at the time of acquisition by our predecessor or us, we believe that none of these burdens should materially detract from the value of these properties or from our interest in these properties or should materially interfere with their use in the operation of our business.

Facilities

Our Nettleton Station and our Bradford Station are located on properties that are owned by third parties in which we have leasehold interests. Our North Little Rock Terminal, our El Dorado Terminal and tank farm, our Tyler Terminal and tank farm, the El Dorado Rail Offloading Racks and the Tyler Crude Tank are located on property leased by third parties and Delek.

Liens and Encumbrances

Substantially all of the assets described above are pledged under and encumbered by our credit agreement. 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.

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Corporate Headquarters

Delek leases its corporate headquarters at 7102 Commerce Way, Brentwood, Tennessee. The lease is for 54,000 square feet and expires in April 2022. We pay Delek a proportionate share of the costs to operate the building pursuant to the Omnibus Agreement. Please read Item 1. "Business—Commercial Agreements—Other Agreements with Delek."

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.

We are reporting the following proceeding to comply with SEC regulations which require disclosure of proceedings arising under federal, state or local provisions regulating the discharge of materials into the environment or protecting the environment, if we reasonably believe that such proceedings may result in monetary sanctions of $100,000 or more.

In June 2015, the United States Department of Justice notified us that they were pursuing an enforcement action on behalf of the EPA with regard to potential Clean Water Act violations arising from a release in March 2013 at our Magnolia Station located west of the El Dorado Refinery. We are currently attempting to negotiate a resolution to this matter with the EPA and the Arkansas Department of Environmental Quality, which may include monetary penalties and/or other relief.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

Unit Price and Cash Distributions

Our common units represent limited partner interests in us that entitle the holders to the rights and privileges specified in our Partnership Agreement. Our common units trade on the NYSE under the symbol "DKL." There were four holders of record of our common units held by the public as of February 26, 2018. In addition, as of February 26, 2018, Delek and its affiliates owned 15,294,046 of our common units and 497,604 of our general partner units (a 2.0% general partner interest), which together constitute a 63.5% ownership interest in us.

The following table sets forth the range of the daily high and low sales prices per common unit for each quarterly period and the cash distributions to common unitholders with respect to each quarterly period during the years ended December 31, 2017 and December 31, 2016.

Quarter Ended	High Sales Price	Low Sales Price	Quarterly Cash Distribution per Limited Partner Unit (1)	Distribution Date	Record Date
December 31, 2017	$32.80	$26.80	$0.725	February 12, 2018	February 2, 2018
September 30, 2017	$35.54	$28.25	$0.715	November 14, 2017	November 7, 2017
June 30, 2017	$33.85	$28.35	$0.705	August 11, 2017	August 4, 2017
March 31, 2017	$36.05	$28.50	$0.690	May 12, 2017	May 5, 2017
December 31, 2016	$30.60	$21.30	$0.680	February 14, 2017	February 3, 2017
September 30, 2016	$29.59	$25.20	$0.655	November 14, 2016	November 7, 2016
June 30, 2016	$33.92	$24.16	$0.630	August 12, 2016	August 5, 2016
March 31, 2016	$35.25	$21.84	$0.610	May 13, 2016	May 5, 2016

⁽¹⁾  Represents cash distributions attributable to the quarter and declared and paid within 45 days of quarter end in accordance with our Partnership Agreement.

Distributions of Available Cash

Our Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.

Definition of Available Cash

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

• less the amount of cash reserves established by our general partner to:

◦ provide for the proper conduct of our business (including cash reserves for our future capital expenditures and anticipated future debt service requirements and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);

◦ comply with applicable law, any of our debt instruments or other agreements; or

◦ provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of

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such reserves will prevent us from distributing the minimum quarterly distribution on all common units for the current quarter);

• plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter. Under our Partnership Agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners, and with the intent of the borrower to repay such borrowings within 12 months with funds other than from additional working capital borrowings.

Intent to Distribute the Minimum Quarterly Distribution

We intend to pay a quarterly distribution of at least $0.375 per unit per quarter, or $1.50 per unit on an annualized basis, to the extent we have sufficient available cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, we do not have a legal obligation to pay this distribution. The amount of distributions paid under our policy, and the decision to make any distribution, is determined by our general partner, taking into consideration the terms of our Partnership Agreement.

General Partner Interest and Incentive Distribution Rights

Our general partner is currently entitled to 2.0% of all quarterly distributions that we make prior to our liquidation. This general partner interest is represented by 497,604 general partner units. Our general partner has the right, but not the obligation, to contribute up to a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s 2.0% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.

Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48.0%, of the cash we distribute from operating surplus (as defined in our Partnership Agreement) in excess of $0.43125 per unit per quarter. The maximum distribution of 48.0% does not include any distributions that our general partner or its affiliates may receive on common or general partner units that it owns.

Percentage Allocations of Available Cash

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest and that our general partner has not transferred its incentive distribution rights.

	Total Quarterly	Marginal Percentage
	Distribution per Unit	Interest in Distributions
	Target Amount	Unitholders		General Partner
Minimum Quarterly Distribution	$0.37500	98.0	%	2.0	%
First Target Distribution	above $0.37500	98.0	%	2.0	%
	up to $0.43125
Second Target Distribution	above $0.43125	85.0	%	15.0	%
	up to $0.46875
Third Target Distribution	above $0.46875	75.0	%	25.0	%
	up to $0.56250
Thereafter	above $0.56250	50.0	%	50.0	%

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Expiration of Subordination Period

Following theFebruary 12, 2016 payment of the cash distribution attributable to the fourth quarter of 2015, and confirmation by the board of directors of our general partner (based on the recommendation of the conflicts committee) on February 25, 2016 that the requirements under the Partnership Agreement for the conversion of all subordinated units into common units were satisfied, the subordination period ended. As a result, in the first quarter of 2016, all of the Partnership's 11,999,258 outstanding subordinated units converted into common units and began participating pro rata with the other common units in distributions of available cash. The conversion did not impact the amount of cash distributions paid or the total number of the Partnership's outstanding units representing limited partner interests.

Unregistered Sales of Equity Securities

Pursuant to the terms of our Partnership Agreement, our general partner has the right to maintain its proportionate 2.0% general partner interest in the Partnership. The following table provides information regarding the exercise of such right by our general partner during the year ended December 31, 2017. Each sale listed below was exempt from registration under Section 4(a)(2) of the Securities Act.

Date of Sale	Number of General Partner Units Sold	Price per General Partner Unit	Consideration Paid to the Partnership
June 14, 2017	670	$31.90	$21,386
December 11, 2017	432	$30.05	$12,987

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ITEM 6. SELECTED FINANCIAL DATA

The following tables set forth certain selected consolidated financial data as of and for each of the five years in the period ended December 31, 2017. All financial results have been adjusted for subsequent transactions with our Predecessors as noted below.

During the years ended December 31, 2015, 2014 and 2013, the Partnership entered into various transactions with Delek and our general partner pursuant to which we acquired the following assets from Delek:

• two crude oil rail offloading racks, which are designed to receive up to 25,000 barrels per day (“bpd”) of light crude oil or 12,000 bpd of heavy crude oil, or any combination of the two, delivered by rail to Delek's El Dorado Refinery (the "El Dorado Refinery")and related ancillary assets (the “El Dorado Assets”) effective March 31, 2015 (such transaction, the "El Dorado Rail Offloading Racks Acquisition");

• a crude oil storage tank (the "Tyler Crude Tank") with a shell capacity of approximately 350,000 barrels located adjacent to Delek's Tyler Refinery (the "Tyler Refinery") and certain ancillary assets (collectively, with the Tyler Crude Tank, the "Tyler Assets") effective March 31, 2015 (such transaction, the "Tyler Crude Tank Acquisition"); the Tyler Assets, together with the El Dorado Assets, are hereinafter collectively referred to as the "Logistics Assets";

• a refined products terminal (the “El Dorado Terminal”) located at the El Dorado Refinery and 158 storage tanks and certain ancillary assets (the "El Dorado Tank Assets" and, together with the El Dorado Terminal, the “El Dorado Terminal and Tank Assets”) at and adjacent to the El Dorado Refinery effective February 4, 2014 (such transaction, the “El Dorado Acquisition”);

and;

• a refined products terminal (the “Tyler Terminal”) located at the Tyler Refinery and 96 storage tanks and certain ancillary assets (the "Tyler Tank Assets" and, together with the Tyler Terminal, the “Tyler Terminal and Tank Assets”) adjacent to the Tyler Refinery, effective July 26, 2013 (such transaction, the “Tyler Acquisition”).

The El Dorado Rail Offloading Racks Acquisition, the Tyler Crude Tank Acquisition, the El Dorado Acquisition and the Tyler Acquisition were accounted for as transfers between entities under common control; such acquisitions hereinafter collectively referred to as the "Acquisitions from Delek." As entities under common control with Delek, transfers between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years have been retrospectively adjusted to include the historical results of the assets acquired in the Acquisitions from Delek prior to the effective date of each acquisition for all periods presented. Prior to each acquisition date, we refer to the Acquisitions from Delek collectively as our “Predecessors.”

Our financial results may not be comparable, as our Predecessors recorded revenues, general and administrative expenses and financed operations differently than the Partnership. See "Factors Affecting the Comparability of Our Financial Results" in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations for additional information.

The following tables should be read in conjunction with Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements in Item 8.

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	Year Ended December 31,
	2017			2016		2015			2014			2013
Statements of Income and Other Comprehensive Income Data:				(In thousands, except units and per unit data)
Net sales	$	538,075		$	448,059	$	589,669		$	841,253		$	907,428
Operating costs and expenses	449,898			370,409		512,407			762,407			868,697
Operating income	88,177			77,650		77,262			78,846			38,731
Non-operating costs and expenses	18,990			14,765		11,246			8,656			4,570
Income (loss) before income tax (benefit) expense	69,187			62,885		66,016			70,190			34,161
Income tax (benefit) expense	(222		)	81		(195		)	132			757
Net income	69,409			62,804		66,211			70,058			33,404
Less: (Loss) income attributable to Predecessors	—			—		(637		)	(1,939		)	(14,426		)
Net income attributable to partners	$	69,409		$	62,804	$	66,848		$	71,997		$	47,830
Less: General partners' interest in net income, including incentive distribution rights	18,429			12,193		5,163			2,366			957
Limited partners' interest in net income	$	50,980		$	50,611	$	61,685		$	69,631		$	46,873
Net income per limited partner unit:
Common - (basic)	$	2.09		$	2.08	$	2.55		$	2.88		$	1.95
Common - (diluted)	$	2.09		$	2.07	$	2.52		$	2.85		$	1.93
Subordinated - Delek (basic and diluted)	$	—		$	2.19	$	2.54		$	2.88		$	1.95
Weighted average limited partner units outstanding:
Common units - (basic)	24,348,063			22,490,264		12,237,154			12,171,548			12,025,249
Common units - (diluted)	24,376,972			22,558,717		12,356,914			12,302,629			12,148,774
Subordinated units - Delek (basic and diluted)	—			1,803,167		11,999,258			11,999,258			11,999,258
Cash distributions per limited partner unit	$	2.835		$	2.575	$	2.240		$	1.900		$	1.600

	Year Ended December 31,
	2017			2016			2015			2014		2013
Balance Sheet Data:				(In thousands)
Property, plant and equipment, net	$	255,068		$	251,029		$	253,848		$	254,779	$	242,512
Total assets	443,530			415,547			375,288			331,286		319,350
Total debt, including current maturities	422,649			392,600			351,600			251,750		164,800
Total liabilities	472,755			428,831			386,306			291,505		214,142
Total (deficit) equity	(29,225		)	(13,284		)	(11,018		)	39,781		105,208

ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") is management’s analysis of our financial performance and of significant trends that may affect our future performance. The MD&A should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K (the "Annual Report on Form 10-K"). Those statements in the MD&A that are not historical in nature should be deemed forward-looking statements that are

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inherently uncertain. See "Forward-Looking Statements" below for a discussion of the factors that could cause actual results to differ materially from those projected in these statements.

In January 2017, Delek US Holdings, Inc. ("Old Delek") and various related entities entered into an Agreement and Plan of Merger with Alon USA Energy, Inc. (NYSE: ALJ) ("Alon USA"), as subsequently amended on February 27 and April 21, 2017 (as so amended, the "Merger Agreement"). The related merger (the "Delek/Alon Merger") was effective July 1, 2017 (the “Effective Time”), resulting in a new post-combination consolidated registrant renamed Delek US Holdings, Inc. (“New Delek”), with Alon USA and Old Delek surviving as wholly-owned subsidiaries. New Delek is the successor issuer to Old Delek and Alon USA pursuant to Rule 12g-3(c) under the Securities Exchange Act of 1934, as amended (the "Exchange Act").

Unless the context otherwise requires, references in this report to "Delek Logistics Partners, LP," the "Partnership," "we," "us," "our," or like terms, may refer to Delek Logistics Partners, LP, one or more of its consolidated subsidiaries or all of them taken as a whole. Unless the context otherwise requires, references in this report to "Delek" refer collectively to Old Delek with respect to periods prior to July 1, 2017, or New Delek, with respect to periods on or after July 1, 2017, and any of Old Delek's or New Delek's, as applicable, subsidiaries, other than the Partnership and its subsidiaries and its general partner.

On March 31, 2015, the Partnership, through its wholly owned subsidiary Delek Logistics Operating, LLC, acquired from Delek two crude oil rail offloading racks, which racks are designed to receive up to 25,000 barrels per day (“bpd”) of light crude oil or 12,000 bpd of heavy crude oil, or some combination of the two, delivered by rail to the El Dorado Refinery and related ancillary assets (the “El Dorado Assets”) (such transaction, the "El Dorado Rail Offloading Racks Acquisition").

On March 31, 2015, the Partnership, through its wholly owned subsidiary Delek Marketing & Supply, LP, acquired from Delek a crude oil storage tank (the "Tyler Crude Tank") located adjacent to Delek's Tyler, Texas refinery, (the "Tyler Refinery") and certain ancillary assets (collectively, with the Tyler Crude Tank, the "Tyler Assets") (such transaction, the "Tyler Crude Tank Acquisition"). The Tyler Crude Tank has approximately 350,000 barrels of shell capacity and primarily supports the Tyler Refinery. The Tyler Assets, together with the El Dorado Assets, are hereinafter collectively referred to as the "Logistics Assets."

The El Dorado Rail Offloading Racks Acquisition and the Tyler Crude Tank Acquisition are hereinafter collectively referred to as the "Acquisitions from Delek." The Acquisitions from Delek were accounted for as transfers between entities under common control. As an entity under common control with Delek, we record the assets that Delek has contributed to us on our balance sheet at Delek's historical basis instead of fair value. Transfers between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. Accordingly, the accompanying financial statements and related notes of the Partnership have been retrospectively adjusted to include: (i) the historical results of the El Dorado Assets, as owned and operated by Delek, for all periods presented through March 31, 2015 (the "El Dorado Assets Predecessor") and (ii) the historical results of the Tyler Assets, as owned and operated by Delek, for all periods presented through March 31, 2015 (the "Tyler Assets Predecessor"). The El Dorado Assets Predecessor, together with the Tyler Assets Predecessor, are hereinafter collectively referred to as our "Predecessors."

You should read the following discussion of our financial condition and results of operations in conjunction with our historical consolidated financial statements and notes thereto.

Forward-Looking Statements

This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the" Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). 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 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, 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.

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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:

• our substantial dependence on Delek or its assignees and their support of and respective ability to pay us under our commercial agreements;

• our future coverage, leverage, financial flexibility and growth, and our ability to improve performance and achieve distribution growth at any level or at all;

• Delek’s future growth, financial performance, share repurchases, crude oil supply pricing and flexibility and product distribution;

• positive industry dynamics, including Permian Basin growth, efficiencies and takeaway capacity;

• the age and condition of our assets and operating hazards and other risks incidental to transporting, storing and gathering crude oil, intermediate and refined products, including, but not limited to, costs, penalties, regulatory or legal actions and other effects related to spills, releases and tank failures;

• changes in insurance markets impacting costs and the level and types of coverage available;

• the timing and extent of changes in commodity prices and demand for refined products;

• the wholesale marketing margins we are able to obtain and the number of barrels of product we are able to purchase and sell in our west Texas wholesale business;

• the suspension, reduction or termination of Delek's or its assignees' or any third-party's obligations under our commercial agreements including the duration, fees or terms thereof;

• the results of our investments in joint ventures;

• the ability to secure commercial agreements with Delek or third parties upon expiration of existing agreements;

• disruptions due to acts of God, equipment interruption or failure at our facilities, Delek’s facilities or third-party facilities on which our business is dependent;

• changes in the availability and cost of capital of debt and equity financing;

• our reliance on information technology systems in our day-to-day operations;

• changes in general economic conditions;

• the effects of existing and future laws and governmental regulations, including, but not limited to, the rules and regulations promulgated by the Federal Energy Regulatory Commission ("FERC") and those relating to environmental protection, pipeline integrity and safety;

• competitive conditions in our industry;

• actions taken by our customers and competitors;

• the demand for crude oil, refined products and transportation and storage services;

• our ability to successfully implement our business plan;

• an inability to have growth projects completed on time and on budget;

• an inability of Delek to grow as expected and realize the synergies and the other expected benefits of its merger with Alon USA, which became effective as of July 1, 2017, and Delek's acquisition of the remaining interest in Alon USA Partners, LP that Delek did not already own, which became effective as of February 7, 2018;

• as it relates to our potential future growth opportunities, including dropdowns, and other potential benefits, the ability to successfully integrate the businesses of Delek and Alon USA;

• our ability to successfully integrate acquired businesses;

• natural disasters, weather-related delays, casualty losses and other matters beyond our control;

• changes or volatility in interest and inflation rates;

• labor relations;

• large customer defaults;

• changes in tax status and regulations;

• the effects of future litigation; and

• other factors discussed elsewhere in this Annual Report on Form 10-K.

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 results or future period trends. We can give no assurances that any of the events

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anticipated by the 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.

Business Overview

The Partnership primarily owns and operates crude oil, intermediate and refined products logistics and marketing assets. We gather, transport, offload and store crude oil and intermediate products and market, distribute, transport and store refined products primarily in select regions of the southeastern United States and Texas for Delek and third parties. A substantial majority of our existing assets are both integral to and dependent upon the success of Delek’s refining operations as many of our assets are contracted exclusively to Delek in support of its Tyler and El Dorado Refineries.

We also own membership interests in two joint ventures that were formed to plan, develop, construct, own, operate and maintain separate pipeline systems and certain ancillary assets, which are serving third parties and subsidiaries of Delek. We own a 50% membership interest in the entity formed with an affiliate of Plains All American Pipeline, L.P. ("CP LLC") to operate one of these pipeline systems and a 33% membership interest in the entity formed with Rangeland Energy II, LLC ("Rangeland RIO") to operate the other pipeline system. The pipeline system constructed by Rangeland RIO was completed and began operations in September 2016. The pipeline system constructed by CP LLC was completed and began operations in January 2017. In February 2018, Andeavor acquired Rangeland RIO.

The Partnership is not a taxable entity for federal income tax purposes or the income taxes of those states that follow the federal income tax treatment of partnerships. Instead, for purposes of such income taxes, each partner of the Partnership is required to take into account its share of items of income, gain, loss and deduction in computing its federal and state income tax liabilities, regardless of whether cash distributions are made to the partner by the Partnership. The taxable income reportable to each partner takes into account differences between the tax basis and the fair market value of our assets and financial reporting bases of assets and liabilities, the acquisition price of the partner's units and the taxable income allocation requirements under the Partnership's First Amended and Restated Agreement of Limited Partnership (the "Partnership Agreement").

Recent Developments

Big Spring Asset Dropdown. On February 26, 2018, a definitive agreement was entered into between the Partnership and Delek to acquire certain logistics assets primarily located adjacent to Delek's Big Spring, Texas refinery. In connection with the closing of the transaction, Delek, the Partnership and various of their subsidiaries expect to enter into a new wholesale and marketing agreement and amend certain existing contracts, such as new throughput and tankage agreement for the Big Spring Logistics Assets. See Note 21 to the consolidated financial statements in Item 8. Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.

Formation of Green Plains Joint Venture.On February 20, 2018, the Partnership and Green Plains Partners LP ("Green Plains") announced the companies have formed DKGP Energy Terminals, LLC ("DKGP Energy"), a joint venture engaging in the light products terminalling business. The Partnership and Green Plains will each own a 50% membership interest in DKGP Energy. See Item 1, "Business—Recent Developments—Formation of Green Plains Joint Venture" for additional information related to this transaction.

Acquisition of Non-controlling Interest in Alon Partnership.On November 8, 2017, Delek and Alon USA Partners, LP (the "Alon Partnership") entered into a definitive merger agreement under which Delek agreed to acquire all of the outstanding limited partner units of the Alon Partnership that Delek did not already own in an all-equity transaction (the "Alon Partnership Transaction"). The Alon Partnership Transaction was approved by the board of directors of Delek and by all voting members of the board of directors of the general partner of the Alon Partnership upon the recommendation from its conflicts committee. The Alon Partnership Transaction closed on February 7, 2018.

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Big Spring Pipeline Acquisition.  On September 15, 2017, the Partnership, through its wholly owned subsidiary Delek Marketing & Supply, LP, acquired from Plains Pipeline, L.P. an approximately 40-mile pipeline and related ancillary assets. See Item 1, "Business—Recent Developments—Big Spring Pipeline Acquisition" for additional information on this acquisition.

Delek/Alon Merger. In January 2017, Old Delek, New Delek and various related entities entered into the Merger Agreement with Alon USA. The transactions contemplated by the Merger Agreement became effective on July 1, 2017, and, among other things, resulted in Alon USA and Old Delek surviving as wholly-owned subsidiaries of New Delek.

The Delek/Alon Mergers did not affect the Partnership's commercial agreements with Delek discussed in Note 4 to the consolidated financial statements in Item 8. Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.

Inflation Adjustments. The tariffs on our FERC-regulated pipelines and the throughput fees and storage fees under our agreements with Delek and third parties are subject to increase or decrease annually, 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. See Item 1, "Business—Recent Developments—Inflation Adjustments" for additional information on these changes.

6.750% Senior Notes Due 2025. On May 23, 2017, the Partnership and Delek Logistics Finance Corp., a Delaware corporation and a wholly owned subsidiary of the Partnership (“Finance Corp.” and together with the Partnership, the “Issuers”), issued $250.0 million in aggregate principal amount of 6.750% senior notes due 2025 (the “2025 Notes”). See Item 1, "Business—Recent Developments—6.750% Senior Notes Due 2025" for additional information.

Caddo Pipeline. In March 2015, we entered into a joint venture to construct a crude oil pipeline system and related ancillary assets (the "Caddo Pipeline"), which is serving third parties and subsidiaries of Delek. We own a 50% membership interest in the entity formed with an affiliate of Plains All American Pipeline, L.P. to construct the Caddo Pipeline. Operations on the Caddo Pipeline began in January 2017.

Business Strategies

Our objectives are to maintain stable cash flows and to grow the quarterly distributions paid to our unitholders over time. We are focused on growing our asset base within our geographic area through acquisitions, project development, joint ventures and enhancing our existing systems. While we will continue to evaluate ways to provide Delek with logistics services, our emphasis will be to increase the logistics services that we offer to third parties. We intend to achieve these objectives through the following business strategies:

• Generate Stable Cash Flow. We will continue to pursue opportunities to provide logistics, marketing and other services to Delek and third parties pursuant to long-term, fee-based contracts. In new service contracts, we will endeavor to include minimum volume throughput, or other commitments, similar to those included in our current commercial agreements with Delek.

• Focus on Growing Our Business. We intend to evaluate and pursue opportunities to grow our business through both strategic acquisitions and expansion and construction projects, both internally funded or in combination with potential external partners. We believe that our strong relationship with Delek will enhance our opportunities to grow our business.

◦ Pursue Acquisitions. We plan to pursue strategic acquisitions that both complement our existing assets and provide attractive returns for our unitholders. As we continue to grow through acquisitions, we believe we will be able to increase our third party business.

Additionally, Delek has granted us a right of first offer on certain logistics assets. We intend to review our right to purchase any such assets as they are offered to us under the terms of the right of first offer, from time to time. Delek is also required, under certain circumstances, to offer us the opportunity to purchase additional logistics assets that Delek may acquire or construct in the future. As a result of the Alon Partnership Transaction, we anticipate additional growth opportunities through subsequent dropdowns of logistics assets acquired by Delek through the transaction. In addition to those opportunities to acquire assets from Delek, we believe that our current asset base, and our knowledge of the regional markets in which we operate, will enable us to target and complete attractive third-party acquisitions.

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◦ Pursue Attractive Expansion and Construction Opportunities.We intend to pursue organic growth opportunities that complement our existing businesses or that provide attractive returns within or outside our current geographic footprint. We plan to evaluate potential opportunities to make capital investments that will be used to expand our existing asset base through the expansion and construction of new logistics assets to support growth of any of our customers', including Delek's, businesses and from increased third-party activity. These construction projects may be developed either through joint venture relationships or by us acting independently, depending on size and scale.

• Optimize Our Existing Assets and Expand Our Customer Base. We seek to enhance the profitability of our existing assets by adding incremental throughput volumes, improving operating efficiencies and increasing system-wide utilization. We also expect to further diversify our customer base by increasing third-party throughput volumes running through certain of our existing systems and expanding our existing asset portfolio to service more third-party customers.

Commercial Agreements

The Partnership has a number of long-term, fee-based commercial agreements with Delek under which we provide various services, including crude oil gathering and crude oil, intermediate and refined products transportation and storage services, and marketing, terminalling and offloading services to Delek, and Delek commits to provide us with minimum monthly throughput volumes of crude oil, intermediate and refined products. Generally, these agreements include minimum quarterly volume, revenue or throughput commitments and have tariffs or fees indexed to inflation-based indices, provided that the tariffs or fees will not be decreased below the initial amount. See Note 4 to the consolidated financial statements in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K for a discussion of our material agreements with Delek.

How We Evaluate Our Operations

We use a variety of financial and operating metrics to analyze our segment performance. These metrics are significant factors in assessing our operating results and profitability and include: (i) volumes (including pipeline throughput and terminal volumes); (ii) contribution margin and gross margin per barrel; (iii) operating and maintenance expenses; and (iv) EBITDA and distributable cash flow (as such terms are defined below).

Volumes. The amount of revenue we generate primarily depends on the volumes of crude oil, intermediate and refined products that we handle in our pipeline, transportation, terminalling, storage and marketing operations. These volumes are primarily affected by the supply of and demand for crude oil, intermediate and refined products in the markets served directly or indirectly by our assets. Although Delek has committed to minimum volumes under certain of the commercial agreements, as described above, our results of operations will be impacted by:

• Delek’s utilization of our assets in excess of its minimum volume commitments;

• our ability to identify and execute acquisitions and organic expansion projects and capture incremental volume increases from Delek or third parties;

• our ability to increase throughput volumes at our refined products terminals and provide additional ancillary services at those terminals;

• our ability to identify and serve new customers in our marketing and trucking operations; and

• our ability to make connections to third-party facilities and pipelines.

Contribution Margin and Gross Margin per Barrel. Because we do not allocate general and administrative expenses by segment, we measure the performance of our segments by the amount of contribution margin generated in operations. Contribution margin is calculated as net sales less cost of goods sold and operating expenses.

For our wholesale marketing and terminalling segment, we also measure gross margin per barrel. Gross margin per barrel reflects the gross margin (net sales less cost of goods sold) of the wholesale marketing operations divided by the number of barrels of refined products sold during the measurement period. Both contribution margin and gross margin per barrel can be affected by fluctuations in the prices and cost of gasoline, distillate fuel, ethanol and Renewable Identification Numbers ("RINs"). Historically, the profitability of our wholesale marketing operations has been affected by commodity price volatility, specifically as it relates to changes in the price of refined products between the time we purchase such products from our suppliers and the time we sell the products to our wholesale customers, and the fluctuation in the value of RINs. Commodity price volatility may also impact our wholesale marketing operations

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when the selling price of finished products does not adjust as quickly as the purchase price. Our wholesale marketing gross margin can also be impacted by fixed price ethanol agreements that we enter into to fix the price we pay for ethanol.

Operating and Maintenance Expenses. We seek to maximize the profitability of our operations by effectively managing operating and maintenance expenses. These expenses are comprised primarily of labor expenses, lease costs, utility costs, insurance premiums, repairs and maintenance expenses and property taxes. These expenses generally remain relatively stable across broad ranges of throughput volumes, but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses. Additionally, compliance with federal, state and local laws and regulations relating to the protection of the environment, health and safety may require us to incur additional expenditures. We will seek to manage our maintenance expenditures on our pipelines and terminals by scheduling maintenance over time to avoid significant variability in our maintenance expenditures and minimize their impact on our cash flow.

EBITDA and Distributable Cash Flow. We define EBITDA as net income (loss) before net interest expense, income tax expense, depreciation and amortization expense. During the year ended December 31, 2016, we revised our definition of distributable cash flow to include the reconciliation of this non-U.S. GAAP measure from U.S. GAAP net cash from operating activities rather than from EBITDA. Distributable cash flow is derived from net cash flow from operating activities plus or minus changes in assets and liabilities, less maintenance capital expenditures net of reimbursements and other adjustments not expected to settle in cash. We believe this revision is a more appropriate reflection of a liquidity measure by which users of our financial statements can assess our ability to generate cash. Additionally, distributable cash flow and EBITDA are not presentations made in accordance with accounting principles generally accepted in the United States ("U.S. GAAP").  

EBITDA and distributable cash flow are non-U.S. GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

• our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis, or in the case of EBITDA, financing methods;

• the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;

• our ability to incur and service debt and fund capital expenditures; and

• the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of EBITDA and distributable cash flow provides information useful to investors in assessing our financial condition and results of operations. EBITDA and distributable cash flow should not be considered alternatives to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. EBITDA and distributable cash flow have important limitations as analytical tools, because they exclude some, but not all, items that affect net income and net cash provided by operating activities. Additionally, because EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a reconciliation of EBITDA and distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with U.S. GAAP, please refer to "—Results of Operations" below.

Factors Affecting the Comparability of Our Financial Results

Our future results of operations may not be comparable to our historical results of operations for the reasons described below:

Revenues. There are differences between the way the Predecessors recorded revenues and the way the Partnership records revenues after the Acquisitions from Delek. Because our assets, including the Logistics Assets, were historically a part of the integrated operations of Delek, the Predecessors generally recognized the costs and most revenue associated with the terminalling and storage services provided to Delek on an intercompany basis. Accordingly, the revenues in the Predecessors' consolidated financial statements are different than those reflected in the Partnership's consolidated financial statements, as the Predecessors' amounts relate primarily to amounts received from third parties, while the Partnership's revenues will also reflect amounts associated with our commercial agreements with Delek in addition to amounts received from third parties.

General and Administrative Expenses. The Predecessors' general and administrative expenses included direct monthly charges for the management and operation of our logistics assets and certain expenses allocated by Delek for general corporate services, such

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as treasury, accounting and legal services. These expenses were charged or allocated to the Predecessors based on the nature of the expenses and our proportionate share of employee time and headcount.

Delek continues to charge the Partnership for the management and operation of our logistics assets, including an annual fee under our Omnibus Agreement (as defined in Note 4 to our consolidated financial statements) with Delek, for the provision of various centralized corporate services. Additionally, the Partnership is required to reimburse Delek for direct or allocated costs and expenses incurred by Delek on behalf of the Partnership. The Partnership also incurs additional incremental annual general and administrative expenses as a result of being a publicly traded partnership.

Financing. The Partnership paid a cash distribution to its unitholders at a distribution rate of $0.725 per unit for the quarter ended December 31, 2017 ($2.90 per unit on an annualized basis). Our Partnership Agreement requires that the Partnership distribute to its unitholders quarterly all of its available cash as defined in the Partnership Agreement. As a result, the Partnership expects to fund future capital expenditures primarily from operating cash flows, borrowings under our revolving credit facility and any potential future issuances of equity and debt securities.

Market Trends

Master Limited Partnerships

Fluctuations in crude oil prices and the prices of related refined products impact our operations and the operations of other master limited partnerships in the midstream energy sector. In particular, crude oil prices and the prices of related refined products have the ability to influence drilling activity in many basins and the amounts of capital spending that crude oil exploration companies and smaller producers incur to support future growth. During the first half of 2016, depressed crude oil prices resulted in a reduction in drilling activity, which created excess capacity and reduced throughput on many crude oil pipelines in the United States and limited the need for new infrastructure projects as crude oil production in the United States was in a period of decline. However, in the latter half of 2016, and throughout the year ended December 31, 2017, market conditions improved. The prices of crude oil and related refined products have increased. Drilling activity has escalated as a result of increasing crude oil prices, particularly in the Permian basin which has attractive drilling economics supported by improved efficiencies and drilling cost. As market conditions improve and demand for our assets' capacity benefits from increased drilling activity, we expect our operations and results to benefit from the trend, particularly in the west Texas area where our results are most driven by market factors. Additionally, improving market conditions allow for the development of profitable growth projects that are needed to support future distribution growth in the midstream energy sector and for the Partnership.

West Texas Marketing Operations

Overall demand for gathering and terminalling services in a particular area is generally driven by crude oil production in the area, which can be impacted by crude oil prices, refining economics and access to alternate delivery and transportation infrastructure. Additionally, volatility in crude oil, intermediate and refined products prices in the west Texas area and the value attributable to RINs can affect the results of our west Texas operations. For example, as discussed above, drilling activity and the prices of crude oil and related refined products have recently increased, resulting in higher demand for finished products from our west Texas operations to industries that support crude oil exploration and production. See below for the high, low and average price per barrel of WTI crude oil for each of the quarterly periods during the years ended December 31, 2017, 2016 and 2015.

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Also, the volatility of finished products prices may impact our margin in the west Texas operations when the selling price of finished products does not adjust as quickly as the purchase price. See below for the range of prices per gallon of gasoline and diesel for each of the quarterly periods during the years ended December 31, 2017, 2016 and 2015.

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Our west Texas operations can benefit from RINs that are generated by ethanol blending activities. As a result, changes in the price of RINs can affect our results of operations. The RINs we generate are sold primarily to Delek at market prices. We sold approximately $5.6 million, $6.7 million and $5.8 million of RINs to Delek during the years ended December 31, 2017, 2016 and 2015, respectively. See below for the high, low and average prices of RINs for each of the quarterly periods during the years ended December 31, 2017, 2016 and 2015.

All of these factors are subject to change over time. As part of our overall business strategy, management considers aspects such as location, acquisition and expansion opportunities and factors impacting the utilization of the refineries (and therefore throughput volumes), which may impact our performance in the market.

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Seasonality and Customer Maintenance Programs

The volume and throughput of crude oil, intermediate and refined products transported through our pipelines and sold through our terminals and to third parties are directly affected by the level of supply and demand for all such products in the markets served directly or indirectly by our assets or our customers. 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. In addition, our refining customers, such as Delek, occasionally reduce or suspend operations to perform planned maintenance during the winter, when demand for their products is lower. Accordingly, these factors affect the need for crude oil or finished products by our customers, and therefore limit our volumes or throughput during these periods, and our operating results will generally be lower during the first and fourth quarters of the year. We believe, however, that many of the potential effects of seasonality on our revenues and contribution margin will be substantially mitigated due to our commercial agreements with Delek that typically include minimum volume and throughput commitments.

Results of Operations

A discussion and analysis of the factors contributing to our results of operations is presented below. The accompanying consolidated financial statements and related notes of the Partnership have been retrospectively adjusted to include the historical results of the Logistics Assets for all periods presented through March 31, 2015. The financial statements, together with the following information, are intended to provide investors with a reasonable basis for assessing our historical operations, but should not serve as the only criteria for predicting our future performance.

The following table and discussion present a summary of our consolidated results of operations for the years ended December 31, 2017, 2016 and 2015, including a reconciliation of EBITDA to net income and distributable cash flow to net cash provided by operating activities (in thousands, except unit and per unit amounts). Our financial results may not be comparable, as our Predecessors recorded revenues, general and administrative expenses and financed operations differently than the Partnership. See "—Factors Affecting the Comparability of Our Financial Results" for additional information.

Statements of Income and Comprehensive Income Data
(In thousands, except unit data and per unit data)
	Years ended December 31,
	2017			2016			2015
Net sales:
Pipelines and transportation	$	121,729		$	122,172		$	131,379
Wholesale marketing and terminalling	416,346			325,887			458,290
Total	538,075			448,059			589,669
Operating costs and expenses:
Cost of goods sold	372,890			302,158			436,304
Operating expenses	43,274			37,198			44,923
General and administrative expenses	11,840			10,256			11,384
Depreciation and amortization	21,914			20,813			19,692
(Gain) loss on asset disposals	(20		)	(16		)	104
Total operating costs and expenses	449,898			370,409			512,407
Operating income	88,177			77,650			77,262
Interest expense, net	23,944			13,587			10,658
(Income) loss from equity method investments	(4,953		)	1,178			588
Other income, net	(1		)	—			—
Total non-operating costs and expenses	18,990			14,765			11,246
Income before income tax (benefit) expense	69,187			62,885			66,016
Income tax (benefit) expense	(222		)	81			(195		)
Net income	69,409			62,804			66,211
Less: Loss attributable to Predecessors	—			—			(637		)
Net income attributable to partners	$	69,409		$	62,804		$	66,848
Comprehensive income attributable to partners	$	69,409		$	62,804		$	66,848
EBITDA (1)	$	115,045		$	97,285		$	96,366
Less: General partner's interest in net income, including incentive distribution rights	18,429			12,193			5,163
Limited partners' interest in net income	$	50,980		$	50,611		$	61,685
Net income per limited partner unit (2):
Common units - (basic)	$	2.09		$	2.08		$	2.55
Common units - (diluted)	$	2.09		$	2.07		$	2.52
Subordinated units - Delek (basic and diluted)	$	—		$	2.19		$	2.54
Weighted average limited partner units outstanding (2):
Common units - (basic)	24,348,063			22,490,264			12,237,154
Common units - (diluted)	24,376,972			22,558,717			12,356,914
Subordinated units - Delek (basic and diluted)	—			1,803,167			11,999,258
Cash distributions per limited partner unit	$	2.835		$	2.575		$	2.240

⁽¹⁾  For a definition of EBITDA, see "—How We Evaluate Our Operations—EBITDA and Distributable Cash Flow."

⁽²⁾  We base our calculation of net income per unit on the weighted-average number of common and subordinated limited partner units outstanding during the period. The weighted-average number of common and subordinated units reflects the conversion

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of the subordinated units to common units on February 25, 2016. See Notes 5 and 12 to our accompanying consolidated financial statements for further discussion.

(in thousands)	Years Ended December 31,
	2017			2016			2015 (2)
Reconciliation of net income to EBITDA:
Net income	$	69,409		$	62,804		$	66,211
Add:
Income tax (benefit) expense	(222		)	81			(195		)
Depreciation and amortization	21,914			20,813			19,692
Interest expense, net	23,944			13,587			10,658
EBITDA (1)	$	115,045		$	97,285		$	96,366
Reconciliation of net cash from operating activities to distributable cash flow:
Net cash provided by operating activities	$	87,703		$	100,707		$	68,024
Changes in assets and liabilities	3,462			(14,861		)	20,106
Maintenance and regulatory capital expenditures (3)	(9,444		)	(5,920		)	(11,841		)
Reimbursement from Delek for capital expenditures (4)(5)	3,453			3,251			5,503
Accretion of asset retirement obligations	(292		)	(266		)	(251		)
Deferred income taxes	111			173			(14		)
Gain (loss) on asset disposals	20			16			(104		)
Distributable cash flow (1)	$	85,013		$	83,100		$	81,423

⁽¹⁾  For a definition of EBITDA and distributable cash flow, please see "—How We Evaluate Our Operations—EBITDA and Distributable Cash Flow."

⁽²⁾  EBITDA and distributable cash flow include net loss of $0.2 million related to our Predecessors during the year ended December 31, 2015.

⁽³⁾  Maintenance and regulatory capital expenditures represent cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets, and for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity. Examples of maintenance and regulatory capital expenditures are expenditures for the repair, refurbishment and replacement of pipelines and terminals, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

⁽⁴⁾  For the years ended December 31, 2017, 2016 and 2015, Delek reimbursed us for certain capital expenditures pursuant to the terms of the Omnibus Agreement (as defined in Note 4 to our consolidated financial statements).

⁽⁵⁾  In the current year, the reimbursed capital expenditure amounts in the determination of distributable cash flow were revised to reflect the accrual of reimbursed capital expenditures from Delek rather than the cash amounts received for reimbursed capital expenditures during the years ended December 31, 2017, 2016 and 2015. This resulted in an increase to the distributable cash flow of $1.4 million and $0.3 million during the years ended December 31, 2016 and 2015, respectively, from amounts presented on our Annual Report on Form 10-K for the year ended December 31, 2016.

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Segment Data:

The following is a summary of business segment capital expenditures for the periods indicated (in thousands):

	Year Ended December 31,
	2017		2016		2015
Capital spending (excluding business combinations)
Pipelines and Transportation	$	14,262	$	8,478	$	16,030
Wholesale Marketing and Terminalling	4,141		3,289		6,397
Total capital spending	$	18,403	$	11,767	$	22,427

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Consolidated Results of Operations - Comparison of the Year EndedDecember 31, 2017 versus the Year EndedDecember 31, 2016 and the Year EndedDecember 31, 2016 versus the Year EndedDecember 31, 2015

The following table presents a summary of our consolidated results of operations and our segment operating performance for the years ended December 31, 2017, December 31, 2016 and December 31, 2015 (in thousands). The discussion immediately following presents the consolidated results of operations.

	Year Ended December 31,
	2017			2016			2015
Pipelines and Transportation
Net sales:
Affiliate	109,298			$	103,749		102,551
Third-Party	12,431			18,423			28,828
Total Pipelines and Transportation	121,729			122,172			131,379
Operating costs and expenses:
Cost of goods sold	18,210			19,425			19,607
Operating expenses	33,240			29,235			33,751
Segment contribution margin	$	70,279		$	73,512		$	78,021
Wholesale Marketing and Terminalling
Net Sales:
Affiliate	46,982			45,815			50,013
Third-Party	369,364			280,072			408,277
Total Wholesale Marketing and Terminalling	416,346			325,887			458,290
Operating costs and expenses:
Cost of goods sold	354,680			282,733			416,697
Operating expenses	10,034			7,963			11,172
Segment contribution margin	$	51,632		$	35,191		$	30,421
Consolidated
Net Sales:
Affiliate	$	156,280		$	149,564		$	152,564
Third-Party	381,795			298,495			437,105
Net sales	538,075			448,059			589,669
Operating costs and expenses:
Cost of goods sold	372,890			302,158			436,304
Operating expenses	43,274			37,198			44,923
Contribution margin	121,911			108,703			108,442
General and administrative expenses	11,840			10,256			11,384
Depreciation and amortization	21,914			20,813			19,692
(Loss) gain on asset disposals	(20		)	(16		)	104
Operating income	$	88,177		$	77,650		$	77,262

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Net Sales

We generated net sales of $538.1 million for the year ended December 31, 2017 compared to $448.1 million for 2016, an increase of $90.0 million, or 20.1%. The increase was primarily attributable to increases in the average sales prices per gallon of gasoline and diesel and in volumes sold in our west Texas marketing operations. The average sales prices per gallon of gasoline and diesel sold increased $0.33 per gallon and $0.39 per gallon, respectively, during the year ended December 31, 2017 compared to average sales prices during 2016. The net increase of gasoline and diesel gallons sold in west Texas was 8.0 million gallons during the year ended December 31, 2017 compared to gallons sold during 2016. Also contributing to the increase in net sales were increased fees under our marketing agreement with Delek as a result of increased throughput due to higher demand following product supply disruptions associated with Hurricane Harvey. Partially offsetting the increase was a decline in fees on our Paline Pipeline System. During the year ended December 31, 2017, the Paline Pipeline System was a FERC regulated pipeline with a tariff established for potential shippers, compared to the year ended December 31, 2016, when the pipeline capacity was under contract with two third parties for a monthly fee.

We generated net sales of $448.1 million for the year ended December 31, 2016 compared to $589.7 million for 2015, a decrease of $141.6 million, or 24.0%. The decrease was primarily attributable to decreases in both the average sales prices per gallon of gasoline and diesel and in volumes sold in our west Texas marketing operations. The average sales prices per gallon of gasoline and diesel sold decreased $0.29 per gallon and $0.28 per gallon, respectively, during the year ended December 31, 2016 compared to average sales prices during 2015. Volumes of gasoline and diesel sold in west Texas decreased 33.5 million gallons and 13.9 million gallons, respectively, during the year ended December 31, 2016 compared to gallons sold during 2015. Further contributing to the decrease were declines in fees on our Paline Pipeline System as a result of lower contractual volumes and declines in fuel surcharge revenues and lower asphalt hauling associated with our trucking assets. Partially offsetting the decreases were increased throughput at most of our terminals, the majority of which occurred at our terminals in El Dorado, Arkansas and Tyler, Texas, as operations matched commercial demand, and the effects of the throughput and tankage agreements for the Logistics Assets, pursuant to which we generated revenue on the Logistics Assets during all periods for the year ended December 31, 2016, with no comparable revenue earned during the first quarter of 2015. Also offsetting the decreases were increases in volumes and fees associated with our marketing agreement with Delek, which increased primarily as a result of the turnaround that occurred at the Tyler Refinery in the first quarter of 2015, during which the refinery was not fully operational.

Cost of Goods Sold

Cost of goods sold was $372.9 million for the year ended December 31, 2017 compared to $302.2 million for the year ended December 31, 2016, an increase of $70.7 million, or 23.4%. The increase in cost of goods sold was primarily attributable to increases in the average cost per gallon of gasoline and diesel and in volumes purchased in our west Texas marketing operations. The average cost per gallon of gasoline and diesel purchased increased $0.27 per gallon and $0.31 per gallon, respectively, during the year ended December 31, 2017 compared to average costs during 2016. The net increase of gasoline and diesel gallons purchased in west Texas was 8.0 million gallons during the year ended December 31, 2017, compared to gallons purchased during 2016.

Cost of goods sold was $302.2 million for the year ended December 31, 2016, compared to $436.3 million for 2015, a decrease of $134.1 million, or 30.7%. The decrease in cost of goods sold was primarily attributable to decreases in both the average cost per gallon of gasoline and diesel and in volumes purchased in our west Texas marketing operations. The average cost per gallon of gasoline and diesel purchased decreased $0.27 per gallon and $0.30 per gallon, respectively, during the year ended December 31, 2016 compared to average costs during 2015. Gallons of gasoline and diesel purchased in west Texas decreased 33.5 million gallons and 13.9 million gallons, respectively, during the year ended December 31, 2016 compared to gallons purchased during 2015.

Operating Expenses

Operating expenses were $43.3 million for the year ended December 31, 2017 compared to $37.2 million for 2016, an increase of $6.1 million or 16.3%. The increase in operating expenses during the year ended December 31, 2017 compared to 2016, was primarily due to increases in labor and utilities costs associated with certain of our pipelines as a result of increased usage and higher maintenance costs associated with certain of our tanks at our tank farms. Also contributing to the increase were employee incentive costs incurred during the year ended December 31, 2017, with no comparable costs incurred during the year ended December 31, 2016. Partially offsetting these increases were a reduction in operating expenses for one of our terminal locations at which we incurred increased costs related to internal tank contamination during the year ended December 31, 2016 that were not incurred during the year ended December 31, 2017.

Operating expenses were $37.2 million for the year ended December 31, 2016 compared to $44.9 million for 2015, a decrease of $7.7 million, or 17.2%. The decrease in operating expenses during the year ended December 31, 2016, compared to 2015, was due to cost saving initiatives taken during the year ended December 31, 2016, which resulted in decreases in

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maintenance costs and supplies expenses associated with our terminals, including tanks at those terminals, and the SALA Gathering System. Partially offsetting these decreases were increases in operating expenses related to internal tank contamination at one of our terminals and hydro testing on our Paline Pipeline during the year ended December 31, 2016.

Contribution Margin

Contribution margin for the year ended December 31, 2017 was $121.9 million compared to $108.7 million in 2016, an increase of $13.2 million, or 12.2%. The increase in contribution margin was primarily attributable to improved contribution margin in our west Texas operations as a result of increased drilling activity in the region, which has improved market conditions and increased demand. Also contributing to the increase in contribution margin were increased fees associated with our marketing agreement with Delek as described above. Partially offsetting these increases was a decline in fees on our Paline Pipeline System as described above.

Contribution margin for the year ended December 31, 2016 was $108.7 million compared to $108.4 million in 2015, an increase of $0.3 million, or 0.2%. The increase in contribution margin was primarily attributable to increased throughput at most of our terminals and increased fees associated with the Logistics Assets and marketing agreement as discussed above. Also contributing to the increase were improved margins in our west Texas operations as a result of increased drilling activity in the region, which has improved market conditions and increased demand. Our contribution margin in our west Texas operations during the year ended December 31, 2015 was impacted by lower crude oil prices that reduced demand in the region and lowered throughput in our west Texas operations. Partially offsetting the increases were declines in fees on our Paline Pipeline System and declines in fuel surcharge revenues and lower asphalt hauling associated with our trucking assets as discussed above.

General and Administrative Expenses

General and administrative expenses were $11.8 million for the year ended December 31, 2017, compared to $10.3 million for the year ended December 31, 2016, an increase of $1.5 million, or 15.4%. The increase in general and administrative expenses was primarily due to increases in certain direct employee costs allocated to us as a result of an increase in employee headcount in connection with operating and maintaining our assets and in employee incentive costs incurred during the year ended December 31, 2017, with no comparable costs incurred during the year ended December 31, 2016.

General and administrative expenses were $10.3 million for the year ended December 31, 2016 compared to $11.4 million for the year ended December 31, 2015, a decrease of $1.1 million, or 9.9%. The decrease in general and administrative expenses was

primarily due to decreases in professional services feesduring the year ended December 31, 2016 compared to the year ended December 31, 2015, during which we incurred greater professional services fees in connection with our various acquisition activities and joint venture projects.

Depreciation and Amortization

Depreciation and amortization was $21.9 million for the year ended December 31, 2017 compared to $20.8 million for the year ended December 31, 2016, an increase of $1.1 million, or 5.3%. The increase in depreciation and amortization was primarily due to the addition of assets to our asset base as a result of the completion of capital projects that were placed into service during the year ended December 31, 2017 compared to the year ended December 31, 2016.

Depreciation and amortization was $20.8 million for the year ended December 31, 2016 compared to $19.7 million for the year ended December 31, 2015, an increase of $1.1 million, or 5.7%. The increase in depreciation and amortization was primarily due to the Logistics Assets added to our asset base and the completion of capital projects, which were placed into service during the year ended December 31, 2016 compared to the year ended December 31, 2015.

Interest Expense

Interest expense was $23.9 million for the year ended December 31, 2017 compared to $13.6 million for the year ended December 31, 2016, an increase of $10.3 million, or 76.2%. This increase was primarily attributable to higher total debt balances and higher average interest rates on our debt outstanding under 2025 Notes and our revolving credit facility.

Interest expense was $13.6 million for the year ended December 31, 2016 compared to $10.7 million for the year ended December 31, 2015, an increase of $2.9 million, or 27.5%. This increase was primarily attributable to increases in interest costs under our revolving credit facility due to changes in debt utilization and interest rates thereunder as a result of increased borrowings incurred in connection with continued investments made in our joint ventures.

Income Tax Expense

Income tax benefit was $0.2 million for the year ended December 31, 2017 compared to expense of $0.1 million for the year ended December 31, 2016. The Partnership is not subject to federal income taxes as a limited partnership. Accordingly, our taxable income or loss is included in the federal and state income tax returns of our partners.

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Income tax expense was $0.1 million for the year ended December 31, 2016, compared to a benefit of $0.2 million for the year ended December 31, 2015.

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Operating Segments

We review operating results in two reportable segments: (i) pipelines and transportation and (ii) wholesale marketing and terminalling. Decisions concerning the allocation of resources and assessment of operating performance are made based on this segmentation. Management measures the operating performance of each reportable segment based on the segment contribution margin. Segment contribution margin is defined as net sales less cost of goods sold and operating expenses, excluding depreciation and amortization. Segment reporting is more fully discussed in Note 15 to our accompanying consolidated financial statements.

Pipelines and Transportation Segment

Our pipelines and transportation segment assets provide crude oil gathering and crude oil, intermediate and refined products transportation and storage services to Delek and third parties. These assets include the Lion Pipeline System, the SALA Gathering System, the Paline Pipeline System, the East Texas Crude Logistics System, the Tyler-Big Sandy Product Pipeline, the El Dorado Tank Assets, the Tyler Tank Assets, the Greenville-Mount Pleasant Pipeline and Greenville Storage Facility, the El Dorado Rail Offloading Racks, the Tyler Crude Tank and refined product pipeline capacity leased from Enterprise TE Products Pipeline Company LLC that runs from El Dorado, Arkansas to our Memphis terminal and the Big Spring Pipeline. In addition to these operating systems, we own 95 tractors and 231 trailers used to haul primarily crude oil and other products for related and third parties.

The following table and discussion present the results of operations and certain operating statistics of the pipelines and transportation segment for the years ended December 31, 2017, 2016 and 2015 (in thousands):

	Year Ended December 31,
	2017	2016	2015
Throughputs (average bpd)
Lion Pipeline System:
Crude pipelines (non-gathered)	59,362	56,555	54,960
Refined products pipelines to Enterprise Systems	51,927	52,071	57,366
SALA Gathering System	15,871	17,756	20,673
East Texas Crude Logistics System	15,780	12,735	18,828

Pipelines and Transportation Segment Operational Comparison of the Year EndedDecember 31, 2017 versus the Year EndedDecember 31, 2016 and the Year EndedDecember 31, 2016 versus the Year EndedDecember 31, 2015

Net Sales

Net sales for the pipelines and transportation segment were $121.7 million for the year ended December 31, 2017 compared to $122.2 million for the year ended December 31, 2016, a decrease of $0.5 million, or 0.4%. The decrease in net sales was primarily attributable to declines in fees on our Paline Pipeline System. During the year ended December 31, 2017, the Paline Pipeline System was a FERC regulated pipeline with a tariff established for potential shippers, compared to the year ended December 31, 2016, when the pipeline capacity was under contract with two third parties for a monthly fee. Partially offsetting the decrease were increases in pipeline fees associated with our Greenville-Mount Pleasant Pipeline and a related pipeline connection.

Net sales for the pipelines and transportation segment were $122.2 million for the year ended December 31, 2016 compared to $131.4 million for the year ended December 31, 2015, a decrease of $9.2 million, or 7.0%. The decrease in net sales was primarily attributable to declines in fees on our Paline Pipeline System, as a result of lower contractual volumes and declines in fuel surcharge revenues and lower asphalt hauling associated with our trucking assets. Partially offsetting these decreases were the effects of the throughput and tankage agreements for the Logistics Assets, pursuant to which we generated revenue on the Logistics Assets during all periods for the year ended December 31, 2016, with no comparable revenue earned during the first quarter of 2015.

Cost of Goods Sold

Cost of goods sold for the pipelines and transportation segment was $18.2 million for the year ended December 31, 2017 compared to $19.4 million for the year ended December 31, 2016, a decrease of $1.2 million, or 6.3%. The decrease in cost of goods sold was attributable to lower pipeline allowance losses on our Paline Pipeline System, reduced costs associated with our leased refined product pipeline capacity as a result of lower volumes on the pipeline and decreases in transportation costs related to our trucking assets duringthe year ended December 31, 2017, compared to the year ended December 31, 2016.

Cost of goods sold was $19.4 million for the year ended December 31, 2016 compared to $19.6 million for the year ended December 31, 2015, a decrease of $0.2 million, or 0.9%. The decrease in cost of goods sold was attributable to lower pipeline allowance losses duringthe year ended December 31, 2016 compared to the year ended December 31, 2015.

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Operating Expenses

Operating expenses for the pipelines and transportation segment were $33.2 million for the year ended December 31, 2017 compared to $29.2 million for the year ended December 31, 2016, an increase of $4.0 million, or 13.7%. The increase in operating expenses was primarily due to increases in labor and utilities costs associated with certain of our pipelines as a result of increased usage. Also contributing to the increase were higher maintenance costs associated with certain of our tanks at our tank farms.

Operating expenses were $29.2 million for the year ended December 31, 2016 compared to $33.8 million for the year ended December 31, 2015, a decrease of $4.6 million, or 13.4%. The decrease in operating expenses was primarily due to cost saving initiatives taken during the year ended December 31, 2016, which resulted in decreases in maintenance costs and supplies expenses associated with our tanks and the SALA Gathering System. Partially offsetting these decreases were increases in costs associated with the hydro testing of our Paline Pipeline.

Contribution Margin

Contribution margin for the pipelines and transportation segment for the year ended December 31, 2017 was $70.3 million, or 57.6% of our consolidated segment contribution margin, compared to $73.5 million, or 67.6% of our consolidated segment contribution margin, for the year ended December 31, 2016, a decrease of $3.2 million, or 4.4%. The decrease in the pipelines and transportation segment contribution margin was primarily attributable to decreases in net sales related to our Paline Pipeline System as described above.

Contribution margin for the pipelines and transportation segment for the year ended December 31, 2016 was $73.5 million, or 67.6% of our consolidated segment contribution margin, compared to $78.0 million, or 71.9% of our consolidated segment contribution margin, for the year ended December 31, 2015, a decrease of $4.5 million, or 5.8%. The decrease in the pipelines and transportation segment contribution margin was primarily attributable to decreases in net sales as described above.

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Wholesale Marketing and Terminalling Segment

We use our wholesale marketing and terminalling assets to generate revenue by providing wholesale marketing and terminalling services to Delek’s refining operations and to independent third parties.

The table and discussion below present the results of operations and certain operating statistics of the wholesale marketing and terminalling segment for the years ended December 31, 2017, 2016 and 2015 (in thousands):

	Year Ended December 31,
	2017		2016		2015
Operating Information:
East Texas - Tyler Refinery sales volumes (average bpd)	73,655		68,131		59,174
West Texas marketing throughputs (average bpd)	13,817		13,257		16,357
West Texas marketing gross margin per barrel	$	4.03	$	1.43	$	1.35
Terminalling throughputs (average bpd) (1)	124,488		122,350		106,514

⁽¹⁾ Consists of terminalling throughputs at our Memphis and Nashville, Tennessee terminals, our Big Sandy, Tyler and Mount Pleasant, Texas terminals and our North Little Rock and El Dorado, Arkansas terminals.

Wholesale Marketing and Terminalling Segment Operational Comparison of the Year EndedDecember 31, 2017 versus the Year EndedDecember 31, 2016 and the Year EndedDecember 31, 2016 versus the Year EndedDecember 31, 2015

Net Sales

Net sales for the wholesale marketing and terminalling segment were $416.3 million for the year ended December 31, 2017 compared to $325.9 million for the year ended December 31, 2016, an increase of $90.4 million, or 27.8%. The increase was primarily attributable to increases in the average sales prices per gallon of gasoline and diesel and in volumes sold in our west Texas marketing operations. Also contributing to the increase in net sales were increased fees associated with our marketing agreement with Delek as a result of increased throughput due to higher demand following product supply disruptions associated with Hurricane Harvey.

Net sales for the wholesale marketing and terminalling segment were $325.9 million for the year ended December 31, 2016 compared to $458.3 million for the year ended December 31,

2015, a decrease of $132.4 million, or 28.9%. The decrease was primarily attributable to decreases in the average sales prices per gallon of gasoline and diesel and in volumes sold in our west Texas marketing operations. Partially offsetting the decrease were increased throughput at most of our terminals, the majority of which occurred at our terminals in El Dorado, Arkansas and Tyler, Texas, as operations matched commercial demand and increases in volumes and fees associated with our marketing agreement with Delek, which increased primarily as a result of the turnaround that occurred at the Tyler Refinery in the first quarter of 2015, during which the refinery was not fully operational.

The following charts show summaries of the average sales prices per gallon of gasoline and diesel and finished products volume impacting our west Texas operations for the years ended December 31, 2017, 2016 and 2015.

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Cost of Goods Sold

Cost of goods sold for the wholesale marketing and terminalling segment was $354.7 million for the year ended December 31, 2017 compared to $282.7 million for the year ended December 31, 2016, an increase of $72.0 million, or 25.4%. The increase in cost of goods sold was attributable to increases in the average cost per gallon of gasoline and diesel and in volumes purchased in our west Texas marketing operations.

Cost of goods sold was $282.7 million in the year ended December 31, 2016 compared to $416.7 million for the year ended December 31, 2015, a decrease of $134.0 million, or 32.1%. The decrease in cost of goods sold was attributable to decreases in the average cost per gallon of gasoline and diesel and in volumes purchased in our west Texas marketing operations.

The following chart shows a summary of the average prices per gallon of gasoline and diesel purchased in our west Texas operations for the years ended December 31, 2017, 2016 and 2015. Refer to the Finished Products Volume chart above for a summary of volumes impacting our west Texas operations.

Operating Expenses

Operating expenses in the wholesale marketing and terminalling segment were approximately $10.0 million for the year ended December 31, 2017 compared to $8.0 million for the year December 31, 2016, an increase of $2.0 million, or 26.0%. The increase in operating expenses was primarily due to increases in employee costs allocated to us as a result of an increase in employee headcount in connection with operating and maintaining our assets. Also contributing to the increase were employee incentive costs incurred during the year ended December 31, 2017, with no comparable costs incurred during the year ended December 31, 2016. Partially offsetting the increase were a reduction in operating expenses for one of our terminal locations

at which we incurred increased costs related to internal tank contamination during the year ended December 31, 2016 that were not incurred during the year ended December 31, 2017.

Operating expenses in the wholesale marketing and terminalling segment were approximately $8.0 million for the year ended December 31, 2016 compared to $11.2 million for the year ended December 31, 2015, a decrease of $3.2 million, or 28.7%. The decrease in operating expenses was primarily due to cost saving initiatives taken during the year ended December 31, 2016, which resulted in decreases in maintenance costs and supplies expenses at our terminals, including tanks at those terminals. Partially offsetting these decreases was an increase in operating expense related to internal tank contamination at one of our terminals during the year ended December 31, 2016.

Contribution Margin

Contribution margin for the wholesale marketing and terminalling segment amounted to $51.6 million, or 42.4% of our consolidated segment contribution margin, for the year ended December 31, 2017 compared to $35.2 million, or 32.4% of our consolidated segment contribution margin, for the year ended December 31, 2016, an increase of $16.4 million, or 46.7%. The increase in contribution margin was primarily attributable to improved contribution margin in our west Texas operations as a result of increased drilling activity in the region, which has improved market conditions and increased demand. Additionally, contribution margin in our west Texas operations benefited from higher margins during a period of product supply disruptions associated with Hurricane Harvey. Also contributing to the increase were increased fees associated with our marketing agreement with Delek as described above. Further contributing to the increase was a reduction in operating expenses for one of our terminal locations at which we incurred increased costs related to internal tank contamination during the year ended December 31, 2016 that were not incurred during the year ended December 31, 2017.

Contribution margin for the wholesale marketing and terminalling segment amounted to $35.2 million, or 32.4% of our consolidated segment contribution margin, for the year ended December 31, 2016 compared to $30.4 million, or 28.1% of our consolidated segment contribution margin, for the year ended December 31, 2015, an increase of $4.8 million, or 15.7%. The increase in contribution margin was attributable to increases in terminalling volumes and increased fees under our marketing agreement with Delek, as discussed above. Also contributing to the increase were improved margins in our west Texas operations as a result of increased drilling activity in the region, which has improved market conditions and increased demand. Our contribution margin in our west Texas operations during the year ended December 31, 2015 was impacted by lower crude oil prices that reduced demand in the region and lowered throughput in our west Texas operations.

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Liquidity and Capital Resources

We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our revolving credit facility and potential issuances of additional equity and debt securities. We believe that cash generated from these sources will be sufficient to satisfy the anticipated cash requirements associated with our existing operations, including minimum quarterly cash distributions, for at least the next 12 months.

On February 12, 2018, we paid a cash distribution of $0.725 per limited partner unit for the quarter ended December 31, 2017, which equates to $22.8 million, or $2.90 per limited partner unit on an annualized basis, based on the number of common and general partner units outstanding, including general partner incentive distribution rights.

The table below summarizes the quarterly distributions related to our 2017 fiscal quarters:

Quarter Ended	Total Quarterly Distribution Per Limited Partner Unit	Total Quarterly Distribution Per Limited Partner Unit, Annualized	Total Cash Distribution, including general partner interest and IDRs (in thousands)	Date of Distribution
March 31, 2017	$0.690	$2.76	$21,024	May 12, 2017
June 30, 2017	$0.705	$2.82	$21,783	August 11, 2017
September 30, 2017	$0.715	$2.86	$22,270	November 14, 2017
December 31, 2017	$0.725	$2.90	$22,777	February 12, 2018

Expiration of Subordination Period

In the first quarter of 2016, all of the Partnership's 11,999,258 outstanding subordinated units converted into common units and began participating pro rata with the other common units in distributions of available cash. See Notes 5 and 12 to the consolidated financial statements in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K for additional information.

Cash Flows

The following table sets forth a summary of our consolidated cash flows for the years ended December 31, 2017, 2016 and 2015 (in thousands):

	Year Ended December 31,
	2017			2016			2015
Cash Flow Data:
Cash flows provided by operating activities	$	87,703		$	100,707		$	68,024
Cash flows used in investing activities	(30,672		)	(72,692		)	(56,592		)
Cash flows used in financing activities	(52,415		)	(27,956		)	(13,293		)
Net increase (decrease) in cash and cash equivalents	$	4,616		$	59		$	(1,861	)

Cash Flows from Operating Activities

Net cash provided by operating activities was $87.7 million for the year ended December 31, 2017, compared to $100.7 million for 2016. The decrease in cash flows provided by operations was due to increases in accounts receivable, inventory and other current assets and income from equity method investments. Inventory increased as a result of increases in purchases associated with our west Texas operations. Income from equity method investments was $5.0 million during the year ended December 31, 2017, partially offset by distributions of $3.1 million, compared to a loss of $1.2 million during the year ended December 31, 2016. Partially offsetting the decrease in cash flows provided by operations were increases in accounts payable, which were due to increases in payables to suppliers in our west Texas operations and

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to vendors associated with certain of our capital projects.  Net income for the year ended December 31, 2017 was $69.4 million, compared to net income of $62.8 million in 2016.

Net cash provided by operating activities was $100.7 million for the year ended December 31, 2016, compared to $68.0 million for 2015. The increase in cash flows provided by operations was due to decreases in accounts receivable and inventories and other current assets. Accounts receivable decreased as a result of the receipt of an excise tax refund related to finished product purchases from the Tyler Refinery. Inventories and other current assets decreased as a result of lower prices in our west Texas operations.  Net income for the year ended December 31, 2016 was $62.8 million, compared to net income of $66.2 million in 2015.

Cash Flows from Investing Activities

Net cash used in investing activities was $30.7 million for the year ended December 31, 2017, compared to $72.7 million used in 2016. The decrease in cash used in investing activities was primarily due to decreases in contributions made to our joint ventures. Partially offsetting these decreases were increases in our capital expenditures. We contributed approximately $3.5 million in cash to our joint ventures during the year ended December 31, 2017, compared to contributions of approximately $61.6 million during the year ended December 31, 2016 for the construction of two pipeline systems and ancillary assets. We purchased the Big Spring Pipeline and associated rights-of-way during the year ended December 31, 2017 for $9.0 million. We did not have any acquisitions during the year ended December 31, 2016. Cash used in investing activities during the year ended December 31, 2017 includes the cash portion of our capital expenditures, which was $18.2 million. Total capital expenditures for 2017 were $18.4 million, compared to total capital expenditures of $11.8 million made during the year ended December 31, 2016. Capital expenditures made during the year ended December 31, 2017 related primarily to maintenance projects on certain of our tanks, discretionary projects on our terminalling assets and a discretionary project on a crude oil pipeline connection. Capital expenditures made during the year ended December 31, 2016 related primarily to maintenance projects on certain of our tanks and crude pipelines, discretionary projects on our terminalling assets, maintenance projects on our Lion Pipeline System and hydro testing on our Paline Pipeline System.

Net cash used in investing activities was $72.7 million for the year ended December 31, 2016, compared to $56.6 million used in 2015. Cash used in investing activities in 2016 included the cash portion of our capital expenditures of approximately $11.3 million. Total capital expenditures for 2016 were $11.8 million. This compares to total capital expenditures made during the year ended December 31, 2015 of $22.4 million. Capital expenditures made during the year ended December 31, 2016 related primarily to maintenance projects on certain of our tanks and crude pipelines, discretionary projects on our terminalling assets, maintenance projects on our Lion Pipeline System and hydro testing on our Paline Pipeline System. Capital expenditures made during the year ended December 31, 2015 related primarily to projects on certain of our tanks and crude pipelines, our terminalling assets and the purchase of assets from Delek. We had no third party acquisition activity during the year ended December 31, 2016 compared to $0.4 million during the year ended December 31, 2015. Additionally, we contributed approximately $61.6 million in cash to our joint ventures during the year ended December 31, 2016 compared to $37.4 million during the year ended December 31, 2015. Partially offsetting the cash used in investing activities during the year ended December 31, 2015 was an asset sale generating proceeds of approximately $1.2 million.

Cash Flows from Financing Activities

Net cash used in financing activities was $52.4 million in the year ended December 31, 2017, compared to $28.0 million used in 2016. The increase in cash used in financing activities was primarily due to increases in our quarterly cash distributions and net payments under the Second Amended and Restated Credit Agreement, as defined below. We paid quarterly cash distributions totaling $86.2 million during the year ended December 31, 2017, compared to quarterly cash distributions totaling $70.9 million during the year ended December 31, 2016. We made net payments of $212.7 million under our Second Amended and Restated Credit Agreement during the year ended December 31, 2017, compared to net proceeds of $41.0 million during the year ended December 31, 2016. Offsetting the cash used in financing activities during the year ended December 31, 2017 were net proceeds under the 2025 Notes and reimbursement of capital expenditures by Delek. The Partnership received net proceeds, after deducting the initial purchasers' discounts, commissions and offering expenses, of $242.3 million from the issuance of the 2025 Notes. Reimbursements of capital expenditures from Delek amounted to $4.3 million during the year ended December 31, 2017 compared to $1.9 million during the year ended December 31, 2016.

Net cash used in financing activities was $28.0 million in the year ended December 31, 2016, compared to $13.3 million used in 2015. We paid quarterly cash distributions totaling $70.9 million during the year ended December 31, 2016, compared to quarterly cash distributions totaling $56.6 million during the year ended December 31, 2015. We had no acquisition activity during the year ended December 31, 2016, compared to cash paid of $61.9 million in exchange for assets included in the El Dorado Rail Offloading Racks Acquisition and the Tyler Crude Tank Acquisition during the year ended December 31, 2015. Partially offsetting the cash used in financing activities during the years ended December 31, 2016 and 2015 were net proceeds of $41.0 million and $99.9 million, respectively, under the Second Amended and Restated Credit Agreement.

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Cash Position and Indebtedness

As of December 31, 2017, we had $4.7 million cash and cash equivalents, and we had total indebtedness of $422.6 million. Unused credit commitments under the Second Amended and Restated Credit Agreement were $511.1 million, and we had letters of credit issued of $9.0 million as of December 31, 2017. We believe we were in compliance with the applicable covenants in the Second Amended and Restated Credit Agreement as of December 31, 2017.

We entered into a senior secured revolving credit agreement on November 7, 2012, with Fifth Third Bank, as administrative agent, and a syndicate of lenders. The agreement was amended and restated on July 9, 2013 and was most recently amended and restated on December 30, 2014 (the "Second Amended and Restated Credit Agreement"). Under the terms of the Second Amended and Restated Credit Agreement, the lender commitments are $700.0 million. The Second Amended and Restated Credit Agreement also contains an accordion feature whereby the Partnership can increase the size of the revolving credit facility to an aggregate of $800.0 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent. The Second Amended and Restated Credit Agreement contains an option for Canadian dollar denominated borrowings. The Second Amended and Restated Credit Agreement matures on December 30, 2019.

On May 23, 2017, the Partnership and Finance Corp. issued $250.0 million in aggregate principal amount of 6.750% senior notes due 2025. The 2025 Notes are general unsecured senior obligations of the Issuers. The net proceeds from the issuance of the 2025 Notes totaled approximately $242.3 million, after deducting the initial purchasers' discount, commissions and offering expenses. The Partnership used substantially all of the net proceeds to pay down a portion of the outstanding balance under the Partnership's revolving credit facility.

See Note 11 to the consolidated financial statements in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K for a complete discussion of our third-party indebtedness.

Agreements Governing Certain Indebtedness of Delek

Although we are not contractually bound by and are not liable for Delek’s debt under its credit arrangements, we are indirectly affected by certain prohibitions and limitations contained therein. Specifically, certain of Delek's credit arrangements require that Delek meet certain minimum levels for (i) consolidated shareholders’ equity and (ii) a ratio of consolidated shareholders' equity to adjusted total assets. We cannot assure you that such covenants will not impact our ability to use the full capacity under our revolving credit facility in the future. Delek, due to its majority ownership and control of our general partner, has the ability to prevent us from taking actions that would cause Delek to violate any covenant in its credit arrangements or otherwise be in default under any of its credit arrangements. Please read Item 1A. "Risk Factors—Risks Relating to Our Business—Delek’s level of indebtedness, the terms of its borrowings and any future credit ratings could adversely affect our ability to grow our business, our ability to make cash distributions to our unitholders and our credit profile. Our current and future credit ratings may also be affected by Delek’s level of indebtedness and creditworthiness.”

Capital Spending

A key component of our long-term strategy is our capital expenditure program. Our capital expenditures for the year ended December 31, 2017 were $18.4 million, of which approximately $14.3 million was spent in our pipelines and transportation segment and approximately $4.1 million was spent in our wholesale marketing and terminalling segment. Our capital expenditure budget is approximately $17.5 million for 2018.

The following table summarizes our actual capital expenditures for the year ended December 31, 2017 and planned capital expenditures for the full year 2018 by major category (in thousands):

	Year Ended December 31,
	2018 Forecast		2017 Actual (2)
Capital Spending:
Regulatory	$	3,789	$	3,208
Maintenance (1)	8,818		7,896
Discretionary	4,910		7,299
Total capital spending	$	17,517	$	18,403

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⁽¹⁾  Maintenance capital expenditures represent cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets, and for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity. Examples of maintenance capital expenditures are expenditures for the repair, refurbishment and replacement of pipelines and terminals, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations. Delek has agreed to reimburse us with respect to certain assets it has transferred to us pursuant to the terms of the Omnibus Agreement (as defined in Note 4 to our consolidated financial statements).

⁽²⁾  Of the total $18.4 million spent in 2017, $9.0 million was related to growth projects.

For the full year 2018, we plan to spend approximately $17.5 million, of which $10.3 million is budgeted to the pipelines and transportation segment and $7.2 million to the wholesale marketing and terminalling segment. We plan to spend approximately $4.9 million for discretionary projects in 2018, of which $3.7 million is expected to be spent in the pipelines and transportation segment and $1.2 million in the wholesale marketing and terminalling segment. The majority of the $3.7 million budgeted to discretionary projects in the pipelines and transportation segment relates to the construction of a new tank and a pipeline pump expansion. We plan to spend approximately $8.8 million for maintenance projects in 2018, of which $4.7 million is expected to be spent in the pipelines and transportation segment and $4.1 million in the wholesale marketing and terminalling segment. The majority of the $4.7 million budgeted for maintenance projects in the pipelines and transportation segment relates to the repair and replacement of certain of our tanks. The majority of the $4.1 million budgeted for maintenance projects in the wholesale marketing and terminalling segment relates to repairs on certain of our tanks and system upgrades at the terminals.

Under the Omnibus Agreement, Delek reimburses us for (i) certain expenses that we incur for inspections, maintenance, repairs and failures of certain assets we acquired from Delek to cause such assets to comply with applicable regulatory and/or industry standards, (ii) certain expenses that we incur for inspections, maintenance, repairs and failures of most of the storage tanks and pipelines contributed to us by Delek (subject to a deductible of $0.5 million per year for certain assets as specified) that are necessary to comply with minimum standards under certain United States Department of Transportation pipeline integrity rules and certain American Petroleum Institute storage tank standards for a period of five years from the date of the purchase of the affected assets, and (iii) for certain non-discretionary maintenance capital expenditures with respect to certain of our assets in excess of specified amounts.

The amount of our capital expenditure budget is subject to change due to unanticipated increases in the cost, scope and completion time for our capital projects. For example, we may experience increases in the cost of and/or timing to obtain necessary equipment required for our continued compliance with government regulations or to complete improvement projects. Additionally, the scope and cost of employee or contractor labor expense related to installation of that equipment could increase from our projections.

Contractual Obligations and Commitments

Information regarding our known contractual obligations of the types described below, as of December 31, 2017, is set forth in the following table (in thousands):

	<1 Year		1-3 Years		3-5 Years		>5 Years		Total
Long term debt and notes payable	$	—	$	179,900	$	—	250,000		$	429,900
Capital lease obligations	—		—		—		—		—
Interest (1)	24,765		41,618		33,750		42,188		142,321
Operating lease commitments (2)	2,482		1,029		466		9		3,986
Total	$	27,247	$	222,547	$	34,216	$	292,197	$	576,207

⁽¹⁾  Includes expected interest payments on debt outstanding under our revolving credit facility in place at December 31, 2017 and on the 2025 Notes. Floating interest rate debt is calculated using December 31, 2017 rates.

⁽²⁾  Amounts reflect future estimated lease payments under operating leases having remaining non-cancelable terms in excess of one year as of December 31, 2017.

We also have other noncurrent liabilities pertaining to environmental liabilities and asset retirement obligations. With the exception of amounts classified as current, there is uncertainty as to the timing of future cash flows related to these obligations. As such, we have excluded the future cash flows from the contractual commitments table above. See additional information on asset retirement obligations and environmental liabilities in Notes 2 and 19, respectively, to our consolidated financial statements in Item 8.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements through the date of this Annual Report on Form 10-K.

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Critical Accounting Policies

We prepare our consolidated financial statements in conformity with U.S. GAAP, and in the process of applying these principles, we must make judgments, assumptions and estimates based on the best available information at the time. To aid a reader’s understanding, management has identified our critical accounting policies. These policies are considered critical, because they are both most important to the portrayal of our financial condition and results and require our most difficult, subjective or complex judgments. Often they require judgments and estimation about matters which are inherently uncertain and involve measuring, at a specific point in time, events which are continuous in nature. Actual results may differ based on the accuracy of the information utilized and subsequent events, of which we may have little or no control.

Property, Plant and Equipment and Intangibles Impairment

Property, plant and equipment and definite life intangibles are evaluated for impairment whenever indicators of impairment exist. Accounting standards require that if an impairment indicator is present, we must assess whether the carrying amount of the asset is unrecoverable by estimating the sum of the future cash flows expected to result from the asset, undiscounted and without interest charges. We derive the required undiscounted cash flow estimates from our historical experience and our internal business plans. If the carrying amount is more than the recoverable amount, an impairment charge must be recognized based on the fair value of the asset. We use quoted market prices when available and our internal cash flow estimates discounted at an appropriate interest rate to determine fair value, as appropriate.

Goodwill and Potential Impairment

Goodwill is reviewed at least annually for impairment, or more frequently if indicators of impairment exist. Goodwill is tested by comparing net book value of the operating segments to the estimated fair value of the reporting unit. In assessing the recoverability of goodwill, assumptions are made with respect to future business conditions and estimated expected future cash flows to determine the fair value of a reporting unit. We use a market participant weighted average cost of capital, estimated minimal growth rates for revenue, gross profit and capital expenditures based on history and our best estimate of future forecasts. We also estimate the fair values of our reporting units using a multiple of expected future cash flows, such as those used by third party analysts. If these estimates and assumptions change in the future, due to such factors as a decline in general economic conditions, competitive pressures on sales and margins, and other economic and industry factors beyond management’s control, an impairment charge may be required.

New Accounting Pronouncements

See Note 2 to the consolidated financial statements in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K for a discussion of new accounting pronouncements applicable to us.

ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk. Market risk is the risk of loss arising from adverse changes in market rates and prices. As we do not take title to any of the crude oil that we handle, and typically we take title to only limited volumes of light products in our marketing business, we have limited direct exposure to risks associated with fluctuating commodity prices. However, from time to time, we enter into Gulf Coast product swap arrangements with respect to the products we purchase to hedge our exposure to fluctuations in commodity prices for the period between our purchase of products and subsequent sales to our customers. At December 31, 2017 and 2016, we had open derivative contracts representing 370,000 barrels and 93,000 barrels, respectively, of refined petroleum products. We recognized (losses) gains associated with commodity derivatives not designated as hedging instruments of $(1.6) million, $2.1 million and $0.4 million for the years ended December 31, 2017, 2016 and 2015, respectively. These amounts were recorded to cost of goods sold in the accompanying consolidated statements of income. Please see Note 17 to our accompanying consolidated financial statements for additional detail related to our derivative instruments.

Impact of Changing Prices. Our revenues and cash flows, as well as estimates of future cash flows, are sensitive to changes in energy prices. Shifts in the cost of crude oil, the prices of refined products and the cost of ethanol can generate changes in the operating margin in our wholesale marketing and terminalling segment. A hypothetical ten percent adverse change in year-end market prices of the underlying commodities being hedged by derivative contracts would result in a nominal decrease in market value of the hedge contracts at December 31, 2017.  This hypothetical loss was estimated by multiplying the difference between the hypothetical and the actual year-end market prices of the underlying commodities by the contract volume amounts.

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Interest Rate Risk. Debt that we incur under our revolving credit facility bears interest at floating rates and will expose us to interest rate risk. The annualized impact of a hypothetical one percent change in interest rates on our floating rate debt outstanding as of December 31, 2017 would be to change interest expense by approximately $1.8 million.

From time to time, we may use certain derivative instruments to hedge our exposure to floating interest rates. Additionally, our prior revolving credit facility required us to maintain interest rate hedging arrangements with respect to at least 50% of the amount funded on November 7, 2012 under the revolving credit facility, which was required to be in place for at least a three-year period beginning no later than March 7, 2013. Accordingly, effective February 25, 2013, we entered into an interest rate hedge in the form of a London Interbank Offered Rate interest rate cap for a term of three years for a total notional amount of $45.0 million, thereby meeting the requirements in effect at that time. The interest rate hedge remained in place in accordance with its terms through its maturity date in February 2016. In accordance with ASC 815, Derivatives and Hedging, we recorded no non-cash expense representing the change in estimated fair value of the interest rate hedge agreement for the years ended December 31, 2017 and 2016, respectively.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by Item 8 is incorporated by reference to the section beginning on page F-1.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING ANDFINANCIAL DISCLOSURE

None.

ITEM 9A.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e)) under the Securities Exchange Act of 1934, as amended ("Exchange Act") that are designed to provide reasonable assurance that the information that we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. It should be noted that, because of inherent limitations, our disclosure controls and procedures, however well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the disclosure controls and procedures are met.

Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) under the Exchange Act) as of the end of the period covered by this report, and has, based on this evaluation, concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosures.

Management's Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process that is designed under the supervision of our Chief Executive Officer and Chief Financial Officer, and implemented by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP. Our internal control over financial reporting includes those policies and procedures that:

i. Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

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ii. Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and that receipts and expenditures recorded by us are being made only in accordance with authorizations of our management and Board of Directors; and

iii. Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

Management has conducted its evaluation of the effectiveness of internal control over financial reporting as of December 31, 2017, based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management's assessment included an evaluation of the design of our internal control over financial reporting and testing the operational effectiveness of our internal control over financial reporting. Management reviewed the results of the assessment with the Audit Committee of the Board of Directors. Based on its assessment and review with the Audit Committee, management concluded that, at December 31, 2017, we maintained effective internal control over financial reporting.

Report of Independent Registered Public Accounting Firm

Our independent registered public accounting firm, Ernst & Young LLP, has audited the effectiveness of our internal control over financial reporting as of December 31, 2017, as stated in their report, which is included in the section beginning on page F-1.

The information required by Item 8 is incorporated by reference to the section beginning on page F-1.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15-d-15(f) under the Exchange Act) during the fourth quarter of fiscal 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

From time to time, we make changes to our internal control over financial reporting that are intended to enhance its effectiveness and which do not have a material effect on our overall internal control over financial reporting.

ITEM 9B.  OTHER INFORMATION

On February 26, 2018, the Board of our general partner adopted Amendment No. 1 (“Amendment No. 1”) to the Partnership Agreement, effective upon adoption, in response to certain changes to the Internal Revenue Code enacted by the Bipartisan Budget Act of 2015 (the “BBA”) relating to partnership audit and adjustment procedures. Amendment No. 1 amends Section 9.3 of the Partnership Agreement to implement administrative provisions including the designation of a partnership representative to assist the Partnership with tax-related matters, and Section 9.4 to enable the Partnership to seek indemnity and reimbursement from unitholders for taxes paid by the Partnership that the unitholder would have owed individually had the tax been assessed at the unitholder level. A copy of Amendment No. 1 is filed as Exhibit 3.2(b) to this Annual Report on Form 10-K.

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PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Our general partner, Delek Logistics GP, LLC, is an indirect subsidiary of Delek. As of December 31, 2017, three individuals (Messrs. Yemin, Ginzburg and Green) who serve as both directors and executive officers of the general partner and as officers - and, with respect to Mr. Yemin, a director - of Delek, also own membership interests of 5.00%, 0.20% and 0.20%, respectively, in the general partner. Our general partner manages our operations and activities on our behalf through its officers and directors. References in this Part III to the "Board," "directors," or "officers" refer to the Board, directors and officers of our general partner.

The Board of Directors of Our General Partner

The directors of our general partner oversee our operations. The members of the Board are not elected by our unitholders and will not be subject to re-election by our unitholders in the future. The general partner is a limited liability company and its directors are elected by its members, all of which are subsidiaries, affiliates, directors, officers and/or employees of Delek. The directors hold office for a term of one year or until their successors have been elected or qualified or until their earlier death or removal. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly without recourse to the general partner. Our general partner therefore may cause us to incur indebtedness or other obligations that are without recourse to the general partner.

Our common units are traded on the NYSE. Because we are a limited partnership, we rely on an exemption from the provisions of Section 303A.01 of the NYSE Listed Company Manual which would require the Board to be composed of a majority of independent directors. Despite this exemption, our Board is currently comprised of a majority of independent directors, though this could change in the future. We are not required to establish either a compensation or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members, and all of our audit committee members are required to meet the independence and experience tests established by the NYSE and the Exchange Act.

At the date of this report, the Board consists of the following nine members: Ezra Uzi Yemin, Charles J. Brown, III, Mark B. Cox, Francis C. D'Andrea, Eric D. Gadd, Assaf Ginzburg, Frederec Green, Ronald Haddock and Reuven Spiegel. The Board has determined that each of Messrs. Brown, D'Andrea, Gadd, Haddock and Spiegel qualifies as an independent director under applicable SEC rules and regulations and the rules of the NYSE. Under the NYSE's listing standards, a director will not be deemed independent unless the Board affirmatively determines that the director has no material relationship with us. Based upon information requested from and provided by each director concerning his background, employment and affiliations, including commercial, industrial, banking, consulting, legal, accounting, charitable and familial relationships, the Board has determined that each of Messrs. Brown, D'Andrea, Gadd, Haddock and Spiegel has no material relationship with Delek or us, either directly or as a partner, stockholder or officer of an organization that has a relationship with Delek or us, and each of them is therefore independent under the NYSE's listing standards and applicable SEC rules and regulations.

Director Experience and Qualifications

The members of the general partner are responsible for filling vacancies on the Board at any time during the year and for selecting individuals to serve on the Board. From time to time, the members may utilize the services of search firms or consultants to assist in identifying and screening potential candidates. In accordance with the general partner's Governance Guidelines, in evaluating potential Board candidates, the members consider such qualifications and other factors as they deem appropriate, including the individual’s independence, education, experience, reputation, judgment, skill, integrity and industry knowledge. Directors should have experience in positions with a high degree of responsibility; be leaders in the organizations with which they are affiliated; and have the time, energy, interest and willingness to serve as a member of the Board. While the general partner has no policy requiring consideration of racial or ethnic classifications, gender, religion or sexual orientation, the members give consideration to the diversity of experiences and backgrounds of its directors, the degree to which the individual’s qualities and attributes will complement those of other directors, the extent to which the candidate would be a desirable addition to the Board and committees thereof, and other factors.

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Executive Officers of Our General Partner

Our general partner's executive officers manage the day-to-day affairs of our business and conduct our operations. The executive officers of our general partner are appointed by the Board and serve in that capacity at the discretion of the Board. All of our general partner's executive officers are employees and officers of Delek. While the amount of time that our general partner's executive officers devote to our business varies in any given year, we currently estimate that approximately 10% to 20% of their productive business time is spent on the management and conduct of our operations for all executive officers except Mr. Moret, who following his appointment as President of our general partner in November 2017 now devotes a majority of his time to our operations. The executive officers of our general partner intend to devote as much of their time as is necessary for the proper conduct of our business. We also utilize a significant number of Delek's employees to operate our business and provide us with general and administrative services. Under the Omnibus Agreement, we pay Delek an annual fee, indexed for inflation, for Delek's provision of centralized corporate services, including executive management services of Delek employees who devote less than 50% of their time to our business, financial and administrative services, information technology services, legal services, health, safety and environmental services, human resource services, and insurance administration. In addition, we reimburse Delek for allocated expenses of personnel who devote 50% or more of their time performing services for our benefit.

Directors and Executive Officers of Our General Partner

The following table shows information for the directors and executive officers of our general partner.

Name	Age	Position With Delek Logistics GP, LLC
Ezra Uzi Yemin	49	Chairman of the Board of Directors and Chief Executive Officer
Charles J. Brown, III	70	Director, Chairman of Conflicts Committee and Member of Audit and EHS Committees
Mark Baker Cox	59	Director
Francis C. D'Andrea	64	Director, Chairman of Audit Committee and Member of Conflicts and EHS Committees
Eric D. Gadd	62	Director, Chairman of EHS Committee and Member of Audit and Conflicts Committees
Assi Ginzburg	42	Director and Executive Vice President
Frederec Green	52	Director and Executive Vice President
Ron W. Haddock	77	Director
Reuven Spiegel	61	Director and Member of Audit, EHS and Conflicts Committees
Alan P. Moret	63	President
Kevin L. Kremke	44	Executive Vice President and Chief Financial Officer
Melissa M. Buhrig	42	Executive Vice President, General Counsel and Secretary
Daniel L. Gordon	40	Executive Vice President
Jared Paul Serff	50	Executive Vice President
Avigal Soreq	39	Executive Vice President

Ezra Uzi Yemin has served as the Chief Executive Officer and the Chairman of the Board of our general partner since April 2012. He has also served as the chairman of the board of directors of Delek since December 2012, its chief executive officer since June 2004 and its president and a director since April 2001. Mr. Yemin has served as the president of Alon USA Partners GP, LLC, an affiliate of the Partnership, since July 2017 and the chairman of the board of directors of Alon USA Energy, Inc., an affiliate of the Partnership, since May 2015. Mr. Yemin’s duties include the formulation of our policies and strategic direction, oversight of executive officers, and overall responsibility for our operations and performance. The Board believes that, because he has worked for Delek since its founding, Mr. Yemin brings to the Board a thorough and complete understanding of our business, operations and operating environment, as well as that of Delek (the owner of approximately 63.5% of our units and the customer on whom the Partnership is most dependent). Mr. Yemin also brings to the Board substantial leadership, planning and industry experience.

Charles J. Brown, III has served as a member of the Board of our general partner since November 2012, as a member of the Audit Committee and Conflicts Committee (of which he is Chairman) since November 2012 and as a member of the Environmental, Health and Safety Committee (the "EHS Committee") since its inception in October 2016. Mr. Brown is a licensed attorney with more than 30 years of experience in the energy industry. Since July 2013, Mr. Brown has served as the executive vice president of Apex Clean Energy, Inc., an independent renewable energy company, where he manages legal and business development activities. Mr. Brown is currently the owner of, and since 2011, the chief advisor for, CRW Energy, a consulting firm focused in the international power and utility industries. From 2008 through 2011, Mr. Brown served as a partner in the energy department of a large international law firm. Mr. Brown was appointed to the

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Board because of his experience in the energy industry, and because, as an attorney, he provides the Board with valuable expertise in matters involving the financial, legal, regulatory and risk matters affecting the Partnership.

Mark Baker Cox has been a member of the Board of our general partner since April 2012. From October 2016 to January 2017, Mr. Cox served as anExecutive Vice President and Chief Administrative Officer of our general partner and Delek. From May 2013 until February 2016, Mr. Cox was the chief financial officer of Eco-Energy, Inc., an alternative energy company focused on the marketing, trading, transportation and blending of biofuels. He was an executive vice president of our general partner from April 2012 until March 2013 and of Delek from September 2009 until March 2013. Mr. Cox served as the chief financial officer of our general partner from April 2012 until January 2013 and as the chief financial officer of Delek from September 2009 until January 2013. From June 2007 until September 2009, Mr. Cox served as the senior vice president-treasurer and director of investor relations of Western Refining, Inc. Between 1994 and 2007, he was employed by Giant Industries, Inc., and served in various positions including vice president, executive vice president, treasurer, chief financial officer and assistant secretary. Mr. Cox was appointed to the Board because his energy industry and financial experience provides the Board with valuable expertise in financial and accounting matters typically confronted by companies in our industry.

Francis C. D'Andrea has served as a member of the Board of our general partner since August 2015, as Chairman of the Audit Committee and as a member of the Conflicts Committee since August 2015. He has also been a member of the EHS Committee since its inception in October 2016. Mr. D’Andrea is a certified public accountant. From 1979 through his retirement in 2012, Mr. D’Andrea served in various roles with Deloitte & Touche LLP, culminating in the role of senior partner from 2011 through 2012, preceded by his role as managing partner from 2005 through 2011 of Deloitte’s Houston/New Orleans audit practice, and was involved in such capacities with several public companies, including sponsors of master limited partnerships. Mr. D’Andrea was appointed to the Board of our general partner because the Board believes that his experience as a certified public accountant and partner with Deloitte & Touche LLP provides the Board with valuable experience in matters involving finance and accounting in general and master limited partnerships in particular.

Eric D. Gadd has served as a member of the Board of our general partner since October 2013 and as Chairman of the EHS Committee since its inception in October 2016. Mr. Gadd is currently principal director at Contanda LLC, which is a private company that operates bulk liquid terminals in North America. He has also been a member of the Audit Committee and Conflicts Committee since October 2013. Mr. Gadd is the founder and president of the consulting firm Awelon LLC, which is focused on expanding business development opportunities for both public and private companies in the energy sector. He has over 35 years of diverse experience in the energy industry including exploration and production field services, mid-stream, renewable energy, commodity trading and risk management, and mergers and acquisitions. Prior to forming Awelon LLC in 2006, Mr. Gadd held various executive positions with multiple leading companies in the energy industry over a 25-year period. Mr. Gadd was appointed to the Board because of his extensive energy industry experience.

Assi Ginzburg has served as an Executive Vice President and member of the Board of our general partner since April 2012. Mr. Ginzburg has also served as Delek's executive vice president since May 2009 and as a vice president of Delek since February 2005. Previously, Mr. Ginzburg served as chief financial officer of our general partner and Delek from January 2013 to June 2017 and as a member of the board of directors of Alon USA Energy, Inc. from May 2015 until its acquisition by Delek in July 2017. Mr. Ginzburg has been a member of the Israel Institute of Certified Public Accountants since 2001. Mr. Ginzburg was instrumental in the successful completion of our initial public offering in November 2012, and he was appointed to the Board because his financial experience and knowledge of our and Delek's businesses provide the Board with valuable expertise into relevant business and financial and accounting matters.

Frederec Green has been an Executive Vice President and a member of the Board of our general partner since April 2012. Mr. Green has been Delek's chief operating officer since November 2016, an executive vice president of Delek since May 2009 and was the primary operational officer for Delek's refining operations from January 2005 to December 2016. He has served as an executive vice president and chief operating officer of Alon USA Partners GP, LLC since July 2017, its chief executive officer since August 2017, and a member of the board of directors of Alon USA Energy, Inc. since May 2015. Mr. Green has more than 25 years of experience in the refining industry, including 14 years at Murphy Oil USA, Inc. (NYSE: MUR), where he served as a senior vice president during his last six years. Mr. Green was appointed to the Board because of his extensive energy industry experience and his in-depth knowledge of our and Delek's businesses and operations.

Ron W. Haddock has served as a member of the Board of our general partner since July 2017. Mr. Haddock is currently Chairman and Chief Executive Officer of AEI Services LLC, an international power generation/distribution and natural gas distribution company, positions he has held since 2004 and August 2003, respectively. He also served on the board of Alon Energy USA, Inc. from December 2000 until its acquisition by Delek in July 2017 and has served on the board of Petron Corporation, an oil refining and marketing company in the Philippines since December 2008. From January 1989 to July 2000, Mr. Haddock served as chief executive officer of FINA, Inc., a Belgian oil company. Mr. Haddock also served on the boards of Safety-Kleen Systems, Inc., a waste management, oil recycling and refining company, from 2003 to 2012, and Trinity Industries, Inc. (NYSE: TRN), a diversified transportation, industrial and construction company, from 2007 to 2013, as well as eight other corporate boards. The Board believes that Mr. Haddock’s extensive directorship experience, past executive positions within the refining industry, financial reporting background and expertise qualify him to serve as a member of the Board.

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Reuven Spiegel has served as a member of the Board of our general partner since July 2014, as a member of the Audit Committee and Conflicts Committee since September 2014 and as a member of the EHS Committee since its inception in October 2016. Mr. Spiegel has served in the financial and real estate industry since 1983. Prior to joining the Board, Mr. Spiegel served as president, chief executive officer, and senior executive vice president of Israel Discount Bank Ltd. (TLV: DSCT) from 2001 through 2014. In 2005 and 2006, Mr. Spiegel also served as chairman of the board of Discount Mortgage Bank. The Board believes that Mr. Spiegel's financial industry experience provides the Board with valuable expertise in the Partnership's financial and accounting matters.

Alan P. Moret has been the President of our general partner since November 2017 and an Executive Vice President of our general partner since July 2017. Mr. Moret was the chief executive officer of Alon USA Partners GP, LLC from January 2017 until August 2017 and the interim chief executive officer of Alon USA Energy, Inc. from January 2017 until its merger with a subsidiary of Delek in July 2017. Prior to these appointments, Mr. Moret served as senior vice president of supply, trading and logistics at Alon USA Partners GP, LLC since 2008 and, prior to that, as Senior vice president of supply of Alon USA Energy, Inc.'s Asphalt Division where he directed the company's asphalt operations and marketing. Mr. Moret joined Alon USA Energy, Inc. in August 2006 in connection with Alon's acquisition of Paramount Petroleum Corporation, where he served as president from November 2001 to August 2006. Prior to joining Paramount Petroleum Corporation, Mr. Moret held various positions with Atlantic Richfield Company, most recently as president of ARCO Crude Trading, Inc. and served as president of ARCO Seaway Pipeline Company from 1997 to 1998.

Kevin L. Kremkehas served as the Chief Financial Officer of our general partner since June 2017 and an Executive Vice President of our general partner since April 2017. He has also served as Delek's chief financial officer since June 2017 and as an executive vice president of Delek since April 2017.He served as an executive vice president and secretary of Alon USA Partners GP, LLC since July 2017 and its chief financial officer since August 2017. He has served as a director of Alon USA Energy, Inc. since July 2017.Prior to joining us in April 2017, Mr. Kremke served as the chief financial officer of Ciner Resources Corporation and Ciner Resources LP (NYSE: CINR), a publicly traded master limited partnership, since June 2014, and as director of the general partner of Ciner Resources LP since December 2014.His responsibilities at Ciner Resources Corporation included overseeing the overall financing activities, strategic planning, investor relations, treasury and accounting.He also has served on the audit committee of American Natural Soda Ash Corporation since June 2014. From August 2011 to February 2014, Mr. Kremke served as the vice president of finance and strategic planning at Cheniere Energy, Inc. (NYSE American: LNG).

Melissa M. Buhrig has served as the Executive Vice President, General Counsel and Secretary of our general partner and of Delek since October 2017. Ms. Buhrig has nearly 18 years of legal experience, primarily in the refining sector. Most recently, she served as senior vice president - services and compliance officer for Western Refining, Inc. and Western Refining Logistics, LP (NYSE: WNRL). Ms. Buhrig joined Western Refining in 2005 as deputy general counsel and held roles of increasing responsibility including vice president, assistant general counsel and secretary. In 2014, she joined the general partner of Northern Tier Energy LP as executive vice president, general counsel, secretary and compliance officer until completion of the merger between Western Refining, Inc. and Northern Tier Energy in 2016. 

Daniel L. Gordon has been an Executive Vice President of our general partner since October 2014, an executive vice president of Delek since August 2014, a vice president of Delek since November 2012, and a vice president of Delek's former subsidiary, MAPCO Express, Inc., from 2011 until the sale of our retail segment in November 2016. Prior to joining us in 2011, Mr. Gordon had served as president of Aska Energy in Atlanta, Georgia since 2009.

Jared Paul Serff has served as an Executive Vice President of our general partner and Delek since May 2017 and a Vice President since July 2015. Prior to joining us, Mr. Serff was the chief human resources officer of Itron, Inc. (NASDQ: ITRI) from July 2004 to February 2014. Itron is a publicly-traded technology company offering products and services in energy and water resource management. Mr. Serff’s responsibilities at Itron included overseeing the global human resources function supporting approximately 10,000 employees operating in 60 countries around the world.

Avigal Soreq has been an Executive Vice President of our general partner since October 2015 and a Vice President since December 2012. He has also served as Delek's chief commercial officer since November 2016, an executive vice president of Delek since August 2015 and as a vice president of Delek since December 2012. He served as a member of the board of directors of Alon USA Energy, Inc. from May 2015 until its acquisition by Delek in July 2017. Prior to joining us in October 2011, Mr. Soreq worked in business development for SunPower Corporation (NASDAQ: SPWR), an American energy company that designs and manufactures solar panels. Prior to joining SunPower Corporation, Mr. Soreq worked as a senior finance and business consultant for Trabelsy & Co and as a consultant in the corporate finance department for KPMG’s Tel-Aviv office. Mr. Soreq served in the Israeli Air Force in various roles between 1996 and 2004 and reached the rank of Major. Mr. Soreq is a certified public accountant in Israel.

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Board Leadership Structure

Mr. Yemin serves as Chairman of the Board. Our general partner has no policy with respect to the unification or separation of the offices of Chairman and CEO. Rather, the Board's policy is to let the Board make such a determination in the manner it deems most appropriate for the general partner and us at a given point in time. At this time, the Board believes that our general partner's Chief Executive Officer is best situated to serve as Chairman of the Board because he is the director most familiar with our business and industry. He is also the Chairman of the board of directors of Delek, which provides the Board and us with important interaction with, and access to, our most important customer and majority unitholder. Mr. Yemin also brings to the Board and us the perspectives of our majority unitholder and the principal executive officer and chairman of the board of a publicly traded company. As such, the Board feels that combining the roles of Chairman and CEO provides the Board with the individual who is most capable of effectively identifying strategic priorities and leading the discussion and execution of strategy and facilitating the information flow between management and the Board and its committees, which are essential to effective governance of the Partnership. The Board met 20 times in the year ended December 31, 2017, with each director attending at least 75% of the aggregate of all meetings of the Board and committees on which he served during the year.

Executive Sessions

Independent directors and management have different perspectives and roles in strategy development. Our independent directors bring experience, oversight and expertise from outside the Partnership and our industry, while the other Board members bring experience and expertise specific to us and Delek. In addition, the independent directors are the sole members of our Audit and Conflicts Committees. The NYSE listing standards require our independent directors to meet at regularly scheduled executive sessions without management. Our independent directors generally conduct such executive sessions in connection with each quarterly meeting of the Audit Committee and otherwise as may be necessary. Mr. Spiegel was appointed lead independent director of the Board during the year ended December 31, 2017. In this capacity, Mr. Spiegel generally presides over these executive sessions.

Communications with the Board of Directors of Our General Partner

Unitholders or other interested parties who wish to communicate with any of our directors, any committee chairperson or the Board may do so by writing to the director, committee chairperson or the Board in care of the Secretary of the general partner of Delek Logistics Partners, LP at 7102 Commerce Way, Brentwood, Tennessee 37027. Any such communication received will be forwarded directly to the director to whom it is addressed. If the communication is addressed to the Board and no particular director is named, the communication will be forwarded, depending on the subject matter, to the appropriate committee chairperson or to all members of the Board.

Committees of the Board of Directors of Our General Partner

Audit Committee

The Board has a standing Audit Committee. The Audit Committee consists of Messrs. D'Andrea (chairman), Brown, Gadd and Spiegel. Mr. D'Andrea joined the committee in August 2015. Mr. Brown joined the committee at its inception in November 2012, and Messrs. Gadd and Spiegel joined the committee in October 2013 and September 2014, respectively. The Audit Committee met seven times during the year ended December 31, 2017, either in person or telephonically, with each member attending at least 75% of all meetings of the Audit Committee and at least 75% of the aggregate of all meetings of the Board and committees on which he served during the year.

The Board has determined that (i) each of Messrs. D'Andrea, Brown, Gadd and Spiegel qualifies as independent under applicable SEC rules and regulations and the rules of the NYSE and as financially literate, and (ii) Mr. D'Andrea meets the definition of an “audit committee financial expert” within the meaning of Item 407(d)(5) of Regulation S-K.

The purpose of the Audit Committee is to provide assistance to the Board in the oversight of (a) the quality and integrity of our financial statements; (b) the disclosure and financial reporting process, including our financial statements; (c) our internal controls and procedures for financial reporting; (d) the performance of our internal audit function and the independent registered public accounting firm employed by us for the purpose of preparing and issuing an audit report or related work; (e) the qualifications and independence of our independent registered public accounting firm; and (f) our compliance with policies under our Code of Business Conduct & Ethics and legal and regulatory requirements. These responsibilities are set forth in the Audit Committee’s charter, which is available on our corporate website at www.DelekLogistics.com.

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Conflicts Committee

The Conflicts Committee consists of Messrs. Brown (chairman), D'Andrea, Gadd and Spiegel. The Board has determined that each of Messrs. Brown, D'Andrea, Gadd and Spiegel qualifies as independent under applicable SEC rules and regulations and the rules of the NYSE. Mr. Brown joined the committee at its inception in November 2012. Messrs. Gadd, Spiegel and D'Andrea joined the committee in October 2013, September 2014 and August 2015, respectively. The Conflicts Committee met two times during the year ended December 31, 2017, either in person or telephonically, with each member attending at least 75% of all meetings of the Conflicts Committee.

Our Partnership Agreement does not require that the Board seek approval from the Conflicts Committee to determine the resolution of any conflict of interest between us and Delek or any other person. However, pursuant to the Partnership Agreement and our Related Party Transactions Policy adopted by the Board, the Board or management of our general partner may submit certain related party transactions for review and approval or ratification by the Board or an authorized committee thereof. It is generally expected that the Conflicts Committee will be best suited to review such related party transactions. In certain instances, the Related Party Transactions Policy effectively requires that certain related party transactions be submitted to the Conflicts Committee for review. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, may not hold an ownership interest in the general partner or its affiliates other than common units or awards under any long-term incentive plan, equity compensation plan or similar plan implemented by the general partner or the Partnership and must meet the independence and experience standards established by the NYSE and the SEC to serve on an audit committee of a board of directors. Any unitholder challenging any matter approved by the Conflicts Committee in accordance with the terms of our Partnership Agreement will have the burden of proving that the members of the Conflicts Committee did not act in good faith in accordance with the terms of our Partnership Agreement. For further discussion of the Conflicts Committee and the Related Party Transactions Policy, see Item 13. "Certain Relationships and Related Transactions and Director Independence—Certain Relationships and Related Transactions—Procedures for Review, Approval or Ratification of Transactions with Related Parties."

Environmental, Health and Safety Committee

The EHS Committee was formed in October 2016 and has consisted of Messrs. Gadd (chairman), Brown, D'Andrea and Spiegel from its inception. The EHS Committee met four times in 2017, either in person or telephonically, with each member attending at least 75% of all meetings of the EHS Committee.The purpose of the EHS Committee is to assist the Board in fulfilling certain of the Board’s oversight responsibilities by, among other things, overseeing management’s establishment and administration of the Company’s environmental, health and safety policies, programs, procedures and initiatives. These responsibilities are set forth in the EHS Committee's charter, which is available on our corporate website at www.DelekLogistics.com.

Director Nominations and Corporate Governance

As a limited partnership, we rely on an exemption from the provisions of the NYSE Listed Company Manual, which would otherwise require us to have a nominating and corporate governance committee. Our general partner is a limited liability company and its directors are not elected by our unitholders, but by its members in their sole discretion. Accordingly, the Board believes it is unnecessary to have a nominating and corporate governance committee or a committee performing the functions of such a committee. Candidates to serve on the Board are reviewed and selected in accordance with our general partner's Governance Guidelines, which are available on our corporate website at www.DelekLogistics.com. Pursuant to the Merger Agreement, Delek agreed to cause our general partner to increase the size of the Board by one seat, to appoint an individual selected by the Independent Director Committee of Alon USA prior to the closing date of the Delek/Alon Merger to such newly created seat, and to cause such individual to be re-elected to the Board for terms to be no less than two years after the closing date of the Delek/Alon Merger, subject to our Governance Guidelines. Ronald Haddock was designated by the Independent Director Committee of Alon USA to fill such seat pursuant to the Merger Agreement and, on July 18, 2017, the Board elected Mr. Haddock to fill such seat for a term ending no less than two years after the closing date of the Delek/Alon Merger, subject to our Governance Guidelines.

Compensation Decisions

Our general partner does not have a compensation committee. Our general partner has decided that a compensation committee is not necessary at this time, primarily because neither our general partner nor the Partnership regularly provides compensation to the general partner's executive officers.

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However, our Board believes it is important to promote the interests of the Partnership by providing to employees of the Partnership's affiliates and others who perform services for us or on our behalf, incentive compensation awards for their service. Accordingly, the general partner adopted the Delek Logistics GP, LLC 2012 Long-Term Incentive Plan (the "LTIP"). Due to the fact that several of the members of the Board perform services on our behalf in their roles as executive officers of Delek, the LTIP is administered by the Conflicts Committee with respect to those awards. The disinterested members of the full Board may also grant awards and the Conflicts Committee may delegate, and has delegated in the past, to an executive officer of the general partner the authority to issue awards to non-Section 16 officers of the general partner. A compensation consultant was not used in the formulation of our executive compensation framework, objectives and philosophy. For a further discussion on the compensation practices of the general partner, see Item 11. Executive Compensation.

Governance Guidelines, Code of Business Conduct & Ethics and Committee Charters

The Governance Guidelines of the Board of Directors of our general partner, the charter of the Audit Committee of our general partner and our Code of Business Conduct & Ethics covering all employees, including our principal executive officer, principal financial officer, principal accounting officer and controllers, are available on our website, www.DelekLogistics.com under the "About Us - Corporate Governance" caption. A copy of any of these documents will be mailed upon request made to Investor Relations, Delek Logistics Partners, LP, or ir@deleklogistics.com. We intend to disclose any amendments to, or waivers of, the Code of Business Conduct & Ethics on behalf of our Chief Executive Officer, Chief Financial Officer and persons performing similar functions on our website, at www.DelekLogistics.com, under the “Investor Relations” caption, promptly following the date of any such amendment or waiver.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Exchange Act, and regulations of the SEC thereunder, requires the executive officers and directors of our general partner and persons who own more than ten percent of our common units, as well as certain affiliates of such persons, to file initial reports of ownership of our common units and changes in their ownership with the SEC. Executive officers, directors and persons owning more than ten percent of our common units are required by SEC regulations to furnish us with copies of all Section 16(a) reports they file.

Based solely on our review of the copies of such reports received by us and written representations that no other reports were required for or by those persons, we believe that, during the year ended December 31, 2017, all filing requirements applicable to the executive officers and directors of our general partner and owners of more than ten percent of our common units were met, except for the following late reports:

• On April 17, 2017, Delek US Holdings, Inc. filed a Form 4 reporting the acquisition of 1,800 common units that occurred on April 12, 2017.

• On November 15, 2017, Ms. Melissa M. Buhrig filed a Form 3 reporting that Ms. Buhrig became an executive officer on October 24, 2017.

• On December 13, 2017, Mr. Frederec Green filed a Form 4 reporting the disposition of 1,367 common units that occurred on December 10, 2017 due to the fact that the vesting date fell over a weekend.

• On December 13, 2017, Mr. Ezra Uzi Yemin filed a Form reporting the disposition of 3,348 common units that occurred on December 10, 2017 due to the fact that the vesting date fell over a weekend.

• On December 14, 2017, Mr. Daniel L. Gordon filed a Form 4 reporting the disposition of 273 common units that occurred on December 10, 2017 due to the fact that the vesting date fell over a weekend.

• On December 13, 2017, Mr. Assaf Ginzburg filed a Form 4 reporting the disposition of 673 common units that occurred on December 10, 2017 due to the fact that the vesting date fell over a weekend.

• On February 14, 2018, Mr. Mark Cox filed a Form 5 reporting the disposition of 81 common units that occurred on June 10, 2015, 81 common units that occurred on June 10, 2016, 80 common units that occurred on June 10, 2016 and 814 common units that occurred on June 10, 2017.

• On February 19, 2018, Mr. Francis D'Andrea filed a Form 4/A correcting certain information contained in a Form 4 filed by Mr. Francis D'Andrea reporting the acquisition of 2,018 common units that occurred on June 10, 2017.

ITEM 11.    EXECUTIVE COMPENSATION

All of our general partner's executive officers are employees of Delek. Neither we nor our general partner directly employs any of the executive officers responsible for managing our business.

Compensation Discussion and Analysis

This Compensation Discussion and Analysis (“CD&A”) discusses the principles underlying our general partner's compensation programs and the key executive compensation decisions that were made for 2017. It also explains the most important factors relevant to such

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decisions. This CD&A provides context and background for the compensation earned and awarded to the individuals named in the Summary Compensation Table below. These individuals may be referred to herein as our named executive officers or “NEOs.”

Overview - Compensation Decisions and Allocation of Compensation Expenses

Our general partner does not have a compensation committee. Our general partner has determined that a compensation committee is not necessary at this time, primarily because our general partner's executive officers do not regularly receive material compensation from our general partner or the Partnership.

However, our Board believes it is important to promote the interests of the Partnership and the general partner by providing incentive compensation to employees of the Partnership's affiliates and others who perform services for us or on our behalf. Accordingly, pursuant to our Partnership Agreement, the general partner is allowed to and has adopted the LTIP. Due to the fact that several of the members of the Board perform services on our behalf in their roles as executive officers of Delek, the LTIP is administered by the Conflicts Committee, with respect to awards to these individuals. The disinterested members of the Board may also grant awards and the Conflicts Committee may delegate, and has delegated in the past, to an executive officer of the general partner the authority to issue awards to non-Section 16 officers of the general partner.

Under the terms of the Omnibus Agreement, we pay an annual administrative fee of $3.7 million per year to Delek for the provision of general and administrative services. The general and administrative services covered by the annual administrative fee include, without limitation, executive management services of Delek employees who devote less than 50% of their time to our business, financial and administrative services, information technology services, legal services, health, safety and environmental services, human resources services and insurance administration. No service covered by the administrative fee is assigned any particular value individually. Additionally, the Omnibus Agreement requires us to reimburse Delek directly for a proportionate amount of the salary and employee benefits costs of Delek employees who devote more than 50% of their time to our business and affairs.

None of our NEOs devoted more than 50% of his total business time to our business and affairs in 2017. Although our NEOs provide services to both Delek and us, no portion of the administrative fee is specifically allocated to services provided by our NEOs to us. Instead, the administrative fee covers all centralized services provided to us by Delek, and we have not reimbursed Delek for the cost of such services. Except for awards under the LTIP, Delek has the ultimate decision-making authority with respect to the compensation of our NEOs.

Compensation Objectives and Philosophy

Because neither we nor our general partner directly employ any of our NEOs, and because our NEOs are compensated by Delek to manage our business and affairs, we did not provide traditional fixed or discretionary compensation (e.g. salary or bonus) to our NEOs in 2017. However, we believe that our NEOs should have an ongoing stake in our success, that their interests should be aligned with those of our unitholders and that the best interests of our unitholders will be most effectively advanced by enabling our NEOs, who are responsible for our management, growth and success, to receive compensation in the form of long-term incentive awards. Accordingly, our executive compensation program consists of a single element: long-term incentives in the form of awards under the LTIP, which was adopted in connection with the Offering and is administered by the Conflicts Committee. The Conflicts Committee’s decisions with respect to the amount of awards made under the LTIP to our NEOs are governed by the following objectives:

• to motivate and retain our general partner's key executives;

• to align the long-term economic interests of our general partner's executives with those of our unitholders; and

• to reward excellence and performance by our general partner's executives that increases the value of our units.

Awards may be made under the LTIP to officers, directors and employees of Delek, our general partner or its affiliates, as well as any consultants or other individuals who perform services for us. Phantom units have been the sole form of award under the LTIP to date, and these awards are accompanied by distribution equivalent rights that provide for a lump sum amount paid in cash on the vesting date that is equal to the accrued distributions from the grant date of the phantom units through the vesting date. No phantom units were granted to our executive officers in 2017.

Pursuant to the terms of the LTIP, upon the occurrence of an Exchange Transaction (as defined in the LTIP, and generally including a merger, consolidation, acquisition, reorganization or similar extraordinary transaction), the Board may, in its discretion, accelerate the vesting of the phantom units, adjust the terms of any outstanding phantom units, or, in the event of an Exchange Transaction in which

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our unitholders receive equity of another entity, provide for the conversion of the phantom units into comparable awards for such entity's equity. By providing the potential for immediate value to our NEOs in connection with an Exchange Transaction, this provision aligns our NEOs' interests with those of our unitholders and incentivizes our NEOs to work to maximize the value of our units in the event such a transaction were to occur. For additional detail regarding the amount of compensation our NEOs may be entitled to in the event of their termination or a change-in-control, see “—Potential Payments Upon Termination or Change-In-Control.”

Compensation Consultants

Our general partner does not have a compensation committee, and its Board did not retain a compensation consultant with respect to compensation paid to our NEOs or to its non-employee directors in 2017, as the Board elected to keep 2017 compensation to its non-employee directors the same as it was in 2016 and 2015.

Perquisites

Our general partner does not provide any fringe benefits or perquisites to our NEOs.

Unit Ownership Requirements

Our general partner does not have express unit ownership requirements.

Prohibition Against Speculative Transactions

Our general partner's Code of Business Conduct & Ethics, which applies to all executive officers and directors of our general partner, prohibits speculative transactions in our units such as short sales, puts, calls or other similar options to buy or sell our units in an effort to hedge certain economic risks or otherwise.

Guidelines for Trades by Insiders

We maintain policies that govern trading in our units by officers and directors required to report under Section 16 of the Exchange Act, as well as certain other employees who may have regular access to material non-public information about us. These policies include pre-approval requirements for all trades and periodic trading “black-out” periods designed with reference to our quarterly financial reporting schedule. We also require pre-approval of all trading plans adopted pursuant to Rule 10b5-1 promulgated under the Exchange Act. To mitigate the potential for abuse, no trades are allowed under a trading plan within 30 days after adoption. In addition, we discourage termination or amendment of trading plans by prohibiting trades under new or amended plans within 90 days following a plan termination or amendment.

Compensation Committee Report

The members of the Conflicts Committee have reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussions, the Conflicts Committee recommended to the Board of our general partner that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

The members of the Conflicts Committee have submitted this Report to the Board of Directors as of February 28, 2018:

Charles J. Brown, III (Chairman)

Francis C. D'Andrea

Eric D. Gadd

Reuven Spiegel

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2017 Summary Compensation Table

The Summary Compensation Table below summarizes the compensation for the fiscal year ended December 31, 2017 (and the two prior fiscal years) for our general partner's principal executive officer (Mr. Yemin), former principal financial officer (Mr. Ginzburg) and current principal financial officer (Mr. Kremke). Messrs. Yemin, Ginzburg and Kremke are referred to collectively herein as our "named executive officers" or "NEOs."

(a)	(b)	(c)	(d)	(e)	(f)	(i)	(j)
Name and Principal Position (1)	Fiscal Year	Salary ($)	Bonus ($)	Unit Awards ($)	Option Awards ($)	All Other Compensation ($)	Total ($)
Ezra Uzi Yemin Chief Executive Officer	2017	—	—	—	—	—	—
	2016	—	—	—	—	—	—
	2015	—	—	—	—	—	—
Assaf Ginzburg Executive Vice President and Former Chief Financial Officer	2017	—	—	—	—	—	—
	2016	—	—	—	—	—	—
	2015	—	—	—	—	—	—
Kevin Kremke Chief Financial Officer	2017	—	—	—	—	—	—
	2016	—	—	—	—	—	—
	2015	—	—	—	—	—	—

⁽¹⁾  Because none of our executive officers received total compensation from us or our general partner in excess of $100,000 in 2017, information is presented only for Messrs. Yemin, Ginzburg and Kremke.

Grants of Plan Based Awards in 2017

Because our NEOs continued to benefit from significant plan-based equity awards granted in prior years, our NEOs were not granted plan-based equity awards during 2017.

Outstanding Equity Awards at December 31, 2017

The following table provides information regarding the number of outstanding equity awards held by our NEOs at December 31, 2017.

	Option Awards				Unit Awards
Name	Number of Securities Underlying Unexercised Options Exercisable	Number of Securities Underlying Unexercised Options Unexercisable	Option Exercise Price	Option Expiration Date	Number of Units That Have Not Vested	Market Value of Units That Have Not Vested
Ezra Uzi Yemin	—	—	n/a	n/a	—	$—
Assaf Ginzburg	—	—	n/a	n/a	—	$—
Kevin Kremke	—	—	n/a	n/a	—	$—

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Option Exercises and Stock Vested in 2017

The following table provides information about the vesting of phantom units for our NEOs during fiscal year 2017.

	Option Awards		Stock Awards (1)
Name	Number of Shares Acquired on Exercise	Value Realized on Exercise	Number of Shares Acquired on Vesting	Value Realized on Vesting
Ezra Uzi Yemin	—	n/a	24,488	$758,516
Assaf Ginzburg	—	n/a	5,000	$154,875
Kevin Kremke	—	n/a	—	$—

⁽¹⁾  Consists of the following:

Date	NEO	Phantom Units Vested	Fair Market Value Per Unit	Value Realized on Vesting
6/10/2017	Yemin	12,244	$32.20	$394,257
	Ginzburg	2,500		$80,500
	Kremke	—		$—
12/10/2017	Yemin	12,244	$29.75	$364,259
	Ginzburg	2,500		$74,375
	Kremke			$—

Potential Payments Upon Termination or Change-In-Control

The following table discloses the estimated payments and benefits that would be provided by us to each of our NEOs, assuming that each of the triggering events relating to termination of employment or change in control described in their respective employment agreements with Delek and the LTIP took place on December 31, 2017 and their last day of employment with our general partner or its affiliates was December 31, 2017. Due to a number of factors that affect the nature and amount of any benefits provided upon the events discussed below, any actual amounts paid or distributed may differ. Factors that could affect these amounts include the timing during the year of any such event and our stock price.

Name	Termination of Employment	Change-In-Control (1)
Ezra Uzi Yemin	—	$—
Assaf Ginzburg	—	$—
Kevin Kremke	—	$—

⁽¹⁾ The phantom units previously held by Messrs. Yemin and Ginzburg were fully vested as of December 31, 2017.

2012 Long-Term Incentive Plan

Under the terms of the LTIP and the applicable awards, phantom units that have not vested at the time the participant’s employment with our general partner or its affiliates terminates will generally be immediately forfeited, unless the Board determines otherwise. In the event of an Exchange Transaction, defined generally under the LTIP to include a merger, consolidation, acquisition or disposition of stock, separation, reorganization, liquidation or other similar event or transaction designated by the Board in which our unitholders receive cash, stock or other property in exchange for or in connection with their units, our NEOs may be entitled, at the discretion of the Board, to the accelerated vesting of phantom units awarded under the LTIP. The LTIP and applicable awards provide that the Board may, in its discretion, (i) accelerate the vesting of the phantom units, (ii) make other adjustments to the terms of the phantom units, or (iii) in the event the Exchange Transaction involves the receipt of equity of another entity in exchange for units, convert the phantom units into comparable awards relating to such entity's equity.

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Compensation of Directors in 2017

Officers and employees of Delek or its subsidiaries do not receive additional compensation for service on the Board or its committees. The compensation framework for the Board's other directors during 2017 (Messrs. Brown, Cox, D'Andrea, Gadd, Haddock and Spiegel) (the "Compensated Directors") was determined by the Board. In setting compensation for the Compensated Directors, the Board considers various factors and objectives, including aligning the interests of Compensated Directors with the interests of unitholders and attracting and retaining qualified directors to serve on the Board. From time to time, the Board also engages an independent compensation consultant to provide an analysis of compensation paid to directors of entities considered by the Board to be peers of the Partnership at the time. For 2017, the Board did not engage a compensation consultant to evaluate Compensated Director compensation, and instead considered the other factors outlined above. The Board determined to keep the amount of compensation for the Compensated Directors in 2017 the same as it was in 2016 and 2015, except that Mr. Spiegel was awarded a portion of the $10,000 Lead Director Fee for his service as Lead Independent Director in 2017, which was not previously a position on the Board. This compensation includes a cash retainer for service on the Board and its Committees (and a Lead Director fee), payable quarterly, and an annual equity award of phantom units under the LTIP that vests semi-annually over a one-year period, as set forth below:

Board of Directors Retainer (Per Year)	$50,000
Lead Director Fee (Per Year)	$10,000
Committee Retainers (Per Year):	Chairman	Others
Audit Committee	$10,000	$5,000
Conflicts Committee	$5,000	$2,500
EHS Committee	$5,000	$3,000
Target Value for Equity Awards (Per Year)	$65,000

In addition, each director is reimbursed for out-of-pocket expenses in connection with attending meetings of the Board and committee meetings. Each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law pursuant to our Partnership Agreement.

The following table sets forth a summary of the compensation we paid to the members of the Board for service during 2017.

Director Compensation
Name (1)	Fees Earned or Paid in Cash ($)(2)	Stock Awards ($)(3)	Option Awards ($)	All Other Compensation ($)	Total ($)
Charles J. Brown, III	62,750	64,980	—	—	127,730
Mark Baker Cox	35,278	64,980	—	—	100,258
Francis C. D'Andrea	67,750	64,980	—	—	132,730
Eric D. Gadd	62,083	64,980	—	—	127,063
Ron W. Haddock (4)	13,125	—	—	—	13,125
Reuven Spiegel	62,750	64,980	—	—	127,730

⁽¹⁾  Because they are officers and employees of Delek or its subsidiaries, Messrs. Yemin, Ginzburg and Green did not receive any compensation for their service as directors in 2017.

⁽²⁾  This column reports the amount of cash compensation earned in 2017 for Board and committee service and the Lead Director Fee.

⁽³⁾  Amounts in this column represent the aggregate grant date fair value computed in accordance with FASB ASC Topic 718 for financial statement reporting purposes. Assumptions used in the calculation of this amount for the 2017 fiscal year are included in Note 13 to our audited financial statements for the 2017 fiscal year included in this Annual Report on Form 10-K. The grant date fair value of $32.20 per unit is equal to the NYSE closing price of our common units as of the June 10, 2017 grant date. Messrs. Brown, Cox, D'Andrea, Gadd and Spiegel held 1,248, 0, 632, 1,498 and 1,248 outstanding phantom units, respectively, at December 31, 2017.

⁽⁴⁾  As of July 2017, Mr. Haddock joined the Board and began receiving compensation as a director at that time.

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Compensation Committee Interlocks and Insider Participation

Messrs. Brown, D'Andrea, Gadd and Spiegel served on the Conflicts Committee during 2017 and Mr. Yemin and the Board assisted the committee with respect to compensation matters. There are no interlocking relationships requiring disclosure pursuant to Item 407(e)(4)(iii) of Regulation S-K.

CEO Pay Ratio

As discussed above, as a master limited partnership, we have no employees.  Rather, all of the employees that conduct our business are employed by our general partner and its non-Partnership affiliates.  Moreover, as disclosed above, we did not pay any compensation amounts to our chief executive officer in 2017.  As a result, we are unable to provide an estimate of the relationship of the median of the annual total compensation of employees that conduct our business and the annual total compensation of our chief executive officer.

We expect the CEO pay ratio disclosure with respect to employees of Delek, including our NEOs, to be set forth in Delek’s annual proxy statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN OWNERS AND MANAGEMENT ANDRELATED STOCKHOLDER MATTERS

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth, as of February 26, 2018 (the "Measurement Date"), (i) the beneficial ownership of our units representing limited partnership interests and Common Stock of Delek US Holdings, Inc. by all directors and director nominees of our general partner, our NEOs and all of our executive officers as a group and (ii) the beneficial ownership of our units representing limited partnership interests by each person known by us to own more than five percent of such units or more than five percent of any class of our units. The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. Unless otherwise indicated below, each person or entity has an address in care of our principal executive offices at 7102 Commerce Way, Brentwood, Tennessee 37027.

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Name of Beneficial Owner (1)	Amount, Nature and Percentage of Beneficial Ownership of Common Units (2)		Amount, Nature and Percentage of Beneficial Ownership of Subordinated Units (2)		Amount, Nature and Percentage of Beneficial Ownership of General Partner Units (2)		Amount and Nature of Beneficial Ownership of Common Stock (2)
	Delek Logistics Partners, LP						Delek US Holdings, Inc.
	(#)	(%)	(#)	(%)	(#)	(%)	(#) (3)	(%)
Beneficial Owners of More Than 5% of Units:
Delek US Holdings, Inc. (4)	15,294,046	62.7	—	n/a	497,604	100.0	n/a	n/a
Advisory Research Inc. (5)	1,643,562	6.7	—	n/a	—	n/a	n/a	n/a
Directors, Director Nominees and NEOs:
Ezra Uzi Yemin (6)	261,570	*	—	n/a	—	n/a	368,367	*
Charles Brown	10,919	*	—	n/a	—	n/a	—	n/a
Mark Baker Cox	29,626	*	—	n/a	—	n/a	39,000	*
Francis C. D'Andrea	4,768	*	—	n/a	—	n/a	—	n/a
Eric Gadd	8,494	*	—	n/a	—	n/a	—	n/a
Assi Ginzburg (7)	16,510	*	—	n/a	—	n/a	33,872	*
Frederec Green (8)	68,552	*	—	n/a	—	n/a	78,421	*
Ron W. Haddock	—	*	—	n/a	—	n/a	—	n/a
Reuven Spiegel	6,494	*	—	n/a	—	n/a	—	n/a
Kevin Kremke	—	*	—	n/a	—	n/a	—	n/a
Melissa Buhrig	—	*	—	n/a	—	n/a	—	n/a
Alan P. Moret	—	*	—	n/a	—	n/a	—	n/a
Dan Gordon	2,181	*	—	n/a	—	n/a	15,498	*
All directors, all director nominees, all NEOs and all executive officers as a group (13 persons)	409,114	1.7					535,158	*

* Less than 1% of our issued and outstanding common units of Delek Logistics Partners, LP or issued and outstanding shares of Delek US Holdings, Inc. Common Stock, as applicable.

⁽¹⁾  Unless otherwise indicated, the address for all beneficial owners is 7102 Commerce Way, Brentwood, Tennessee 37027.

⁽²⁾  For purposes of this table, a person is deemed to have “beneficial ownership” of any securities when such person has the right to acquire them within 60 days after the Measurement Date. The percentage of our units beneficially owned is based on a total of 24,382,633 common units representing limited partner interests and 497,604 general partner units issued and outstanding on the Measurement Date. The percentage ownership of Delek US Holdings, Inc. Common Stock is based on a total of 83,919,132 shares issued and outstanding shares on the Measurement Date (excluding securities held by or for the account of the registrant or its subsidiaries). For purposes of computing the percentage of outstanding securities held by each person named above, any securities which such person has the right to acquire within 60 days after the Measurement Date are deemed to be outstanding but are not deemed to be outstanding for the purpose of computing the percentage ownership of any other person.

⁽³⁾  For non-qualified stock options (“NQSOs”) and restricted stock units (“RSUs”) under the Delek US Holdings, Inc. 2006 Long-Term Incentive Plan, or 2016 Long-Term Incentive Plan, we report shares equal to the number of NQSOs or RSUs that are vested or that will vest within 60 days of the Measurement Date. For stock appreciation rights (“SARs”) under the Delek US Holdings, Inc. 2006 Long-Term Incentive Plan, or 2016 Long-Term Incentive Plan, we report the shares that would be delivered upon exercise of SARs that are vested or that will vest within 60 days of the Measurement Date (which is calculated by multiplying the number of SARs by the difference between the $33.97 fair market value of Delek US Holdings, Inc. Common Stock on the Measurement Date and the exercise price divided by $33.97).

⁽⁴⁾  Subsidiaries of Delek US Holdings, Inc. hold the common units and general partner units. Lion Oil Company and Delek Marketing & Supply, LLC directly hold 12,611,465 and 2,682,581 common units, respectively. Delek Logistics GP, LLC directly holds all general partner units. Delek US Holdings, Inc. is the ultimate parent of each of these entities and may, therefore, be deemed to beneficially own the units held by each such entity. Delek US Holdings, Inc. files information with, or furnishes information to, the United States Securities and Exchange Commission (the "SEC") pursuant to the information requirements of the Securities Exchange Act of 1934, as amended.

⁽⁵⁾  According to a Schedule 13G/A filed with the SEC on February 13, 2017 by Advisory Research Inc. with an address of 180 North Stetson Avenue, Suite 5500, Chicago, Illinois 60601 and Piper Jaffray Companies with an address of 800 Nicollet Mall, Suite 800, Minneapolis, Minnesota 55402. The Schedule 13G/A reports that Advisory Research Inc. has sole voting power with respect to 1,639,937 of the reported units and sole dispositive power with respect to all of the reported units and Piper Jaffray Companies has shared voting power with respect to 1,639,937 of the reported units and shared dispositive power with respect to all of the reported units.

⁽⁶⁾  33,500 of our units and 106,802 shares of Delek US Holdings, Inc. Common Stock are held of record by Yemin Investments, L.P., a limited partnership of which Mr. Yemin is the sole general partner. Delek US Holdings, Inc. Common Stock includes 11,654 RSUs that will vest within 60 days of the Measurement Date and 21,261 performance-vesting RSUs for completed performance periods that will vest within 60 days of the Measurement Date.

⁽⁷⁾  Delek US Holdings, Inc. Common Stock includes 8,033 RSUs that will vest within 60 days of the Measurement Date.

⁽⁸⁾  Delek US Holdings, Inc. Common Stock includes 5,326 RSUs that will vest within 60 days of the Measurement Date.

EQUITY COMPENSATION PLAN INFORMATION

The following table provides certain information as of December 31, 2017 regarding our general partner's equity compensation plans.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)	(b)	(c)
Equity compensation plans approved by security holders	546,784	N/A	123,031
Equity compensation plans not approved by security holders	—	N/A	—
TOTAL	546,784	N/A	123,031

(a) The amounts in column (a) of this table reflect only phantom units that have been granted under the LTIP. No Awards (as defined under the LTIP) have been made other than the phantom units, each of which represent rights to receive (upon vesting and payout) one common unit in the Partnership or an amount of cash equal to the fair market value of such unit. These phantom units vest over one- to five-year service periods from the date of grant.

(b) Column (b) of this table is not applicable because phantom units do not have an exercise price.

(c) The LTIP was adopted by the Delek Logistics GP, LLC in connection with the closing of our Offering and provides for the making of certain awards, including common units, restricted units, phantom units, unit appreciation rights and distribution equivalent rights. For information about the LTIP, which did not require approval by our limited partners, refer to Item 11 of this Annual Report on Form 10-K.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTORINDEPENDENCE

The information required by Item 407(a) of Regulation S-K is included in Item 10. Directors, Executive Officers and Corporate Governance above.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

As of February 26, 2018, Delek owned 15,294,046 common units and 497,604 general partner units, as well as incentive distribution rights, which collectively represents a 63.5% ownership interest in the Partnership. Certain transactions with Delek and its affiliated entities are considered to be related party transactions under Item 404 of Regulation S-K because Delek and its affiliates, including our general partner, own more than five percent of our equity interests. In addition, Messrs. Yemin, Ginzburg, Kremke, Green, Gordon, Serff and Soreq and Ms. Buhrig serve as executive officers of both Delek and our general partner.

Distributions and Payments to Delek and Our General Partner

Our Partnership Agreement generally requires us to make quarterly cash distributions of 98% of our "available cash" to limited partners, including Delek, and 2.0% to our general partner (assuming it makes any capital contributions necessary to maintain its 2.0% interest in us). In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, the general partner may be entitled to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target distribution level. Our distribution made for the quarter ended December 31, 2017 was made above the highest target distribution level. During 2017, we made cash distributions totaling $86.2 million to our unitholders, of which $60.1 million was paid to Delek and our general partner.

Acquisitions

On February 26, 2018, a definitive agreement was entered into between the Partnership and Delek for the Partnership to acquire certain logistics assets primarily located adjacent to Delek's Big Spring, Texas refinery for $315.0 million. In addition, the parties expect to enter into a new wholesale marketing agreement, whereby the Partnership will market certain finished products produced at the Big Spring refinery to various branded and unbranded customers in return for a marketing fee. The Partnership and various of their subsidiaries also expect

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to enter into and amend certain existing contracts, such as a new throughput and tankage agreement for the Big Spring Logistics Assets. The transaction and related agreements are to be approved by the Conflicts Committee of Delek Logistics’ general partner. This transaction is described in greater detail in Note 21 to our consolidated financial statements included in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.

Commercial Agreements, Omnibus Agreement and Operations and Management Services Agreement

We have entered into a number of long-term, fee-based commercial agreements with Delek under which we provide various services, including crude oil gathering and crude oil, intermediate and refined products transportation and storage services, and marketing, terminalling and offloading services to Delek, and Delek commits to minimum monthly throughput volumes of crude oil, intermediate and refined products. See Note 4 to the consolidated financial statements in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K, for a discussion of our material commercial agreements with Delek. The amounts paid under those agreements and other non-contractual arrangements with Delek during 2017 are as follows:

• Delek, directly or indirectly, paid us approximately $2.1 million pursuant to the Memphis terminalling agreement and $1.2 million for terminalling services at our Nashville, Tennessee terminal;

• Delek paid us approximately $9.3 million pursuant to the East Texas Crude Logistics System pipeline and tankage agreement;

• Delek paid us approximately $20.4 million pursuant to the East Texas marketing agreement;

• Delek paid us approximately $3.6 million pursuant to the amended and restated services agreement for the Big Sandy terminal and pipeline;

• Delek paid us approximately $20.3 million pursuant to the Tyler Terminal and Tank Assets Throughput and Tankage Agreement;

• Delek, directly or indirectly, paid us approximately $2.0 million pursuant to the North Little Rock terminalling services agreement;

• Delek, directly or indirectly, paid us approximately $19.5 million pursuant to the El Dorado Terminal and Tank Assets Throughput and Tankage Agreement;

• Delek paid us approximately $4.3 million related to revenue earned on our Greenville-Mount Pleasant Assets;

• Delek paid us approximately $10.8 million related to revenue earned on trucking services;

• Delek paid us approximately $6.1 million related to the El Dorado Rail Offloading Racks; and

• Delek paid us approximately $2.0 million related to the Tyler Crude Tank.

For a discussion of a third party's involvement in certain of these agreements, see Item 1. "Business—Commercial Agreements—Delek's Crude Oil and Refined Products Supply and Offtake Arrangement."

Omnibus Agreement. The Omnibus Agreement (as defined in Note 4 to our consolidated financial statements) governs a number of important aspects of the Partnership’s business relationship with Delek. For a more extensive summary of this agreement and its amendment history, see Item 1, “Business—Commercial Agreements—Other Agreements with Delek.” The Omnibus Agreement addresses, among other things, the following matters:

• an agreement whereby Delek will not compete with us under certain circumstances;

• our right of first offer to acquire certain of Delek's logistics assets, including certain terminals, storage facilities and other related assets located at the Tyler and El Dorado Refineries and, under specified circumstances, logistics and marketing assets that Delek may acquire or construct in the future;

• Delek's right of first refusal to purchase our assets that serve its refineries;

• our obligation to pay an annual fee to Delek, currently in the amount of $3.7 million, for Delek's provision of centralized corporate services, including executive management services of Delek employees who devote less than 50% of their time to our business, financial and administrative services, information technology services, legal services, health, safety and environmental services, human resource services, and insurance administration;

• Delek's reimbursement to us for certain operating expenses and certain maintenance capital expenditures and Delek's indemnification of us for certain matters, including environmental, title and tax matters;

• reimbursement to us for certain designated periods of time related to the date of acquisition of the relevant asset for any operating expenses in excess of certain thresholds per year that we incur for inspections, maintenance and repairs to any of the storage tanks contributed to us by Delek that are necessary to comply with the DOT pipeline integrity rules and certain API storage tank standards; and

• reimbursement to us for certain designated periods of time related to the date of acquisition of the relevant asset for all non-discretionary maintenance capital expenditures, other than those required to comply with applicable environmental laws and regulations, in excess of certain thresholds for such 12-month period and per year that we make with respect to the assets contributed to us by Delek for which we have not been reimbursed as described above.

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Pursuant to the terms of the Omnibus Agreement, we paid Delek or our general partner approximately $4.0 million and $21.7 million during the year ended December 31, 2017 for general corporate and administrative services and operational and management services, respectively. Additionally, we paid Delek $12.1 million for various other operational and general and administrative services.

We were reimbursed $0.3 million pursuant to the Omnibus Agreement in relation to expenses incurred in connection with crude oil releases. We were also reimbursed $3.5 million for certain capital improvements pursuant to the terms of the Omnibus Agreement. In addition, we were reimbursed $0.9 million million for tax related to Delek's refining operations.

Other Related Party Transactions

In addition to the agreements described above, we purchased finished product and bulk biofuels from Delek, totaling $41.5 million and $13.5 million, respectively, during the year ended December 31, 2017. We sold RINs in the amount of approximately $5.6 million to Delek during the year ended December 31, 2017. We also sold $0.8 million of finished product in our west Texas operations to Delek and Alon USA, an equity method investee of Delek prior to the Delek/Alon merger during the year ended December 31, 2017.

We entered into a senior secured revolving credit agreement on November 7, 2012, with Fifth Third Bank, as administrative agent, and a syndicate of lenders. The agreement was amended and restated on July 9, 2013 (the "Amended and Restated Credit Agreement") and was most recently amended and restated on December 30, 2014 (the "Second Amended and Restated Credit Agreement"). The obligations under the Second Amended and Restated Credit Agreement are secured by first priority liens on substantially all of the Partnership's and its U.S. subsidiaries' tangible and intangible assets. Additionally, Delek Marketing & Supply, LLC ("Delek Marketing") provides a limited guaranty of the Partnership's obligations under the Second Amended and Restated Credit Agreement. Delek Marketing's guaranty is (i) limited to an amount equal to the principal amount, plus unpaid and accrued interest, of a promissory note made by Delek US in favor of Delek Marketing (the "Holdings Note") and (ii) secured by Delek Marketing's pledge of the Holdings Note to our lenders under the Second Amended and Restated Credit Agreement. As of December 31, 2017, the principal amount of the Holdings Note was $102.0 million, plus unpaid interest accrued since the issuance date. The Second Amended and Restated Credit Agreement, the guaranty and the transactions related to it are described in greater detail in Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Cash Position and Indebtedness.”

Procedures for Review, Approval or Ratification of Transactions with Related Parties

The Board of Directors of our general partner has adopted a written policy for the review, approval and ratification of transactions with related parties. The Board of Directors reviews this policy annually. For the purposes of this policy, a related party is defined as (i) any director or executive officer of our general partner, (ii) any unitholder owning in excess of 5% of our common units or an affiliate of our general partner, (iii) any immediate family member of an individual of any such person, (iv) any entity in which we have an investment that is accounted for under the equity method of accounting, and (v) any entity that is owned or controlled by someone listed in (i) - (iv) above or any entity in which someone listed in (i) - (iv) above has a substantial ownership interest or control of such entity. A related party transaction under the policy is generally expected to be a transaction in which we are a participant with a related party and which requires disclosure under Item 404 of Regulation S-K, other than transactions that are undertaken pursuant to existing agreements and the ongoing performance of which meet certain prior filing or approval requirements. Transactions that are otherwise resolved under Section 7.9 of the Partnership Agreement are not required to be reviewed or approved under the policy.

Subject to certain exceptions, the policy requires that related party transactions, as defined by the policy, be approved by the Board of Directors of the general partner or an authorized committee of the Board of Directors, subject to the guidelines of the policy. Pursuant to the policy, the Conflicts Committee of the Board of Directors of our general partner is generally considered the best suited to review related party transactions and has been authorized by the Board of Directors to do so. If a related party transaction, that would otherwise require approval under the policy, is not approved prior to entry into such transaction, management may enter into such transaction, subject to ratification by the Board or an authorized committee of the Board.

The policy further sets forth certain categories of transactions between the Partnership and its subsidiaries on one hand and Delek and its subsidiaries on the other hand that are deemed to be approved by the Board of Directors and are therefore able to be effected by management of the general partner under the relevant general authorization policies and procedures and after taking into account all relevant facts and circumstances. Additionally, the policy effectively requires all related party transactions that (i) involve the purchase and sale of products or services that are effected at either (x) cost (including, when relevant, a nominal fee for services) or (y) the then-prevailing market prices that we would pay or charge to third parties ("Market Based Transactions") undertaken outside the ordinary course of business and involve an aggregate amount of more than $2.5 million annually or (ii) are not Market Based Transactions and are undertaken outside the ordinary course of business, or (iii) are not Market Based Transactions and are undertaken within the ordinary course of business and involve an aggregate amount of more than $2.5 million annually be approved by the Board of Directors or an authorized committee thereof. Pursuant to the policy, the Conflicts Committee is generally the best suited to review these transactions and it is expected they will be the committee that does so.

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The Board of Directors of our general partner has also adopted a written code of business conduct and ethics, under which a director or officer of the general partner or of any of our subsidiaries would be expected to bring to the attention of the Audit Committee of the Board of Directors of the general partner or the general partner's General Counsel, any conflict or potential conflict of interest that may arise between such party, on the one hand, and us, on the other hand.

ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit fees. Audit fees of $709,573 and $631,199 paid for the services of Ernst & Young LLP during fiscal years 2017 and 2016, respectively, include services related to the audits of our consolidated financial statements and internal controls over financial reporting, reviews of our quarterly condensed consolidated financial statements and audit services provided in connection with acquisitions and investments and regulatory filings. Fees and expenses are for services in connection with the audit of our fiscal years ended December 31, 2017 and December 31, 2016, regardless of when the fees and expenses were paid.

Audit-related fees. Audit-related fees of $70,300 paid for the services of Ernst & Young LLP during fiscal year 2016 include services related to agreed upon procedures for us and our subsidiaries related to acquisition due diligence services. No audit-related fees were paid in 2017.

Tax Fees and All Other Fees. No tax fees or other fees were paid for the services of Ernst & Young LLP during fiscal years 2017 and 2016.

The Audit Committee has considered and determined that the provision of non-audit services by our independent registered public accounting firm is compatible with maintaining auditor independence.

Pre-Approval Policies and Procedures. In general, all engagements performed by our independent registered public accounting firm, whether for auditing or non-auditing services, must be pre-approved by the Audit Committee. During the years ended December 31, 2017 and 2016, all of the services performed for us by Ernst & Young LLP were pre-approved by the Audit Committee.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Certain Documents Filed as Part of this Annual Report on Form 10-K:

1. Financial Statements. The accompanying Index to Financial Statements and Schedule on page F-1 of this Annual Report on Form 10-K is provided in response to this item.

2. List of Financial Statement Schedules. All schedules are omitted because the required information is either not present, not present in material amounts or included within the Consolidated Financial Statements.

3. Exhibits - See below.

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EXHIBITS

Exhibit No.		Description
1.1		Purchase Agreement, dated as of May 18, 2017, among the Partnership, Finance Corp., the Guarantors named therein and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the Initial Purchasers named therein (incorporated by reference to Exhibit 1.1 to the Partnership’s Form 8-K filed on May 24, 2017).
3.1		Certificate of Limited Partnership of Delek Logistics Partners, LP (incorporated by reference to Exhibit 3.1 to the Partnership's Form S-1 (File No. 333-182631) filed on July 12, 2012).
3.2(a)		First Amended and Restated Agreement of Limited Partnership of Delek Logistics Partners, LP, dated November 7, 2012 (incorporated by reference to Exhibit 3.1 to the Partnership's Form 8-K filed on November 7, 2012, SEC File No. 001-35721).
3.2(b)	#	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Delek Logistics Partners, LP, dated February 27, 2018.
3.3		Certificate of Formation of Delek Logistics GP, LLC (incorporated by reference to Exhibit 3.3 to the Partnership's Registration Statement on Form S-1 (File No. 333-182631) filed on July 12, 2012).
3.4		Third Amended and Restated Limited Liability Company Agreement of Delek Logistics GP, LLC, dated as of December 10, 2013 (incorporated by reference to Exhibit 3.1 to the Partnership’s Form 8-K filed on December 13, 2013).
4.1		Indenture, dated as of May 23, 2017, among Delek Logistics, LP, Delek Logistics Finance Corp., the Guarantors named therein and U.S. Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Partnership's Form 8-K filed on May 24, 2017).
4.2		Form of 6.750% Senior Notes due 2025 (incorporated by reference to Exhibit A to Exhibit 4.1 to the Partnership's Form 8-K filed on May 24, 2017).
4.3		Registration Rights Agreement, dated as of May 23, 2017, among Delek Logistics, LP, Delek Logistics Finance Corp., the Guarantors named therein and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the initial purchasers (incorporated by reference to Exhibit 4.3 to the Partnership's Form 8-K filed on May 24, 2017).
10.1	*	Amended and Restated Employment Agreement, dated as of July 8, 2011, by and between Paramount Petroleum Corporation and Alan P. Moret (the “Moret Employment Agreement”) (incorporated by reference to Exhibit 10.1 to Alon USA Energy, Inc.'s Form 8-K filed on July 13, 2011, SEC File No. 001-32567).
10.2	*	First Amendment, dated as of May 12, 2015, by and between Alan P. Moret and Alon USA GP, LLC to the Moret Employment Agreement (incorporated by reference to Exhibit 10.4 to Alon USA Energy, Inc.'s Form 8-K filed on May 15, 2015, SEC File No. 001-32567).
10.3	*	Second Amendment, dated as of July 1, 2017, by and among Alan P. Moret, Alon USA GP, LLC, and Delek US Holdings, Inc. to the Moret Employment Agreement (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on July 10, 2017).
10.4	*#	Executive Employment Agreement, dated as of February 27, 2018, by and between Alan P. Moret and Delek US Energy, Inc.
10.5	*	Executive Employment Agreement, effective October 24, 2017, by and between Delek US Holdings, Inc. and Melissa M. Buhrig (incorporated by reference to Exhibit 10.1 to the Partnership's Form 8-K filed on October 30, 2017.
10.6	++	Marketing Agreement, dated November 7, 2012, by and between Delek Refining, Ltd. and Delek Marketing & Supply, LP (incorporated by reference to Exhibit 10.6 to the Partnership's Form 8-K filed on November 7, 2012, SEC File No. 001-35721).
10.7		First Amendment to Marketing Agreement, dated July 26, 2013, by and between Delek Refining, Ltd. and Delek Marketing & Supply, LP (incorporated by reference to Exhibit 10.1 to the Partnership's Form 10-Q filed on November 3, 2016).
10.8		Second Amendment to Marketing Agreement, dated as of December 19, 2016, but effective as of October 1, 2016, by and between Delek Refining, Ltd. and Delek Marketing & Supply, LP (incorporated by reference to Exhibit 10.1 to the Partnership's Form 10-K filed on February 28, 2017).

10.9		Throughput and Tankage Agreement (El Dorado Terminal and Tankage), dated as of February 10, 2014, by and among Lion Oil Company and Delek Logistics Operating, LLC, and for limited purposes, J. Aron & Company (incorporated by reference to Exhibit 10.3 to the Partnership’s Form 8-K filed on February 14, 2014).
10.10		Amendment to Throughput and Tankage Agreement (El Dorado Terminal and Tankage), dated as of July 22, 2016, but effective as of February 11, 2014, by and between Lion Oil Company and Delek Logistics Operating, LLC (incorporated by reference to Exhibit 10.1 to the Partnership's Form 10-Q filed on August 5, 2016).
10.11	*	General Terms and Conditions for Phantom Unit Awards under the Delek Logistics GP, LLC 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Partnership's Form 10-Q filed on August 5, 2016).
10.12		Third Amended and Restated Omnibus Agreement, dated as of March 31, 2015, by and among Delek US Holdings, Inc., Lion Oil Company, Delek Logistics Operating, LLC, Delek Marketing & Supply, LP, Delek Refining, Ltd., Delek Logistics Partners, LP, Paline Pipeline Company, LLC, SALA Gathering Systems, LLC, Magnolia Pipeline Company, LLC, El Dorado Pipeline Company, LLC, Delek Crude Logistics, LLC, Delek Marketing-Big Sandy, LLC, DKL Transportation, LLC and Delek Logistics GP, LLC (incorporated by reference to Exhibit 10.3 to the Partnership’s Form 8-K filed on April 6, 2015).
10.13		First Amendment to Third Amended and Restated Omnibus Agreement, dated as of August 3, 2015, by and among Delek US Holdings, Inc., Lion Oil Company, Delek Logistics Operating, LLC, Delek Marketing & Supply, LP, Delek Refining, Ltd., Delek Logistics Partners, LP, Paline Pipeline Company, LLC, SALA Gathering Systems, LLC, Magnolia Pipeline Company, LLC, El Dorado Pipeline Company, LLC, Delek Crude Logistics, LLC, Delek Marketing-Big Sandy, LLC, DKL Transportation, LLC and Delek Logistics GP, LLC (incorporated by reference to Exhibit 10.2 to the Partnership’s Form 10-Q filed on August 6, 2015).
10.14		Second Amended and Restated Credit Agreement, dated as of December 30, 2014, by and among Delek Logistics Partners, LP, Delek Logistics Operating, LLC, Delek Marketing GP, LLC, Delek Marketing & Supply, LP, Delek Crude Logistics, LLC, Delek Marketing-Big Sandy, LLC, Magnolia Pipeline Company, LLC, El Dorado Pipeline Company, LLC, SALA Gathering Systems, LLC, Paline Pipeline Company, LLC, DKL Transportation, LLC and Fifth Third Bank, as administrative agent, and a syndicate of lenders (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on January 6, 2015).
10.15		Contribution, Conveyance and Assumption Agreement, dated November 7, 2012, by and among Delek Logistics Partners, LP, Delek Logistics GP, LLC, Delek Logistics Operating, LLC, Delek Crude Logistics, LLC, Delek US Holdings, Inc., Delek Marketing & Supply, LLC, Delek Marketing and Supply, LP, Lion Oil Company and Delek Logistics Services Company (incorporated by reference to Exhibit 10.4 to the Partnership's Form 8-K filed on November 7, 2012, SEC File No. 001-35721).
10.16	*	Delek Logistics GP, LLC 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to the Partnership's Form 8-K filed on November 7, 2012, SEC File No. 001-35721).
10.17	*	Form of Phantom Unit Agreement for Directors under the Delek Logistics GP, LLC 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 10-Q filed on August 6, 2015).
10.18		Pipelines and Tankage Agreement (East Texas Crude Logistics System), dated November 7, 2012, by and between Delek Refining, Ltd. and Delek Crude Logistics, LLC (incorporated by reference to Exhibit 10.7 to the Partnership's Form 8-K filed on November 7, 2012, SEC File No. 001-35721).
10.19		Amended and Restated Services Agreement (Big Sandy Terminal and Pipeline), dated July 25, 2013, by and between Delek Refining, Ltd. and Delek Marketing-Big Sandy, LLC (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K/A filed on July 31, 2013).
10.20		Pipelines and Storage Facilities Agreement, dated November 7, 2012, by and among Lion Oil Company, Delek Logistics Partners, LP, SALA Gathering Systems, LLC, El Dorado Pipeline Company, LLC, Magnolia Pipeline Company, LLC and J. Aron & Company (incorporated by reference to Exhibit 10.9 to the Partnership's Form 8-K filed on November 7, 2012, SEC File No. 001-35721).
10.21	*	Form of Director Phantom Unit Award (incorporated by reference to Exhibit 10.6 to the Partnership's Amendment No. 3 to Registration Statement on Form S-1 (File No. 333-182631), filed on October 16, 2012).
10.22	*	Form of Employee Phantom Unit Award (incorporated by reference to Exhibit 10.7 to the Partnership's Amendment No. 3 to Registration Statement on Form S-1 (File No. 333-182631), filed on October 16, 2012).
10.23	*	Form of Indemnification Agreement for Directors and Officers of Delek Logistics GP, LLC (incorporated by reference to Exhibit 10.13 to the Partnership's Amendment No. 4 to Registration Statement on Form S-1 (File No. 333-182631), filed on October 24, 2012).
10.24		Asset Purchase Agreement (Tyler Terminal and Tankage), dated July 26, 2013, by and between Delek Marketing & Supply, LP and Delek Refining, Ltd. (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on August 1, 2013).
10.25		Throughput and Tankage Agreement (Tyler Terminal and Tankage), dated July 26, 2013, by and between Delek Marketing & Supply, LP and Delek Refining, Ltd. (incorporated by reference to Exhibit 10.3 to the Partnership’s Form 8-K filed on August 1, 2013).

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10.26		Amended and Restated Site Services Agreement (Tyler Terminal and Tankage), dated March 31, 2015, by and between Delek Marketing & Supply, LP and Delek Refining, Ltd. (incorporated by reference to Exhibit 10.4 to the Partnership’s Form 10-Q filed on May 8, 2015).
10.27		Asset Purchase Agreement (El Dorado Terminal and Tankage), dated as of February 10, 2014, by and between Lion Oil Company and Delek Logistics Operating, LLC (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on February 14, 2014).
10.28		Amended and Restated Site Services Agreement (El Dorado Terminal and Tankage), dated as of March 31, 2015, by and between Lion Oil Company and Delek Logistics Operating, LLC (incorporated by reference to Exhibit 10.5 to the Partnership’s Form 10-Q filed on May 8, 2015).
10.29		Asset Purchase Agreement (El Dorado Rail Offloading Facility), dated as of March 31, 2015, among Lion Oil Company, Lion Oil Trading & Transportation, LLC, Delek US Holdings, Inc. and Delek Logistics Operating, LLC (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on April 6, 2015).
10.30		Throughput Agreement (El Dorado Rail Offloading Facility), dated as of March 31, 2015, among Lion Oil Company, Lion Oil Trading & Transportation, LLC and Delek Logistics Operating, LLC (incorporated by reference to Exhibit 10.2 to the Partnership’s Form 8-K filed on April 6, 2015).
10.31	++	First Amended and Restated Limited Liability Company Agreement of Rangeland Rio Pipeline, LLC, dated March 20, 2015, by and between Rangeland Energy II, LLC and DKL RIO, LLC (incorporated by reference to Exhibit 10.6 to the Partnership’s Form 10-Q filed on May 8, 2015).
10.32	++	Amended and Restated Limited Liability Company Agreement of Caddo Pipeline LLC, dated March 20, 2015, by and between Plains Pipeline, L.P. and DKL Caddo, LLC (incorporated by reference to Exhibit 10.7 to the Partnership’s Form 10-Q filed on May 8, 2015).
21.1	#	Subsidiaries of Registrant.
23.1	#	Consent of Independent Registered Public Accounting Firm (Ernst & Young LLP).
24.1	#	Power of Attorney.
31.1	#	Certification of Delek Logistics GP, LLC's Chief Executive Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act of 1934, as amended.
31.2	#	Certification of Delek Logistics GP, LLC's Chief Financial Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act of 1934, as amended.
32.1	##	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	##	Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	^	The following materials from Delek Logistics Partners, LP's Annual Report on Form 10-K for the annual period ended December 31, 2017, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of December 31, 2017 and 2016; (ii) Consolidated Statements of Income and Comprehensive Income for the years ended December 31, 2017, 2016 and 2015; (iii) Consolidated Statements of Changes in Partners’ Equity for the years ended December 31, 2017, 2016 and 2015; (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015; and (v) Notes to Consolidated Financial Statements.
*		Management contract or compensatory plan or arrangement.
#		Filed herewith.
##		Furnished herewith.
++		Confidential treatment has been requested and granted with respect to certain portions of this exhibit pursuant to Rule 24b-2 of the Securities Exchange Act of 1934. Omitted portions have been filed separately with the Securities and Exchange Commission.
^		Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files in Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

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Delek Logistics Partners, LP

Consolidated Financial Statements

As of December 31, 2017 and 2016 and

For Each of the Three Years Ended December 31, 2017, 2016 and 2015

INDEX TO FINANCIAL STATEMENTS

Reports of Independent Registered Public Accounting Firm	F-2
Audited Financial Statements:
Consolidated Balance Sheets	F-4
Consolidated Statements of Income and Comprehensive Income	F-5
Consolidated Statements of Partners' Equity (Deficit)	F-6
Consolidated Statements of Cash Flows	F-7
Notes to Consolidated Financial Statements	F-8

All other financial schedules are not required under related instructions, or are inapplicable and therefore have been omitted.

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors of Delek Logistics GP, LLC and

Unitholders of Delek Logistics Partners, LP

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Delek Logistics Partners, LP (the Partnership) as of December 31, 2017 and 2016, and the related consolidated statements of income and comprehensive income, partners' equity (deficit) and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the consolidated financial position of the Partnership at December 31, 2017 and 2016, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 28, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2012.

Nashville, Tennessee

February 28, 2018

F-2

Report of Independent Registered Public Accounting Firm

The Board of Directors of Delek Logistics GP, LLC and

Unitholders of Delek Logistics Partners, LP

Opinion on Internal Control over Financial Reporting

We have audited Delek Logistics Partners, LP’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Delek Logistics Partners, LP (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of Delek Logistics Partners, LP as of December 31, 2017 and 2016, the related consolidated statements of income and comprehensive income, partners’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and our report dated February 28, 2018 expressed an unqualified opinion thereon. 

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definitions and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Nashville, Tennessee

February 28, 2018

F-3

Delek Logistics Partners, LP

Consolidated Balance Sheets

(in thousands, except unit and per unit data)

	December 31,
	2017			2016
ASSETS
Current assets:
Cash and cash equivalents	$	4,675		$	59
Accounts receivable	23,013			19,202
Accounts receivable from related parties	1,124			2,834
Inventory	20,855			8,875
Other current assets	783			1,071
Total current assets	50,450			32,041
Property, plant and equipment:
Property, plant and equipment	367,179			342,407
Less: accumulated depreciation	(112,111		)	(91,378		)
Property, plant and equipment, net	255,068			251,029
Equity method investments	106,465			101,080
Goodwill	12,203			12,203
Intangible assets, net	15,917			14,420
Other non-current assets	3,427			4,774
Total assets	$	443,530		$	415,547
LIABILITIES AND DEFICIT
Current liabilities:
Accounts payable	$	19,147		$	10,853
Excise and other taxes payable	4,700			4,841
Tank inspection liabilities	902			1,013
Pipeline release liabilities	1,000			1,097
Accrued expenses and other current liabilities	6,033			2,925
Total current liabilities	31,782			20,729
Non-current liabilities:
Long-term debt	422,649			392,600
Asset retirement obligations	4,064			3,772
Other non-current liabilities	14,260			11,730
Total non-current liabilities	440,973			408,102
Deficit:
Common unitholders - public; 9,088,587 units issued and outstanding at December 31, 2017 (9,263,415 at December 31, 2016)	174,378			188,013
Common unitholders - Delek; 15,294,046 units issued and outstanding at December 31, 2017 (15,065,192 at December 31, 2016)	(197,206		)	(195,076		)
General partner - 497,604 units issued and outstanding at December 31, 2017 (496,502 at December 31, 2016)	(6,397		)	(6,221		)
Total deficit	(29,225		)	(13,284		)
Total liabilities and deficit	$	443,530		$	415,547

See accompanying notes to the consolidated financial statements

F-4

Delek Logistics Partners, LP

Consolidated Statements of Income and Comprehensive Income

(In thousands, except unit and per unit data)

	Year Ended December 31,
	2017			2016			2015
Net sales:
Affiliate (1)	$	156,280		$	149,564		$	152,564
Third party	381,795			298,495			437,105
Net sales	538,075			448,059			589,669
Operating costs and expenses:
Cost of goods sold	372,890			302,158			436,304
Operating expenses	43,274			37,198			44,923
General and administrative expenses	11,840			10,256			11,384
Depreciation and amortization	21,914			20,813			19,692
(Gain) loss on asset disposals	(20		)	(16		)	104
Total operating costs and expenses	449,898			370,409			512,407
Operating income	88,177			77,650			77,262
Interest expense, net	23,944			13,587			10,658
(Income) loss from equity method investments	(4,953		)	1,178			588
Other income, net	(1		)	—			—
Total non-operating expenses	18,990			14,765			11,246
Income before income tax (benefit) expense	69,187			62,885			66,016
Income tax (benefit) expense	(222		)	81			(195		)
Net income	69,409			62,804			66,211
Less: loss attributable to Predecessors	—			—			(637		)
Net income attributable to partners	69,409			$	62,804		$	66,848
Comprehensive income attributable to partners	$	69,409		$	62,804		$	66,848
Less: General partner's interest in net income, including incentive distribution rights	18,429			12,193			5,163
Limited partners' interest in net income	$	50,980		$	50,611		$	61,685
Net income per limited partner unit (2):
Common units - (basic)	$	2.09		$	2.08		$	2.55
Common units - (diluted)	$	2.09		$	2.07		$	2.52
Subordinated units - Delek (basic and diluted)	$	—		$	2.19		$	2.54
Weighted average limited partner units outstanding (2):
Common units - (basic)	24,348,063			22,490,264			12,237,154
Common units - (diluted)	24,376,972			22,558,717			12,356,914
Subordinated units - Delek (basic and diluted)	—			1,803,167			11,999,258
Cash distributions per limited partner unit	$	2.835		$	2.575		$	2.240

⁽¹⁾ See Note 4 for a description of our material affiliate revenue transactions.

⁽²⁾ We base our calculation of net income per unit on the weighted-average number of common and subordinated limited partner units outstanding during the period. The weighted-average number of common and subordinated units reflect the conversion of the subordinated units to common units on February 25, 2016. See Notes 5 and 12 for further discussion.

See accompanying notes to the consolidated financial statements

F-5

Delek Logistics Partners, LP

Consolidated Statements of Partners' Equity (Deficit)

				Partnership
	Equity of Predecessors			Common - Public			Common - Delek			Subordinated - Delek			General Partner - Delek			Total
	(In thousands)
Balance at December 31, 2014	$	19,726		$	194,737		$	(241,112	)	$	73,515		$	(7,085	)	$	39,781
Sponsor contributions of equity to the Predecessor	115			—			—			—			—			115
Loss attributable to Predecessor	(637		)	—			—			—			—			(637		)
Allocation of net assets acquired by the unitholders	(19,204		)	—			18,820			—			384			—
Cash distributions (1)	—			(20,755		)	(66,698		)	(25,919		)	(5,156		)	(118,528		)
Sponsorship contribution of fixed assets	—			—			573			—			11			584
Net income attributable to partners	—			24,039			7,121			30,525			5,163			66,848
Unit-based compensation	—			740			219			940			(1,493		)	406
Other	—			(360		)	249			(460		)	984			413
Balance at December 31, 2015	—			198,401			(280,828		)	78,601			(7,192		)	(11,018		)
Sponsor contributions of equity to the Predecessor	—			—			—			—			—			—
Loss attributable to Predecessor	—			—			—			—			—			—
Allocation of net assets acquired by the unitholders	—			—			—			—			—			—
Cash distributions (2)	—			(23,847		)	(25,271		)	(11,503		)	(10,244		)	(70,865		)
Sponsorship contribution of fixed assets	—			—			5,063			—			104			5,167
Net income attributable to partners	—			19,667			27,002			3,942			12,193			62,804
Unit-based compensation	—			664			1,046			—			(1,111		)	599
Subordinated unit conversion	—			—			71,040			(71,040		)	—			—
Delek unit repurchases from public	—			(6,872		)	6,872			—			—			—
Other	—			—			—			—			29			29
Balance at December 31, 2016	—			188,013			(195,076		)	—			(6,221		)	(13,284		)
Cash distributions (3)	—			(25,978		)	(42,490		)	—			(17,691		)	(86,159		)
Sponsor contribution of fixed assets	—			—			65			—			2			67
Net income attributable to partners	—			19,015			31,965			—			18,429			69,409
Unit-based compensation	—			619			1,039			—			(937		)	721
Delek unit repurchases from public	—			(7,291		)	7,291			—			—			—
Other	—			—			—			—			21			21
Balance at December 31, 2017	$	—		$	174,378		$	(197,206	)	$	—		$	(6,397	)	$	(29,225	)

⁽¹⁾ Cash distributions include $61.9 million in cash payments for the El Dorado Rail Offloading Racks Acquisition and the Tyler Crude Tank Acquisition. As an entity under common control with Delek, we record the assets that we acquire from Delek on our balance sheet at Delek's historical book basis instead of fair value. Additionally, any excess of cash paid over the historical book basis of the assets acquired from Delek is recorded within equity. As a result of the El Dorado Rail Offloading Racks Acquisition and the Tyler Crude Tank Acquisition, our equity balance decreased $42.7 million during the year ended December 31, 2015. Distributions also include $0.4 million related to distribution equivalents on vested phantom units.

⁽²⁾ Cash distributions include $0.3 million related to distribution equivalents on vested phantom units.

⁽³⁾ Cash distributions include $0.5 million related to distribution equivalents on vested phantom units.

See accompanying notes to the consolidated financial statements

F-6

Delek Logistics Partners, LP - Consolidated Statements of Cash Flows

(in thousands)

	Year Ended December 31,
	2017			2016			2015
Cash flows from operating activities:
Net income	$	69,409		$	62,804		$	66,211
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	21,914			20,813			19,692
Amortization of deferred revenue	(1,234		)	(1,085		)	(596		)
Amortization of deferred financing costs and debt discount	2,048			1,460			1,460
Accretion of asset retirement obligations	292			266			251
Loss (gain) on asset disposals	(20		)	(16		)	104
Deferred income taxes	(111		)	(173		)	14
(Income) loss from equity method investments	(4,953		)	1,178			588
Dividends from equity method investments	3,099			—			—
Unit-based compensation expense	721			599			406
Changes in assets and liabilities:
Accounts receivable	(3,811		)	15,847			(7,197		)
Inventories and other current assets	(11,692		)	2,045			(907		)
Accounts payable and other current liabilities	10,859			3,551			(13,734		)
Accounts receivable/payable to related parties	1,682			(6,983		)	1,737
Non-current assets and liabilities, net	(500		)	401			(5		)
Net cash provided by operating activities	87,703			100,707			68,024
Cash flows from investing activities:
Asset acquisitions	(9,003		)	—			(400		)
Purchases of property, plant and equipment	(18,184		)	(11,287		)	(19,956		)
Proceeds from sales of property, plant and equipment	46			175			1,198
Equity method investments	(3,531		)	(61,580		)	(37,434		)
Net cash used in investing activities	(30,672		)	(72,692		)	(56,592		)
Cash flows from financing activities:
Proceeds from issuance of additional units to maintain 2% General Partner interest	21			29			50
Distributions to general partner	(17,691		)	(10,244		)	(3,918		)
Distributions to common unitholders - public	(25,978		)	(23,847		)	(20,755		)
Distributions to common unitholders - Delek	(42,490		)	(25,271		)	(6,046		)
Distributions to subordinated unitholders - Delek	—			(11,503		)	(25,919		)
Distributions to Delek for acquisitions	—			—			(61,890		)
Proceeds from revolving credit facility	277,100			314,750			396,400
Payments of revolving credit facility	(489,800		)	(273,750		)	(296,550		)
Proceeds from issuance of senior notes	248,112			—			—
Deferred financing costs paid	(5,951		)	—			—
Predecessor division equity contribution	—			—			115
Reimbursement of capital expenditures by Delek	4,262			1,880			5,220
Net cash used in financing activities	(52,415		)	(27,956		)	(13,293		)
Net increase (decrease) in cash and cash equivalents	4,616			59			(1,861		)
Cash and cash equivalents at the beginning of the period	59			—			1,861
Cash and cash equivalents at the end of the period	$	4,675		$	59		$	—

	Year Ended December 31,
	2017		2016		2015
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest	$	19,441	$	12,206	$	9,009
Income taxes	$	60	$	224	$	4
Non-cash investing activities:
Equity method investments	$	—	$	—	$	3,832
Increase in accrued capital expenditures	$	194	$	480	$	2,471
Non-cash financing activities:
Sponsor contribution of fixed assets	$	67	$	5,167	$	584

See accompanying notes to the consolidated financial statements

F-7

Delek Logistics Partners, LP

Notes to Consolidated Financial Statements

1. General

Organization

As used in this report, the terms "Delek Logistics Partners, LP," the "Partnership," "we," "us," or "our" may refer to Delek Logistics Partners, LP, one or more of its consolidated subsidiaries or all of them taken as a whole.

The Partnership is a Delaware limited partnership formed in April 2012 by Old Delek (as defined below) and its subsidiary Delek Logistics GP, LLC, our general partner (our "general partner').

In January 2017, Delek US Holdings, Inc. ("Old Delek") (and various related entities) entered into an Agreement and Plan of Merger with Alon USA Energy, Inc. (NYSE: ALJ) ("Alon USA"), as subsequently amended on February 27 and April 21, 2017 (as so amended, the "Merger Agreement"). The related merger (the "Delek/Alon Merger") was effective July 1, 2017 (the “Effective Time”), resulting in a new post-combination consolidated registrant renamed Delek US Holdings, Inc. (“New Delek”), with Alon USA and Old Delek surviving as wholly-owned subsidiaries. New Delek is the successor issuer to Old Delek and Alon USA pursuant to Rule 12g-3(c) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Unless the context otherwise requires, references in this report to "Delek" refer collectively to Old Delek with respect to periods prior to July 1, 2017, or New Delek, with respect to periods on or after July 1, 2017, and any of Old Delek's or New Delek's, as applicable, subsidiaries, other than the Partnership and its subsidiaries and its general partner.

On March 31, 2015, the Partnership, through its wholly owned subsidiary Delek Logistics Operating, LLC ("OpCo"), acquired from Delek two crude oil rail offloading racks, which are designed to receive up to 25,000 barrels per day (“bpd”) of light crude oil or 12,000 bpd of heavy crude oil, or any combination of the two, delivered by rail to the El Dorado Refinery and related ancillary assets (the “El Dorado Assets”) (such transaction, the "El Dorado Rail Offloading Racks Acquisition").

On March 31, 2015, the Partnership, through its wholly owned subsidiary Delek Marketing & Supply, LP, acquired from Delek a crude oil storage tank ("the Tyler Crude Tank") located adjacent to Delek's Tyler, Texas refinery (the "Tyler Refinery") and certain ancillary assets (collectively, with the Tyler Crude Tank, the "Tyler Assets") (such transaction, the "Tyler Crude Tank Acquisition"). The Tyler Crude Tank has approximately 350,000 barrels of shell capacity and primarily supports the Tyler Refinery. The Tyler Assets, together with the El Dorado Assets, are hereinafter collectively referred to as the "Logistics Assets."

The El Dorado Rail Offloading Racks Acquisition and the Tyler Crude Tank Acquisition are hereinafter collectively referred to as the "Acquisitions from Delek." The Acquisitions from Delek were accounted for as transfers between entities under common control. As entities under common control with Delek, we record the assets that Delek has contributed to us on our balance sheet at Delek's historical basis instead of fair value. Transfers between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. Accordingly, the accompanying financial statements and related notes of the Partnership have been retrospectively adjusted to include, (i) the historical results of the El Dorado Assets, as owned and operated by Delek, for all periods presented through March 31, 2015 (the "El Dorado Assets Predecessor") and (ii) the historical results of the Tyler Assets, as owned and operated by Delek, for all periods presented through March 31, 2015 (the "Tyler Assets Predecessor"). The El Dorado Assets Predecessor, together with the Tyler Assets Predecessor, are hereinafter collectively referred to as our "Predecessors." See Note 3 for further information regarding the Acquisitions from Delek.

Description of Business

The Partnership primarily owns and operates logistics and marketing assets for crude oil and intermediate and refined products. A substantial majority of our existing assets are integral to and dependent on the success of Delek’s refining and marketing operations. We gather, transport and store crude oil and market, wholesale market, distribute, transport and store refined products in select regions of the southeastern United States and west Texas for Delek and third parties.

The Partnership generates revenue by charging fees for gathering, transporting, offloading and storing crude oil and for marketing, wholesale marketing, distributing, transporting and storing refined products. A substantial majority of our contribution margin, which we define as net sales less cost of goods sold and operating expenses, is derived from commercial agreements with Delek with initial terms ranging from five to ten years.

F-8

2.  Accounting Policies

Basis of Presentation

Our consolidated financial statements include the accounts of the Partnership and its subsidiaries as well as our Predecessors. All intercompany accounts and transactions have been eliminated. The financial statements of our Predecessors have been prepared from the separate records maintained by Delek and may not necessarily be indicative of the conditions that would have existed or the results of operations if our Predecessors had been operated as an unaffiliated entity. Our Predecessors did not record all revenues for intercompany gathering, pipeline transportation, terminalling and storage services. Transfers between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. As an entity under common control with Delek, we record the assets that Delek has contributed to us on our balance sheet at Delek's historical basis instead of fair value.

We have evaluated subsequent events through the filing of this Annual Report on Form 10-K. Any material subsequent events that occurred during this time have been properly recognized or disclosed in our financial statements. The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“U.S. GAAP”) and in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Segment Reporting

We are an energy business focused on crude oil, intermediate and refined products pipeline and storage activities and wholesale marketing, terminalling and offloading activities. Management reviews operating results in two reportable segments: (i) pipelines and transportation and (ii) wholesale marketing and terminalling. The pipelines and transportation segment provides crude oil gathering, transportation and storage services to Delek's refining operations and independent third parties. The wholesale marketing and terminalling segment provides marketing, wholesale marketing and terminalling services to Delek's refining operations and independent third parties. 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 its reportable segments based on the segment contribution margin. Segment contribution margin is defined as net sales less cost of goods sold and operating expenses, excluding depreciation and amortization. Segment reporting is more fully discussed in Note 15.

Cash and Cash Equivalents

We maintain cash and cash equivalents in accounts with large, U.S. financial institutions. Any highly liquid investments purchased with an original maturity of three months or less are considered to be cash equivalents.

Accounts Receivable

Accounts receivable primarily consists of trade receivables generated in the ordinary course of business. We perform on-going credit evaluations of our customers and generally do not require collateral on accounts receivable. All accounts receivable amounts are considered to be fully collectible. Accordingly, no allowance for doubtful accounts has been established as of December 31, 2017 and 2016. One third-party customer accounted for approximately 22.0% of the consolidated accounts receivable balance as of December 31, 2017. Two third-party customers accounted for approximately 36.6% of the consolidated accounts receivable balance as of December 31, 2016.

Inventory

Inventory consists of refined products, which are stated at the lower of cost or net realizable value, with cost determined on a first-in, first-out ("FIFO") basis. One third party vendor and Delek accounted for approximately 65.8% and 11.6%, respectively, of our inventory purchases in our wholesale marketing and terminalling segment during the year ended December 31, 2017. Two third party vendors in our wholesale marketing and terminalling segment accounted for approximately 72.0% of our inventory purchases during the year ended December 31, 2016. One third party vendor and Delek accounted for approximately 62.6% and 24.9%, respectively, of our inventory purchases in our wholesale marketing and terminalling segment during the year ended December 31, 2015.

F-9

Property, Plant and Equipment

Assets acquired in conjunction with business acquisitions are recorded at estimated fair market value in accordance with the purchase method of accounting as prescribed in Accounting Standards Codification ("ASC") 805, Business Combinations ("ASC 805"). Other acquisitions of property and equipment are carried at cost. Acquisitions of net assets that do not constitute a business are accounted for by allocating the cost of the acquisition to individual assets acquired and liabilities assumed on relative fair value basis and shall not give rise to goodwill as prescribed in ASC 805.

Betterments, renewals and extraordinary repairs that extend the life of an asset are capitalized. Maintenance and repairs are charged to expense as incurred.

Depreciation is computed using the straight-line method over management’s estimated useful lives of the related assets, except for automotive equipment, which is depreciated using a declining-balance method. The estimated useful lives are as follows:

	Years
Buildings and building improvements	15-40
Pipelines, tanks and terminals	15-40
Asset retirement obligation assets	15-50
Other equipment	3-15

Intangible Assets

Intangible assets consist of a long-term supply contract and indefinite-lived rights of way. We amortize the definite-lived long-term supply contract on a straight-line basis over the estimated useful life of 11.5 years. The amortization expense is included in depreciation and amortization in the accompanying consolidated financial statements.

Property, Plant and Equipment and Intangibles Impairment

Property, plant and equipment and definite life intangibles are evaluated for impairment whenever indicators of impairment exist. In accordance with ASC 360, Property, Plant and Equipment and ASC 350, Intangibles - Goodwill and Other, we evaluate the realizability of these long-lived assets as events occur that might indicate potential impairment. In doing so, we assess whether the carrying amount of the asset is unrecoverable by estimating the sum of the future cash flows expected to result from the asset, undiscounted and without interest charges. If the carrying amount is more than the recoverable amount, an impairment charge must be recognized based on the fair value of the asset.

Goodwill and Potential Impairment

Goodwill in an acquisition represents the excess of the aggregate purchase price over the fair value of the identifiable net assets. Our goodwill is recorded at original fair value and is not amortized. Goodwill is subject to annual assessment to determine if an impairment of value has occurred and we perform this review annually in the fourth quarter. We could also be required to evaluate our goodwill if, prior to our annual assessment, we experience disruptions in our business, have unexpected significant declines in operating results, or sustain a permanent market capitalization decline. If an asset’s carrying amount exceeds its fair value, the impairment assessment leads to the testing of the implied fair value of the asset’s goodwill to its carrying amount. If the implied fair value is less than the carrying amount, a goodwill impairment charge is recorded. Our annual assessment of goodwill did not result in an impairment charge during the years ended December 31, 2017, 2016 or 2015.

Equity Method Investments

For equity investments that are not required to be consolidated under the variable or voting interest model, we evaluate the level of influence we are able to exercise over an entity’s operations to determine whether to use the equity method of accounting. Our judgment regarding the level of control over an equity method investment includes considering key factors such as our ownership interest, participation in policy-making and other significant decisions and material intercompany transactions. Amounts recognized for equity method investments are included in equity method investments in our consolidated balance sheet and adjusted for our shares of the net earnings and losses of the investee and cash distributions, which are separately presented in our consolidated statements of income and comprehensive income and our consolidated statements of cash flows. We evaluate our equity method investments for impairment whenever events or changes in circumstances indicate that the carrying amounts of such investments may be impaired. A loss is recorded in earnings in the current period if a decline in the value of an equity method investment is determined to be other than temporary.

F-10

Derivatives

We record all derivative financial instruments, including forward fuel contracts, at estimated fair value in accordance with the provisions of ASC 815, Derivatives and Hedging ("ASC 815"). Changes in the fair value of the derivative instruments are recognized in operations, unless we elect to apply the hedge accounting treatment permitted under the provisions of ASC 815 allowing such changes to be classified as other comprehensive income for cash flow hedges. We validate the fair value of all derivative financial instruments on a periodic basis, utilizing exchange pricing and/or price index developers, such as Platts or Argus. During the years ended December 31, 2017, 2016 and 2015, we did not elect to apply hedge accounting treatment to our derivative positions and, therefore, all changes in fair value are reflected in the statements of income and comprehensive income.

Our policy under the guidance of ASC 815-10-45, Derivatives and Hedging—Other Presentation Matters ("ASC 815-10-45"), is to net the fair value amounts recognized for multiple derivative instruments executed with the same counterparty and offset these values against any cash collateral associated with these derivative positions. See Note 17 for further discussion.

Fair Value of Financial Instruments

The fair values of financial instruments are estimated based upon current market conditions and quoted market prices for the same or similar instruments. Management estimates that the carrying value approximates fair value for all of our assets and liabilities that fall under the scope of ASC 825, Financial Instruments ("ASC 825").

We apply the provisions of ASC 820, Fair Value Measurements and Disclosure ("ASC 820"), in our presentation and disclosures regarding fair value, which pertain to certain financial assets and liabilities measured at fair value in the balance sheet on a recurring basis. ASC 820 defines fair value, establishes a framework for measuring fair value and expands disclosures about such measurements that are permitted or required under other accounting pronouncements. See Note 16 for further discussion.

We apply the provisions of ASC 825 as it pertains to the fair value option. This standard permits the election to carry financial instruments and certain other items similar to financial instruments at fair value on the balance sheet, with all changes in fair value reported in earnings. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. As of December 31, 2017 and 2016, we did not make the fair value election for any financial instruments not already carried at fair value in accordance with other standards.

Self-Insurance Reserves

We have no employees. Rather, we are managed by the directors and officers of our general partner. However, Delek employees providing services to the Partnership are covered under Delek’s insurance programs. Delek has workers' compensation and liability insurance with varying retentions and deductibles with limits that management considers adequate.

Environmental Expenditures

We have historically accrued environmental and clean-up related costs of a non-capital nature when it is both probable that a liability has been incurred and the amount can be reasonably estimated. Environmental liabilities represent the current estimated costs to investigate and remediate contamination at our properties. This estimate is based on internal and third-party assessments of the extent of the contamination, the selected remediation technology and review of applicable environmental regulations, typically considering estimated activities and costs for the next 15 years, unless a specific longer range estimate is practicable. Accruals for estimated costs from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study and include, but are not limited to, costs to perform remedial actions and costs of machinery and equipment that are dedicated to the remedial actions and that does not have an alternative use. Such accruals are adjusted as further information develops or circumstances change. We discount environmental liabilities to their present value if payments are fixed and determinable. Expenditures for equipment necessary for environmental issues relating to ongoing operations are capitalized. Estimated recoveries of costs from other parties are recorded on an undiscounted basis as assets when their realization is deemed probable.

Asset Retirement Obligations

We recognize liabilities which represent the fair value of a legal obligation to perform asset retirement activities, including those that are conditional on a future event, when the amount can be reasonably estimated. These obligations are related to the required cleanout of our pipelines and terminal tanks and removal of certain above-grade portions of our pipelines situated on right-of-way property.

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The reconciliation of the beginning and ending carrying amounts of asset retirement obligations as of December 31, 2017 and 2016 is as follows (in thousands):

	December 31,
	2017		2016
Beginning balance	$	3,772	$	3,506
Accretion expense	292		266
Ending balance	$	4,064	$	3,772

In order to determine fair value, management must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free rate and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation.

Revenue Recognition

Revenues for products sold are recorded at the point of sale upon delivery of product, which is the point at which title to the product is transferred, and when payment has either been received or collection is reasonably assured. Service revenues are recognized as crude oil, intermediate and refined products are shipped through, delivered by or stored in our pipelines, trucks, terminals and storage facility assets, as applicable. We do not recognize product sales revenues for these services, as title on the product never passes to us. All service revenues are based on regulated tariff rates or contractual rates.

Cost of Goods Sold and Operating Expenses

Cost of goods sold includes all costs of refined products, additives and related transportation. It also includes costs associated with the operation of our trucking assets. We do not recognize product cost of goods sold related to our shipping, delivering and storage services, as title to the product never passes to us. Operating expenses include the costs associated with the operation of owned terminals and other logistics assets, terminalling expense at third-party locations and pipeline maintenance costs.

Sales, Use and Excise Taxes

Our policy is to exclude sales, use and excise taxes from revenue when we are an agent of the taxing authority, in accordance with ASC 605-45, Revenue Recognition—Principal Agent Considerations.

Deferred Financing Costs

Deferred financing costs are included in other non-current assets in the accompanying consolidated balance sheets and represent expenses related to issuing and amending our revolving credit facility. Deferred financing costs associated with our 6.750% Senior Notes are included as a reduction to the associated debt balance in the accompanying consolidated balance sheets. These costs represent expenses related to issuing the senior notes. These amounts are amortized ratably over the remaining term of the respective financing and are included in interest expense in the accompanying consolidated statements of income and comprehensive income.

Operating Leases

We lease certain equipment and have surface leases under various operating lease arrangements, most of which provide the option, after the initial lease term, to renew the leases. None of these lease arrangements include fixed rental rate increases.

Income Taxes

We are not a taxable entity for federal income tax purposes or the income taxes of those states that follow the federal income tax treatment of partnerships. Instead, for purposes of these income taxes, each partner of the Partnership is required to take into account its share of income, gain, loss and deduction in computing its federal and state income tax liabilities, regardless of whether cash distributions are made to such partner by the Partnership. The taxable income reportable to each partner takes into account differences between the tax basis and fair market value of our assets, the acquisition price of such partner's units and the taxable income allocation requirements under the First Amended and Restated Agreement of Limited Partnership (the "Partnership Agreement").

We are subject to income taxes in certain states that do not follow the federal tax treatment of Partnerships. These taxes are accounted for under the provisions of ASC 740, Income Taxes (ASC 740). This statement generally requires DKL to record deferred income taxes for

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the differences between the book and tax bases of its assets and liabilities, which are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. Deferred income tax expense or benefit represents the net change during the year in our deferred income tax assets and liabilities, exclusive of the amounts held in other comprehensive income.

U.S. GAAP requires management to evaluate uncertain tax positions taken by the Partnership. The financial statement effects of a tax position are recognized when the position is more likely than not, based on the technical merits, to be sustained upon examination by the Internal Revenue Service. Management has analyzed the tax positions taken by the Partnership, and has concluded that there are no uncertain positions taken or expected to be taken. The Partnership is subject to routine audits by taxing jurisdictions.

Equity Based Compensation

Our general partner provides equity-based compensation to officers, directors and employees of our general partner or its affiliates, and certain consultants, affiliates of our general partner or other individuals who perform services for us, which includes unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The fair value of our phantom units is determined based on the closing market price of our common units on the grant date. The estimated fair value of our phantom units is amortized over the vesting period using the straight line method. Awards vest over one- to five-year service periods, unless such awards are amended in accordance with the LTIP. It is our practice to issue new units when phantom units vest.

Net Income per Limited Partner Unit

We use the two-class method when calculating the net income per unit applicable to limited partners because we have more than one participating class of securities. Our participating securities consist of common units, subordinated units, general partner units and incentive distribution rights ("IDRs"). The two-class method is based on the weighted-average number of common units outstanding during the period. Basic net income per unit applicable to limited partners (including subordinated unitholders) is computed by dividing limited partners’ interest in net income, after deducting our general partner’s 2% interest and IDRs, by the weighted-average number of outstanding common and subordinated units. Our net income is allocated to our general partner and limited partners in accordance with their respective partnership percentages after giving effect to priority income allocations for IDRs to our general partner, which is the holder of the IDRs pursuant to our Partnership Agreement. The weighted-average number of common units reflects the conversion of the subordinated units to common units on February 25, 2016. See Notes 5 and 12 for further discussion.

Diluted net income per unit applicable to common limited partners includes the effects of potentially dilutive units on our common units. At present, the only potentially dilutive units outstanding consist of unvested phantom units. Basic and diluted net income per unit applicable to subordinated limited partners are the same because there are no potentially dilutive subordinated units outstanding.

Comprehensive Income

Comprehensive income for the years ended December 31, 2017, 2016 and 2015 was equivalent to net income.

New Accounting Pronouncements

In August 2017, the Financial Accounting Standards Board (the "FASB") issued guidance to refine and expand hedge accounting for both financial and commodity risks. Its provisions create more transparency around how economic results are presented, both on the face of the financial statements and in the footnotes and align the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. It also makes certain targeted improvements to simplify the application of hedge accounting guidance. This guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, and can be early adopted for any interim or annual financial statements that have not yet been issued. We expect to adopt this guidance on or before the effective date and are currently evaluating the impact that adopting this new guidance will have on our business, financial condition and results of operations.

In May 2017, the FASB issued guidance that clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. The modification accounting guidance applies if the value, vesting conditions or classification of the award changes. This guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, and can be early adopted for any interim or annual financial statements that have not yet been issued. We expect to adopt this guidance on or before the effective date and are currently evaluating the impact that adopting this new guidance will have on our business, financial condition and results of operations.

In January 2017, the FASB issued guidance that eliminates Step 2 of the goodwill impairment test, which required a comparison of the implied fair value of goodwill of a reporting unit with the carrying amount of that goodwill for that reporting unit. It also eliminates the requirements for any reporting unit with a zero or negative carrying amount to perform a qualitative assessment and, if it fails that qualitative

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assessment, to perform Step 2 of the goodwill impairment test. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. This guidance is effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We expect to adopt this guidance on or before the effective date and we do not anticipate that the adoption will have a material impact on our business, financial condition or results of operations.

In January 2017, the FASB issued guidance clarifying the definition of a business in order to assist entities with evaluating when a set of transferred assets and activities is considered a business. In general, we expect that the revised definition will result in fewer acquisitions being accounted for as business combinations than under the current guidance. This guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years and should be applied prospectively. Early adoption is permitted under certain circumstances. We early adopted this guidance as of July 1, 2017 and the adoption did not have a material impact on our business, financial condition or results of operations.

In March 2016, the FASB issued guidance that simplifies several aspects of the accounting for share-based payment award transactions, including the accounting for excess tax benefits and deficiencies, classification of awards as either equity or liabilities and classification of excess tax benefits on the statement of cash flows.  This guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years and can be early adopted for any interim or annual financial statements that have not yet been issued.  We prospectively adopted this guidance on January 1, 2017 and the adoption did not have a material impact on our business, financial condition or results of operations.

In February 2016, the FASB issued guidance that requires the recognition of a lease liability and a right-of-use asset, initially measured at the present value of the lease payments, in the statement of financial condition for all leases previously accounted for as operating leases. This guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. We expect to adopt this guidance on or before the effective date and are currently evaluating the impact adopting this new guidance will have on our business, financial condition and results of operations. 

In July 2015, the FASB issued guidance requiring entities to measure FIFO or average cost inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.  This guidance does not change the measurement of inventory measured using LIFO or the retail inventory method.  This guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years.   We adopted this guidance on January 1, 2017 and the adoption did not have a material impact on our business, financial condition or results of operations. 

In May 2014, the FASB issued guidance regarding “Revenue from Contracts with Customers,” to clarify the principles for recognizing revenue. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires improved interim and annual disclosures that enable the users of financial statements to better understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. The new guidance is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period, and can be adopted retrospectively. We expect to adopt the new standard in the first quarter of 2018 using the modified retrospective transition method. Based on the analysis performed to date, we do not expect the adoption of the standard to have a material impact on the timing or pattern of revenue recognition.

3. Acquisitions

Acquisitions from Delek

During the year ended December 31, 2015, the Partnership acquired the assets listed below from Delek:

• the El Dorado Assets effective March 31, 2015 for approximately $42.5 million in cash financed with borrowings under the Partnership's amended and restated senior secured revolving credit facility; and

• the Tyler Assets effective March 31, 2015 for approximately $19.4 million in cash financed with borrowings under the Partnership's amended and restated senior secured revolving credit facility.

Financial Results of the Acquisitions from Delek

The Acquisitions from Delek were considered transfers of businesses between entities under common control. Accordingly, the Acquisitions from Delek were recorded at amounts based on Delek's historical carrying value as of each respective acquisition date, which were $7.6 million and $11.6 million as of March 31, 2015, for the El Dorado Rail Offloading Racks Acquisition and the Tyler Crude Tank

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Acquisition, respectively. Our historical financial statements have been retrospectively adjusted to reflect the results of operations, financial position, cash flows and equity attributable to the Acquisitions from Delek as if we owned the assets for all periods presented. The results of the El Dorado Assets and the Tyler Assets are included in the pipelines and transportation segment.

Acquisitions from Third Parties

On September 15, 2017, the Partnership, through its wholly owned subsidiary, Delek Marketing & Supply, LP acquired from Plains Pipeline, L.P. an approximately 40-mile pipeline and related ancillary assets (the "Big Spring Pipeline") (such transaction, the "Big Spring Acquisition") for approximately $9.0 million to complement our existing asset base. The Big Spring Pipeline originates in Big Spring, Texas and terminates in Midland, Texas. The Big Spring Acquisition was accounted for as an asset acquisition. The following table summarizes the allocation of the relative fair value assigned to the asset groups for the Big Spring Pipeline (in thousands):

Property, plant and equipment	$	6,443
Intangible assets (1)	2,560
Total	$	9,003

⁽¹⁾ Intangible assets acquired represent rights-of-way assets with indefinite useful lives. Rights-of-way assets are not subject to amortization.

4. Related Party Transactions

Commercial Agreements

The Partnership has a number of long-term, fee-based commercial agreements with Delek under which we provide various services, including crude oil gathering and crude oil, intermediate and refined products transportation and storage services, and marketing, terminalling and offloading services to Delek. Most of these agreements have an initial term ranging from five to ten years, which may be extended for various renewal terms at the option of Delek. In November 2017, Delek opted to renew certain of these agreements for subsequent five-year terms expiring in November 2022. In the case of our marketing agreement with Delek, the initial term has been extended through 2026. The fees under each agreement are payable to us monthly by Delek or certain third parties to whom Delek has assigned certain of its rights and are generally subject to increase or decrease on July 1 of each year, by the amount of any change in various inflation-based indices, including the Federal Energy Regulatory Commission oil pipeline index or various iterations of 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. In most circumstances, if Delek or the applicable third party assignee fails to meet or exceed the minimum volume or throughput commitment during any calendar quarter, Delek, and not any third party assignee, will be required to make a quarterly shortfall payment to us equal to the volume of the shortfall multiplied by the applicable fee, subject to certain exceptions as specified in the applicable agreement. Carry-over of any volumes or revenue in excess of such commitment to any subsequent quarter is not permitted.

Under each of these agreements, we are required to maintain the capabilities of our pipelines and terminals, such that Delek may throughput and/or store, as the case may be, specified volumes of crude oil, intermediate and refined products. To the extent that Delek is prevented by our failure to maintain such capacities from throughputting or storing such specified volumes for more than 30 days per year, Delek's minimum throughput commitment will be reduced proportionately and prorated for the portion of the quarter during which the specified throughput capacity was unavailable, and/or the storage fee will be reduced, prorated for the portion of the month during which the specified storage capacity was unavailable. Such reduction would occur even if actual throughput or storage amounts were below the minimum volume commitment levels.

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Our material commercial agreements with Delek include the following:

Asset/Operation	Initiation Date	Initial/Maximum Term (years) (1)	Service	Minimum Throughput Commitment (bpd)	Fee (/bbl)
Lion Pipeline System and SALA Gathering System:
Crude Oil Pipelines (non-gathered)	November 2012	5 / 15	Crude oil and refined products transportation	46,000 (2)	$ 0 .95 (3)
Refined Products Pipelines	November 2012	5 / 15		40,000	$	0.11
SALA Gathering System	November 2012	5 / 15	Crude oil gathering	14,000	$ 2.55 (3)
East Texas Crude Logistics System:
Crude Oil Pipelines	November 2012	5 / 15	Crude oil transportation and storage	35,000	$ 0.45 (4)
Storage	November 2012	5 / 15		N/A	$ 278,923/month
East Texas Marketing	November 2012	10 (5)	Marketing products for Tyler Refinery	50,000	$ 0.777 (5)
Big Sandy Terminal: (6)
Refined Products Transportation	November 2012	5 / 15	Refined products transportation, dedicated terminalling services and storage for the Tyler Refinery	5,000	$	0.56
Terminalling	November 2012	5 / 15		5,000	$	0.56
Storage	November 2012	5 / 15		N/A	$ 55,735/month
Tyler Throughput and Tankage:
Refined Products Throughput	July 2013	8 / 16	Dedicated Terminalling and storage	50,000	$	0.36
Storage	July 2013	8 / 16		N/A	$ 832,530/month
Memphis Pipeline	October 2013	5	Refined Products Transportation	10,959	$	1.35
El Dorado Throughput and Tankage:
Refined Products Throughput	February 2014	8 / 16	Dedicated terminalling and storage	11,000	$	0.51
Storage	February 2014	8 / 16		N/A	$1,319,135/month
El Dorado Assets Throughput:
Light Crude Throughput	March 2015	9/15	Dedicated Offloading Services	N/A (7)	$ 1.11
Heavy Crude Throughput	March 2015	9/15	Dedicated Offloading Services	N/A (7)	$ 2.28

⁽¹⁾ Maximum term gives effect to the extension of the commercial agreement pursuant to the terms thereof.

⁽²⁾ Excludes volumes gathered on the SALA Gathering System.

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⁽³⁾ Volumes gathered on the SALA Gathering System will not be subject to an additional fee for transportation on our Lion Pipeline System to the El Dorado Refinery.

⁽⁴⁾ For any volumes in excess of 50,000 bpd, the throughput fee will be $0.670/bbl.

⁽⁵⁾ For any volumes in excess of 50,000 bpd, the throughput fee will be $0.738/bbl. Following the primary term, the marketing agreement automatically renews for successive one-year terms, unless either party provides notice of non-renewal 10 months prior to the expiration of the then-current term. The initial primary term for the marketing agreement has been extended through 2026.

⁽⁶⁾ On July 19, 2013, we acquired the Hopewell Pipeline in order to effectively connect it with the Big Sandy Pipeline and thereby return the Big Sandy Terminal to operation. In connection with the acquisition, on July 25, 2013, we and Delek entered into the Amended and Restated Services Agreement (Big Sandy Terminal and Pipeline), which amended and restated the terminalling services agreement for the Big Sandy Terminal originally entered into in November 2012.

⁽⁷⁾  The throughput agreement provides for a minimum throughput fee of $1.5 million per quarter for throughput of a combination of light and heavy crude.

Pursuant to an arrangement with Delek and Lion Oil Company ("Lion Oil"), to which we are not a party, J. Aron & Company ("J. Aron") acquires and holds title to substantially all crude oil, intermediate and refined products transported on our Lion Pipeline System, SALA Gathering System and on pipeline capacity we lease from Enterprise TE Products Pipeline Company LLC that runs from the El Dorado Refinery to our Memphis Terminal (the "Memphis Pipeline"). J. Aron is therefore considered the shipper for the liquid it owns on the Lion Pipeline System, the SALA Gathering System and the Memphis Pipeline. J. Aron also has title to the refined products stored at our Memphis, North Little Rock and El Dorado terminals and in the El Dorado storage tanks. Under (i) our pipelines and storage agreement with Lion Oil relating to the Lion Pipeline System and the SALA Gathering System, (ii) our terminalling agreements with Lion Oil relating to the Memphis and North Little Rock terminals and (iii) our throughput and tankage agreement relating to the terminal and tank assets at and adjacent to the El Dorado Refinery, Lion Oil has assigned to J. Aron certain of its rights under these agreements, including the right to have J. Aron's crude oil and intermediate and refined products stored in or transported on or through these systems, Memphis and North Little Rock terminals and the terminal and tank assets at and adjacent to the El Dorado Refinery, with Lion Oil acting as J. Aron's agent for scheduling purposes. Accordingly, even though this is effectively a financing arrangement for Delek whereby J. Aron sells the product back to Delek, J. Aron is technically our primary customer under each of these agreements. J. Aron retains these storage and transportation rights for the term of its arrangement with Delek and Lion Oil, which currently runs through April 30, 2020, and J. Aron pays us for the transportation, throughput and storage services we provide to it. The rights assigned to J. Aron do not alter Lion Oil's obligations to meet certain throughput minimum volumes under our agreements with respect to the transportation, throughputting and storage of crude oil, intermediate and refined products through our facilities, but J. Aron's throughput is credited toward Lion Oil's minimum throughput commitments. Accordingly, Lion Oil is responsible for making any shortfall payments incurred under the pipelines and storage agreement or the terminalling agreement which may result from minimum throughputs or volumes not being met.

Other Agreements with Delek

In addition to the commercial agreements described above, the Partnership has entered into the following agreements with Delek:

Omnibus Agreement

Omnibus Agreement. The Partnership entered into an omnibus agreement with Delek, our general partner, OpCo, Lion Oil and certain of the Partnership’s and Delek’s other subsidiaries on November 7, 2012, which was subsequently amended and restated on July 26, 2013, February 10, 2014 and March 31, 2015 and further amended on August 3, 2015 (collectively, as amended, the "Omnibus Agreement"). The Omnibus Agreement governs the provision of certain operational services and reimbursement obligations, among other matters, between the Partnership and Delek.

Pursuant to the terms of the Omnibus Agreement, we were reimbursed for certain capital expenditures in the amount of $4.3 million, $1.9 million and $5.2 million, during the years ended December 31, 2017, 2016 and 2015, respectively. These amounts are recorded in other long-term liabilities and are amortized to revenue over the life of the underlying revenue agreement corresponding to the asset. Additionally, we were reimbursed or indemnified, as the case may be, for costs incurred in excess of certain amounts related to certain asset failures, pursuant to the terms of the Omnibus Agreement. We were reimbursed $0.3 million and $1.2 million during the years ended December 31, 2017 and 2016, respectively, for these matters. We were reimbursed for the costs incurred in connection with an asset failure near Fouke, Arkansas and the subsequent repair of the asset during the year ended December 31, 2015 pursuant to the Omnibus Agreement. These reimbursements are recorded as a reduction to operating expense.

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Other Agreements

Our general partner operates our business on our behalf and is entitled under our Partnership Agreement to be reimbursed for the cost of providing those services, which include certain labor related costs. We and our subsidiaries paid Delek approximately $18.8 million, $15.7 million and $22.8 million pursuant to the Partnership Agreement during the years ended December 31, 2017, 2016 and 2015, respectively. These amounts are included in operating expenses in the accompanying consolidated statements of income and comprehensive income.

Predecessors' Transactions

Related-party transactions of the Predecessors were settled through division equity. Costs related specifically to us have been identified and included in the accompanying consolidated statements of income and comprehensive income. Prior to the Acquisitions from Delek, we were not allocated certain corporate costs. These costs were primarily allocated based on a percentage of salaries expense and property, plant and equipment costs. In the opinion of management, the methods for allocating these costs are reasonable. It is not practicable to estimate the costs that would have been incurred by us if we had been operated on a stand-alone basis.

Summary of Transactions

Revenues from affiliates consist primarily of revenues from gathering, transportation, storage, offloading, Renewable Identification Numbers, wholesale marketing and products terminalling services provided primarily to Delek based on regulated tariff rates or contractually based fees and product sales. Affiliate operating expenses are primarily comprised of amounts we reimburse Delek, or our general partner, as the case may be, for the services provided to us under the Partnership Agreement. These expenses could also include reimbursement and indemnification amounts from Delek, as provided under the Omnibus Agreement. Additionally, the Partnership is required to reimburse Delek for direct or allocated costs and expenses incurred by Delek on behalf of the Partnership and for charges Delek incurred for the management and operation of our logistics assets, including an annual fee for various centralized corporate services, which are included in general and administrative services. In addition to these transactions, we purchase finished products and bulk biofuels from Delek, the costs of which are included in cost of goods sold.

A summary of revenue and expense transactions with Delek and its affiliates, including expenses directly charged and allocated to our Predecessors, are as follows (in thousands):

	Year Ended December 31,
	2017		2016		2015
Revenues	$	156,280	$	149,564	$	152,564
Cost of Goods Sold	$	54,982	$	32,514	$	105,461
Operating and maintenance expenses (1)	$	29,483	$	27,668	$	31,636
General and administrative expenses (2)	$	7,492	$	6,254	$	6,356

⁽¹⁾  Operating and maintenance expenses include costs allocated to our Predecessors for operating support provided by Delek, including certain labor related costs, property and liability insurance costs and certain other operating expenses. Costs allocated to our Predecessors by Delek were $0.2 million for the year ended December 31, 2015.

⁽²⁾  No general and administrative expenses were allocated to our Predecessors by Delek for the year ended December 31, 2015.

Quarterly Cash Distribution

Our common and general partner unitholders and the holders of IDRs are entitled to receive quarterly distributions of available cash as it is determined by the board of directors of our general partner in accordance with the terms and provisions of our Partnership Agreement. During the years ended December 31, 2017, 2016 and 2015, we paid quarterly cash distributions, of which $60.1 million, $47.0 million and $35.9 million, respectively, were paid to Delek and our general partner. On January 23, 2018, our general partner's board of directors declared a quarterly cash distribution totaling $22.8 million based on the available cash as of the date of determination for the end of the fourth quarter of 2017, which was paid on February 12, 2018 to unitholders of record on February 2, 2018. The distribution included $16.2 million paid to both Delek and our general partner, including the distribution as holder of the IDRs.

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5. Net Income Per Unit

We use the two-class method when calculating the net income per unit applicable to limited partners, because we have more than one participating class of securities. Our participating securities consist of common units, subordinated units, general partner units and IDRs. The two-class method is based on the weighted-average number of common units outstanding during the period. Basic net income per unit applicable to limited partners (including subordinated unitholders) is computed by dividing limited partners’ interest in net income, after deducting our general partner’s 2.0% interest and IDRs, by the weighted-average number of outstanding common and subordinated units. Our net income is allocated to our general partner and limited partners in accordance with their respective partnership percentages after giving effect to priority income allocations for IDRs, which are held by our general partner pursuant to our Partnership Agreement. The IDRs are paid following the close of each quarter.

Earnings in excess of distributions are allocated to our general partner and limited partners based on their respective ownership interests. Payments made to our unitholders are determined in relation to actual distributions declared and are not based on the net income allocations used in the calculation of net income per unit.

Diluted net income per unit applicable to common limited partners includes the effects of potentially dilutive units on our common units. During the years ended December 31, 2017, 2016 and 2015, the only potentially dilutive units outstanding consist of unvested phantom units. Basic and diluted net income per unit applicable to subordinated limited partners are the same because there are no potentially dilutive subordinated units outstanding.

Following the February 12, 2016 payment of the cash distribution attributable to the fourth quarter of 2015 and confirmation by the board of directors of our general partner (based on the recommendation of the Conflicts Committee) on February 25, 2016 that the requirements under the Partnership Agreement for the conversion of all subordinated units into common units were satisfied, the subordination period ended. As a result, in the first quarter of 2016, all of the Partnership's 11,999,258 outstanding subordinated units converted into common units and began participating pro rata with the other common units in distributions of available cash. The conversion did not impact the amount of the cash distribution paid or the total number of the Partnership's outstanding units representing limited partner interests. The Partnership's net income was allocated to the general partner and the limited partners, including the holders of the subordinated units through February 24, 2016, in accordance with our Partnership Agreement.

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Our distributions earned with respect to a given period are declared subsequent to quarter end. Therefore, the table below represents total cash distributions applicable to the period in which the distributions are earned. The calculation of net income per unit is as follows (dollars in thousands, except per unit amounts):

	Year Ended December 31,
	2017			2016			2015
Net income attributable to partners	$	69,409		$	62,804		$	66,848
Less: General partner's distribution (including IDRs) (1)	18,797			12,437			5,013
Less: Limited partners' distribution	69,057			58,158			27,439
Less: Subordinated partner's distribution	—			4,424			26,878
(Distributions) earnings excess	$	(18,445	)	$	(12,215	)	$	7,518
General partner's earnings:
Distributions (including IDRs) (1)	$	18,797		$	12,437		$	5,013
Allocation of (distributions) earnings excess	(368		)	(244		)	150
Total general partner's earnings	$	18,429		$	12,193		$	5,163
Limited partners' earnings on common units:
Distributions	$	69,057		$	58,158		$	27,439
Allocation of (distributions) earnings excess	(18,077		)	(11,489		)	3,721
Total limited partners' earnings on common units	$	50,980		$	46,669		$	31,160
Limited partners' earnings on subordinated units:
Distributions	$	—		$	4,424		$	26,878
Allocation of (distributions) earnings excess	—			(482		)	3,647
Total limited partner's earnings on subordinated units	$	—		$	3,942		$	30,525
Weighted average limited partner units outstanding (2):
Common units - (basic)	24,348,063			22,490,264			12,237,154
Common units - (diluted)	24,376,972			22,558,717			12,356,914
Subordinated units - Delek (basic and diluted) (3)	—			1,803,167			11,999,258
Net income per limited partner unit (2):
Common - (basic)	$	2.09		$	2.08		$	2.55
Common - (diluted) (4)	$	2.09		$	2.07		$	2.52
Subordinated - (basic and diluted)	$	—		$	2.19		$	2.54

⁽¹⁾  General partner distributions (including IDRs) consist of the 2% general partner interest and IDRs, which represent the right of the general partner to receive increasing percentages of quarterly distributions of available cash from operating surplus in excess of $0.43125 per unit per quarter. See Note 12 for further discussion related to IDRs.

⁽²⁾  We base our calculation of net income per unit on the weighted-average number of common and subordinated limited partner units outstanding during the period. The weighted-average number of common and subordinated units reflects the conversion of the subordinated units to common units on February 25, 2016.

⁽³⁾  On February 25, 2016, all of the Partnership's 11,999,258 outstanding subordinated units converted into common units and began participating pro rata with the other common units in distributions of available cash. Distributions and the Partnership's net income were allocated to the subordinated units through February 24, 2016.

⁽⁴⁾   There were no outstanding common unit equivalents excluded from the diluted earnings per unit calculation during the year ended December 31, 2017. Outstanding common unit equivalents totaling 4,240 and 6,200 were excluded from the diluted earnings per

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unit calculation for the years ended December 31, 2016 and 2015, respectively, as these common unit equivalents did not have a dilutive effect under the treasury stock method.

6. Major Customers

Delek, directly or indirectly, accounted for 28.9%, 32.8% and 25.9% of our total revenues for the years ended December 31, 2017, 2016 and 2015, respectively. Sunoco LP accounted for 9.0%, 10.5% and 16.2% of our total revenues for the years ended December 31, 2017, 2016 and 2015, respectively.

7. Inventory

Inventories consisted of $20.9 million and $8.9 million of refined petroleum products as of December 31, 2017 and 2016, respectively. Inventory is stated at the lower of cost or net realizable value, with cost determined on a FIFO basis. We recognize lower of cost or net realizable value charges as a component of cost of goods sold in the consolidated statements of income and comprehensive income, which amounted to a nominal amount and $0.3 million during the years ended December 31, 2017 and 2015, respectively. There was no lower of cost or net realizable value charge during the year ended December 31, 2016.

8.  Property, Plant and Equipment

Property, plant and equipment, at cost, consist of the following (in thousands):

	December 31,
	2017			2016
Land and land improvements	$	4,440		$	4,435
Building and building improvements	2,804			2,236
Pipelines, tanks and terminals	314,251			305,302
Asset retirement obligation assets	2,073			2,073
Other equipment	14,650			12,925
Construction in process	28,961			15,436
	367,179			342,407
Less: accumulated depreciation	(112,111		)	(91,378		)
	$	255,068		$	251,029

Property, plant and equipment, accumulated depreciation and depreciation expense by reporting segment as of and for the years ended December 31, 2017 and 2016 are as follows (in thousands):

	As of and For the Year Ended December 31, 2017
	Pipelines and Transportation			Wholesale Marketing and Terminalling			Consolidated
Property, plant and equipment	$	300,134		$	67,045		$	367,179
Less: accumulated depreciation	(84,435		)	(27,676		)	(112,111		)
Property, plant and equipment, net	$	215,699		$	39,369		$	255,068
Depreciation expense	$	17,268		$	3,583		$	20,851

	As of and For the Year Ended December 31, 2016
	Pipelines and Transportation			Wholesale Marketing and Terminalling			Consolidated
Property, plant and equipment	$	279,155		$	63,252		$	342,407
Less: Accumulated depreciation	(67,032		)	(24,346		)	(91,378		)
Property, plant and equipment, net	$	212,123		$	38,906		$	251,029
Depreciation expense	$	16,133		$	3,617		$	19,750

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9.  Goodwill

Goodwill represents the excess of the aggregate purchase price over the fair value of the identifiable net assets acquired. Goodwill acquired in a business combination is recorded at fair value and is not amortized. Our goodwill relates to the west Texas assets contributed to us by Delek Marketing & Supply, LLC ("Delek Marketing"), a direct wholly owned subsidiary of Delek, in connection with our initial public offering (the "Offering") and to the purchase price allocation of certain of our third party acquisitions.

We perform an annual assessment of whether goodwill retains its value. This assessment is done more frequently if indicators of potential impairment exist. We performed our annual goodwill impairment review in the fourth quarter of 2017, 2016 and 2015. We performed a discounted cash flows test, using a market participant weighted average cost of capital, and estimated minimal growth rates for revenue, gross profit and capital expenditures based on history and our best estimate of future forecasts. We also estimated the fair values using a multiple of expected future cash flows, such as those used by third party analysts. In 2017, 2016 and 2015, the annual impairment review resulted in the determination that no impairment of goodwill had occurred.

Our goodwill accounts in our wholesale marketing and terminalling segment amounted to $7.5 million as of December 31, 2017, 2016 and 2015. Our goodwill accounts in our pipelines and transportation segment amounted to $4.7 million as of December 31, 2017, 2016 and 2015. During the year ended December 31, 2015, we recorded goodwill of $0.5 million in our pipelines and transportation segment in connection with the acquisition of certain trucks and trailers acquired in 2014.

10.  Other Intangible Assets

Our identifiable intangible assets are as follows (in thousands):

	Useful			Accumulated
As of December 31, 2017	Life	Gross		Amortization			Net
Intangible assets subject to amortization:
Supply contract	11.5	$	12,227	$	(12,138	)	$	89
Intangible assets not subject to amortization:
Rights-of-way assets	Indefinite	15,828					15,828
Total		$	28,055	$	(12,138	)	$	15,917

	Useful			Accumulated
As of December 31, 2016	Life	Gross		Amortization			Net
Intangible assets subject to amortization:
Supply contract	11.5	$	12,227	$	(11,075	)	$	1,152
Intangible assets not subject to amortization:
Rights-of-way assets	Indefinite	13,268					13,268
Total		$	25,495	$	(11,075	)	$	14,420

Amortization of intangible assets was $1.1 million during each of the years ended December 31, 2017, 2016 and 2015, and is included in depreciation and amortization on the accompanying consolidated statements of income and comprehensive income. Amortization expense is estimated to be $0.1 million for the year ended December 31, 2018, at which point our supply contract will be fully amortized.

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11. Long-Term Obligations

Second Amended and Restated Credit Agreement

We entered into a senior secured revolving credit agreement on November 7, 2012, with Fifth Third Bank, as administrative agent, and a syndicate of lenders. The agreement was amended and restated on July 9, 2013 (the "Amended and Restated Credit Agreement") and was most recently amended and restated on December 30, 2014 (the "Second Amended and Restated Credit Agreement"). Under the terms of the Second Amended and Restated Credit Agreement, the lender commitments were increased from $400.0 million to $700.0 million. The Second Amended and Restated Credit Agreement also contains an accordion feature, whereby the Partnership can increase the size of the credit facility to an aggregate of $800.0 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent. The Second Amended and Restated Credit Agreement contains an option for Canadian dollar denominated borrowings.

Borrowings denominated in U.S. dollars bear interest at either a U.S. dollar prime rate, plus an applicable margin, or the London Interbank Offered Rate ("LIBOR"), plus an applicable margin, at the election of the borrowers. Borrowings denominated in Canadian dollars bear interest at either a Canadian dollar prime rate, plus an applicable margin, or the Canadian Dealer Offered Rate, plus an applicable margin, at the election of the borrowers. The applicable margin in each case varies based upon the Partnership's most recent total leverage ratio calculation delivered to the lenders, as called for and defined under the terms of the credit facility. At December 31, 2017, the weighted average interest rate for our borrowings under the credit facility was approximately 4.3%. Additionally, the Second Amended and Restated Credit Agreement requires us to pay a leverage-ratio dependent quarterly fee on the average unused revolving commitment. As of December 31, 2017, this fee was 0.50% per year.

The obligations under the Second Amended and Restated Credit Agreement remain secured by first priority liens on substantially all of the Partnership's and its subsidiaries' tangible and intangible assets. Additionally, Delek Marketing continues to provide a limited guaranty of the Partnership's obligations under the Second Amended and Restated Credit Agreement. Delek Marketing's guaranty is (i) limited to an amount equal to the principal amount, plus unpaid and accrued interest, of a promissory note made by Delek US in favor of Delek Marketing (the "Holdings Note") and (ii) secured by Delek Marketing's pledge of the Holdings Note to our lenders under the Second Amended and Restated Credit Agreement. As of December 31, 2017, the principal amount of the Holdings Note was $102.0 million, plus unpaid interest accrued since the issuance date. The Second Amended and Restated Credit Agreement matures on December 30, 2019.

As of December 31, 2017, we had $179.9 million in outstanding borrowings under the Second Amended and Restated Credit Agreement. Additionally, we had in place letters of credit totaling $9.0 million, primarily securing obligations with respect to gasoline and diesel purchases. No amounts were drawn under these letters of credit at December 31, 2017. Unused credit commitments under the Second Amended and Restated Credit Agreement as of December 31, 2017 were $511.1 million.

6.750% Senior Notes Due 2025

On May 23, 2017, the Partnership and Delek Logistics Finance Corp., a Delaware corporation and a wholly owned subsidiary of the Partnership (“Finance Corp.” and together with the Partnership, the “Issuers”), issued $250.0 million in aggregate principal amount of 6.750% senior notes due 2025 (the “2025 Notes”). The 2025 Notes are general unsecured senior obligations of the Issuers. The 2025 Notes are unconditionally guaranteed jointly and severally on a senior unsecured basis by the Partnership's existing subsidiaries (other than Finance Corp., the "Guarantors") and will be unconditionally guaranteed on the same basis by certain of the Partnership’s future subsidiaries. The 2025 Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right of payment to anyfuture subordinated indebtedness of the Issuers. Interest on the 2025 Notes is payable semi-annually in arrears on each May 15 and November 15, commencing November 15, 2017.

At any time prior to May 15, 2020, the Issuers may redeem up to 35% of the aggregate principal amount of the 2025 Notes with the net cash proceeds of one or more equity offerings by the Partnership at a redemption price of 106.750% of the redeemed principal amount, plus accrued and unpaid interest, if any, subject to certain conditions and limitations. Prior to May 15, 2020, the Issuers may redeem all or part of the 2025 Notes, at a redemption price of the principal amount, plus accrued and unpaid interest, if any, plus a "make whole" premium, subject to certain conditions and limitations. In addition, beginning on May 15, 2020, the Issuers may, subject to certain conditions and limitations, redeem all or part of the 2025 Notes at a redemption price of 105.063% for the twelve-month period beginning on May 15, 2020, 103.375% for the twelve-month period beginning on May 15, 2021, 101.688% for the twelve-month period beginning on May 15, 2022 and 100.00% beginning on May 15, 2023 and thereafter, plus accrued and unpaid interest, if any. There are also certain redemption provisions in the event of a change of control, accompanied or followed by a ratings downgrade within a certain period of time, subject to certain conditions and limitations.

In connection with the issuance of the 2025 Notes, the Issuers and the Guarantors entered into a registration rights agreement, whereby the Issuers and the Guarantors are required to exchange the 2025 Notes for new notes with terms substantially identical in all material

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respects with the 2025 Notes (except the new notes will not contain terms with respect to transfer restrictions). The Issuers and the Guarantors will use their commercially reasonable efforts to cause the exchange offer to be consummated not later than 365 days after May 23, 2017.

As of December 31, 2017, we had $250.0 million in outstanding principal amount of the 2025 Notes. Outstanding borrowings under the 2025 Notes are net of deferred financing costs and debt discount of $5.5 million and $1.7 million, respectively, as of December 31, 2017.

Principal maturities of the Partnership's existing third party debt instruments for the next five years and thereafter are as follows as of December 31, 2017 (in thousands):

	2018		2019		2020		2021		2022		Thereafter		Total
Second Amended and Restated Credit Agreement	$	—	$	179,900	$	—	$	—	$	—	$	—	$	179,900
2025 Notes	$	—	$	—	$	—	$	—	$	—	$	250,000	$	250,000

F-24

12. Equity

We had 9,088,587 common limited partner units held by the public outstanding as of December 31, 2017. Additionally, as of December 31, 2017, Delek owned a 61.5% limited partner interest in us, consisting of 15,294,046 common limited partner units and a 94.6% interest in our general partner, which owns the entire 2.0% general partner interest consisting of 497,604 general partner units. Affiliates, who are also members of our general partner's management and board of directors, own the remaining 5.4% interest in our general partner.

Equity Activity

On February 25, 2016, the requirements under the Partnership Agreement for the conversion of all subordinated units into common units were satisfied, and the subordination period ended. As a result, in the first quarter of 2016, all of the Partnership's 11,999,258 outstanding subordinated units converted into common units and began participating pro rata with the other common units in distributions of available cash. The conversion did not impact the amount of the cash distribution paid or the total number of the Partnership's outstanding units representing limited partner interests.

The table below summarizes the changes in the number of units outstanding from December 31, 2014 through December 31, 2017 (in units).

	Common - Public		Common - Delek	Subordinated		General Partner	Total
Balance at December 31, 2014	9,417,189		2,799,258	11,999,258		494,197	24,709,902
GP units issued to maintain 2% interest	—		—	—		1,248	1,248
Unit-based compensation awards (1)	61,084		—	—		—	61,084
Balance at December 31, 2015	9,478,273		2,799,258	11,999,258		495,445	24,772,234
GP units issued to maintain 2% interest	—		—	—		1,057	1,057
Unit-based compensation awards (1)	51,818		—	—		—	51,818
Delek unit repurchases from public	(266,676	)	266,676	—		—	—
Subordinated unit conversion	—		11,999,258	(11,999,258	)	—	—
Balance at December 31, 2016	9,263,415		15,065,192	—		496,502	24,825,109
GP units issued to maintain 2% interest	—		—	—		1,102	1,102
Unit-based compensation awards	54,026		—	—		—	54,026
Delek unit repurchases from public	(228,854	)	228,854	—		—	—
Balance at December 31, 2017	9,088,587		15,294,046	—		497,604	24,880,237

⁽¹⁾ Unit-based compensation awards are presented net of 14,053, 17,276 and 21,144 units withheld for taxes as of December 31, 2017, 2016 and 2015, respectively.

Issuance of Additional Securities

Our Partnership Agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders. Costs associated with the issuance of securities are allocated to all unitholders' capital accounts based on their ownership interest at the time of issuance.

F-25

Allocations of Net Income

Our Partnership Agreement contains provisions for the allocation of net income and loss to the unitholders and our general partner. For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interest. Normal allocations according to percentage interests are made after giving effect to priority income allocations in an amount equal to incentive cash distributions allocated 100% to our general partner.

The following table presents the allocation of the general partner's interest in net income (in thousands, except percentage of ownership interest):

	Year Ended December 31,
	2017			2016			2015
Net income attributable to partners	$	69,409		$	62,804		$	66,848
Less: General partner's IDRs	(17,389		)	(11,160		)	(3,904		)
Net income available to partners	$	52,020		$	51,644		$	62,944
General partner's ownership interest	2.0		%	2.0		%	2.0		%
General partner's allocated interest in net income	1,040			1,033			1,259
General partner's IDRs	17,389			11,160			3,904
Total general partner's interest in net income	$	18,429		$	12,193		$	5,163

Incentive Distribution Rights

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and our unitholders in any available cash from operating surplus that we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that (i) our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest and (ii) our general partner has not transferred its IDRs.

		Target Quarterly Distribution per Unit		Marginal Percentage Interest in Distributions
		Target Amount		Unitholders		General Partner
Minimum Quarterly Distribution		$	0.37500	98.0	%	2.0	%
First Target Distribution	above	$	0.37500	98.0	%	2.0	%
	up to	$	0.43125
Second Target Distribution	above	$	0.43125	85.0	%	15.0	%
	up to	$	0.46875
Third Target Distribution	above	$	0.46875	75.0	%	25.0	%
	up to	$	0.56250
Thereafter	thereafter	$	0.56250	50.0	%	50.0	%

Cash Distributions

Our Partnership Agreement sets forth the calculation to be used to determine the amount and priority of available cash distributions that our limited partner unitholders and general partner will receive. Our distributions earned with respect to a given period are declared subsequent to quarter end. The table below summarizes the quarterly distributions related to our quarterly financial results:

F-26

Quarter Ended	Total Quarterly Distribution Per Limited Partner Unit		Total Quarterly Distribution Per Limited Partner Unit, Annualized		Total Cash Distribution, including general partner interest and IDRs (in thousands)		Date of Distribution	Unitholders Record Date
December 31, 2015	$	0.590	$	2.36	$	16,124	February 12, 2016	February 5, 2016
March 31, 2016	$	0.610	$	2.44	$	17,095	May 13, 2016	May 5, 2016
June 30, 2016	$	0.630	$	2.52	$	18,085	August 12, 2016	August 5, 2016
September 30, 2016	$	0.655	$	2.62	$	19,302	November 14, 2016	November 7, 2016
December 31, 2016	$	0.680	$	2.72	$	20,537	February 14, 2017	February 3, 2017
March 31, 2017	$	0.690	$	2.76	$	21,024	May 12, 2017	May 5, 2017
June 30, 2017	$	0.705	$	2.82	$	21,783	August 11, 2017	August 4, 2017
September 30, 2017	$	0.715	$	2.86	$	22,270	November 14, 2017	November 7, 2017
December 31, 2017	$	0.725	$	2.90	$	22,777	February 12, 2018	February 2, 2018

The allocation of total quarterly cash distributions made to general and limited partners for the years ended December 31, 2017, 2016 and 2015 is set forth in the table below. Distributions earned with respect to a given period are declared subsequent to quarter end. Therefore, the table below presents total cash distributions applicable to the period in which the distributions are earned (in thousands, except per unit amounts):

	Year Ended December 31,
	2017		2016		2015
General partner's distributions:
General partner's distributions	$	1,408	$	1,277	$	1,109
General partner's IDRs	17,389		11,160		3,904
Total general partner's distributions	18,797		12,437		5,013
Limited partners' distributions:
Common	69,057		58,158		27,439
Subordinated	—		4,424		26,878
Total limited partners' distributions	69,057		62,582		54,317
Total cash distributions	$	87,854	$	75,019	$	59,330
Cash distributions per limited partner unit	$	2.835	$	2.575	$	2.240

13. Equity Based Compensation

The Delek Logistics GP, LLC 2012 Long-Term Incentive Plan (the "LTIP") was adopted by the Delek Logistics GP, LLC board of directors in connection with the completion of the Offering in November 2012. The LTIP provides for officers, directors and employees of our general partner or its affiliates, and any consultants, affiliates of our general partner or other individuals who perform services for us. The LTIP consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The LTIP limits the number of common units that may be delivered pursuant to awards under the plan to 612,207 units. The LTIP is administered by the Conflicts Committee of the board of directors of our general partner.

We incurred approximately $0.7 million, $0.6 million and $0.4 million of unit-based compensation expense related to the Partnership during the years ended December 31, 2017, 2016 and 2015, respectively. These amounts are included in general and administrative expenses in the accompanying consolidated statements of income and comprehensive income. The fair value of phantom unit awards under the LTIP is determined based on the closing market price of our common limited partner units on the grant date. The estimated fair value of our phantom units is amortized over the vesting period using the straight line method. Awards vest over one- to five-year service periods, unless such awards are amended in accordance with the LTIP. The total fair value of phantom units vested was $1.7 million, $1.7 million and $1.9 million during the years ended December 31, 2017, 2016 and 2015, respectively.

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As of December 31, 2017, there was $0.4 million of total unrecognized compensation cost related to non-vested equity-based compensation arrangements, which is expected to be recognized over a weighted-average period of 0.7 years.

A summary of our unit award activity for the years ended December 31, 2017, 2016 and 2015, is set forth below:

		Number of Phantom Units		Weighted-Average Grant Price
Non-vested	December 31, 2014	215,464		$	23.48
Granted		11,836		$	39.73
Vested		(82,228	)	$	23.55
Non-vested	December 31, 2015	145,072		$	24.76
Granted		12,475		$	26.05
Vested		(69,094	)	$	24.66
Forfeited		(14,500	)	$	22.65
Non-vested	December 31, 2016	73,953		$	25.49
Granted		10,090		$	32.20
Vested		(68,079	)	$	24.60
Non-vested	December 31, 2017	15,964		$	33.54

14. Equity Method Investments

In March 2015, we entered into two joint ventures that have constructed separate crude oil pipeline systems and related ancillary assets, which are serving third parties and subsidiaries of Delek. We own a 50% membership interest in the entity formed with an affiliate of Plains All American Pipeline, L.P. ("CP LLC") to operate one of these pipeline systems and a 33% membership interest in the entity formed with Rangeland Energy II, LLC ("Rangeland RIO") to operate the other pipeline system. The pipeline system constructed by Rangeland RIO was completed and began operations in September 2016. The pipeline system constructed by CP LLC was completed and began operations in January 2017.

The Partnership's investments in these two entities were financed through a combination of cash from operations and borrowings under the Second Amended and Restated Credit Agreement. As of December 31, 2017, the Partnership's investment balance in these joint ventures was $106.5 million.

We do not consolidate any part of the assets or liabilities or operating results of our equity method investees. Our share of net income or loss of the investees will increase or decrease, as applicable, the carrying value of our investments in unconsolidated affiliates. With respect to CP LLC and Rangeland RIO, we determined that these entities do not represent variable interest entities and consolidation was not required. We have the ability to exercise significant influence over each of these joint ventures through our participation in the management committees, which make all significant decisions. However, since all significant decisions require the consent of the other investor(s) without regard to economic interest, we have determined that we have joint control and have applied the equity method of accounting. Our investment in these joint ventures is reflected in our pipelines and transportation segment.

Summarized Financial Information

Combined summarized financial information for our equity method investees is shown below (in thousands):

	Year Ended		Year Ended
	December 31, 2017		December 31, 2016
Current assets	$	12,671	$	7,760
Non-current assets	$	244,329	$	237,516
Current liabilities	$	1,798	$	4,512

F-28

	Year Ended		Year Ended			Year Ended
	December 31, 2017		December 31, 2016			December 31, 2015
Revenues	$	28,805	$	2,217		$	—
Gross profit	$	28,805	$	2,217		$	—
Net Income/loss	$	10,714	$	(3,641	)	$	(1,967	)

15. Segment Data

We aggregate our operating segments into two reportable segments: (i) pipelines and transportation and (ii) wholesale marketing and terminalling:

• The assets and investments reported in the pipelines and transportation segment provide crude oil gathering, and crude oil, intermediate and finished products transportation and storage services to Delek's refining operations and independent third parties.

• The wholesale marketing and terminalling segment provides wholesale marketing and terminalling services to Delek's refining operations and independent third parties.

Our operating segments adhere to the accounting policies used for our consolidated financial statements, as described in Note 2. Our operating segments are managed separately, because each segment requires different industry knowledge, technology and marketing strategies. 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 its reportable segments based on segment contribution margin. Segment contribution margin is defined as net sales less cost of goods sold and operating expenses.

During the year ended December 31, 2015, we acquired the Logistics Assets from Delek. Our historical financial statements have been retrospectively adjusted as appropriate to reflect the results of operations attributable to the Logistics Assets as if we owned the assets for all periods presented. The results of the Logistics Assets are included in the pipelines and transportation segment.

F-29

The following is a summary of business segment operating performance as measured by contribution margin for the period indicated (in thousands):

	Year Ended December 31,
	2017			2016			2015
Pipelines and Transportation
Net sales:
Affiliate	109,298			$	103,749		102,551
Third party	12,431			18,423			28,828
Total pipelines and transportation	121,729			122,172			131,379
Operating costs and expenses:
Cost of goods sold	18,210			19,425			19,607
Operating expenses	33,240			29,235			33,751
Segment contribution margin	$	70,279		$	73,512		$	78,021
Capital spending (excluding business combinations)	$	14,262		$	8,478		$	16,030
Wholesale Marketing and Terminalling
Net sales:
Affiliate	46,982			45,815			50,013
Third party	369,364			280,072			408,277
Total wholesale marketing and terminalling	416,346			325,887			458,290
Operating costs and expenses:
Cost of goods sold	354,680			282,733			416,697
Operating expenses	10,034			7,963			11,172
Segment contribution margin	$	51,632		$	35,191		$	30,421
Capital spending (excluding business combinations)	$	4,141		$	3,289		$	6,397
Consolidated
Net sales:
Affiliate	$	156,280		$	149,564		$	152,564
Third party	381,795			298,495			437,105
Total Consolidated	538,075			448,059			589,669
Operating costs and expenses:
Cost of goods sold	372,890			302,158			436,304
Operating expenses	43,274			37,198			44,923
Contribution margin	121,911			108,703			108,442
General and administrative expenses	11,840			10,256			11,384
Depreciation and amortization	21,914			20,813			19,692
(Gain) loss on asset disposals	(20		)	(16		)	104
Operating income	$	88,177		$	77,650		$	77,262
Capital spending (excluding business combinations)	$	18,403		$	11,767		$	22,427

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The following table summarizes the total assets for each segment as of December 31, 2017 and 2016 (in thousands).

	Year Ended December 31,
	2017		2016
Pipelines and transportation	$	349,351	$	337,349
Wholesale marketing and terminalling	94,179		78,198
Total Assets	$	443,530	$	415,547

16. Fair Value Measurements

The fair values of financial instruments are estimated based upon current market conditions and quoted market prices for the same or similar instruments. Management estimates that the carrying value approximates fair value for all of our assets and liabilities that fall under the scope of ASC 825.

We apply the provisions of ASC 820, which defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. ASC 820 applies to commodity and interest rate derivatives that are measured at fair value on a recurring basis. The standard also requires that we assess the impact of nonperformance risk on our derivatives. Nonperformance risk is not considered material as of December 31, 2017.

ASC 820 requires disclosures that categorize assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting our assumptions about pricing by market participants.

Over the counter ("OTC") commodity swaps and any interest rate swaps and caps are generally valued using industry-standard models that consider various assumptions, including quoted forward prices, spot prices, interest rates, time value, volatility factors and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines the classification as Level 2 or 3. Our contracts are valued based on exchange pricing and/or price index developers such as Platts or Argus and are, therefore, classified as Level 2.

The fair value hierarchy for our financial assets and liabilities accounted for at fair value on a recurring basis at December 31, 2017 and 2016 was as follows: (in thousands):

	As of December 31, 2017
	Level 1		Level 2			Level 3		Total
Liabilities
OTC commodity swaps	—		(1,087		)	—		(1,087		)
Net liabilities	$	—	$	(1,087	)	$	—	$	(1,087	)

	As of December 31, 2016
	Level 1		Level 2			Level 3		Total
Assets
OTC commodity swaps	$	—	$	9		$	—	$	9
Total assets	—		9			—		9
Liabilities
OTC commodity swaps	—		(82		)	—		(82		)
Net assets	$	—	$	(73	)	$	—	$	(73	)

The derivative values above are based on analysis of each contract as the fundamental unit of account as required by ASC 820. Derivative assets and liabilities with the same counterparty are not netted where the legal right of offset exists. This differs from the presentation in the financial statements, which reflects our policy under the guidance of ASC 815-10-45, wherein we have elected to

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offset the fair value amounts recognized for multiple derivative instruments executed with the same counterparty where the legal right of offset exists.

As of December 31, 2017 and 2016, we had cash collateral of $0.3 million and a cash deficit of $0.6 million, respectively, netted with the net derivative position of our counterparty. See Note 17 for further information regarding derivative instruments.

17. Derivative Instruments

From time to time, we enter into forward fuel contracts to limit the exposure to price fluctuations for physical purchases of finished products in the normal course of business. We use derivatives to reduce the impact of market price volatility on our results of operations. Typically, we enter into forward fuel contracts with major financial institutions in which we fix the purchase price of finished grade fuel for a predetermined number of units with fulfillment terms of less than 90 days.

From time to time, we may also enter into interest rate hedging agreements to limit floating interest rate exposure under the Second Amended and Restated Credit Agreement. Our initial credit facility required us to maintain interest rate hedging arrangements on at least 50% of the amount funded on November 7, 2012 under the credit facility, which was required to be in place for at least a three-year period beginning no later than March 7, 2013. Accordingly, effective February 25, 2013, we entered into an interest rate hedge in the form of a LIBOR interest rate cap for a term of three years for a total notional amount of $45.0 million, thereby meeting the requirements in effect at that time. The interest rate hedge remained in place in accordance with its term through its maturity date in February 2016.

The following table presents the fair value of our derivative instruments, as of December 31, 2017 and 2016. The fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under our master netting arrangements, including any cash deficit or collateral on deposit with our counterparties. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements. As a result, the asset and liability amounts below may differ from the amounts presented in our accompanying consolidated balance sheets. During the years ended December 31, 2017 and 2016, we did not elect hedge accounting treatment for these derivative positions. As a result, all changes in fair value are marked to market in the accompanying consolidated statements of income and comprehensive income. See Note 16 for further information regarding the fair value of derivative instruments.

(in thousands)		December 31, 2017					December 31, 2016
Derivative Type	Balance Sheet Location	Assets		Liabilities			Assets		Liabilities
Derivatives:
OTC commodity swaps (1)	Other current assets	$	—	$	(1,087	)	$	9	$	(82	)
Total gross value of derivatives		—		(1,087		)	9		(82		)
Less: Counterparty netting and cash collateral (2)		—		(290		)	9		621
Total net fair value of derivatives		$	—	$	(797	)	$	—	$	(703	)

⁽¹⁾  As of December 31, 2017 and 2016, we had open derivative contracts representing 370,000 barrels and 93,000 barrels, respectively, of refined petroleum products.

⁽²⁾  As of December 31, 2017 and 2016, we had cash collateral of $0.3 million and a cash deficit of $0.6 million, respectively, netted with the net derivative position of our counterparty.

Recognized gains (losses) associated with our derivatives for the years ended December 31, 2017 and 2016 were as follows (in thousands):

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		Year Ended December 31,
Derivative Type	Income Statement Location	2017			2016			2015
Interest rate derivatives	Interest expense	$	—		$	—		$	(24	)
OTC commodity swaps	Cost of goods sold	(1,550		)	(2,122		)	441
	Total	$	(1,550	)	$	(2,122	)	$	417

18. Income Taxes

For tax purposes, each partner of the Partnership is required to take into account its share of income, gain, loss and deduction in computing its federal and state income tax liabilities, regardless of whether cash distributions are made to such partner by the Partnership. The taxable income reportable to each partner takes into account differences between the tax basis and fair market value of our assets, the acquisition price of such partner's units and the taxable income allocation requirements under our Partnership Agreement.

The Partnership is not a taxable entity for federal income tax purposes. While most states do not impose an entity level tax on partnership income, the Partnership is subject to entity level tax in both Tennessee and Texas. The Partnership does not file a separate Texas tax return. Our results of operations are included in Delek’s consolidated return. However, the provisions of ASC 740 have been followed as if we were a stand-alone entity. As a result, the Partnership must record deferred income taxes for the differences between book and tax bases of its assets and liabilities based on those states' enacted tax rates and laws that will be in effect when the differences are expected to reverse. The consolidated Texas franchise tax return for Delek, including the Partnership, is currently under examination for tax years 2012 through 2015. No material adjustments have been identified at this time.

The total non-current deferred tax assets were $0.4 million and $0.3 million as of December 31, 2017 and 2016, respectively, and are included in other non-current assets in our accompanying consolidated balance sheets. The majority component of our non-current deferred tax assets as of December 31, 2017 and 2016 was depreciation and amortization.

The difference between the actual income tax expense and the tax expense computed by applying the statutory federal income tax rate to income before income taxes is attributable to the following (in thousands):

	Year Ended December 31,
	2017			2016			2015
State income taxes	(222		)	121			171
Other items	—			(40		)	(366		)
Income tax expense (benefit)	$	(222	)	$	81		$	(195	)

Income tax expense (benefit) is as follows (in thousands):

	Year Ended December 31,
	2017			2016			2015
Current	$	(111	)	$	254		$	(209	)
Deferred	(111		)	(173		)	14
Total	$	(222	)	$	81		$	(195	)

Delek files a consolidated Texas gross margin tax return, and tax payments for the Partnership are paid by Delek. Therefore, a portion of the current tax payable is included in accounts receivable/payable from related parties. As of December 31, 2017 and 2016, income taxes payable of $0.3 million and $0.1 million, respectively, were included in accounts receivable/payable from related parties in the accompanying consolidated balance sheets. Taxes that are determined on a consolidated basis apply the “benefits for loss” allocation method; thus, tax attributes are realized when used in the combined tax return to the extent that they have been subject to a valuation allowance.

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We recognize accrued interest and penalties related to unrecognized tax benefits as an adjustment to the current provision for income taxes. There were no uncertain tax positions recorded as of December 31, 2017 or 2016, and there were no interest or penalties recognized related to uncertain tax positions for the years ended December 31, 2017, 2016 or 2015. We have examined uncertain tax positions for any material changes in the next 12 months and none are expected.

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19. Commitments and Contingencies

Litigation

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. See "Crude Oil Releases" below for a potential enforcement action.

Environmental Health and Safety

We are subject to extensive and periodically changing federal, state and local laws and regulations relating to the protection of the environment, health and safety. Among other things, these laws and regulations govern the emission or discharge of pollutants into or onto the land, air and water, the handling and disposal of solid and hazardous wastes, and the remediation of contamination and the protection of workers and the public. Compliance with existing and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to develop, maintain, operate and upgrade equipment and facilities. Numerous permits or other authorizations are required under these laws for the operation of our terminals, pipelines and related operations, and may be subject to revocation, modification and renewal. These laws and permits may become the basis for 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, or that relate to pre-existing conditions for which we have assumed or are assigned responsibility. Releases of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, or is not a reimbursable event under the Omnibus Agreement, subject us to substantial expenses, including costs to respond to, contain and remediate a release, to comply with applicable laws and regulations and to resolve claims by third parties for personal injury, property damage or natural resources damages. These impacts could directly and indirectly affect our business. We cannot currently determine the amounts of such future impacts; however, we accrue liabilities for such events when we are able to determine if an amount is probable and can be reasonably estimated.

Crude Oil Releases

We have experienced several crude oil releases involving our assets, including, but not limited to, the following releases:

• In January 2016, a crude oil release of less than 30 barrels occurred from a gathering line at the Modisette pumping station near El Dorado, Arkansas;

• In January 2016, a crude oil release of approximately 350 barrels occurred from the Paline Pipeline near Woodville, Texas (the "Paline Release");

• In April 2015, a crude oil release of an estimated 130 barrels was discovered from a gathering line near Fouke, Arkansas; and

• In March 2013, a release of approximately 5,900 barrels of crude oil, the majority of which was contained on-site, occurred from a pumping facility at our Magnolia Station located west of the El Dorado Refinery (the "Magnolia Release").

Cleanup operations and site maintenance and remediation efforts on these and other releases have been substantially completed. We may incur additional expenses as a result of further scrutiny by regulatory authorities and continued compliance with laws and regulations to which our assets are subject. Expenses incurred for the remediation of these crude oil releases are included in operating expenses in our consolidated statements of income and comprehensive income and are subsequently reimbursed by Delek pursuant to the terms of the Omnibus Agreement. Reimbursements are recorded as a reduction to operating expense. We do not believe the total costs associated with these events, whether alone or in the aggregate, including any fines or penalties and net of partial insurance reimbursement, will have a material adverse effect upon our business, financial condition or results of operations, as we are reimbursed by Delek for such costs.

In June 2015, the United States Department of Justice notified the Partnership that it was pursuing an enforcement action on behalf of the Environmental Protection Agency (the "EPA") with regard to potential Clean Water Act violations arising from the Magnolia Release. We are currently attempting to negotiate a resolution to this matter with the EPA and the State of Arkansas, which may include monetary penalties and/or other relief. As of December 31, 2017, we have accrued $1.0 million, which we have recorded in pipeline release liabilities in our consolidated balance sheet, for the Magnolia Release in connection with these proceedings.

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Contracts and Agreements

The majority of the petroleum products we sold prior to December 31, 2017 in west Texas were purchased from Noble Petro, Inc. ("Noble Petro"). Under the terms of a supply contract (the "Abilene Contract") with Noble Petro that expired on December 31, 2017, we purchased petroleum products based on monthly average prices from Noble Petro at the Abilene, Texas terminal, which we own, for sales and exchange with third parties at the Abilene and San Angelo terminals. We leased the Abilene and San Angelo, Texas terminals to Noble Petro under a separate Terminal and Pipeline Lease and Operating Agreement, that expired on December 31, 2017. We purchase spot barrels from various third parties, which may continue to include Noble Petro, and from Delek for sale to wholesale customers in west Texas.

Letters of Credit

As of December 31, 2017, we had in place letters of credit totaling $9.0 million under the Second Amended and Restated Credit Agreement, primarily securing obligations with respect to gasoline and diesel purchases. No amounts were drawn under these letters of credit at December 31, 2017.

Operating Leases

We lease certain equipment and have surface leases under various operating lease arrangements, most of which provide the option, after the initial lease term, to renew the leases. None of these lease arrangements include fixed rental rate increases. Lease expense for all operating leases for the years ended December 31, 2017, 2016 and 2015 totaled $5.6 million, $5.7 million and $5.3 million, respectively.

The following is an estimate of our future minimum lease payments for operating leases having remaining noncancelable terms in excess of one year as of December 31, 2017 (in thousands):

2018	$	2,482
2019	546
2020	483
2021	293
2022	173
Thereafter	8
Total future minimum rentals	$	3,985

20.  Selected Quarterly Financial Data (Unaudited)

Quarterly financial information for the years ended December 31, 2017 and 2016 is summarized below. The quarterly financial information summarized below has been prepared by management and is unaudited (in thousands, except per unit data).

	For the Three Month Periods Ended
	March 31, 2017		June 30, 2017		September 30, 2017		December 31, 2017
Net sales	$	129,473	$	126,769	$	130,626	$	151,207
Operating income	$	18,472	$	23,371	$	22,636	$	23,698
Net income	$	14,595	$	18,977	$	16,923	$	18,914
Limited partners' interest in net income	$	10,486	$	14,425	$	12,178	$	13,891
Net income per limited partner unit:
Common (basic)	$	0.43	$	0.59	$	0.50	$	0.57
Common (diluted)	$	0.43	$	0.59	$	0.50	$	0.57

F-36

	For the Three Month Periods Ended
	March 31, 2016		June 30, 2016		September 30, 2016		December 31, 2016
Net sales	$	104,056	$	111,853	$	107,470	$	124,680
Operating income	$	18,974	$	22,512	$	17,001	$	19,163
Net income	$	15,448	$	18,893	$	13,151	$	15,312
Limited partners' interest in net income	$	13,195	$	16,102	$	9,892	$	11,422
Net income per limited partner unit:
Common (basic)	$	0.54	$	0.66	$	0.41	$	0.47
Common (diluted)	$	0.54	$	0.66	$	0.41	$	0.47
Subordinated - Delek (basic and diluted)	$	0.54	$	—	$	—	$	—

21. Subsequent Events

Distribution Declaration

On January 23, 2018, our general partner's board of directors declared a quarterly cash distribution of $0.725 per share, paid on February 12, 2018, to unitholders of record on February 2, 2018.    

Big Spring Asset Dropdown

On February 26, 2018, a definitive agreement was entered into between the Partnership and Delek for the Partnership to acquire certain logistics assets primarily located adjacent to Delek's Big Spring, Texas refinery (“Big Spring Refinery”), which are discussed in more detail below (“Big Spring Logistics Assets”). In addition, the parties entered into a new wholesale marketing agreement, whereby the Partnership will market certain finished products produced at the Big Spring refinery to various branded and unbranded customers in return for a marketing fee.

The Big Spring Logistics Assets will include:

• Approximately 60 storage tanks and certain ancillary assets (such as tank pumps and piping) primarily located adjacent to the Big Spring Refinery;

• An asphalt terminal and a light products terminal;

• Certain crude oil and refined product pipelines; and

• Other logistics assets, such as four underground saltwells used for natural gas liquids storage.

The purchase price is $315.0 million, financed through a combination of cash on hand and borrowings on the Partnership’s revolving credit facility, with closing expected to occur in March 2018.

In connection with the closing of the transaction, Delek, the Partnership and various of their subsidiaries expect to enter into and amend certain existing contracts, such as a new throughput and tankage agreement for the Big Spring Logistics Assets. The transaction has been and related agreements are expected to be approved by the Conflicts Committee of Delek Logistics’ general partner, which is comprised solely of independent directors.

Formation of Green Plains Joint Venture

On February 20, 2018, the Partnership and Green Plains Partners LP ("Green Plains") announced the companies have formed DKGP Energy Terminals, LLC ("DKGP Energy"), a joint venture engaging in the light products terminalling business. The Partnership and Green Plains will each own a 50% membership interest in DKGP Energy. DKGP Energy signed a membership interest purchase agreement to acquire two light products terminals located in Caddo Mills, Texas and North Little Rock, Arkansas from an affiliate of American Midstream Partners, L.P. ("American Midstream"). Subject to customary closing conditions and regulatory approvals, this transaction is expected to close in the first half of 2018. DKGP Energy will consist of the assets purchased from the affiliate of American Midstream and assets contributed by the Partnership. Immediately prior to the closing of the acquisition by the joint venture of the two terminals from American Midstream, the Partnership will contribute to the joint venture its North Little Rock, Arkansas terminal and its

F-37

Greenville tank farm located in Caddo Mills, Texas. The DKGP Energy board will oversee the newly formed joint venture and will appoint an affiliate of the Partnership as the operator with day-to-day operational responsibilities of the four terminals.

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ITEM 16. FORM 10-K SUMMARY

None.

98

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Delek Logistics Partners, LP

by and through its general partner, Delek Logistics GP, LLC

By:    /s/ Kevin Kremke

Kevin Kremke

Executive Vice President and Chief Financial Officer

Dated: February 28, 2018

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by or on behalf of the following persons on behalf of the registrant and in the capacities indicated on February 28, 2018:

/s/ Ezra Uzi Yemin

Ezra Uzi Yemin

Chairman of the Board of Directors and Chief

Executive Officer

(Principal Executive Officer)

/s/ Kevin L. Kremke

Kevin L. Kremke

Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

/s/ Charles J. Brown, III*

Charles J. Brown, III

Director

/s/ Mark Baker Cox*

Mark Baker Cox

Director

/s/ Francis C. D'Andrea*

Francis C. D'Andrea

Director

/s/ Eric D. Gadd*

Eric D. Gadd

Director

/s/ Assi Ginzburg

Assi Ginzburg

Director and Executive Vice President

/s/ Frederec Green

Frederec Green

Director and Executive Vice President

/s/ Ron W. Haddock

Ron W. Haddock

Director

99

/s/ Reuven Spiegel*

Reuven Spiegel

Director

*By:/s/ Kevin L. Kremke

Kevin L. Kremke

Individually and as Attorney-in-Fact

100

EX-3.2(B)

EXHIBIT 3.2(b)

AMENDMENT NO. 1 TO THE FIRST AMENDED AND RESTATED
AGREEMENT OF LIMITED PARTNERSHIP OF DELEK LOGISTICS PARTNERS, LP

This Amendment No. 1 (this “Amendment”) to the First Amended and Restated Agreement of Limited Partnership of Delek Logistics Partners, LP (the “Partnership”), dated as of November 7, 2012 (the “Partnership Agreement”), is hereby adopted effective as of January 27, 2018, by Delek Logistics GP, LLC, a Delaware limited liability company (the “General Partner”), as general partner of the Partnership.

RECITALS

WHEREAS, the General Partner desires to amend and restate Section 9.3 (Tax Controversies) and Section 9.4 (Withholding) of the Partnership Agreement in their entirety as a result of amendments made to the Code by the Bipartisan Budget Act of 2015 (the “BBA”); and

WHEREAS, pursuant to Section 6.3(c) and Section 9.4 of the Partnership Agreement, the General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners, as determined appropriate under the circumstances by the General Partner; and

WHEREAS, pursuant to Section 9.2(b) of the Partnership Agreement, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code; and

WHEREAS, pursuant to Section 9.3 of the Partnership Agreement, the General Partner is designated as the “tax matters partner” (as defined in Section 6231(a)(7) of the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith, and each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings; and

WHEREAS, Section 13.1(c) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement to reflect a change that the General Partner determines to be necessary or appropriate to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes; and

WHEREAS, Section 13.1(d)(i) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement to reflect a change that the General Partner determines does not adversely affect the Limited Partners considered as a whole or any particular class of Partnership Interests as compared to other classes of Partnership Interests in any material respect; and

WHEREAS, Section 13.1(d)(ii)(A) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement to reflect a change that the General Partner determines is necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act); and

WHEREAS, Section 13.1(d)(iv) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement to reflect a change that the General Partner determines is required to effect the intent expressed in the IPO Registration Statement or the intent of the provisions of the Partnership Agreement or is otherwise contemplated by the Partnership Agreement; and

WHEREAS, acting pursuant to the power and authority granted to it under Section 13.1(c) of the Partnership Agreement, the General Partner has determined that the following amendment to the Partnership Agreement is necessary or appropriate to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes; and

WHEREAS, acting pursuant to the power and authority granted to it under Section 13.1(d)(i) of the Partnership Agreement, the General Partner has determined that the following amendment to the Partnership Agreement does not adversely affect the Limited Partners considered as a whole or any particular class of Partnership Interests as compared to other classes of Partnership Interests in any material respect; and

WHEREAS, acting pursuant to the power and authority granted to it under Section 13.1(d)(ii)(A) of the Partnership Agreement, the General Partner has determined that the following amendment to the Partnership Agreement is necessary or appropriate to satisfy certain requirements, conditions or guidelines contained in the Code and the Treasury Regulations promulgated thereunder; and

WHEREAS, acting pursuant to the power and authority granted to it under Section 13.1(d)(iv) of the Partnership Agreement, the General Partner has determined that the following amendment to the Partnership Agreement is required to effect the intent expressed in the IPO Registration Statement or the intent of the provisions of the Partnership Agreement or is otherwise contemplated by the Partnership Agreement.

NOW, THEREFORE, the General Partner does hereby amend the Partnership Agreement as follows:

1.     INTERPRETATION     

This Amendment is made and delivered pursuant to the Partnership Agreement. Except as otherwise provided herein, capitalized terms used but not defined in this Amendment have the meanings ascribed to them in the Partnership Agreement.

2.     AMENDMENTS TO PARTNERSHIP AGREEMENT    

2.1Section 1.1 of the Partnership Agreement is hereby amended by inserting the following definitions alphabetically:

“BBA” means the Bipartisan Budget Act of 2015.

“Imputed Underpayment” means an imputed underpayment under Section 6225 of the Code, as amended by the BBA.

“Partnership Representative” has the meaning set forth in Section 6223 of the Code, as amended by the BBA.

“Tax Matters Partner” has the meaning set forth in Section 6231(a)(7) of the Code, prior to amendment by the BBA.

2

2.2Section 9.3 of the Partnership Agreement is hereby amended and restated in its entirety as follows:

Section 9.3     Tax Controversies.

(a)    For taxable years beginning on or before December 31, 2017, the General Partner is designated as the Tax Matters Partner. For each taxable year beginning after December 31, 2017, the General Partner shall be or shall designate the Partnership Representative and any other Persons necessary to conduct proceedings under Subchapter C of Chapter 63 of the Code (as amended by the BBA) for such year. Any such designated Person or Persons shall serve at the pleasure of, and act at the direction of, the General Partner. The Partnership Representative, as directed by the General Partner, shall exercise any and all authority of the “partnership representative” under the Code (as amended by the BBA), including, without limitation, (i) binding the Partnership and its Partners with respect to actions taken under Subchapter C of Chapter 63 of the Code (as amended by the BBA), and (ii) determining whether to make any available election under Section 6226 of the Code (as amended by the BBA).

(b) The General Partner (acting through the Partnership Representative to the extent permitted by Section 9.3(a)) is authorized and required to act on behalf of and represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and the General Partner is authorized to expend Partnership funds for professional services and costs associated therewith.

(c)    Each Partner agrees to cooperate with the General Partner (or its designee) and to do or refrain from doing any or all things reasonably requested by the General Partner (or its designee) in its capacity as the Tax Matters Partner or the Partnership Representative, or as a person otherwise authorized and required to act on behalf of and represent the Partnership pursuant to Section 9.3(b).

(d)    The General Partner is authorized to amend the provisions of this Agreement as appropriate to reflect the proposal or promulgation of Treasury Regulations implementing or interpreting the partnership audit, assessment and collection rules adopted by the BBA, including any amendments to those rules.

2.3Section 9.4 of the Partnership Agreement is hereby amended and restated in its entirety as follows:

Section 9.4     Withholding and Other Tax Payments by the Partnership.

(a)     If taxes and related interest, penalties or additions to tax are paid by the Partnership on behalf of all or less than all the Partners or former Partners (including, without limitation, any payment by the Partnership of an Imputed Underpayment), the General Partner may treat such payment as a distribution of cash to such Partners, treat such payment as a general expense of the Partnership, or, in the case of an Imputed Underpayment, require that persons who were Partners of the Partnership in the taxable year to which the payment relates (including former Partners) indemnify the Partnership upon request for their allocable share of that payment, in each case as determined appropriate under the circumstances by the General Partner. The amount of any such indemnification obligation of, or deemed distribution of cash to, a Partner or former Partner in respect of an Imputed Underpayment shall be reduced to the extent that the Partnership receives a reduction in the amount of the Imputed Underpayment which, in the determination of the General Partner, is attributable to actions taken

3

by, the tax status or attributes of, or tax information provided by or attributable to, such Partner or former Partner pursuant to or described in Section 6225(c) of the Code (as amended by the BBA).

(b)    Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income or from a distribution to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 or Section 12.4(c) in the amount of such withholding from such Partner.

3.     GENERAL

3.1Full Force and Effect.  Except to the extent specifically amended herein or supplemented hereby, the Partnership Agreement remains unchanged and in full force and effect, and this Amendment will be governed by and subject to the terms of the Partnership Agreement, as amended by this Amendment.

3.2Governing Law.  This Amendment shall be governed by, and interpreted in accordance with, the laws of the State of Delaware, all rights and remedies being governed by such laws without regard to principles of conflicts of laws.

3.3Counterparts.  This Amendment may be executed in one or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.

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4

EXHIBIT 3.2(b)

IN WITNESS WHEREOF, the General Partner has caused this Amendment to be duly executed as of the date first written above.

GENERAL PARTNER:

DELEK LOGISTICS GP, LLC

By:    /s/ Kevin Kremke    

Name: Kevin Kremke

Title: Executive Vice President and Chief Financial Officer

By:    /s/ Melissa M. Buhrig    

Name: Melissa M. Buhrig

Title: Executive Vice President, General Counsel and Secretary

EX-10.4

Exhibit 10.4

EXECUTIVE EMPLOYMENT AGREEMENT

This Executive Employment Agreement (the "Agreement") is entered into this 27th day of February, 2018, by and between ALAN P. MORET (the "Executive") and DELEK US ENERGY, INC. (the "Company"), who, in return for the mutual promises set forth herein, agree as follows:

1. Term. The term of this Agreement (the "Term") is effective as of January I, 2018 and shall expire on June 30, 2019 unless terminated earlier as provided for herein.

2. Scope of Employment. During the Tenn, the Company shall employ Executive and he shall render services to Company in the capacity of President of Delek Logistics GP, LLC, the General Partner of Delek Logistics Partners, LP ("DKL"), a subsidiary of Company, and as Executive Vice President of Delek US Holdings, Inc., the parent of Company, as well as such other titles as may be established by the Company from time to time. During the Term, Executive may also serve as an executive vice president of any affiliated or subsidiary entities of the Company required to be listed by the Company or DK under Item 60l(b)(21) of Regulation S-K of the United States Security and Exchange Commission (the "SEC"). Executive shall devote his full business time and best effort to the successful functioning of the Company's business and shall faithfully and industriously perform all duties pertaining to his position, including such additional duties as may be assigned from time to time, to the best of his ability, experience and talent; provided, however, that Executive may pursue charitable or civic activities, engage in passive personal investments, participate in industry association and trade groups, and serve as an executor, trustee or in other similar fiduciary capacities; provided that any such activities do not interfere with the performance of his responsibilities and obligations pursuant to this Agreement. Executive shall be subject at all times during the Term hereof to the direction and control of the Company's Board of Directors (the "Board") in respect of the work to be done.

3. Compensation.

(a) Base Compensation. During the Term, Executive's annual salary (the "Base Compensation") shall be (i) no less than the annualized equivalent of $400,000, (ii) subject to all appropriate federal and state withholding taxes, and (iii) payable at the same times and under the same conditions as salaries are paid to the Company's other employees in accordance with the normal payroll practices of the Company. The Base Compensation shall be reviewed and may be increased from time to time following the Effective Date by the Board (or any applicable committee thereof) in its sole discretion applied consistent with this Section 3(a). The Base Compensation shall at all times during the Term be, and remain, more than the compensation of Executive's subordinates at all times. If the Base Compensation is adjusted after the Effective Date, the Base Compensation defined above shall also be adjusted for all purposes of this Agreement.

(b) Annual Bonus. Executive will be eligible to participate in the Company's annual cash incentive plan at a level that is commensurate with Executive's positions as determined by the Board (or any committee thereof) in its sole and reasonable discretion. The Executive's Annual Bonus target for service during the 2018 fiscal year will be 75% of Executive's Base Compensation at December 31, 2018. The maximum Annual Bonus shall be 200% of such Annual Bonus target. The Annual Bonus may be based upon achievement of performance measures and objectives established by the Board from time to time. The Annual Bonus is typically paid in the first fiscal quarter of the year following the applicable bonus year. For purposes of this Agreement, an "Annual Bonus" shall mean a cash bonus, if any, awarded by the Company's Board of Directors (or any applicable Committee thereof) to Executive in recognition of

Executive's service during the preceding fiscal year in a manner consistent with the Company's

annual bonus program for senior executives.

(c) Long-TermIncentiveCompensation. Executive shall be eligible to participate in the Company's long-term incentive plans that may be in effect from time to time for the Company, its parent, and/or its subsidiaries including, without limitation, the Delek US Holdings, Inc. 2016 Long-Tenn Incentive Plan and the Delek Logistics GP, LLC 2012 Long-Tenn Incentive Plan (collectively, the "Plans") on terms commensurate with his position and duties, as determined by the Board or any other authorized administrator of a Plan (the "Plan Administrator") in their sole discretion. Program design, including, without limitation, performance measures and weighting, is at the sole discretion of the Plan Administrator. Executive acknowledges that he may be granted awards under Plans that are not subject to control of the Board or any applicable committee thereof). If so, the obligations of the Board (or any applicable committee thereof) hereunder including, without limitation, any obligations to accelerate the vesting of such award, shall be fully discharged as long as the Board (or any applicable committee thereof) uses reasonable efforts to ensure that such obligations are met by the applicable Plan Administrator.

4. Fringe Benefits/ Reimbursement of Business Expenses.

(a) General. The Company shall make available, or cause to be made available to him, throughout the period of his employment hereunder, such benefits, as may be put into effect from time to time by the Company generally for other senior Executives of the Company. The Company expressly reserves the right to modify such benefits available to Executive at any time provided that such modifications apply to other similarly situated employees.

(b) Business Expenses. Executive will be reimbursed for all reasonable out-of-pocket business, business entertainment and travel expenses paid by him in connection with the perfonnance of his duties for the Company, in accordance with and subject to applicable Company expense incurrence and reimbursement policies.

(c) Other Benefits. During the Tenn, the Company will pay the Executive's reasonable costs of professional tax and financial counseling, provided that, beginning with the calendar year 2018, the costs of such benefit does not exceed $25,000 in any calendar year. Perquisites and other personal benefits that are not integrally and directly related to the perfonnance of the Executive's duties and confer a direct or indirect benefit upon him that has a personal aspect may be disclosed in public filings according to the regulations of the SEC).

5. Vacation TimeISick Leave. Executive will be granted twenty-five (25) working days of vacation per calendar year. Unused vacation will accrue and carry over into a new calendar year during the Tenn and the amount attributed to accrued and unused vacation will be paid to the Executive upon the termination of employment. Vacation time shall be taken only after providing reasonable notice to the person to whom the Executive reports. Executive will be provided with sick leave according to the Company's standard policies.

6. Compliance With Company Policies. Executive shall comply with and abide by all applicable policies and directives of the Company, its parent and each of their subsidiaries including, without limitation, the Codes of Business Conduct & Ethics for the Company, its parent and each of their subsidiaries, the Supplemental Insider Trading Policies for the Company, its parent and each of their subsidiaries and any applicable employee handbooks or manuals. The Company, its parent and each of their subsidiaries may, in their sole discretion, change, modify or adopt new policies and directives affecting Executive's

employment. In the event of any conflict between the tenns of this Agreement and the employment policies and directives of the Company, its parent and each of their subsidiaries, the tenns of this Agreement will control. The Executive acknowledges that the Company's parent DK and its subsidiary DKL are currently subject to SEC reporting requirements pursuant to the Securities Exchange Act of 1934, as amended (the "Exchange Act"), the continued listing requirements of the New York Stock Exchange or any other securities exchange on which the securities of the Company may be listed from time to time for public trading (collectively a "Securities Market"), and other federal securities laws and regulations applicable to publicly traded companies in the United States. As an employee and officer of the Company and as an officer of DK and/or DKL, Executive will, in such capacities, be required to comply with applicable federal securities laws and regulations (including, without limitation, the reporting requirements under Exchange Act Section 16(a) and related SEC rules and regulations), Securities Market listing requirements as well as certain policies of the Company, its parent and each of their subsidiaries designed to comply with such laws and regulations.

7. Confidentiality. Executive recognizes that during the course of his employment, he will be exposed to infonnation or ideas of a confidential or proprietary nature that pertain to Company's business, financial, legal, marketing, administrative, personnel, technical or other functions or which constitute trade secrets (including, without limitation, specifications, designs, plans, drawings, software, data, prototypes, the identity of sources and markets, marketing infonnation and strategies, business and financial plans and strategies, methods of doing business, data processing and technical systems, programs and practices, customers and users and their needs, sales history, financial health or material non-public information as defined under federal securities law) (collectively "Confidential Information"). Confidential Information also includes such information of third parties that has been provided to Company in confidence. All such information is deemed "confidential" or "proprietary" whether or not it is so marked. Information will not be considered Confidential Information to the extent that it is or becomes generally available to the public other than through any breach of this Agreement by or at the discretion of Executive. Nothing in this Section will prohibit the use or disclosure by Executive of knowledge that is in general use in the industry or general business knowledge, was known to him prior to his service to the Company or which enters the public domain other than through any breach of this Agreement by or at the discretion of Executive. Executive may also disclose such information if required by court order or applicable law provided that he (a) uses his reasonable best efforts to give the Company written notice as far in advance as is practicable to allow the Company to seek a protective order or other appropriate remedy (except to the extent that his compliance with the foregoing would cause him to violate a court order or other legal requirement), (b) discloses only such infonnation as Executive believes in good faith to be required by law, and (c) uses his reasonable best efforts (at the Company's expense) to obtain confidential treatment for any Confidential Infonnation so disclosed. During Executive's employment and for so long as the Confidential Information remains confidential or proprietary thereafter, he shall hold Confidential Information in confidence, shall use it only in connection with the perfonnance of his duties on behalf of the Company, shall restrict its disclosure to those directors, employees or independent contractors of the Company with a need to know such Confidential Infonnation, and shall not disclose, copy or use Confidential Infonnation for the benefit of anyone other than the Company without the Company's prior written consent. However, nothing in this Agreement shall prohibit the Executive from reporting possible violations oflaw to any governmental agency or entity in accordance with applicable whistleblower protection provisions including, without limitation, the rules promulgated under Section 21F of the Exchange Act or Section 806 of the Sarbanes-Oxley Act of 2002, or require the Executive to notify the Company (or obtain its prior approval) of any such reporting. Executive shall, upon Company's request or his termination of employment, return to the Company and/or certify in a fonn satisfactory to the Company the destruction of any and all written documents containing Confidential Infonnation in his possession, custody or control. For the avoidance of doubt, Executive shall not retain any copy in any form of any Confidential Information following such request or tennination.

8. Restrictive Covenants.

(a) Non-Competition.

(i) In consideration of the Confidential Information provided to the Executive and the other benefits provided to him pursuant to this Agreement, Executive agrees that, if his employment ends during the Term, then, during a six month Non-Compete Period (as defined below), he will not, without the prior written consent of the Company (which shall not be unreasonably withheld), directly or indirectly, either as an individual or as an employee, officer, director, shareholder, partner, equity participant, sole proprietor, independent contractor, consultant or in any other capacity conduct any business, or assist any person in conducting any business, that is directly in competition with the Company's Business (as defined below) in the Territory (as defined below). It is expressly agreed and understood that this restriction is not intended to and shall not prevent Executive from employment or other engagement by a person or entity that competes with Company's Business as long as he does not personally compete or assist such person or entity in such restricted competition. The tenns of this Section 8(a) shall not apply to the ownership by Executive ofless than 5% of a class of equity securities of an entity, which securities are publicly traded on any national securities exchange.

(ii) For any termination except for a termination by the Company for Cause, the "Non­ Compete Period" shall commence upon the date that notice of termination of employment is delivered or deemed delivered under the notice provisions of this Agreement, it being acknowledged and agreed that the Non-Compete Period may commence to run, or even completely run, during a period of time during which the Executive remains employed by the Company (assuming that he continues to be so employed after the delivery of such notice of termination). In the event of a tennination by the Company for Cause, the Non-Compete Period shall commence upon the date that Executive's employment with the Company ends.

(iii) For purposes of this Section 8(a), the "Company's Business'' means the businesses conducted by the Company, its parent and each of their subsidiaries at the time of the termination of the Executive's employment over which he has primary responsibility at the time of the tennination of his employment (it being agreed and understood that other aspects of the businesses conducted by the Company, its parent and/or each of their subsidiaries is not within such definition).

(iv) For purposes of Section 8(a), the "Territory" shall mean the following geographic areas as of the commencement of the Non-Compete Period (A) a 75 mile radius from any of the Company's refining facilities, (B) a 75 mile radius from any of the Company's wholesale refined products distribution facilities and (C) a 50 mile radius from any of the Company's retail fuel and/or convenience merchandise facilities.

(b) Non-Interferencewith Commercial Relationships. During the Executive's employment with the Company, and for a period of six months thereafter, Executive will not, directly or indirectly, either as an individual or as an employee, officer, director, shareholder, partner, equity participant, sole proprietor, independent contractor, consultant or in any other capacity whatsoever approach or solicit any customer or vendor of Company for the purpose of causing, directly or indirectly, any such customer or vendor to cease doing business with the Company, its parent and/or each of their subsidiaries, nor will Executive engage in any other activity that

interferes or could reasonably be expected to interfere in any material way with the commercial relationships between the Company, its parent and each of their subsidiaries and snch customers or vendors. The foregoing covenant shall be in addition to any other covenants or agreements to which the Executive may be subject.

(c) Non-Interference with Employment Relationships. During the Executive's employment with the Company, and for a period of one year thereafter, Executive shall not, without the Company's prior written consent, directly or indirectly: (i) induce or attempt to induce any Company employee to terminate his/her employment with the Company; or (ii) interfere with or disrupt the Company's relationship with any of its employees or independent contractors. The foregoing does not prohibit the Executive (personally or as an employee, officer, director, shareholder, partner, equity participant, sole proprietor, independent contractor, consultant or in any other capacity) from hiring or employing an individual that contacts the Executive on his/her own initiative without any direct or indirect solicitation by the Executive other than customary fonns of general solicitation such as newspaper advertisements or internet postings.

(d) It is understood and agreed that the scope of each of the covenants contained in this Section 8 is reasonable as to time, area, and persons and is necessary to protect the legitimate business interest of the Company. It is further agreed that such covenants will be regarded as divisible and will be operative as to time, area and persons to the extent that they may be so operative.

9. Copyright, Inventions, Patents. The Company shall have all right, title and interest to all intellectual property (including, without limitation, graphic designs, cop,Tights, trademarks and patents) created during the course of the Executive's employment with the Company. The Executive hereby assigns to Company all copyright ownership and rights to any work developed by him or at his discretion and reduced to practice for or on behalf of the Company or which relate to the Company's business during the course of the employment relationship. At the Company's expense and for a period beginning on the Effective Date and continuing for three years following the termination of his employment, the Executive shall reasonably assist or support tbe Company to obtain, maintain, and assert its rights in such intellectual property and work product including, without limitation, the giving of evidence in suits and proceedings, and the furnishing and/or assigning of all documentation and other materials relative to the Company's intellectual property rights.

10. Termination of Employment.

(a) TenninationBy Company For Cause. The Company may immediately terminate this Agreement and/or the Executive's employment at any time for Cause. Upon any such tennination, the Company shall be under no further obligation to the Executive hereunder except as otherwise required by law, and the Company will reserve all further rights and remedies available to it at law or in equity.

(b) Tennination by Executive for Good Reason. Within 30 calendar days after Executive becomes (or should have become) aware of the occurrence of a Good Reason during the Term, Executive may tenninate this Agreement (and his employment hereunder) by providing 30 calendar days advance written notice of tennination and pro,ided that the condition remains uncured by the end of such 30-day period. After such 30-day period, Executive shall either resign his employment immediate or, if he continues in employment beyond such 30-day period, Executive shall have irrevocably waived and released any right to resign for Good Reason based upon the circumstances identified in his advance notice of tennination. In the event of any such tennination, Executive shall be entitled to the separation benefits under Section

(I 0)(c) as if the Company had tenninated his employment without Cause. This provision shall not apply if Executive is terminated by reason of death or Disability.

(c) Tennination At-Will By Company. Subject to the provisions of (f) below, the Company may terminate this Agreement (and Executive's employment hereunder) at any time and for any reason. If the termination occurs during the Tenn and is other than for Cause, Executive shall be entitled to the following (in addition to all accrued compensation and benefits through the date of tennination): (i) the Separation Payment, (ii) the costs of continuing family health insurance coverage under COBRA through November 26, 2020 following termination of employment, provided, that the Company may, in its sole discretion, (A) pay such amounts directly to the applicable provider or (B) pay an equivalent amount directly to Executive, (iii) the Post-Employment Annual Bonus and (iv) Accelerated Vesting upon tennination. This provision shall not apply if Executive is tenninated by reason of death or Disability.

(d) Termination At-Will By Executive. Executive may terminate this Agreement (and Executive's employment hereunder) at any time and for any reason (other than death or Disability). If the Executive tenninates this Agreement and his employment hereunder during the Tenn, the Executive must provide the Company with advance written notice of termination equal to the lesser of three months or the balance of the Term (the "Required Notice").

(i) If Executive terminates his employment during the Tenn other than for a Good Reason and provides at least three months advance written notice of termination (even if the Required Notice is less than three months), Executive shall be entitled to a single lump sum payment upon tennination equal to 50% of his annualized salary at the time the notice of termination is delivered and the costs of continuing family health insurance coverage under COBRA through November 26, 2020 following termination of employment, provided, that the Company may, in its sole discretion, (A) pay such amounts directly to the applicable provider or (B) pay an equivalent amount directly to Executive.

(ii) If Executive (A) terminates his employment during the Term other than for a Good Reason without providing the Required Notice or (B) fails to render services to the Company in a diligent and good faith manner after the delivery of the Required Notice and continues or repeats snch failure after receiving written notice of such failure, he shall receive compensation only in the manner stated in Section 10(a) and the Company may immediately tenninate his employment. This Section l0(d)(ii) shall not apply if Executive is terminated by reason of death or Disability.

This Section 10(d) shall not apply if the Executive is tenninated by reason of death or Disability.

(e) AcceleratedTenninationAfter Notice. Nothing herein shall limit the Company's right to terminate this Agreement and/or Executive's employment after the Company receives notice of tennination from him. However, if the Company receives the Required Notice from Executive and then tenninates this Agreement and/or his employment for any reason other than for Cause or under Section l0(d)(ii)(B), his employment shall tenninate on (and post­ employment provisions of Sections 7, 8(b), 8(c) and 9 shall be effective from) the date on which the Company terminates Executive's employment but he shall be entitled to a single lump sum payment of the amount of such compensation, bonuses, vesting and other benefits as if his tennination had been effective on the earlier of (i) the termination date specified in his notice oftennination or (ii) three months following his notice of termination.

(f) Separation Release. Notwithstanding anything to the contrary, but subject to any applicable six-month delay required by Section 18 hereof and Section 409A of the Internal Revenue Code of 1986, as amended ("Section 409A"), if a payment is otherwise payable to Executive hereunder, payment of such Separation Payment shall be payable in cash to him at the end of the month following the month in which his separation from service (within the meaning of Section 409A) occurs (or such later date as may be required by law). However, Executive's right to receive the Separation Payment shall be conditioned upon (i) his execution and delivery to the Company of a Separation Release (and the expiration of any statutorily mandated revocation period) within 30 days (or such longer period as may be required by law) following the separation from service date and (ii) his continued compliance with this Agreement and any other restrictive covenants to which he is bound. If Executive fails to timely execute and deliver the Separation Release or if he timely revokes his acceptance of the Separation Release thereafter (if such revocation is pennitted), he shall not be entitled to the Separation Payment and shall repay any Separation Payment received. If the foregoing consideration and revocation periods begin in one taxable year and end in a second taxable year, payment will be made in the second taxable year.

(g) Definitions. The following tenns shall have the following meanings as used in this Agreement:

(i) "Accelerated Vesting" means the immediate vesting of all unvested equity awards granted to Executive under the Plans. However, any Accelerated Vesting that occurs other than in the context of a Change in Control will apply to unvested (A) performance awards on a prorated basis through the termination of employment, based on actual results evaluated after the close of the applicable perfonnance period and payable in a lump sum at the same time as perfonnance awards are paid to executives of the Company generally and (B) full value equity awards (e.g., restricted stock, restricted stock units and phantom units) and appreciation equity awards (e.g., non-qualified stock options and stock appreciation rights) only to the extent that such awards that would have vested if Executive's employment had continued during a period equal to the lesser of six months following termination of employment or the balance of the Tenn.

(ii) "Cause" means Executive's: (A) fraud, gross negligence, willful misconduct involving the Company or its affiliates or willful breach of a fiduciary duty, including, without limitation, Section 7 hereof, owed to the Company or its affiliates, (B) conviction of, or plea of nolo contendere to, a felony or crime involving moral turpitude or

(C) deliberate and continual refusal to perform his duties in any material respect on substantially a full-time basis or to act in accordance with any specific and lawful instruction of his supervisor provided that Executive has been given written notice of such conduct and such conduct is not cured within 30 days thereafter.

(iii) "Disability" means the inability of Executive to perform the customary duties of his employment or other service with the Company or its affiliates by reason of a physical or mental incapacity or illness that is expected to result in death or to be of indefinite duration, as determined by a duly licensed physician selected by the Company.

(iv) "Post-Employment Annual Bonus" shall mean the Annual Bonus to which Executive would have otherwise been entitled if his employment had continued through the end of the bonus year based upon the actual perfonnance of the Company, prorated for the period of actual employment during the bonus year, and paid upon the payment of the

annual bonuses to senior executives of the Company pursuant to the Company's annual bonus programs.

(v) "Separation Payment" shall mean an amount equal to sum of Executive's Base Compensation and Annual Bonus as in effect before any notice of termination multiplied by (A) two in the case of a Change in Control or (B) one in all other cases. The Separation Payment shall be payable in a cash lump sum pursuant to Section IO(f). Executive shall have no responsibility for mitigating the amount of any payment provided for herein by seeking other employment or otherwise, and any such payment will not be reduced in the event such other employment is obtained.

(vi) "Separation Release" means a general release of claims against the Company (and its subsidiaries and affiliates) in a fonn reasonably satisfactory to Executive and the Company that pertains to all claims related to Executive's employment and the termination of his employment and that contains appropriate anti-disparagement and continuing confidentiality covenants.

11. Change in Control.

(a) If Executive's employment is tenninated by the Company without Cause or by Executive for Good Reason within two years following a Change in Control, the tennination of his employment shall be deemed to have occurred in the context of a Change in Control, and he shall be entitled to the separation benefits set forth in Section I0(c); provided, however, that if the separation benefits would result in an excess parachute payment under Internal revenue Code Section 280G(a), the separation benefits shall be reduced so as not to result in an excess parachute payment.

(b) For purposes of this Agreement, a "Change in Control" of the Company shall mean any of the following:

(i) Any "person" (as defined in Section 13(h)(8)(E) of the Exchange Act), other than the Company or any of its subsidiaries or any employee benefit plan of the Company or any of its subsidiaries, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Company (or any successor to all or substantially all of the Company's assets) representing more than 30% of the combined voting power of the Company's (or such successor's) then outstanding voting securities that may be cast for the election of directors of the Company (other than as a result of an issuance of securities initiated by the Company (or such successor) in the ordinary course of business);

(ii) As the result of, or in connection with, any cash tender or exchange offer, merger or other business combination or contested election, or any combination of the foregoing transactions, less than 51% of the combined voting power of the then outstanding securities of the Company or any successor company or entity entitled to vote generally in the election of the directors of the Company or such other corporation or entity after such transaction are held in the aggregate by the holders of the Company's securities entitled to vote generally in the election of directors of the Company immediately prior to such transaction;

(iii) All or substantially all of the assets of the Company are sold, exchanged or otherwise

transferred;

(iv) The Company's stockholders approve a plan of liquidation or dissolution of the

Company; or

(v) During any 12-month period within the Tenn, Continuing Directors cease for any reason to constitute at least a majority of the Board. For this purpose, a "Continuing Director" is any person who at the beginning of the Term was a member of the Board, or any person first elected to the Board during the Tenn whose election, or the nomination for election by the Company's shareholders, was approved by a vote of at least two-thirds of the Continuing Directors then in office, but excluding any person

(A)initially appointed or elected to office as result of either an actual or threatened election and/or proxy contest by or on behalf of any "person" or "group" (within the meaning of Section l 3(d) of the Exchange Act) other than the Board, or (B) designated by any "person" or "group'' (within the meaning of Section 13(d) of the Exchange Act)

) who has entered into an agreement with the Company to effect a transaction described in Section l l(b)(i) through (iv).

12. Survival ofTenns. The provisions of Sections 7, 8(b), 8(c), 9 and 10 shall survive the termination or expiration of this Agreement and will continue in effect following the termination of Executive's employment for the periods described therein. If a Change in Control occurs during the Tern,, the provisions of Section 11 shall survive the termination or expiration of this Agreement and will continue in effect following the Change in Control for the periods described therein. The provisions of Section 8(a) shall survive the termination (but not the expiration) of this Agreement.

13. Assignment. This Agreement shall not be assignable by either party without the written consent of the other party except that the Company may assign this Agreement to its parent, a subsidiary, or an affiliate of the Company. Any failure by the Company to assign this Agreement to an unaffiliated third party successor upon the Company's sale or transfer of all or substantially all of its business will be considered the termination of Executive's employment in the context ofa Change in Control effective upon the closing of the applicable transaction without an assignment to the successor, which closing constitutes a Change in Control. Any failure by Executive to consent to the assignment of this Agreement to such unaffiliated third party successor will be considered the tennination of his employment for a Good Reason other than in the context of a Change in Control effective upon the closing of the applicable Change in Control transaction without any assignment to the successor. For the avoidance of doubt, the parties acknowledge that the payment of any benefits under this Section 13 sha11 be made in accordance with the applicable provision of Section 10 or 11 of this Agreement within 30 days of the closing date of the Change in Control transaction, and no payments wi11 be made pursuant to this Section 13 if a Change in Control transaction does not occur.

14. No InducementIAgreement Voluntary. Executive represents that (a) he has not been pressured, misled, or induced to enter into this Agreement based upon any representation by Company or its agents not contained herein, (b) he has entered into tbis Agreement voluntarily, after having the opportunity to consult with representatives of his own choosing and (c) his assent is freely given.

15. Interpretation. Any Section, phrase or other provision of this Agreement that is detennined by a court, arbitrator or arbitration panel of competent jurisdiction to be unreasonable or in conflict with any applicable statute or rule, shall be deemed, if possible, to be modified or altered so that it is not unreasonable or in conflict or, if that is not possible, then it sha11 be deemed omitted from this Agreement. The invalidity of any portion of this Agreement shall not affect the validity of the remaining

portions. Unless expressly stated to the contrary, all references to "days" in this Agreement shall mean calendar days.

16. Prior AgreementsIAmendments. This Agreement (a) represents the entire agreement between the parties in relation to the employment of Executive by the Company on, and subsequent to, the Effective Date and (b) revokes and supersedes all prior agreements pertaining to the subject matter herein, whether written and oral. However, this Agreement does not nullify or otherwise affect any prior equity awards granted to Executive. This Agreement shall not be subject to modification or amendment by any oral representation, or any written statement by either party, except for a dated writing signed by Executive and the Company.

17. Notices. All notices of any kind to be delivered in connection with this Agreement shall be in writing and shall be deemed to have been duly given if personally delivered or if sent by nationally-recognized overnight courier (e.g., FedEx, UPS, etc.) or by registered or certified mail, return receipt requested and postage prepaid, addressed to the Company at 7102 Commerce Way, Brentwood, Tennessee 37027, Attn: General Counsel, to the Executive at his then-existing payroll address, or to such other address as the party to whom notice is to be given may have furnihed to the other in writing in accordance with the provisions of this Section. Any such notice or communication shall be deemed to have been received: (a) if by personal delivery or nationally-recognized overnight courier, on the date of such delivery and (b) if by registered or certified mail, on the third postal service day following the date postmarked.

l8. Applicable Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Tennessee without giving effect to its principles of conflicts of law. The state and federal courts for Davidson County, Tennessee shall be the exclusive venue for any litigation based in significant part upon this Agreement.

19. Mediation/ Arbitration

(a) Any dispute concerning a legally cognizable claim arismg out of this Agreement or in connection with the employment of Executive by Company, including, without limitation, claims of breach of contract, fraud, unlawful termination, discrimination, harassment, retaliation, defamation, tortious infliction of emotional distress, unfair competition, arbitrability and conversion (collectively a "Legal Dispute") shall be resolved according to the following protocol:

(i) The parties shall first submit the Legal Dispute to mediation under the auspices of the American Arbitration Association ("AAA") and pursuant to the mediation rules and procedures promulgated by the AAA. The Company shall pay the expenses associated with the mediation.

(ii) In the event mediation is unsuccessful in fully resolving the Legal Dispute, binding arbitration shall be the method of final resolution. The parties expressly waive their rights to bring action against one another in a court oflaw except as expressly provided herein. In addition to remedies at law, the parties acknowledge that failure to comply with this provision shall entitle the non-breaching party to injunctive relief to enjoin the actions of the breaching party. Any Legal Dispute submitted to Arbitration shall be under the auspices of the AAA and pursuant to the "National Rules for the Resolution of Employment Disputes," or any similar identified rules promulgated at such time the Legal Dispute is submitted for resolution. All mediation and arbitration hearings shall take place in either Davidson or Williamson County, Tennessee. The Company shall pay the filing expenses associated with the arbitration. All other expenses and fees associated with the arbitration shall be determined in accordance with the AAA rules.

(b) Notice of submission of any Legal Dispute to mediation shall be provided no later than one year following the date the submitting party became aware, or should have become aware of, the conduct constituting the alleged claims. Failure to do so shall result in the irrevocable waiver of the claim made in the Legal Dispute.

(c) Notwithstanding that mediation and arbitration are established as the exclusive procedures for resolution of any Legal Dispute, (i) either party may apply to an appropriate judicial or administrative forum for injunctive relief and (ii) claims by Company arising in connection with Sections 7, 8, 9, 10 and/or 11 may be brought in any court of competent jurisdiction.

(d) With respect to any breach or attempted breach of Sections 7, 8 and/or 9 of this Agreement, each party acknowledges that a remedy at law will be inadequate, agrees that the Company will be entitled to specific perfonnance and injunctive and other equitable relief and agrees not to nse as a defense that any party has an adequate remedy at law. This Agreement shall be enforceable in a court of equity, or other tribunal with jurisdiction, by a decree of specific performance, and appropriate injunctive relief may be applied for and granted in connection herewith. Such remedy shall not be exclusive and shall be in addition to any other remedies now or hereafter existing at law or in equity, by statute or otherwise. No delay or omission in exercising any right or remedy set forth in this Agreement shall operate as a waiver thereof or of any other right or remedy and no single or partial exercise thereof shall preclude any other or further exercise thereof or the exercise of any other right or remedy.

20. Section 409A.

(a) It is intended that each installment of the payments provided under this Agreement, if any, is a separate "payment" for purposes of Section 409A and the payments satisfy, to the greatest extent possible, the exemptions from the application of Section 409A provided under Treasury Regulations l.409A-l(b)(4), l.409A-l(b)(9)(iii) and l.409A-l(b)(9)(v). Notwithstanding any other provision to the contrary, a tennination of employment with the Company shall not be deemed to have occurred for purposes of any provision of this Agreement providing for the payment of"deferred compensation" (as such term is defined in Section 409A and the Treasury Regulations promulgated thereunder) upon or following a tennination of employment unless such termination is also a "separation from service" from the Company within the meaning of Section 409A and Section l .409A-l(h) of the Treasury Regulations and, for purposes of any such provision of this Agreement, references to a "separation," "termination," "tennination of employment" or like terms shall mean "separation from service.'·

(b) Notwithstanding anything to the contrary in this Agreement, if the Company detennines (i) that on the date his employment with the Company terminates or at such other time that the Company determines to be relevant, Executive is a "specified employee" (as such term is defined under Treasury Regulation 1.409A-l (i)(l)) of the Company and (ii) that any payments to be provided to him pursuant to this Agreement are or may become subject to the additional tax under Section 409A(a)(l)(B) or any other taxes or penalties imposed under Section 409A if provided at the time otherwise required under this Agreement, then such payments shall be delayed until the date that is six months after the date of his "separation from service" (as such tennis defined under Treasury Regulation 1.409A-l(h)) with the Company, or, if earlier, the date of his death. Any payments delayed pursuant to this Section shall be made in a lump sum

on the first business day of the seventh month following Executive's "separation from service'' (as such tenn is defined under Treasury Regulation 1.409A-1(h)), or, if earlier, the date of his death,

(c) In addition, to the extent that any reimbursement, fringe benefit or other, similar plan or arrangement in which Executive participates during the tenn of his employment under this Agreement or thereafter provides for a "deferral of compensation" within the meaning of Section 409A, then such amount shall be reimbursed in accordance with Section 1.409A- 3(i)(l)(iv) of the Treasury Regulations, including (i) the amount eligible for reimbursement or payment under such plan or arrangement in one calendar year may not affect the amount eligible for reimbursement or pay1nent in any other calendar year (except that a plan providing medical or health benefits may impose a generally applicable limit on the amount that may be reimbursed or paid), (ii) subject to any shorter time periods provided herein or the applicable plans or arrangements, any reimbursement or payment of an expense under such plan or arrangement must be made on or before the last day of the calendar year following the calendar year in which the expense was incurred, and (iii) the right to any reimbursement or in-kind benefit is not subject to liquidation or exchange for another benefit,

(d) For the avoidance of doubt, any payment due under this Agreement within a period following Executive's termination of employment or other event, shall be made on a date during such period as determined by the Company in its sole discretion

(e) Notwithstanding any other provision to the contrary, in no event shall any payment under this Agreement that constitutes "deferred compensation" for purposes of Section 409A and the Treasury Regulations promulgated thereunder be subject to offset by any other amount unless otherwise pennitted by Section 409A,

(f) This Agreement is intended to comply with the applicable requirements under Section 409A and the related Treasury Regulations and guidance issued by the Depai1ment of the Treasury, as modified from time to time, including exceptions and exemptions provided for therein (the "409A Requirements"). Accordingly, this Agreement shall be administered, construed and interpreted in a manner to comply with the 409A Requirements. Specifically, and without limiting the foregoing, if any terms set forth in this Agreement are considered to be ambiguous, such tenns shall be administered, construed and interpreted in a manner to comply with the 409A Requirements.

In witness whereof: the parties have executed this Agreement as of the 27th day of February, 2018.

COMPANY: DELEK US ENERGY, INC.    EXECUTIVE:

By:/s/ Jared Serff         By: /s/ Alan Moret

Name: Jared Serff          Name: Alan Moret

Title: Executive Vice President      Title: President

By:/s/ Kevin Kremke

Name: Kevin Kremke

Title: Executive Vice President and Chief Financial Officer

EX-21.1

EXHIBIT 21.1

Delek Logistics Partners, LP

Subsidiaries of the Registrant

Company Name:	State of Incorporation:
Delek Logistics Operating, LLC	DE
Delek Marketing & Supply, LP	DE
Delek Marketing GP, LLC	DE
Delek Crude Logistics, LLC	TX
Delek Marketing-Big Sandy, LLC	TX
Paline Pipeline Company, LLC	TX
Magnolia Pipeline Company, LLC	DE
SALA Gathering Systems, LLC	TX
El Dorado Pipeline Company, LLC	DE
DKL Transportation, LLC	DE
DKL Caddo, LLC	DE
DKL RIO, LLC	DE

EX-23.1

EXHIBIT 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statement (Form S-8 No. 333-185264) pertaining to the Delek Logistics GP, LLC 2012 Long-Term Incentive Plan of our reports dated February 28, 2018, with respect to the consolidated financial statements of Delek Logistics Partners, LP, and the effectiveness of internal control over financial reporting of Delek Logistics Partners, LP, included in this Annual Report (Form 10-K) for the year ended December 31, 2017.

/s/ Ernst & Young LLP

Nashville, Tennessee

February 28, 2018

EX-24.1

EXHIBIT 24.1

POWER OF ATTORNEY

Each person whose signature appears below appoints EZRA UZI YEMIN and KEVIN KREMKE, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign the Delek Logistics Partners, LP Annual Report on Form 10-K for the year ended December 31, 2017 and any and all future amendments thereto; and to file said Form 10-K and any such amendments with all exhibits thereto, and any and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

This power of attorney may be executed in counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument.

In witness whereof, the undersigned have hereunto set their hands and seals as of the date set forth below.

/s/ Ezra Uzi Yemin	/s/ Frederec Green
Ezra Uzi Yemin	Frederec Green
Date: February 26, 2018	Date: February 26, 2018
/s/ Charles J. Brown III	/s/ Ron W. Haddock
Charles J. Brown III	Ron W. Haddock
Date: February 26, 2018	Date: February 26, 2018
/s/ Mark Baker Cox	Reuven Spiegel
Mark Baker Cox	Reuven Spiegel
Date: February 26, 2018	Date: February 26, 2018
/s/ Francis C. D’Andrea
Francis C. D'Andrea
Date: February 26, 2018
/s/ Eric D. Gadd
Eric D. Gadd
Date: February 26, 2018
/s/ Assi Ginzburg
Assi Ginzburg
Date: February 26, 2018

EX-31.1

EXHIBIT 31.1

Certification by Chief Executive Officer pursuant to

Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,

As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Ezra Uzi Yemin, certify that:

1. I have reviewed this annual report on Form 10-K of Delek Logistics Partners, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:	/s/ Ezra Uzi Yemin
	Ezra Uzi Yemin,
	Chairman and Chief Executive Officer (Principal Executive Officer) of Delek Logistics GP, LLC (the general partner of Delek Logistics Partners, LP)

Dated: February 28, 2018

EX-31.2

EXHIBIT 31.2

Certification by Chief Financial Officer pursuant to

Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,

As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Kevin Kremke, certify that:

1. I have reviewed this annual report on Form 10-K of Delek Logistics Partners, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:	/s/ Kevin Kremke
	Kevin Kremke,
	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) of Delek Logistics GP, LLC (the general partner of Delek Logistics Partners, LP)

Dated: February 28, 2018

EX-32.1

EXHIBIT 32.1

Certification Pursuant to

18 U.S.C. Section 1350,

as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the annual report of Delek Logistics Partners, LP (the “Partnership”) on Form 10-K for the year ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Ezra Uzi Yemin, Chairman and Chief Executive Officer of Delek Logistics GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, and to the best of my knowledge, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/s/ Ezra Uzi Yemin
	Ezra Uzi Yemin,
	Chairman and Chief Executive Officer (Principal Executive Officer) of Delek Logistics GP, LLC (the general partner of Delek Logistics Partners, LP)

Dated: February 28, 2018

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

EXHIBIT 32.2

Certification Pursuant to

18 U.S.C. Section 1350,

as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the annual report of Delek Logistics Partners, LP (the “Partnership”) on Form 10-K for the year ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kevin Kremke, Executive Vice President and Chief Financial Officer of Delek Logistics GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, and to the best of my knowledge, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/s/ Kevin Kremke
	Kevin Kremke,
	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) of Delek Logistics GP, LLC (the general partner of Delek Logistics Partners, LP)

Dated: February 28, 2018

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document and Entity Information Document - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 22, 2018	Jun. 30, 2017
Entity Information [Line Items]
Entity Registrant Name	Delek Logistics Partners, LP
Entity Central Index Key	0001552797
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 296,957,710
Common Units
Entity Information [Line Items]
Common Stock, Shares, Outstanding		24,382,633
General Partner
Entity Information [Line Items]
Common Stock, Shares, Outstanding		497,604

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 4,675	$ 59
Accounts receivable	23,013	19,202
Accounts receivable from related parties	1,124	2,834
Inventory	20,855	8,875
Other current assets	783	1,071
Total current assets	50,450	32,041
Property, plant and equipment:
Property, plant and equipment	367,179	342,407
Less: accumulated depreciation	(112,111)	(91,378)
Property, plant and equipment, net	255,068	251,029
Equity method investments	106,465	101,080
Goodwill	12,203	12,203
Intangible assets, net	15,917	14,420
Other non-current assets	3,427	4,774
Total assets	443,530	415,547
Current liabilities:
Accounts payable	19,147	10,853
Excise and other taxes payable	4,700	4,841
Tank inspection liabilities	902	1,013
Pipeline release liabilities	1,000	1,097
Accrued expenses and other current liabilities	6,033	2,925
Total current liabilities	31,782	20,729
Non-current liabilities:
Long-term debt	422,649	392,600
Asset retirement obligations	4,064	3,772
Other non-current liabilities	14,260	11,730
Total non-current liabilities	440,973	408,102
Deficit:
Total deficit	(29,225)	(13,284)
Total liabilities and deficit	443,530	415,547
General partner - 497,604 units issued and outstanding at December 31, 2017 (496,502 at December 31, 2016)
Deficit:
Total deficit	(6,397)	(6,221)
Common unitholders - public; 9,088,587 units issued and outstanding at December 31, 2017 (9,263,415 at December 31, 2016) | Limited Partner
Deficit:
Total deficit	174,378	188,013
Common unitholders - Delek; 15,294,046 units issued and outstanding at December 31, 2017 (15,065,192 at December 31, 2016) | Limited Partner
Deficit:
Total deficit	$ (197,206)	$ (195,076)

XML

Consolidated Balance Sheets (Parentheticals) - shares	Dec. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Partners' capital account, units	24,880,237	24,825,109		24,772,234	24,709,902
General Partners' Capital Account, Units Outstanding	497,604	496,502
Common - Public
Limited Partners' capital account, units outstanding	9,088,587	9,263,415
Common - Delek
Limited Partners' capital account, units outstanding	15,294,046	15,065,192
Subordinated- Delek
Limited Partners' capital account, units outstanding	0	0	11,999,258
Limited Partner | Common - Public
Partners' capital account, units	9,088,587	9,263,415		9,478,273	9,417,189
Limited Partner | Common - Delek
Partners' capital account, units	15,294,046	15,065,192		2,799,258	2,799,258
Limited Partner | Subordinated- Delek
Partners' capital account, units	0	0		11,999,258	11,999,258
General Partner
Partners' capital account, units	497,604	496,502		495,445	494,197

XML

Consolidated Statements of Income and Comprehensive Income - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net Sales:
Affiliate	[1]	$ 156,280	$ 149,564	$ 152,564
Third party		381,795	298,495	437,105
Net sales		538,075	448,059	589,669
Operating costs and expenses:
Cost of goods sold		372,890	302,158	436,304
Operating expenses		43,274	37,198	44,923
General and administrative expenses		11,840	10,256	11,384
Depreciation and amortization		21,914	20,813	19,692
(Gain) loss on asset disposals		(20)	(16)	104
Total operating costs and expenses		449,898	370,409	512,407
Operating income		88,177	77,650	77,262
Interest expense, net		23,944	13,587	10,658
(Income) loss from equity method investments		(4,953)	1,178	588
Other income, net		(1)	0	0
Total non-operating expenses		18,990	14,765	11,246
Income before income tax (benefit) expense		69,187	62,885	66,016
Income tax (benefit) expense		(222)	81	(195)
Net income		69,409	62,804	66,211
Less: loss attributable to Predecessors		0	0	(637)
Net income attributable to partners		69,409	62,804	66,848
Comprehensive income attributable to partners		69,409	62,804	66,848
Less: General partner's interest in net income, including incentive distribution rights		18,429	12,193	5,163
Limited partners' interest in net income		$ 50,980	$ 50,611	$ 61,685
Weighted average limited partner units outstanding:
Cash distributions per limited partner unit		$ 2.835	$ 2.575	$ 2.2400
Common Units
Net income per limited partner unit:
Common units - (basic)	[2]	2.09	2.08	2.55
Common units - (diluted)	[2]	$ 2.09	$ 2.07	$ 2.52
Weighted average limited partner units outstanding:
Common units - (basic)	[2]	24,348,063	22,490,264	12,237,154
Common units - (diluted)	[2]	24,376,972	22,558,717	12,356,914
Subordinated- Delek
Net income per limited partner unit:
Subordinated units - Delek (basic and diluted)	[2]	$ 0.00	$ 2.19	$ 2.54
Weighted average limited partner units outstanding:
Subordinated units - Delek (basic and diluted)	[2]	0	1,803,167	11,999,258

[1] See Note 4 for a description of our material affiliate revenue transactions.

[2] We base our calculation of net income per unit on the weighted-average number of common and subordinated limited partner units outstanding during the period. The weighted-average number of common and subordinated units reflect the conversion of the subordinated units to common units on February 25, 2016. See Notes 5 and 12 for further discussion.

XML

Consolidated Statements of Partners' Equity (Deficit) - USD ($) $ in Thousands		Total		Equity of Predecessors	Limited Partner Common - Public	Limited Partner Common - Delek	Limited Partner Subordinated- Delek	General Partner
Beginning balance at Dec. 31, 2014		$ 39,781		$ 19,726	$ 194,737	$ (241,112)	$ 73,515	$ (7,085)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Sponsor contributions of equity to the Predecessor		115		115
Loss attributable to Predecessor		(637)		(637)
Allocation of net assets acquired by the unitholders				(19,204)		18,820		384
Cash distributions	[1]	(118,528)			(20,755)	(66,698)	(25,919)	(5,156)
Sponsorship contribution of fixed assets		584				573		11
Net income attributable to partners		66,848			24,039	7,121	30,525	5,163
Unit-based compensation		406			740	219	940	(1,493)
Other		413			(360)	249	(460)	984
Ending balance at Dec. 31, 2015		(11,018)		0	198,401	(280,828)	78,601	(7,192)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Sponsor contributions of equity to the Predecessor		0
Loss attributable to Predecessor		0
Cash distributions	[2]	(70,865)			(23,847)	(25,271)	(11,503)	(10,244)
Sponsorship contribution of fixed assets		5,167				5,063		104
Net income attributable to partners		62,804			19,667	27,002	3,942	12,193
Unit-based compensation		599			664	1,046		(1,111)
Subordinated unit conversion						71,040	(71,040)
Delek unit repurchases from public					(6,872)	6,872
Other		29						29
Ending balance at Dec. 31, 2016		(13,284)		0	188,013	(195,076)	0	(6,221)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Sponsor contributions of equity to the Predecessor		0
Loss attributable to Predecessor		0
Cash distributions		(86,159)	[3]		(25,978)	(42,490)		(17,691)
Sponsorship contribution of fixed assets		67				65		2
Net income attributable to partners		69,409			19,015	31,965		18,429
Unit-based compensation		721			619	1,039		(937)
Delek unit repurchases from public					(7,291)	7,291
Other		21						21
Ending balance at Dec. 31, 2017		$ (29,225)		$ 0	$ 174,378	$ (197,206)	$ 0	$ (6,397)

[1] Cash distributions include $61.9 million in cash payments for the El Dorado Rail Offloading Racks Acquisition and the Tyler Crude Tank Acquisition. As an entity under common control with Delek, we record the assets that we acquire from Delek on our balance sheet at Delek's historical book basis instead of fair value. Additionally, any excess of cash paid over the historical book basis of the assets acquired from Delek is recorded within equity. As a result of the El Dorado Rail Offloading Racks Acquisition and the Tyler Crude Tank Acquisition, our equity balance decreased $42.7 million during the year ended December 31, 2015. Distributions also include $0.4 million related to distribution equivalents on vested phantom units.

[2] Cash distributions include $0.3 million related to distribution equivalents on vested phantom units.

[3] Cash distributions include $0.5 million related to distribution equivalents on vested phantom units.

XML

Consolidated Statements of Partners' Equity (Deficit) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Distribution equivalents on vested phantom units	$ 0.5	$ 0.3	$ 0.4
El Dorado Terminal and Tank Assets
Cash payments for acquisitions		61.9
Tyler Terminal and Tank Assets
Decrease in equity balance due to acquisitions		$ 42.7

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income	$ 69,409	$ 62,804	$ 66,211
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	21,914	20,813	19,692
Amortization of deferred revenue	(1,234)	(1,085)	(596)
Amortization of deferred financing costs and debt discount	2,048	1,460	1,460
Accretion of asset retirement obligations	292	266	251
Loss (gain) on asset disposals	(20)	(16)	104
Deferred income taxes	(111)	(173)	14
(Income) loss from equity method investments	(4,953)	1,178	588
Dividends from equity method investments	3,099	0	0
Unit-based compensation expense	721	599	406
Changes in assets and liabilities:
Accounts receivable	(3,811)	15,847	(7,197)
Inventories and other current assets	(11,692)	2,045	(907)
Accounts payable and other current liabilities	10,859	3,551	(13,734)
Accounts receivable/payable to related parties	1,682	(6,983)	1,737
Non-current assets and liabilities, net	(500)	401	(5)
Net cash provided by operating activities	87,703	100,707	68,024
Cash flows from investing activities:
Asset acquisitions	(9,003)	0	(400)
Purchases of property, plant and equipment	(18,184)	(11,287)	(19,956)
Proceeds from sales of property, plant and equipment	46	175	1,198
Equity method investments	(3,531)	(61,580)	(37,434)
Net cash used in investing activities	(30,672)	(72,692)	(56,592)
Cash flows from financing activities:
Proceeds from issuance of additional units to maintain 2% General Partner interest	21	29	50
Distributions to general partner	(17,691)	(10,244)	(3,918)
Distributions to common unitholders - public	(25,978)	(23,847)	(20,755)
Distributions to common unitholders - Delek	(42,490)	(25,271)	(6,046)
Distributions to subordinated unitholders - Delek	0	(11,503)	(25,919)
Distributions to Delek for acquisitions	0	0	(61,890)
Proceeds from revolving credit facility	277,100	314,750	396,400
Payments of revolving credit facility	(489,800)	(273,750)	(296,550)
Proceeds from issuance of senior notes	248,112	0	0
Deferred financing costs paid	(5,951)	0	0
Predecessor division equity contribution	0	0	115
Reimbursement of capital expenditures by Delek	4,262	1,880	5,220
Net cash used in financing activities	(52,415)	(27,956)	(13,293)
Net increase (decrease) in cash and cash equivalents	4,616	59	(1,861)
Cash and cash equivalents at the beginning of the period	59	0	1,861
Cash and cash equivalents at the end of the period	4,675	59	0
Cash paid during the period for:
Interest	19,441	12,206	9,009
Income taxes	60	224	4
Non-cash investing activities:
Equity method investments	0	0	3,832
Increase in accrued capital expenditures	194	480	2,471
Non-cash financing activities:
Sponsor contribution of fixed assets	$ 67	$ 5,167	$ 584

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General General

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

General

General

Organization

As used in this report, the terms "Delek Logistics Partners, LP," the "Partnership," "we," "us," or "our" may refer to Delek Logistics Partners, LP, one or more of its consolidated subsidiaries or all of them taken as a whole.

The Partnership is a Delaware limited partnership formed in April 2012 by Old Delek (as defined below) and its subsidiary Delek Logistics GP, LLC, our general partner (our "general partner').

In January 2017, Delek US Holdings, Inc. ("Old Delek") (and various related entities) entered into an Agreement and Plan of Merger with Alon USA Energy, Inc. (NYSE: ALJ) ("Alon USA"), as subsequently amended on February 27 and April 21, 2017 (as so amended, the "Merger Agreement"). The related merger (the "Delek/Alon Merger") was effective July 1, 2017 (the “Effective Time”), resulting in a new post-combination consolidated registrant renamed Delek US Holdings, Inc. (“New Delek”), with Alon USA and Old Delek surviving as wholly-owned subsidiaries. New Delek is the successor issuer to Old Delek and Alon USA pursuant to Rule 12g-3(c) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Unless the context otherwise requires, references in this report to "Delek" refer collectively to Old Delek with respect to periods prior to July 1, 2017, or New Delek, with respect to periods on or after July 1, 2017, and any of Old Delek's or New Delek's, as applicable, subsidiaries, other than the Partnership and its subsidiaries and its general partner.

On March 31, 2015, the Partnership, through its wholly owned subsidiary Delek Logistics Operating, LLC ("OpCo"), acquired from Delek two crude oil rail offloading racks, which are designed to receive up to 25,000 barrels per day (“bpd”) of light crude oil or 12,000 bpd of heavy crude oil, or any combination of the two, delivered by rail to the El Dorado Refinery and related ancillary assets (the “El Dorado Assets”) (such transaction, the "El Dorado Rail Offloading Racks Acquisition").

On March 31, 2015, the Partnership, through its wholly owned subsidiary Delek Marketing & Supply, LP, acquired from Delek a crude oil storage tank ("the Tyler Crude Tank") located adjacent to Delek's Tyler, Texas refinery (the "Tyler Refinery") and certain ancillary assets (collectively, with the Tyler Crude Tank, the "Tyler Assets") (such transaction, the "Tyler Crude Tank Acquisition"). The Tyler Crude Tank has approximately 350,000 barrels of shell capacity and primarily supports the Tyler Refinery. The Tyler Assets, together with the El Dorado Assets, are hereinafter collectively referred to as the "Logistics Assets."

The El Dorado Rail Offloading Racks Acquisition and the Tyler Crude Tank Acquisition are hereinafter collectively referred to as the "Acquisitions from Delek." The Acquisitions from Delek were accounted for as transfers between entities under common control. As entities under common control with Delek, we record the assets that Delek has contributed to us on our balance sheet at Delek's historical basis instead of fair value. Transfers between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. Accordingly, the accompanying financial statements and related notes of the Partnership have been retrospectively adjusted to include, (i) the historical results of the El Dorado Assets, as owned and operated by Delek, for all periods presented through March 31, 2015 (the "El Dorado Assets Predecessor") and (ii) the historical results of the Tyler Assets, as owned and operated by Delek, for all periods presented through March 31, 2015 (the "Tyler Assets Predecessor"). The El Dorado Assets Predecessor, together with the Tyler Assets Predecessor, are hereinafter collectively referred to as our "Predecessors." See Note 3 for further information regarding the Acquisitions from Delek.

Description of Business

The Partnership primarily owns and operates logistics and marketing assets for crude oil and intermediate and refined products. A substantial majority of our existing assets are integral to and dependent on the success of Delek’s refining and marketing operations. We gather, transport and store crude oil and market, wholesale market, distribute, transport and store refined products in select regions of the southeastern United States and west Texas for Delek and third parties.

The Partnership generates revenue by charging fees for gathering, transporting, offloading and storing crude oil and for marketing, wholesale marketing, distributing, transporting and storing refined products. A substantial majority of our contribution margin, which we define as net sales less cost of goods sold and operating expenses, is derived from commercial agreements with Delek with initial terms ranging from five to ten years.

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Accounting Policies Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Accounting Policies

Accounting Policies

Basis of Presentation

Our consolidated financial statements include the accounts of the Partnership and its subsidiaries as well as our Predecessors. All intercompany accounts and transactions have been eliminated. The financial statements of our Predecessors have been prepared from the separate records maintained by Delek and may not necessarily be indicative of the conditions that would have existed or the results of operations if our Predecessors had been operated as an unaffiliated entity. Our Predecessors did not record all revenues for intercompany gathering, pipeline transportation, terminalling and storage services. Transfers between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. As an entity under common control with Delek, we record the assets that Delek has contributed to us on our balance sheet at Delek's historical basis instead of fair value.

We have evaluated subsequent events through the filing of this Annual Report on Form 10-K. Any material subsequent events that occurred during this time have been properly recognized or disclosed in our financial statements. The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“U.S. GAAP”) and in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Segment Reporting

We are an energy business focused on crude oil, intermediate and refined products pipeline and storage activities and wholesale marketing, terminalling and offloading activities. Management reviews operating results in two reportable segments: (i) pipelines and transportation and (ii) wholesale marketing and terminalling. The pipelines and transportation segment provides crude oil gathering, transportation and storage services to Delek's refining operations and independent third parties. The wholesale marketing and terminalling segment provides marketing, wholesale marketing and terminalling services to Delek's refining operations and independent third parties. 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 its reportable segments based on the segment contribution margin. Segment contribution margin is defined as net sales less cost of goods sold and operating expenses, excluding depreciation and amortization. Segment reporting is more fully discussed in Note 15.

Cash and Cash Equivalents

We maintain cash and cash equivalents in accounts with large, U.S. financial institutions. Any highly liquid investments purchased with an original maturity of three months or less are considered to be cash equivalents.

Accounts Receivable

Accounts receivable primarily consists of trade receivables generated in the ordinary course of business. We perform on-going credit evaluations of our customers and generally do not require collateral on accounts receivable. All accounts receivable amounts are considered to be fully collectible. Accordingly, no allowance for doubtful accounts has been established as of December 31, 2017 and 2016. One third-party customer accounted for approximately 22.0% of the consolidated accounts receivable balance as of December 31, 2017. Two third-party customers accounted for approximately 36.6% of the consolidated accounts receivable balance as of December 31, 2016.

Inventory

Inventory consists of refined products, which are stated at the lower of cost or net realizable value, with cost determined on a first-in, first-out ("FIFO") basis. One third party vendor and Delek accounted for approximately 65.8% and 11.6%, respectively, of our inventory purchases in our wholesale marketing and terminalling segment during the year ended December 31, 2017. Two third party vendors in our wholesale marketing and terminalling segment accounted for approximately 72.0% of our inventory purchases during the year ended December 31, 2016. One third party vendor and Delek accounted for approximately 62.6% and 24.9%, respectively, of our inventory purchases in our wholesale marketing and terminalling segment during the year ended December 31, 2015.

Property, Plant and Equipment

Assets acquired in conjunction with business acquisitions are recorded at estimated fair market value in accordance with the purchase method of accounting as prescribed in Accounting Standards Codification ("ASC") 805, Business Combinations ("ASC 805"). Other acquisitions of property and equipment are carried at cost. Acquisitions of net assets that do not constitute a business are accounted for by allocating the cost of the acquisition to individual assets acquired and liabilities assumed on relative fair value basis and shall not give rise to goodwill as prescribed in ASC 805.

Betterments, renewals and extraordinary repairs that extend the life of an asset are capitalized. Maintenance and repairs are charged to expense as incurred.

Depreciation is computed using the straight-line method over management’s estimated useful lives of the related assets, except for automotive equipment, which is depreciated using a declining-balance method. The estimated useful lives are as follows:

	Years
Buildings and building improvements	15-40
Pipelines, tanks and terminals	15-40
Asset retirement obligation assets	15-50
Other equipment	3-15

Intangible Assets

Intangible assets consist of a long-term supply contract and indefinite-lived rights of way. We amortize the definite-lived long-term supply contract on a straight-line basis over the estimated useful life of 11.5 years. The amortization expense is included in depreciation and amortization in the accompanying consolidated financial statements.

Property, Plant and Equipment and Intangibles Impairment

Property, plant and equipment and definite life intangibles are evaluated for impairment whenever indicators of impairment exist. In accordance with ASC 360, Property, Plant and Equipment and ASC 350, Intangibles - Goodwill and Other, we evaluate the realizability of these long-lived assets as events occur that might indicate potential impairment. In doing so, we assess whether the carrying amount of the asset is unrecoverable by estimating the sum of the future cash flows expected to result from the asset, undiscounted and without interest charges. If the carrying amount is more than the recoverable amount, an impairment charge must be recognized based on the fair value of the asset.

Goodwill and Potential Impairment

Goodwill in an acquisition represents the excess of the aggregate purchase price over the fair value of the identifiable net assets. Our goodwill is recorded at original fair value and is not amortized. Goodwill is subject to annual assessment to determine if an impairment of value has occurred and we perform this review annually in the fourth quarter. We could also be required to evaluate our goodwill if, prior to our annual assessment, we experience disruptions in our business, have unexpected significant declines in operating results, or sustain a permanent market capitalization decline. If an asset’s carrying amount exceeds its fair value, the impairment assessment leads to the testing of the implied fair value of the asset’s goodwill to its carrying amount. If the implied fair value is less than the carrying amount, a goodwill impairment charge is recorded. Our annual assessment of goodwill did not result in an impairment charge during the years ended December 31, 2017, 2016 or 2015.

Equity Method Investments

For equity investments that are not required to be consolidated under the variable or voting interest model, we evaluate the level of influence we are able to exercise over an entity’s operations to determine whether to use the equity method of accounting. Our judgment regarding the level of control over an equity method investment includes considering key factors such as our ownership interest, participation in policy-making and other significant decisions and material intercompany transactions. Amounts recognized for equity method investments are included in equity method investments in our consolidated balance sheet and adjusted for our shares of the net earnings and losses of the investee and cash distributions, which are separately presented in our consolidated statements of income and comprehensive income and our consolidated statements of cash flows. We evaluate our equity method investments for impairment whenever events or changes in circumstances indicate that the carrying amounts of such investments may be impaired. A loss is recorded in earnings in the current period if a decline in the value of an equity method investment is determined to be other than temporary.

Derivatives

We record all derivative financial instruments, including forward fuel contracts, at estimated fair value in accordance with the provisions of ASC 815, Derivatives and Hedging ("ASC 815"). Changes in the fair value of the derivative instruments are recognized in operations, unless we elect to apply the hedge accounting treatment permitted under the provisions of ASC 815 allowing such changes to be classified as other comprehensive income for cash flow hedges. We validate the fair value of all derivative financial instruments on a periodic basis, utilizing exchange pricing and/or price index developers, such as Platts or Argus. During the years ended December 31, 2017, 2016 and 2015, we did not elect to apply hedge accounting treatment to our derivative positions and, therefore, all changes in fair value are reflected in the statements of income and comprehensive income.

Our policy under the guidance of ASC 815-10-45, Derivatives and Hedging—Other Presentation Matters ("ASC 815-10-45"), is to net the fair value amounts recognized for multiple derivative instruments executed with the same counterparty and offset these values against any cash collateral associated with these derivative positions. See Note 17 for further discussion.

Fair Value of Financial Instruments

The fair values of financial instruments are estimated based upon current market conditions and quoted market prices for the same or similar instruments. Management estimates that the carrying value approximates fair value for all of our assets and liabilities that fall under the scope of ASC 825, Financial Instruments ("ASC 825").

We apply the provisions of ASC 820, Fair Value Measurements and Disclosure ("ASC 820"), in our presentation and disclosures regarding fair value, which pertain to certain financial assets and liabilities measured at fair value in the balance sheet on a recurring basis. ASC 820 defines fair value, establishes a framework for measuring fair value and expands disclosures about such measurements that are permitted or required under other accounting pronouncements. See Note 16 for further discussion.

We apply the provisions of ASC 825 as it pertains to the fair value option. This standard permits the election to carry financial instruments and certain other items similar to financial instruments at fair value on the balance sheet, with all changes in fair value reported in earnings. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. As of December 31, 2017 and 2016, we did not make the fair value election for any financial instruments not already carried at fair value in accordance with other standards.

Self-Insurance Reserves

We have no employees. Rather, we are managed by the directors and officers of our general partner. However, Delek employees providing services to the Partnership are covered under Delek’s insurance programs. Delek has workers' compensation and liability insurance with varying retentions and deductibles with limits that management considers adequate.

Environmental Expenditures

We have historically accrued environmental and clean-up related costs of a non-capital nature when it is both probable that a liability has been incurred and the amount can be reasonably estimated. Environmental liabilities represent the current estimated costs to investigate and remediate contamination at our properties. This estimate is based on internal and third-party assessments of the extent of the contamination, the selected remediation technology and review of applicable environmental regulations, typically considering estimated activities and costs for the next 15 years, unless a specific longer range estimate is practicable. Accruals for estimated costs from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study and include, but are not limited to, costs to perform remedial actions and costs of machinery and equipment that are dedicated to the remedial actions and that does not have an alternative use. Such accruals are adjusted as further information develops or circumstances change. We discount environmental liabilities to their present value if payments are fixed and determinable. Expenditures for equipment necessary for environmental issues relating to ongoing operations are capitalized. Estimated recoveries of costs from other parties are recorded on an undiscounted basis as assets when their realization is deemed probable.

Asset Retirement Obligations

We recognize liabilities which represent the fair value of a legal obligation to perform asset retirement activities, including those that are conditional on a future event, when the amount can be reasonably estimated. These obligations are related to the required cleanout of our pipelines and terminal tanks and removal of certain above-grade portions of our pipelines situated on right-of-way property.

The reconciliation of the beginning and ending carrying amounts of asset retirement obligations as of December 31, 2017 and 2016 is as follows (in thousands):

	December 31,
	2017		2016
Beginning balance	$	3,772	$	3,506
Accretion expense	292		266
Ending balance	$	4,064	$	3,772

In order to determine fair value, management must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free rate and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation.

Revenue Recognition

Revenues for products sold are recorded at the point of sale upon delivery of product, which is the point at which title to the product is transferred, and when payment has either been received or collection is reasonably assured. Service revenues are recognized as crude oil, intermediate and refined products are shipped through, delivered by or stored in our pipelines, trucks, terminals and storage facility assets, as applicable. We do not recognize product sales revenues for these services, as title on the product never passes to us. All service revenues are based on regulated tariff rates or contractual rates.

Cost of Goods Sold and Operating Expenses

Cost of goods sold includes all costs of refined products, additives and related transportation. It also includes costs associated with the operation of our trucking assets. We do not recognize product cost of goods sold related to our shipping, delivering and storage services, as title to the product never passes to us. Operating expenses include the costs associated with the operation of owned terminals and other logistics assets, terminalling expense at third-party locations and pipeline maintenance costs.

Sales, Use and Excise Taxes

Our policy is to exclude sales, use and excise taxes from revenue when we are an agent of the taxing authority, in accordance with ASC 605-45, Revenue Recognition—Principal Agent Considerations.

Deferred Financing Costs

Deferred financing costs are included in other non-current assets in the accompanying consolidated balance sheets and represent expenses related to issuing and amending our revolving credit facility. Deferred financing costs associated with our 6.750% Senior Notes are included as a reduction to the associated debt balance in the accompanying consolidated balance sheets. These costs represent expenses related to issuing the senior notes. These amounts are amortized ratably over the remaining term of the respective financing and are included in interest expense in the accompanying consolidated statements of income and comprehensive income.

Operating Leases

We lease certain equipment and have surface leases under various operating lease arrangements, most of which provide the option, after the initial lease term, to renew the leases. None of these lease arrangements include fixed rental rate increases.

Income Taxes

We are not a taxable entity for federal income tax purposes or the income taxes of those states that follow the federal income tax treatment of partnerships. Instead, for purposes of these income taxes, each partner of the Partnership is required to take into account its share of income, gain, loss and deduction in computing its federal and state income tax liabilities, regardless of whether cash distributions are made to such partner by the Partnership. The taxable income reportable to each partner takes into account differences between the tax basis and fair market value of our assets, the acquisition price of such partner's units and the taxable income allocation requirements under the First Amended and Restated Agreement of Limited Partnership (the "Partnership Agreement").

We are subject to income taxes in certain states that do not follow the federal tax treatment of Partnerships. These taxes are accounted for under the provisions of ASC 740, Income Taxes (ASC 740). This statement generally requires DKL to record deferred income taxes for the differences between the book and tax bases of its assets and liabilities, which are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. Deferred income tax expense or benefit represents the net change during the year in our deferred income tax assets and liabilities, exclusive of the amounts held in other comprehensive income.

U.S. GAAP requires management to evaluate uncertain tax positions taken by the Partnership. The financial statement effects of a tax position are recognized when the position is more likely than not, based on the technical merits, to be sustained upon examination by the Internal Revenue Service. Management has analyzed the tax positions taken by the Partnership, and has concluded that there are no uncertain positions taken or expected to be taken. The Partnership is subject to routine audits by taxing jurisdictions.

Equity Based Compensation

Our general partner provides equity-based compensation to officers, directors and employees of our general partner or its affiliates, and certain consultants, affiliates of our general partner or other individuals who perform services for us, which includes unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The fair value of our phantom units is determined based on the closing market price of our common units on the grant date. The estimated fair value of our phantom units is amortized over the vesting period using the straight line method. Awards vest over one- to five-year service periods, unless such awards are amended in accordance with the LTIP. It is our practice to issue new units when phantom units vest.

Net Income per Limited Partner Unit

We use the two-class method when calculating the net income per unit applicable to limited partners because we have more than one participating class of securities. Our participating securities consist of common units, subordinated units, general partner units and incentive distribution rights ("IDRs"). The two-class method is based on the weighted-average number of common units outstanding during the period. Basic net income per unit applicable to limited partners (including subordinated unitholders) is computed by dividing limited partners’ interest in net income, after deducting our general partner’s 2% interest and IDRs, by the weighted-average number of outstanding common and subordinated units. Our net income is allocated to our general partner and limited partners in accordance with their respective partnership percentages after giving effect to priority income allocations for IDRs to our general partner, which is the holder of the IDRs pursuant to our Partnership Agreement. The weighted-average number of common units reflects the conversion of the subordinated units to common units on February 25, 2016. See Notes 5 and 12 for further discussion.

Diluted net income per unit applicable to common limited partners includes the effects of potentially dilutive units on our common units. At present, the only potentially dilutive units outstanding consist of unvested phantom units. Basic and diluted net income per unit applicable to subordinated limited partners are the same because there are no potentially dilutive subordinated units outstanding.

Comprehensive Income

Comprehensive income for the years ended December 31, 2017, 2016 and 2015 was equivalent to net income.

New Accounting Pronouncements

In August 2017, the Financial Accounting Standards Board (the "FASB") issued guidance to refine and expand hedge accounting for both financial and commodity risks. Its provisions create more transparency around how economic results are presented, both on the face of the financial statements and in the footnotes and align the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. It also makes certain targeted improvements to simplify the application of hedge accounting guidance. This guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, and can be early adopted for any interim or annual financial statements that have not yet been issued. We expect to adopt this guidance on or before the effective date and are currently evaluating the impact that adopting this new guidance will have on our business, financial condition and results of operations.

In May 2017, the FASB issued guidance that clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. The modification accounting guidance applies if the value, vesting conditions or classification of the award changes. This guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, and can be early adopted for any interim or annual financial statements that have not yet been issued. We expect to adopt this guidance on or before the effective date and are currently evaluating the impact that adopting this new guidance will have on our business, financial condition and results of operations.

In January 2017, the FASB issued guidance that eliminates Step 2 of the goodwill impairment test, which required a comparison of the implied fair value of goodwill of a reporting unit with the carrying amount of that goodwill for that reporting unit. It also eliminates the requirements for any reporting unit with a zero or negative carrying amount to perform a qualitative assessment and, if it fails that qualitative assessment, to perform Step 2 of the goodwill impairment test. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. This guidance is effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We expect to adopt this guidance on or before the effective date and we do not anticipate that the adoption will have a material impact on our business, financial condition or results of operations.

In January 2017, the FASB issued guidance clarifying the definition of a business in order to assist entities with evaluating when a set of transferred assets and activities is considered a business. In general, we expect that the revised definition will result in fewer acquisitions being accounted for as business combinations than under the current guidance. This guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years and should be applied prospectively. Early adoption is permitted under certain circumstances. We early adopted this guidance as of July 1, 2017 and the adoption did not have a material impact on our business, financial condition or results of operations.

In March 2016, the FASB issued guidance that simplifies several aspects of the accounting for share-based payment award transactions, including the accounting for excess tax benefits and deficiencies, classification of awards as either equity or liabilities and classification of excess tax benefits on the statement of cash flows.  This guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years and can be early adopted for any interim or annual financial statements that have not yet been issued.  We prospectively adopted this guidance on January 1, 2017 and the adoption did not have a material impact on our business, financial condition or results of operations.

In February 2016, the FASB issued guidance that requires the recognition of a lease liability and a right-of-use asset, initially measured at the present value of the lease payments, in the statement of financial condition for all leases previously accounted for as operating leases. This guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. We expect to adopt this guidance on or before the effective date and are currently evaluating the impact adopting this new guidance will have on our business, financial condition and results of operations. 

In July 2015, the FASB issued guidance requiring entities to measure FIFO or average cost inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.  This guidance does not change the measurement of inventory measured using LIFO or the retail inventory method.  This guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years.   We adopted this guidance on January 1, 2017 and the adoption did not have a material impact on our business, financial condition or results of operations. 

In May 2014, the FASB issued guidance regarding “Revenue from Contracts with Customers,” to clarify the principles for recognizing revenue. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires improved interim and annual disclosures that enable the users of financial statements to better understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. The new guidance is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period, and can be adopted retrospectively. We expect to adopt the new standard in the first quarter of 2018 using the modified retrospective transition method. Based on the analysis performed to date, we do not expect the adoption of the standard to have a material impact on the timing or pattern of revenue recognition.

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Acquisitions Acquisitions

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Acquisitions

Acquisitions

Acquisitions from Delek

During the year ended December 31, 2015, the Partnership acquired the assets listed below from Delek:

• the El Dorado Assets effective March 31, 2015 for approximately $42.5 million in cash financed with borrowings under the Partnership's amended and restated senior secured revolving credit facility; and

• the Tyler Assets effective March 31, 2015 for approximately $19.4 million in cash financed with borrowings under the Partnership's amended and restated senior secured revolving credit facility.

Financial Results of the Acquisitions from Delek

The Acquisitions from Delek were considered transfers of businesses between entities under common control. Accordingly, the Acquisitions from Delek were recorded at amounts based on Delek's historical carrying value as of each respective acquisition date, which were $7.6 million and $11.6 million as of March 31, 2015, for the El Dorado Rail Offloading Racks Acquisition and the Tyler Crude Tank Acquisition, respectively. Our historical financial statements have been retrospectively adjusted to reflect the results of operations, financial position, cash flows and equity attributable to the Acquisitions from Delek as if we owned the assets for all periods presented. The results of the El Dorado Assets and the Tyler Assets are included in the pipelines and transportation segment.

Acquisitions from Third Parties

On September 15, 2017, the Partnership, through its wholly owned subsidiary, Delek Marketing & Supply, LP acquired from Plains Pipeline, L.P. an approximately 40-mile pipeline and related ancillary assets (the "Big Spring Pipeline") (such transaction, the "Big Spring Acquisition") for approximately $9.0 million to complement our existing asset base. The Big Spring Pipeline originates in Big Spring, Texas and terminates in Midland, Texas. The Big Spring Acquisition was accounted for as an asset acquisition. The following table summarizes the allocation of the relative fair value assigned to the asset groups for the Big Spring Pipeline (in thousands):

Property, plant and equipment	$	6,443
Intangible assets (1)	2,560
Total	$	9,003

⁽¹⁾ Intangible assets acquired represent rights-of-way assets with indefinite useful lives. Rights-of-way assets are not subject to amortization.

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Related Party Transactions

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Commercial Agreements

The Partnership has a number of long-term, fee-based commercial agreements with Delek under which we provide various services, including crude oil gathering and crude oil, intermediate and refined products transportation and storage services, and marketing, terminalling and offloading services to Delek. Most of these agreements have an initial term ranging from five to ten years, which may be extended for various renewal terms at the option of Delek. In November 2017, Delek opted to renew certain of these agreements for subsequent five-year terms expiring in November 2022. In the case of our marketing agreement with Delek, the initial term has been extended through 2026. The fees under each agreement are payable to us monthly by Delek or certain third parties to whom Delek has assigned certain of its rights and are generally subject to increase or decrease on July 1 of each year, by the amount of any change in various inflation-based indices, including the Federal Energy Regulatory Commission oil pipeline index or various iterations of 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. In most circumstances, if Delek or the applicable third party assignee fails to meet or exceed the minimum volume or throughput commitment during any calendar quarter, Delek, and not any third party assignee, will be required to make a quarterly shortfall payment to us equal to the volume of the shortfall multiplied by the applicable fee, subject to certain exceptions as specified in the applicable agreement. Carry-over of any volumes or revenue in excess of such commitment to any subsequent quarter is not permitted.

Under each of these agreements, we are required to maintain the capabilities of our pipelines and terminals, such that Delek may throughput and/or store, as the case may be, specified volumes of crude oil, intermediate and refined products. To the extent that Delek is prevented by our failure to maintain such capacities from throughputting or storing such specified volumes for more than 30 days per year, Delek's minimum throughput commitment will be reduced proportionately and prorated for the portion of the quarter during which the specified throughput capacity was unavailable, and/or the storage fee will be reduced, prorated for the portion of the month during which the specified storage capacity was unavailable. Such reduction would occur even if actual throughput or storage amounts were below the minimum volume commitment levels.

Our material commercial agreements with Delek include the following:

Asset/Operation	Initiation Date	Initial/Maximum Term (years) (1)	Service	Minimum Throughput Commitment (bpd)	Fee (/bbl)
Lion Pipeline System and SALA Gathering System:
Crude Oil Pipelines (non-gathered)	November 2012	5 / 15	Crude oil and refined products transportation	46,000 (2)	$ 0 .95 (3)
Refined Products Pipelines	November 2012	5 / 15		40,000	$	0.11
SALA Gathering System	November 2012	5 / 15	Crude oil gathering	14,000	$ 2.55 (3)
East Texas Crude Logistics System:
Crude Oil Pipelines	November 2012	5 / 15	Crude oil transportation and storage	35,000	$ 0.45 (4)
Storage	November 2012	5 / 15		N/A	$ 278,923/month
East Texas Marketing	November 2012	10 (5)	Marketing products for Tyler Refinery	50,000	$ 0.777 (5)
Big Sandy Terminal: (6)
Refined Products Transportation	November 2012	5 / 15	Refined products transportation, dedicated terminalling services and storage for the Tyler Refinery	5,000	$	0.56
Terminalling	November 2012	5 / 15		5,000	$	0.56
Storage	November 2012	5 / 15		N/A	$ 55,735/month
Tyler Throughput and Tankage:
Refined Products Throughput	July 2013	8 / 16	Dedicated Terminalling and storage	50,000	$	0.36
Storage	July 2013	8 / 16		N/A	$ 832,530/month
Memphis Pipeline	October 2013	5	Refined Products Transportation	10,959	$	1.35
El Dorado Throughput and Tankage:
Refined Products Throughput	February 2014	8 / 16	Dedicated terminalling and storage	11,000	$	0.51
Storage	February 2014	8 / 16		N/A	$1,319,135/month
El Dorado Assets Throughput:
Light Crude Throughput	March 2015	9/15	Dedicated Offloading Services	N/A (7)	$ 1.11
Heavy Crude Throughput	March 2015	9/15	Dedicated Offloading Services	N/A (7)	$ 2.28

⁽¹⁾ Maximum term gives effect to the extension of the commercial agreement pursuant to the terms thereof.

⁽²⁾ Excludes volumes gathered on the SALA Gathering System.

⁽³⁾ Volumes gathered on the SALA Gathering System will not be subject to an additional fee for transportation on our Lion Pipeline System to the El Dorado Refinery.

⁽⁴⁾ For any volumes in excess of 50,000 bpd, the throughput fee will be $0.670/bbl.

⁽⁵⁾ For any volumes in excess of 50,000 bpd, the throughput fee will be $0.738/bbl. Following the primary term, the marketing agreement automatically renews for successive one-year terms, unless either party provides notice of non-renewal 10 months prior to the expiration of the then-current term. The initial primary term for the marketing agreement has been extended through 2026.

⁽⁶⁾ On July 19, 2013, we acquired the Hopewell Pipeline in order to effectively connect it with the Big Sandy Pipeline and thereby return the Big Sandy Terminal to operation. In connection with the acquisition, on July 25, 2013, we and Delek entered into the Amended and Restated Services Agreement (Big Sandy Terminal and Pipeline), which amended and restated the terminalling services agreement for the Big Sandy Terminal originally entered into in November 2012.

⁽⁷⁾  The throughput agreement provides for a minimum throughput fee of $1.5 million per quarter for throughput of a combination of light and heavy crude.

Pursuant to an arrangement with Delek and Lion Oil Company ("Lion Oil"), to which we are not a party, J. Aron & Company ("J. Aron") acquires and holds title to substantially all crude oil, intermediate and refined products transported on our Lion Pipeline System, SALA Gathering System and on pipeline capacity we lease from Enterprise TE Products Pipeline Company LLC that runs from the El Dorado Refinery to our Memphis Terminal (the "Memphis Pipeline"). J. Aron is therefore considered the shipper for the liquid it owns on the Lion Pipeline System, the SALA Gathering System and the Memphis Pipeline. J. Aron also has title to the refined products stored at our Memphis, North Little Rock and El Dorado terminals and in the El Dorado storage tanks. Under (i) our pipelines and storage agreement with Lion Oil relating to the Lion Pipeline System and the SALA Gathering System, (ii) our terminalling agreements with Lion Oil relating to the Memphis and North Little Rock terminals and (iii) our throughput and tankage agreement relating to the terminal and tank assets at and adjacent to the El Dorado Refinery, Lion Oil has assigned to J. Aron certain of its rights under these agreements, including the right to have J. Aron's crude oil and intermediate and refined products stored in or transported on or through these systems, Memphis and North Little Rock terminals and the terminal and tank assets at and adjacent to the El Dorado Refinery, with Lion Oil acting as J. Aron's agent for scheduling purposes. Accordingly, even though this is effectively a financing arrangement for Delek whereby J. Aron sells the product back to Delek, J. Aron is technically our primary customer under each of these agreements. J. Aron retains these storage and transportation rights for the term of its arrangement with Delek and Lion Oil, which currently runs through April 30, 2020, and J. Aron pays us for the transportation, throughput and storage services we provide to it. The rights assigned to J. Aron do not alter Lion Oil's obligations to meet certain throughput minimum volumes under our agreements with respect to the transportation, throughputting and storage of crude oil, intermediate and refined products through our facilities, but J. Aron's throughput is credited toward Lion Oil's minimum throughput commitments. Accordingly, Lion Oil is responsible for making any shortfall payments incurred under the pipelines and storage agreement or the terminalling agreement which may result from minimum throughputs or volumes not being met.

Other Agreements with Delek

In addition to the commercial agreements described above, the Partnership has entered into the following agreements with Delek:

Omnibus Agreement

Omnibus Agreement. The Partnership entered into an omnibus agreement with Delek, our general partner, OpCo, Lion Oil and certain of the Partnership’s and Delek’s other subsidiaries on November 7, 2012, which was subsequently amended and restated on July 26, 2013, February 10, 2014 and March 31, 2015 and further amended on August 3, 2015 (collectively, as amended, the "Omnibus Agreement"). The Omnibus Agreement governs the provision of certain operational services and reimbursement obligations, among other matters, between the Partnership and Delek.

Pursuant to the terms of the Omnibus Agreement, we were reimbursed for certain capital expenditures in the amount of $4.3 million, $1.9 million and $5.2 million, during the years ended December 31, 2017, 2016 and 2015, respectively. These amounts are recorded in other long-term liabilities and are amortized to revenue over the life of the underlying revenue agreement corresponding to the asset. Additionally, we were reimbursed or indemnified, as the case may be, for costs incurred in excess of certain amounts related to certain asset failures, pursuant to the terms of the Omnibus Agreement. We were reimbursed $0.3 million and $1.2 million during the years ended December 31, 2017 and 2016, respectively, for these matters. We were reimbursed for the costs incurred in connection with an asset failure near Fouke, Arkansas and the subsequent repair of the asset during the year ended December 31, 2015 pursuant to the Omnibus Agreement. These reimbursements are recorded as a reduction to operating expense.

Other Agreements

Our general partner operates our business on our behalf and is entitled under our Partnership Agreement to be reimbursed for the cost of providing those services, which include certain labor related costs. We and our subsidiaries paid Delek approximately $18.8 million, $15.7 million and $22.8 million pursuant to the Partnership Agreement during the years ended December 31, 2017, 2016 and 2015, respectively. These amounts are included in operating expenses in the accompanying consolidated statements of income and comprehensive income.

Predecessors' Transactions

Related-party transactions of the Predecessors were settled through division equity. Costs related specifically to us have been identified and included in the accompanying consolidated statements of income and comprehensive income. Prior to the Acquisitions from Delek, we were not allocated certain corporate costs. These costs were primarily allocated based on a percentage of salaries expense and property, plant and equipment costs. In the opinion of management, the methods for allocating these costs are reasonable. It is not practicable to estimate the costs that would have been incurred by us if we had been operated on a stand-alone basis.

Summary of Transactions

Revenues from affiliates consist primarily of revenues from gathering, transportation, storage, offloading, Renewable Identification Numbers, wholesale marketing and products terminalling services provided primarily to Delek based on regulated tariff rates or contractually based fees and product sales. Affiliate operating expenses are primarily comprised of amounts we reimburse Delek, or our general partner, as the case may be, for the services provided to us under the Partnership Agreement. These expenses could also include reimbursement and indemnification amounts from Delek, as provided under the Omnibus Agreement. Additionally, the Partnership is required to reimburse Delek for direct or allocated costs and expenses incurred by Delek on behalf of the Partnership and for charges Delek incurred for the management and operation of our logistics assets, including an annual fee for various centralized corporate services, which are included in general and administrative services. In addition to these transactions, we purchase finished products and bulk biofuels from Delek, the costs of which are included in cost of goods sold.

A summary of revenue and expense transactions with Delek and its affiliates, including expenses directly charged and allocated to our Predecessors, are as follows (in thousands):

	Year Ended December 31,
	2017		2016		2015
Revenues	$	156,280	$	149,564	$	152,564
Cost of Goods Sold	$	54,982	$	32,514	$	105,461
Operating and maintenance expenses (1)	$	29,483	$	27,668	$	31,636
General and administrative expenses (2)	$	7,492	$	6,254	$	6,356

⁽¹⁾  Operating and maintenance expenses include costs allocated to our Predecessors for operating support provided by Delek, including certain labor related costs, property and liability insurance costs and certain other operating expenses. Costs allocated to our Predecessors by Delek were $0.2 million for the year ended December 31, 2015.

⁽²⁾  No general and administrative expenses were allocated to our Predecessors by Delek for the year ended December 31, 2015.

Quarterly Cash Distribution

Our common and general partner unitholders and the holders of IDRs are entitled to receive quarterly distributions of available cash as it is determined by the board of directors of our general partner in accordance with the terms and provisions of our Partnership Agreement. During the years ended December 31, 2017, 2016 and 2015, we paid quarterly cash distributions, of which $60.1 million, $47.0 million and $35.9 million, respectively, were paid to Delek and our general partner. On January 23, 2018, our general partner's board of directors declared a quarterly cash distribution totaling $22.8 million based on the available cash as of the date of determination for the end of the fourth quarter of 2017, which was paid on February 12, 2018 to unitholders of record on February 2, 2018. The distribution included $16.2 million paid to both Delek and our general partner, including the distribution as holder of the IDRs.

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Net Income Per Unit Net Income Per Unit

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Net Income Per Unit

Net Income Per Unit

We use the two-class method when calculating the net income per unit applicable to limited partners, because we have more than one participating class of securities. Our participating securities consist of common units, subordinated units, general partner units and IDRs. The two-class method is based on the weighted-average number of common units outstanding during the period. Basic net income per unit applicable to limited partners (including subordinated unitholders) is computed by dividing limited partners’ interest in net income, after deducting our general partner’s 2.0% interest and IDRs, by the weighted-average number of outstanding common and subordinated units. Our net income is allocated to our general partner and limited partners in accordance with their respective partnership percentages after giving effect to priority income allocations for IDRs, which are held by our general partner pursuant to our Partnership Agreement. The IDRs are paid following the close of each quarter.

Earnings in excess of distributions are allocated to our general partner and limited partners based on their respective ownership interests. Payments made to our unitholders are determined in relation to actual distributions declared and are not based on the net income allocations used in the calculation of net income per unit.

Diluted net income per unit applicable to common limited partners includes the effects of potentially dilutive units on our common units. During the years ended December 31, 2017, 2016 and 2015, the only potentially dilutive units outstanding consist of unvested phantom units. Basic and diluted net income per unit applicable to subordinated limited partners are the same because there are no potentially dilutive subordinated units outstanding.

Following the February 12, 2016 payment of the cash distribution attributable to the fourth quarter of 2015 and confirmation by the board of directors of our general partner (based on the recommendation of the Conflicts Committee) on February 25, 2016 that the requirements under the Partnership Agreement for the conversion of all subordinated units into common units were satisfied, the subordination period ended. As a result, in the first quarter of 2016, all of the Partnership's 11,999,258 outstanding subordinated units converted into common units and began participating pro rata with the other common units in distributions of available cash. The conversion did not impact the amount of the cash distribution paid or the total number of the Partnership's outstanding units representing limited partner interests. The Partnership's net income was allocated to the general partner and the limited partners, including the holders of the subordinated units through February 24, 2016, in accordance with our Partnership Agreement.

Our distributions earned with respect to a given period are declared subsequent to quarter end. Therefore, the table below represents total cash distributions applicable to the period in which the distributions are earned. The calculation of net income per unit is as follows (dollars in thousands, except per unit amounts):

	Year Ended December 31,
	2017			2016			2015
Net income attributable to partners	$	69,409		$	62,804		$	66,848
Less: General partner's distribution (including IDRs) (1)	18,797			12,437			5,013
Less: Limited partners' distribution	69,057			58,158			27,439
Less: Subordinated partner's distribution	—			4,424			26,878
(Distributions) earnings excess	$	(18,445	)	$	(12,215	)	$	7,518
General partner's earnings:
Distributions (including IDRs) (1)	$	18,797		$	12,437		$	5,013
Allocation of (distributions) earnings excess	(368		)	(244		)	150
Total general partner's earnings	$	18,429		$	12,193		$	5,163
Limited partners' earnings on common units:
Distributions	$	69,057		$	58,158		$	27,439
Allocation of (distributions) earnings excess	(18,077		)	(11,489		)	3,721
Total limited partners' earnings on common units	$	50,980		$	46,669		$	31,160
Limited partners' earnings on subordinated units:
Distributions	$	—		$	4,424		$	26,878
Allocation of (distributions) earnings excess	—			(482		)	3,647
Total limited partner's earnings on subordinated units	$	—		$	3,942		$	30,525
Weighted average limited partner units outstanding (2):
Common units - (basic)	24,348,063			22,490,264			12,237,154
Common units - (diluted)	24,376,972			22,558,717			12,356,914
Subordinated units - Delek (basic and diluted) (3)	—			1,803,167			11,999,258
Net income per limited partner unit (2):
Common - (basic)	$	2.09		$	2.08		$	2.55
Common - (diluted) (4)	$	2.09		$	2.07		$	2.52
Subordinated - (basic and diluted)	$	—		$	2.19		$	2.54

⁽¹⁾  General partner distributions (including IDRs) consist of the 2% general partner interest and IDRs, which represent the right of the general partner to receive increasing percentages of quarterly distributions of available cash from operating surplus in excess of $0.43125 per unit per quarter. See Note 12 for further discussion related to IDRs.

⁽²⁾  We base our calculation of net income per unit on the weighted-average number of common and subordinated limited partner units outstanding during the period. The weighted-average number of common and subordinated units reflects the conversion of the subordinated units to common units on February 25, 2016.

⁽³⁾  On February 25, 2016, all of the Partnership's 11,999,258 outstanding subordinated units converted into common units and began participating pro rata with the other common units in distributions of available cash. Distributions and the Partnership's net income were allocated to the subordinated units through February 24, 2016.

⁽⁴⁾   There were no outstanding common unit equivalents excluded from the diluted earnings per unit calculation during the year ended December 31, 2017. Outstanding common unit equivalents totaling 4,240 and 6,200 were excluded from the diluted earnings per unit calculation for the years ended December 31, 2016 and 2015, respectively, as these common unit equivalents did not have a dilutive effect under the treasury stock method.

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Major Customer Major Customer

12 Months Ended

Dec. 31, 2017

Major Customer [Abstract]

Major Customer

Major Customers

Delek, directly or indirectly, accounted for 28.9%, 32.8% and 25.9% of our total revenues for the years ended December 31, 2017, 2016 and 2015, respectively. Sunoco LP accounted for 9.0%, 10.5% and 16.2% of our total revenues for the years ended December 31, 2017, 2016 and 2015, respectively.

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Inventory Inventory

12 Months Ended

Dec. 31, 2017

Inventory, Net [Abstract]

Inventory

Inventory

Inventories consisted of $20.9 million and $8.9 million of refined petroleum products as of December 31, 2017 and 2016, respectively. Inventory is stated at the lower of cost or net realizable value, with cost determined on a FIFO basis. We recognize lower of cost or net realizable value charges as a component of cost of goods sold in the consolidated statements of income and comprehensive income, which amounted to a nominal amount and $0.3 million during the years ended December 31, 2017 and 2015, respectively. There was no lower of cost or net realizable value charge during the year ended December 31, 2016.

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Property, Plant and Equipment Property, Plant and Equipment

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment, at cost, consist of the following (in thousands):

	December 31,
	2017			2016
Land and land improvements	$	4,440		$	4,435
Building and building improvements	2,804			2,236
Pipelines, tanks and terminals	314,251			305,302
Asset retirement obligation assets	2,073			2,073
Other equipment	14,650			12,925
Construction in process	28,961			15,436
	367,179			342,407
Less: accumulated depreciation	(112,111		)	(91,378		)
	$	255,068		$	251,029

Property, plant and equipment, accumulated depreciation and depreciation expense by reporting segment as of and for the years ended December 31, 2017 and 2016 are as follows (in thousands):

	As of and For the Year Ended December 31, 2017
	Pipelines and Transportation			Wholesale Marketing and Terminalling			Consolidated
Property, plant and equipment	$	300,134		$	67,045		$	367,179
Less: accumulated depreciation	(84,435		)	(27,676		)	(112,111		)
Property, plant and equipment, net	$	215,699		$	39,369		$	255,068
Depreciation expense	$	17,268		$	3,583		$	20,851

	As of and For the Year Ended December 31, 2016
	Pipelines and Transportation			Wholesale Marketing and Terminalling			Consolidated
Property, plant and equipment	$	279,155		$	63,252		$	342,407
Less: Accumulated depreciation	(67,032		)	(24,346		)	(91,378		)
Property, plant and equipment, net	$	212,123		$	38,906		$	251,029
Depreciation expense	$	16,133		$	3,617		$	19,750

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Goodwill Goodwill

12 Months Ended

Dec. 31, 2017

Goodwill [Abstract]

Goodwill

Goodwill

Goodwill represents the excess of the aggregate purchase price over the fair value of the identifiable net assets acquired. Goodwill acquired in a business combination is recorded at fair value and is not amortized. Our goodwill relates to the west Texas assets contributed to us by Delek Marketing & Supply, LLC ("Delek Marketing"), a direct wholly owned subsidiary of Delek, in connection with our initial public offering (the "Offering") and to the purchase price allocation of certain of our third party acquisitions.

We perform an annual assessment of whether goodwill retains its value. This assessment is done more frequently if indicators of potential impairment exist. We performed our annual goodwill impairment review in the fourth quarter of 2017, 2016 and 2015. We performed a discounted cash flows test, using a market participant weighted average cost of capital, and estimated minimal growth rates for revenue, gross profit and capital expenditures based on history and our best estimate of future forecasts. We also estimated the fair values using a multiple of expected future cash flows, such as those used by third party analysts. In 2017, 2016 and 2015, the annual impairment review resulted in the determination that no impairment of goodwill had occurred.

Our goodwill accounts in our wholesale marketing and terminalling segment amounted to $7.5 million as of December 31, 2017, 2016 and 2015. Our goodwill accounts in our pipelines and transportation segment amounted to $4.7 million as of December 31, 2017, 2016 and 2015. During the year ended December 31, 2015, we recorded goodwill of $0.5 million in our pipelines and transportation segment in connection with the acquisition of certain trucks and trailers acquired in 2014.

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Other Intangible Assets Other Intangible Assets

12 Months Ended

Dec. 31, 2017

Other Intangible Assets Disclosure [Abstract]

Other Intangible Assets

Other Intangible Assets

Our identifiable intangible assets are as follows (in thousands):

	Useful			Accumulated
As of December 31, 2017	Life	Gross		Amortization			Net
Intangible assets subject to amortization:
Supply contract	11.5	$	12,227	$	(12,138	)	$	89
Intangible assets not subject to amortization:
Rights-of-way assets	Indefinite	15,828					15,828
Total		$	28,055	$	(12,138	)	$	15,917

	Useful			Accumulated
As of December 31, 2016	Life	Gross		Amortization			Net
Intangible assets subject to amortization:
Supply contract	11.5	$	12,227	$	(11,075	)	$	1,152
Intangible assets not subject to amortization:
Rights-of-way assets	Indefinite	13,268					13,268
Total		$	25,495	$	(11,075	)	$	14,420

Amortization of intangible assets was $1.1 million during each of the years ended December 31, 2017, 2016 and 2015, and is included in depreciation and amortization on the accompanying consolidated statements of income and comprehensive income. Amortization expense is estimated to be $0.1 million for the year ended December 31, 2018, at which point our supply contract will be fully amortized.

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Long-Term Obligations Long-Term Obligations

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Long-Term Obligations

Long-Term Obligations

Second Amended and Restated Credit Agreement

We entered into a senior secured revolving credit agreement on November 7, 2012, with Fifth Third Bank, as administrative agent, and a syndicate of lenders. The agreement was amended and restated on July 9, 2013 (the "Amended and Restated Credit Agreement") and was most recently amended and restated on December 30, 2014 (the "Second Amended and Restated Credit Agreement"). Under the terms of the Second Amended and Restated Credit Agreement, the lender commitments were increased from $400.0 million to $700.0 million. The Second Amended and Restated Credit Agreement also contains an accordion feature, whereby the Partnership can increase the size of the credit facility to an aggregate of $800.0 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent. The Second Amended and Restated Credit Agreement contains an option for Canadian dollar denominated borrowings.

Borrowings denominated in U.S. dollars bear interest at either a U.S. dollar prime rate, plus an applicable margin, or the London Interbank Offered Rate ("LIBOR"), plus an applicable margin, at the election of the borrowers. Borrowings denominated in Canadian dollars bear interest at either a Canadian dollar prime rate, plus an applicable margin, or the Canadian Dealer Offered Rate, plus an applicable margin, at the election of the borrowers. The applicable margin in each case varies based upon the Partnership's most recent total leverage ratio calculation delivered to the lenders, as called for and defined under the terms of the credit facility. At December 31, 2017, the weighted average interest rate for our borrowings under the credit facility was approximately 4.3%. Additionally, the Second Amended and Restated Credit Agreement requires us to pay a leverage-ratio dependent quarterly fee on the average unused revolving commitment. As of December 31, 2017, this fee was 0.50% per year.

The obligations under the Second Amended and Restated Credit Agreement remain secured by first priority liens on substantially all of the Partnership's and its subsidiaries' tangible and intangible assets. Additionally, Delek Marketing continues to provide a limited guaranty of the Partnership's obligations under the Second Amended and Restated Credit Agreement. Delek Marketing's guaranty is (i) limited to an amount equal to the principal amount, plus unpaid and accrued interest, of a promissory note made by Delek US in favor of Delek Marketing (the "Holdings Note") and (ii) secured by Delek Marketing's pledge of the Holdings Note to our lenders under the Second Amended and Restated Credit Agreement. As of December 31, 2017, the principal amount of the Holdings Note was $102.0 million, plus unpaid interest accrued since the issuance date. The Second Amended and Restated Credit Agreement matures on December 30, 2019.

As of December 31, 2017, we had $179.9 million in outstanding borrowings under the Second Amended and Restated Credit Agreement. Additionally, we had in place letters of credit totaling $9.0 million, primarily securing obligations with respect to gasoline and diesel purchases. No amounts were drawn under these letters of credit at December 31, 2017. Unused credit commitments under the Second Amended and Restated Credit Agreement as of December 31, 2017 were $511.1 million.

6.750% Senior Notes Due 2025

On May 23, 2017, the Partnership and Delek Logistics Finance Corp., a Delaware corporation and a wholly owned subsidiary of the Partnership (“Finance Corp.” and together with the Partnership, the “Issuers”), issued $250.0 million in aggregate principal amount of 6.750% senior notes due 2025 (the “2025 Notes”). The 2025 Notes are general unsecured senior obligations of the Issuers. The 2025 Notes are unconditionally guaranteed jointly and severally on a senior unsecured basis by the Partnership's existing subsidiaries (other than Finance Corp., the "Guarantors") and will be unconditionally guaranteed on the same basis by certain of the Partnership’s future subsidiaries. The 2025 Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right of payment to anyfuture subordinated indebtedness of the Issuers. Interest on the 2025 Notes is payable semi-annually in arrears on each May 15 and November 15, commencing November 15, 2017.

At any time prior to May 15, 2020, the Issuers may redeem up to 35% of the aggregate principal amount of the 2025 Notes with the net cash proceeds of one or more equity offerings by the Partnership at a redemption price of 106.750% of the redeemed principal amount, plus accrued and unpaid interest, if any, subject to certain conditions and limitations. Prior to May 15, 2020, the Issuers may redeem all or part of the 2025 Notes, at a redemption price of the principal amount, plus accrued and unpaid interest, if any, plus a "make whole" premium, subject to certain conditions and limitations. In addition, beginning on May 15, 2020, the Issuers may, subject to certain conditions and limitations, redeem all or part of the 2025 Notes at a redemption price of 105.063% for the twelve-month period beginning on May 15, 2020, 103.375% for the twelve-month period beginning on May 15, 2021, 101.688% for the twelve-month period beginning on May 15, 2022 and 100.00% beginning on May 15, 2023 and thereafter, plus accrued and unpaid interest, if any. There are also certain redemption provisions in the event of a change of control, accompanied or followed by a ratings downgrade within a certain period of time, subject to certain conditions and limitations.

In connection with the issuance of the 2025 Notes, the Issuers and the Guarantors entered into a registration rights agreement, whereby the Issuers and the Guarantors are required to exchange the 2025 Notes for new notes with terms substantially identical in all material respects with the 2025 Notes (except the new notes will not contain terms with respect to transfer restrictions). The Issuers and the Guarantors will use their commercially reasonable efforts to cause the exchange offer to be consummated not later than 365 days after May 23, 2017.

As of December 31, 2017, we had $250.0 million in outstanding principal amount of the 2025 Notes. Outstanding borrowings under the 2025 Notes are net of deferred financing costs and debt discount of $5.5 million and $1.7 million, respectively, as of December 31, 2017.

Principal maturities of the Partnership's existing third party debt instruments for the next five years and thereafter are as follows as of December 31, 2017 (in thousands):

	2018		2019		2020		2021		2022		Thereafter		Total
Second Amended and Restated Credit Agreement	$	—	$	179,900	$	—	$	—	$	—	$	—	$	179,900
2025 Notes	$	—	$	—	$	—	$	—	$	—	$	250,000	$	250,000

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Equity Equity

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Equity

Equity

We had 9,088,587 common limited partner units held by the public outstanding as of December 31, 2017. Additionally, as of December 31, 2017, Delek owned a 61.5% limited partner interest in us, consisting of 15,294,046 common limited partner units and a 94.6% interest in our general partner, which owns the entire 2.0% general partner interest consisting of 497,604 general partner units. Affiliates, who are also members of our general partner's management and board of directors, own the remaining 5.4% interest in our general partner.

Equity Activity

On February 25, 2016, the requirements under the Partnership Agreement for the conversion of all subordinated units into common units were satisfied, and the subordination period ended. As a result, in the first quarter of 2016, all of the Partnership's 11,999,258 outstanding subordinated units converted into common units and began participating pro rata with the other common units in distributions of available cash. The conversion did not impact the amount of the cash distribution paid or the total number of the Partnership's outstanding units representing limited partner interests.

The table below summarizes the changes in the number of units outstanding from December 31, 2014 through December 31, 2017 (in units).

	Common - Public		Common - Delek	Subordinated		General Partner	Total
Balance at December 31, 2014	9,417,189		2,799,258	11,999,258		494,197	24,709,902
GP units issued to maintain 2% interest	—		—	—		1,248	1,248
Unit-based compensation awards (1)	61,084		—	—		—	61,084
Balance at December 31, 2015	9,478,273		2,799,258	11,999,258		495,445	24,772,234
GP units issued to maintain 2% interest	—		—	—		1,057	1,057
Unit-based compensation awards (1)	51,818		—	—		—	51,818
Delek unit repurchases from public	(266,676	)	266,676	—		—	—
Subordinated unit conversion	—		11,999,258	(11,999,258	)	—	—
Balance at December 31, 2016	9,263,415		15,065,192	—		496,502	24,825,109
GP units issued to maintain 2% interest	—		—	—		1,102	1,102
Unit-based compensation awards	54,026		—	—		—	54,026
Delek unit repurchases from public	(228,854	)	228,854	—		—	—
Balance at December 31, 2017	9,088,587		15,294,046	—		497,604	24,880,237

⁽¹⁾ Unit-based compensation awards are presented net of 14,053, 17,276 and 21,144 units withheld for taxes as of December 31, 2017, 2016 and 2015, respectively.

Issuance of Additional Securities

Our Partnership Agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders. Costs associated with the issuance of securities are allocated to all unitholders' capital accounts based on their ownership interest at the time of issuance.

Allocations of Net Income

Our Partnership Agreement contains provisions for the allocation of net income and loss to the unitholders and our general partner. For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interest. Normal allocations according to percentage interests are made after giving effect to priority income allocations in an amount equal to incentive cash distributions allocated 100% to our general partner.

The following table presents the allocation of the general partner's interest in net income (in thousands, except percentage of ownership interest):

	Year Ended December 31,
	2017			2016			2015
Net income attributable to partners	$	69,409		$	62,804		$	66,848
Less: General partner's IDRs	(17,389		)	(11,160		)	(3,904		)
Net income available to partners	$	52,020		$	51,644		$	62,944
General partner's ownership interest	2.0		%	2.0		%	2.0		%
General partner's allocated interest in net income	1,040			1,033			1,259
General partner's IDRs	17,389			11,160			3,904
Total general partner's interest in net income	$	18,429		$	12,193		$	5,163

Incentive Distribution Rights

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and our unitholders in any available cash from operating surplus that we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that (i) our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest and (ii) our general partner has not transferred its IDRs.

		Target Quarterly Distribution per Unit		Marginal Percentage Interest in Distributions
		Target Amount		Unitholders		General Partner
Minimum Quarterly Distribution		$	0.37500	98.0	%	2.0	%
First Target Distribution	above	$	0.37500	98.0	%	2.0	%
	up to	$	0.43125
Second Target Distribution	above	$	0.43125	85.0	%	15.0	%
	up to	$	0.46875
Third Target Distribution	above	$	0.46875	75.0	%	25.0	%
	up to	$	0.56250
Thereafter	thereafter	$	0.56250	50.0	%	50.0	%

Cash Distributions

Our Partnership Agreement sets forth the calculation to be used to determine the amount and priority of available cash distributions that our limited partner unitholders and general partner will receive. Our distributions earned with respect to a given period are declared subsequent to quarter end. The table below summarizes the quarterly distributions related to our quarterly financial results:

Quarter Ended	Total Quarterly Distribution Per Limited Partner Unit		Total Quarterly Distribution Per Limited Partner Unit, Annualized		Total Cash Distribution, including general partner interest and IDRs (in thousands)		Date of Distribution	Unitholders Record Date
December 31, 2015	$	0.590	$	2.36	$	16,124	February 12, 2016	February 5, 2016
March 31, 2016	$	0.610	$	2.44	$	17,095	May 13, 2016	May 5, 2016
June 30, 2016	$	0.630	$	2.52	$	18,085	August 12, 2016	August 5, 2016
September 30, 2016	$	0.655	$	2.62	$	19,302	November 14, 2016	November 7, 2016
December 31, 2016	$	0.680	$	2.72	$	20,537	February 14, 2017	February 3, 2017
March 31, 2017	$	0.690	$	2.76	$	21,024	May 12, 2017	May 5, 2017
June 30, 2017	$	0.705	$	2.82	$	21,783	August 11, 2017	August 4, 2017
September 30, 2017	$	0.715	$	2.86	$	22,270	November 14, 2017	November 7, 2017
December 31, 2017	$	0.725	$	2.90	$	22,777	February 12, 2018	February 2, 2018

The allocation of total quarterly cash distributions made to general and limited partners for the years ended December 31, 2017, 2016 and 2015 is set forth in the table below. Distributions earned with respect to a given period are declared subsequent to quarter end. Therefore, the table below presents total cash distributions applicable to the period in which the distributions are earned (in thousands, except per unit amounts):

	Year Ended December 31,
	2017		2016		2015
General partner's distributions:
General partner's distributions	$	1,408	$	1,277	$	1,109
General partner's IDRs	17,389		11,160		3,904
Total general partner's distributions	18,797		12,437		5,013
Limited partners' distributions:
Common	69,057		58,158		27,439
Subordinated	—		4,424		26,878
Total limited partners' distributions	69,057		62,582		54,317
Total cash distributions	$	87,854	$	75,019	$	59,330
Cash distributions per limited partner unit	$	2.835	$	2.575	$	2.240

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Equity Based Compensation

12 Months Ended

Dec. 31, 2017

Share-based Compensation [Abstract]

Equity Based Compensation

Equity Based Compensation

The Delek Logistics GP, LLC 2012 Long-Term Incentive Plan (the "LTIP") was adopted by the Delek Logistics GP, LLC board of directors in connection with the completion of the Offering in November 2012. The LTIP provides for officers, directors and employees of our general partner or its affiliates, and any consultants, affiliates of our general partner or other individuals who perform services for us. The LTIP consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The LTIP limits the number of common units that may be delivered pursuant to awards under the plan to 612,207 units. The LTIP is administered by the Conflicts Committee of the board of directors of our general partner.

We incurred approximately $0.7 million, $0.6 million and $0.4 million of unit-based compensation expense related to the Partnership during the years ended December 31, 2017, 2016 and 2015, respectively. These amounts are included in general and administrative expenses in the accompanying consolidated statements of income and comprehensive income. The fair value of phantom unit awards under the LTIP is determined based on the closing market price of our common limited partner units on the grant date. The estimated fair value of our phantom units is amortized over the vesting period using the straight line method. Awards vest over one- to five-year service periods, unless such awards are amended in accordance with the LTIP. The total fair value of phantom units vested was $1.7 million, $1.7 million and $1.9 million during the years ended December 31, 2017, 2016 and 2015, respectively.

As of December 31, 2017, there was $0.4 million of total unrecognized compensation cost related to non-vested equity-based compensation arrangements, which is expected to be recognized over a weighted-average period of 0.7 years.

A summary of our unit award activity for the years ended December 31, 2017, 2016 and 2015, is set forth below:

		Number of Phantom Units		Weighted-Average Grant Price
Non-vested	December 31, 2014	215,464		$	23.48
Granted		11,836		$	39.73
Vested		(82,228	)	$	23.55
Non-vested	December 31, 2015	145,072		$	24.76
Granted		12,475		$	26.05
Vested		(69,094	)	$	24.66
Forfeited		(14,500	)	$	22.65
Non-vested	December 31, 2016	73,953		$	25.49
Granted		10,090		$	32.20
Vested		(68,079	)	$	24.60
Non-vested	December 31, 2017	15,964		$	33.54

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Equity Method Investments Equity Method Investments

12 Months Ended

Dec. 31, 2017

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

Equity Method Investments

In March 2015, we entered into two joint ventures that have constructed separate crude oil pipeline systems and related ancillary assets, which are serving third parties and subsidiaries of Delek. We own a 50% membership interest in the entity formed with an affiliate of Plains All American Pipeline, L.P. ("CP LLC") to operate one of these pipeline systems and a 33% membership interest in the entity formed with Rangeland Energy II, LLC ("Rangeland RIO") to operate the other pipeline system. The pipeline system constructed by Rangeland RIO was completed and began operations in September 2016. The pipeline system constructed by CP LLC was completed and began operations in January 2017.

The Partnership's investments in these two entities were financed through a combination of cash from operations and borrowings under the Second Amended and Restated Credit Agreement. As of December 31, 2017, the Partnership's investment balance in these joint ventures was $106.5 million.

We do not consolidate any part of the assets or liabilities or operating results of our equity method investees. Our share of net income or loss of the investees will increase or decrease, as applicable, the carrying value of our investments in unconsolidated affiliates. With respect to CP LLC and Rangeland RIO, we determined that these entities do not represent variable interest entities and consolidation was not required. We have the ability to exercise significant influence over each of these joint ventures through our participation in the management committees, which make all significant decisions. However, since all significant decisions require the consent of the other investor(s) without regard to economic interest, we have determined that we have joint control and have applied the equity method of accounting. Our investment in these joint ventures is reflected in our pipelines and transportation segment.

Summarized Financial Information

Combined summarized financial information for our equity method investees is shown below (in thousands):

	Year Ended		Year Ended
	December 31, 2017		December 31, 2016
Current assets	$	12,671	$	7,760
Non-current assets	$	244,329	$	237,516
Current liabilities	$	1,798	$	4,512

	Year Ended		Year Ended			Year Ended
	December 31, 2017		December 31, 2016			December 31, 2015
Revenues	$	28,805	$	2,217		$	—
Gross profit	$	28,805	$	2,217		$	—
Net Income/loss	$	10,714	$	(3,641	)	$	(1,967	)

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Segment Data

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Segment Data

Segment Data

We aggregate our operating segments into two reportable segments: (i) pipelines and transportation and (ii) wholesale marketing and terminalling:

• The assets and investments reported in the pipelines and transportation segment provide crude oil gathering, and crude oil, intermediate and finished products transportation and storage services to Delek's refining operations and independent third parties.

• The wholesale marketing and terminalling segment provides wholesale marketing and terminalling services to Delek's refining operations and independent third parties.

Our operating segments adhere to the accounting policies used for our consolidated financial statements, as described in Note 2. Our operating segments are managed separately, because each segment requires different industry knowledge, technology and marketing strategies. 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 its reportable segments based on segment contribution margin. Segment contribution margin is defined as net sales less cost of goods sold and operating expenses.

During the year ended December 31, 2015, we acquired the Logistics Assets from Delek. Our historical financial statements have been retrospectively adjusted as appropriate to reflect the results of operations attributable to the Logistics Assets as if we owned the assets for all periods presented. The results of the Logistics Assets are included in the pipelines and transportation segment.

The following is a summary of business segment operating performance as measured by contribution margin for the period indicated (in thousands):

	Year Ended December 31,
	2017			2016			2015
Pipelines and Transportation
Net sales:
Affiliate	109,298			$	103,749		102,551
Third party	12,431			18,423			28,828
Total pipelines and transportation	121,729			122,172			131,379
Operating costs and expenses:
Cost of goods sold	18,210			19,425			19,607
Operating expenses	33,240			29,235			33,751
Segment contribution margin	$	70,279		$	73,512		$	78,021
Capital spending (excluding business combinations)	$	14,262		$	8,478		$	16,030
Wholesale Marketing and Terminalling
Net sales:
Affiliate	46,982			45,815			50,013
Third party	369,364			280,072			408,277
Total wholesale marketing and terminalling	416,346			325,887			458,290
Operating costs and expenses:
Cost of goods sold	354,680			282,733			416,697
Operating expenses	10,034			7,963			11,172
Segment contribution margin	$	51,632		$	35,191		$	30,421
Capital spending (excluding business combinations)	$	4,141		$	3,289		$	6,397
Consolidated
Net sales:
Affiliate	$	156,280		$	149,564		$	152,564
Third party	381,795			298,495			437,105
Total Consolidated	538,075			448,059			589,669
Operating costs and expenses:
Cost of goods sold	372,890			302,158			436,304
Operating expenses	43,274			37,198			44,923
Contribution margin	121,911			108,703			108,442
General and administrative expenses	11,840			10,256			11,384
Depreciation and amortization	21,914			20,813			19,692
(Gain) loss on asset disposals	(20		)	(16		)	104
Operating income	$	88,177		$	77,650		$	77,262
Capital spending (excluding business combinations)	$	18,403		$	11,767		$	22,427

The following table summarizes the total assets for each segment as of December 31, 2017 and 2016 (in thousands).

	Year Ended December 31,
	2017		2016
Pipelines and transportation	$	349,351	$	337,349
Wholesale marketing and terminalling	94,179		78,198
Total Assets	$	443,530	$	415,547

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Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

The fair values of financial instruments are estimated based upon current market conditions and quoted market prices for the same or similar instruments. Management estimates that the carrying value approximates fair value for all of our assets and liabilities that fall under the scope of ASC 825.

We apply the provisions of ASC 820, which defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. ASC 820 applies to commodity and interest rate derivatives that are measured at fair value on a recurring basis. The standard also requires that we assess the impact of nonperformance risk on our derivatives. Nonperformance risk is not considered material as of December 31, 2017.

ASC 820 requires disclosures that categorize assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting our assumptions about pricing by market participants.

Over the counter ("OTC") commodity swaps and any interest rate swaps and caps are generally valued using industry-standard models that consider various assumptions, including quoted forward prices, spot prices, interest rates, time value, volatility factors and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines the classification as Level 2 or 3. Our contracts are valued based on exchange pricing and/or price index developers such as Platts or Argus and are, therefore, classified as Level 2.

The fair value hierarchy for our financial assets and liabilities accounted for at fair value on a recurring basis at December 31, 2017 and 2016 was as follows: (in thousands):

	As of December 31, 2017
	Level 1		Level 2			Level 3		Total
Liabilities
OTC commodity swaps	—		(1,087		)	—		(1,087		)
Net liabilities	$	—	$	(1,087	)	$	—	$	(1,087	)

	As of December 31, 2016
	Level 1		Level 2			Level 3		Total
Assets
OTC commodity swaps	$	—	$	9		$	—	$	9
Total assets	—		9			—		9
Liabilities
OTC commodity swaps	—		(82		)	—		(82		)
Net assets	$	—	$	(73	)	$	—	$	(73	)

The derivative values above are based on analysis of each contract as the fundamental unit of account as required by ASC 820. Derivative assets and liabilities with the same counterparty are not netted where the legal right of offset exists. This differs from the presentation in the financial statements, which reflects our policy under the guidance of ASC 815-10-45, wherein we have elected to offset the fair value amounts recognized for multiple derivative instruments executed with the same counterparty where the legal right of offset exists.

As of December 31, 2017 and 2016, we had cash collateral of $0.3 million and a cash deficit of $0.6 million, respectively, netted with the net derivative position of our counterparty. See Note 17 for further information regarding derivative instruments.

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Derivative Instruments

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

Derivative Instruments

From time to time, we enter into forward fuel contracts to limit the exposure to price fluctuations for physical purchases of finished products in the normal course of business. We use derivatives to reduce the impact of market price volatility on our results of operations. Typically, we enter into forward fuel contracts with major financial institutions in which we fix the purchase price of finished grade fuel for a predetermined number of units with fulfillment terms of less than 90 days.

From time to time, we may also enter into interest rate hedging agreements to limit floating interest rate exposure under the Second Amended and Restated Credit Agreement. Our initial credit facility required us to maintain interest rate hedging arrangements on at least 50% of the amount funded on November 7, 2012 under the credit facility, which was required to be in place for at least a three-year period beginning no later than March 7, 2013. Accordingly, effective February 25, 2013, we entered into an interest rate hedge in the form of a LIBOR interest rate cap for a term of three years for a total notional amount of $45.0 million, thereby meeting the requirements in effect at that time. The interest rate hedge remained in place in accordance with its term through its maturity date in February 2016.

The following table presents the fair value of our derivative instruments, as of December 31, 2017 and 2016. The fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under our master netting arrangements, including any cash deficit or collateral on deposit with our counterparties. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements. As a result, the asset and liability amounts below may differ from the amounts presented in our accompanying consolidated balance sheets. During the years ended December 31, 2017 and 2016, we did not elect hedge accounting treatment for these derivative positions. As a result, all changes in fair value are marked to market in the accompanying consolidated statements of income and comprehensive income. See Note 16 for further information regarding the fair value of derivative instruments.

(in thousands)		December 31, 2017					December 31, 2016
Derivative Type	Balance Sheet Location	Assets		Liabilities			Assets		Liabilities
Derivatives:
OTC commodity swaps (1)	Other current assets	$	—	$	(1,087	)	$	9	$	(82	)
Total gross value of derivatives		—		(1,087		)	9		(82		)
Less: Counterparty netting and cash collateral (2)		—		(290		)	9		621
Total net fair value of derivatives		$	—	$	(797	)	$	—	$	(703	)

⁽¹⁾  As of December 31, 2017 and 2016, we had open derivative contracts representing 370,000 barrels and 93,000 barrels, respectively, of refined petroleum products.

⁽²⁾  As of December 31, 2017 and 2016, we had cash collateral of $0.3 million and a cash deficit of $0.6 million, respectively, netted with the net derivative position of our counterparty.

Recognized gains (losses) associated with our derivatives for the years ended December 31, 2017 and 2016 were as follows (in thousands):

		Year Ended December 31,
Derivative Type	Income Statement Location	2017			2016			2015
Interest rate derivatives	Interest expense	$	—		$	—		$	(24	)
OTC commodity swaps	Cost of goods sold	(1,550		)	(2,122		)	441
	Total	$	(1,550	)	$	(2,122	)	$	417

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Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

For tax purposes, each partner of the Partnership is required to take into account its share of income, gain, loss and deduction in computing its federal and state income tax liabilities, regardless of whether cash distributions are made to such partner by the Partnership. The taxable income reportable to each partner takes into account differences between the tax basis and fair market value of our assets, the acquisition price of such partner's units and the taxable income allocation requirements under our Partnership Agreement.

The Partnership is not a taxable entity for federal income tax purposes. While most states do not impose an entity level tax on partnership income, the Partnership is subject to entity level tax in both Tennessee and Texas. The Partnership does not file a separate Texas tax return. Our results of operations are included in Delek’s consolidated return. However, the provisions of ASC 740 have been followed as if we were a stand-alone entity. As a result, the Partnership must record deferred income taxes for the differences between book and tax bases of its assets and liabilities based on those states' enacted tax rates and laws that will be in effect when the differences are expected to reverse. The consolidated Texas franchise tax return for Delek, including the Partnership, is currently under examination for tax years 2012 through 2015. No material adjustments have been identified at this time.

The total non-current deferred tax assets were $0.4 million and $0.3 million as of December 31, 2017 and 2016, respectively, and are included in other non-current assets in our accompanying consolidated balance sheets. The majority component of our non-current deferred tax assets as of December 31, 2017 and 2016 was depreciation and amortization.

The difference between the actual income tax expense and the tax expense computed by applying the statutory federal income tax rate to income before income taxes is attributable to the following (in thousands):

	Year Ended December 31,
	2017			2016			2015
State income taxes	(222		)	121			171
Other items	—			(40		)	(366		)
Income tax expense (benefit)	$	(222	)	$	81		$	(195	)

Income tax expense (benefit) is as follows (in thousands):

	Year Ended December 31,
	2017			2016			2015
Current	$	(111	)	$	254		$	(209	)
Deferred	(111		)	(173		)	14
Total	$	(222	)	$	81		$	(195	)

Delek files a consolidated Texas gross margin tax return, and tax payments for the Partnership are paid by Delek. Therefore, a portion of the current tax payable is included in accounts receivable/payable from related parties. As of December 31, 2017 and 2016, income taxes payable of $0.3 million and $0.1 million, respectively, were included in accounts receivable/payable from related parties in the accompanying consolidated balance sheets. Taxes that are determined on a consolidated basis apply the “benefits for loss” allocation method; thus, tax attributes are realized when used in the combined tax return to the extent that they have been subject to a valuation allowance.

We recognize accrued interest and penalties related to unrecognized tax benefits as an adjustment to the current provision for income taxes. There were no uncertain tax positions recorded as of December 31, 2017 or 2016, and there were no interest or penalties recognized related to uncertain tax positions for the years ended December 31, 2017, 2016 or 2015. We have examined uncertain tax positions for any material changes in the next 12 months and none are expected.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Litigation

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. See "Crude Oil Releases" below for a potential enforcement action.

Environmental Health and Safety

We are subject to extensive and periodically changing federal, state and local laws and regulations relating to the protection of the environment, health and safety. Among other things, these laws and regulations govern the emission or discharge of pollutants into or onto the land, air and water, the handling and disposal of solid and hazardous wastes, and the remediation of contamination and the protection of workers and the public. Compliance with existing and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to develop, maintain, operate and upgrade equipment and facilities. Numerous permits or other authorizations are required under these laws for the operation of our terminals, pipelines and related operations, and may be subject to revocation, modification and renewal. These laws and permits may become the basis for 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, or that relate to pre-existing conditions for which we have assumed or are assigned responsibility. Releases of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, or is not a reimbursable event under the Omnibus Agreement, subject us to substantial expenses, including costs to respond to, contain and remediate a release, to comply with applicable laws and regulations and to resolve claims by third parties for personal injury, property damage or natural resources damages. These impacts could directly and indirectly affect our business. We cannot currently determine the amounts of such future impacts; however, we accrue liabilities for such events when we are able to determine if an amount is probable and can be reasonably estimated.

Crude Oil Releases

We have experienced several crude oil releases involving our assets, including, but not limited to, the following releases:

• In January 2016, a crude oil release of less than 30 barrels occurred from a gathering line at the Modisette pumping station near El Dorado, Arkansas;

• In January 2016, a crude oil release of approximately 350 barrels occurred from the Paline Pipeline near Woodville, Texas (the "Paline Release");

• In April 2015, a crude oil release of an estimated 130 barrels was discovered from a gathering line near Fouke, Arkansas; and

• In March 2013, a release of approximately 5,900 barrels of crude oil, the majority of which was contained on-site, occurred from a pumping facility at our Magnolia Station located west of the El Dorado Refinery (the "Magnolia Release").

Cleanup operations and site maintenance and remediation efforts on these and other releases have been substantially completed. We may incur additional expenses as a result of further scrutiny by regulatory authorities and continued compliance with laws and regulations to which our assets are subject. Expenses incurred for the remediation of these crude oil releases are included in operating expenses in our consolidated statements of income and comprehensive income and are subsequently reimbursed by Delek pursuant to the terms of the Omnibus Agreement. Reimbursements are recorded as a reduction to operating expense. We do not believe the total costs associated with these events, whether alone or in the aggregate, including any fines or penalties and net of partial insurance reimbursement, will have a material adverse effect upon our business, financial condition or results of operations, as we are reimbursed by Delek for such costs.

In June 2015, the United States Department of Justice notified the Partnership that it was pursuing an enforcement action on behalf of the Environmental Protection Agency (the "EPA") with regard to potential Clean Water Act violations arising from the Magnolia Release. We are currently attempting to negotiate a resolution to this matter with the EPA and the State of Arkansas, which may include monetary penalties and/or other relief. As of December 31, 2017, we have accrued $1.0 million, which we have recorded in pipeline release liabilities in our consolidated balance sheet, for the Magnolia Release in connection with these proceedings.

Contracts and Agreements

The majority of the petroleum products we sold prior to December 31, 2017 in west Texas were purchased from Noble Petro, Inc. ("Noble Petro"). Under the terms of a supply contract (the "Abilene Contract") with Noble Petro that expired on December 31, 2017, we purchased petroleum products based on monthly average prices from Noble Petro at the Abilene, Texas terminal, which we own, for sales and exchange with third parties at the Abilene and San Angelo terminals. We leased the Abilene and San Angelo, Texas terminals to Noble Petro under a separate Terminal and Pipeline Lease and Operating Agreement, that expired on December 31, 2017. We purchase spot barrels from various third parties, which may continue to include Noble Petro, and from Delek for sale to wholesale customers in west Texas.

Letters of Credit

As of December 31, 2017, we had in place letters of credit totaling $9.0 million under the Second Amended and Restated Credit Agreement, primarily securing obligations with respect to gasoline and diesel purchases. No amounts were drawn under these letters of credit at December 31, 2017.

Operating Leases

We lease certain equipment and have surface leases under various operating lease arrangements, most of which provide the option, after the initial lease term, to renew the leases. None of these lease arrangements include fixed rental rate increases. Lease expense for all operating leases for the years ended December 31, 2017, 2016 and 2015 totaled $5.6 million, $5.7 million and $5.3 million, respectively.

The following is an estimate of our future minimum lease payments for operating leases having remaining noncancelable terms in excess of one year as of December 31, 2017 (in thousands):

2018	$	2,482
2019	546
2020	483
2021	293
2022	173
Thereafter	8
Total future minimum rentals	$	3,985

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Selected Quarterly Financial Data (Unaudited) Selected Quarterly Financial Data

12 Months Ended

Dec. 31, 2017

Selected Quarterly Financial Information [Abstract]

Selected Quarterly Financial Data

Selected Quarterly Financial Data (Unaudited)

Quarterly financial information for the years ended December 31, 2017 and 2016 is summarized below. The quarterly financial information summarized below has been prepared by management and is unaudited (in thousands, except per unit data).

	For the Three Month Periods Ended
	March 31, 2017		June 30, 2017		September 30, 2017		December 31, 2017
Net sales	$	129,473	$	126,769	$	130,626	$	151,207
Operating income	$	18,472	$	23,371	$	22,636	$	23,698
Net income	$	14,595	$	18,977	$	16,923	$	18,914
Limited partners' interest in net income	$	10,486	$	14,425	$	12,178	$	13,891
Net income per limited partner unit:
Common (basic)	$	0.43	$	0.59	$	0.50	$	0.57
Common (diluted)	$	0.43	$	0.59	$	0.50	$	0.57

	For the Three Month Periods Ended
	March 31, 2016		June 30, 2016		September 30, 2016		December 31, 2016
Net sales	$	104,056	$	111,853	$	107,470	$	124,680
Operating income	$	18,974	$	22,512	$	17,001	$	19,163
Net income	$	15,448	$	18,893	$	13,151	$	15,312
Limited partners' interest in net income	$	13,195	$	16,102	$	9,892	$	11,422
Net income per limited partner unit:
Common (basic)	$	0.54	$	0.66	$	0.41	$	0.47
Common (diluted)	$	0.54	$	0.66	$	0.41	$	0.47
Subordinated - Delek (basic and diluted)	$	0.54	$	—	$	—	$	—

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Subsequent Events

12 Months Ended

Dec. 31, 2017

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

Distribution Declaration

On January 23, 2018, our general partner's board of directors declared a quarterly cash distribution of $0.725 per share, paid on February 12, 2018, to unitholders of record on February 2, 2018.    

Big Spring Asset Dropdown

On February 26, 2018, a definitive agreement was entered into between the Partnership and Delek for the Partnership to acquire certain logistics assets primarily located adjacent to Delek's Big Spring, Texas refinery (“Big Spring Refinery”), which are discussed in more detail below (“Big Spring Logistics Assets”). In addition, the parties entered into a new wholesale marketing agreement, whereby the Partnership will market certain finished products produced at the Big Spring refinery to various branded and unbranded customers in return for a marketing fee.

The Big Spring Logistics Assets will include:

• Approximately 60 storage tanks and certain ancillary assets (such as tank pumps and piping) primarily located adjacent to the Big Spring Refinery;

• An asphalt terminal and a light products terminal;

• Certain crude oil and refined product pipelines; and

• Other logistics assets, such as four underground saltwells used for natural gas liquids storage.

The purchase price is $315.0 million, financed through a combination of cash on hand and borrowings on the Partnership’s revolving credit facility, with closing expected to occur in March 2018.

In connection with the closing of the transaction, Delek, the Partnership and various of their subsidiaries expect to enter into and amend certain existing contracts, such as a new throughput and tankage agreement for the Big Spring Logistics Assets. The transaction has been and related agreements are expected to be approved by the Conflicts Committee of Delek Logistics’ general partner, which is comprised solely of independent directors.

Formation of Green Plains Joint Venture

On February 20, 2018, the Partnership and Green Plains Partners LP ("Green Plains") announced the companies have formed DKGP Energy Terminals, LLC ("DKGP Energy"), a joint venture engaging in the light products terminalling business. The Partnership and Green Plains will each own a 50% membership interest in DKGP Energy. DKGP Energy signed a membership interest purchase agreement to acquire two light products terminals located in Caddo Mills, Texas and North Little Rock, Arkansas from an affiliate of American Midstream Partners, L.P. ("American Midstream"). Subject to customary closing conditions and regulatory approvals, this transaction is expected to close in the first half of 2018. DKGP Energy will consist of the assets purchased from the affiliate of American Midstream and assets contributed by the Partnership. Immediately prior to the closing of the acquisition by the joint venture of the two terminals from American Midstream, the Partnership will contribute to the joint venture its North Little Rock, Arkansas terminal and its Greenville tank farm located in Caddo Mills, Texas. The DKGP Energy board will oversee the newly formed joint venture and will appoint an affiliate of the Partnership as the operator with day-to-day operational responsibilities of the four terminals.

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General (Policies)

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Combination of Entities under Common Control

Organization

As used in this report, the terms "Delek Logistics Partners, LP," the "Partnership," "we," "us," or "our" may refer to Delek Logistics Partners, LP, one or more of its consolidated subsidiaries or all of them taken as a whole.

The Partnership is a Delaware limited partnership formed in April 2012 by Old Delek (as defined below) and its subsidiary Delek Logistics GP, LLC, our general partner (our "general partner').

In January 2017, Delek US Holdings, Inc. ("Old Delek") (and various related entities) entered into an Agreement and Plan of Merger with Alon USA Energy, Inc. (NYSE: ALJ) ("Alon USA"), as subsequently amended on February 27 and April 21, 2017 (as so amended, the "Merger Agreement"). The related merger (the "Delek/Alon Merger") was effective July 1, 2017 (the “Effective Time”), resulting in a new post-combination consolidated registrant renamed Delek US Holdings, Inc. (“New Delek”), with Alon USA and Old Delek surviving as wholly-owned subsidiaries. New Delek is the successor issuer to Old Delek and Alon USA pursuant to Rule 12g-3(c) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Unless the context otherwise requires, references in this report to "Delek" refer collectively to Old Delek with respect to periods prior to July 1, 2017, or New Delek, with respect to periods on or after July 1, 2017, and any of Old Delek's or New Delek's, as applicable, subsidiaries, other than the Partnership and its subsidiaries and its general partner.

On March 31, 2015, the Partnership, through its wholly owned subsidiary Delek Logistics Operating, LLC ("OpCo"), acquired from Delek two crude oil rail offloading racks, which are designed to receive up to 25,000 barrels per day (“bpd”) of light crude oil or 12,000 bpd of heavy crude oil, or any combination of the two, delivered by rail to the El Dorado Refinery and related ancillary assets (the “El Dorado Assets”) (such transaction, the "El Dorado Rail Offloading Racks Acquisition").

On March 31, 2015, the Partnership, through its wholly owned subsidiary Delek Marketing & Supply, LP, acquired from Delek a crude oil storage tank ("the Tyler Crude Tank") located adjacent to Delek's Tyler, Texas refinery (the "Tyler Refinery") and certain ancillary assets (collectively, with the Tyler Crude Tank, the "Tyler Assets") (such transaction, the "Tyler Crude Tank Acquisition"). The Tyler Crude Tank has approximately 350,000 barrels of shell capacity and primarily supports the Tyler Refinery. The Tyler Assets, together with the El Dorado Assets, are hereinafter collectively referred to as the "Logistics Assets."

The El Dorado Rail Offloading Racks Acquisition and the Tyler Crude Tank Acquisition are hereinafter collectively referred to as the "Acquisitions from Delek." The Acquisitions from Delek were accounted for as transfers between entities under common control. As entities under common control with Delek, we record the assets that Delek has contributed to us on our balance sheet at Delek's historical basis instead of fair value. Transfers between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. Accordingly, the accompanying financial statements and related notes of the Partnership have been retrospectively adjusted to include, (i) the historical results of the El Dorado Assets, as owned and operated by Delek, for all periods presented through March 31, 2015 (the "El Dorado Assets Predecessor") and (ii) the historical results of the Tyler Assets, as owned and operated by Delek, for all periods presented through March 31, 2015 (the "Tyler Assets Predecessor"). The El Dorado Assets Predecessor, together with the Tyler Assets Predecessor, are hereinafter collectively referred to as our "Predecessors." See Note 3 for further information regarding the Acquisitions from Delek.

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Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

Our consolidated financial statements include the accounts of the Partnership and its subsidiaries as well as our Predecessors. All intercompany accounts and transactions have been eliminated. The financial statements of our Predecessors have been prepared from the separate records maintained by Delek and may not necessarily be indicative of the conditions that would have existed or the results of operations if our Predecessors had been operated as an unaffiliated entity. Our Predecessors did not record all revenues for intercompany gathering, pipeline transportation, terminalling and storage services. Transfers between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. As an entity under common control with Delek, we record the assets that Delek has contributed to us on our balance sheet at Delek's historical basis instead of fair value.

We have evaluated subsequent events through the filing of this Annual Report on Form 10-K. Any material subsequent events that occurred during this time have been properly recognized or disclosed in our financial statements. The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“U.S. GAAP”) and in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Segment Reporting

Segment Reporting

We are an energy business focused on crude oil, intermediate and refined products pipeline and storage activities and wholesale marketing, terminalling and offloading activities. Management reviews operating results in two reportable segments: (i) pipelines and transportation and (ii) wholesale marketing and terminalling. The pipelines and transportation segment provides crude oil gathering, transportation and storage services to Delek's refining operations and independent third parties. The wholesale marketing and terminalling segment provides marketing, wholesale marketing and terminalling services to Delek's refining operations and independent third parties. 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 its reportable segments based on the segment contribution margin. Segment contribution margin is defined as net sales less cost of goods sold and operating expenses, excluding depreciation and amortization. Segment reporting is more fully discussed in Note 15.

Cash and Cash Equivalents

Cash and Cash Equivalents

We maintain cash and cash equivalents in accounts with large, U.S. financial institutions. Any highly liquid investments purchased with an original maturity of three months or less are considered to be cash equivalents.

Accounts Receivable

Accounts Receivable

Accounts receivable primarily consists of trade receivables generated in the ordinary course of business. We perform on-going credit evaluations of our customers and generally do not require collateral on accounts receivable. All accounts receivable amounts are considered to be fully collectible. Accordingly, no allowance for doubtful accounts has been established as of December 31, 2017 and 2016. One third-party customer accounted for approximately 22.0% of the consolidated accounts receivable balance as of December 31, 2017. Two third-party customers accounted for approximately 36.6% of the consolidated accounts receivable balance as of December 31, 2016.

Inventory

Inventory

Inventory consists of refined products, which are stated at the lower of cost or net realizable value, with cost determined on a first-in, first-out ("FIFO") basis. One third party vendor and Delek accounted for approximately 65.8% and 11.6%, respectively, of our inventory purchases in our wholesale marketing and terminalling segment during the year ended December 31, 2017. Two third party vendors in our wholesale marketing and terminalling segment accounted for approximately 72.0% of our inventory purchases during the year ended December 31, 2016. One third party vendor and Delek accounted for approximately 62.6% and 24.9%, respectively, of our inventory purchases in our wholesale marketing and terminalling segment during the year ended December 31, 2015.

Property, Plant and Equipment

Property, Plant and Equipment

Assets acquired in conjunction with business acquisitions are recorded at estimated fair market value in accordance with the purchase method of accounting as prescribed in Accounting Standards Codification ("ASC") 805, Business Combinations ("ASC 805"). Other acquisitions of property and equipment are carried at cost. Acquisitions of net assets that do not constitute a business are accounted for by allocating the cost of the acquisition to individual assets acquired and liabilities assumed on relative fair value basis and shall not give rise to goodwill as prescribed in ASC 805.

Betterments, renewals and extraordinary repairs that extend the life of an asset are capitalized. Maintenance and repairs are charged to expense as incurred.

Depreciation is computed using the straight-line method over management’s estimated useful lives of the related assets, except for automotive equipment, which is depreciated using a declining-balance method. The estimated useful lives are as follows:

	Years
Buildings and building improvements	15-40
Pipelines, tanks and terminals	15-40
Asset retirement obligation assets	15-50
Other equipment	3-15

Intangible Assets

Intangible Assets

Intangible assets consist of a long-term supply contract and indefinite-lived rights of way. We amortize the definite-lived long-term supply contract on a straight-line basis over the estimated useful life of 11.5 years. The amortization expense is included in depreciation and amortization in the accompanying consolidated financial statements.

Property, Plant and Equipment and Intangibles Impairment

Property, Plant and Equipment and Intangibles Impairment

Property, plant and equipment and definite life intangibles are evaluated for impairment whenever indicators of impairment exist. In accordance with ASC 360, Property, Plant and Equipment and ASC 350, Intangibles - Goodwill and Other, we evaluate the realizability of these long-lived assets as events occur that might indicate potential impairment. In doing so, we assess whether the carrying amount of the asset is unrecoverable by estimating the sum of the future cash flows expected to result from the asset, undiscounted and without interest charges. If the carrying amount is more than the recoverable amount, an impairment charge must be recognized based on the fair value of the asset.

Goodwill and Potential Impairment

Goodwill and Potential Impairment

Goodwill in an acquisition represents the excess of the aggregate purchase price over the fair value of the identifiable net assets. Our goodwill is recorded at original fair value and is not amortized. Goodwill is subject to annual assessment to determine if an impairment of value has occurred and we perform this review annually in the fourth quarter. We could also be required to evaluate our goodwill if, prior to our annual assessment, we experience disruptions in our business, have unexpected significant declines in operating results, or sustain a permanent market capitalization decline. If an asset’s carrying amount exceeds its fair value, the impairment assessment leads to the testing of the implied fair value of the asset’s goodwill to its carrying amount. If the implied fair value is less than the carrying amount, a goodwill impairment charge is recorded. Our annual assessment of goodwill did not result in an impairment charge during the years ended December 31, 2017, 2016 or 2015.

Equity Method Investments

Equity Method Investments

For equity investments that are not required to be consolidated under the variable or voting interest model, we evaluate the level of influence we are able to exercise over an entity’s operations to determine whether to use the equity method of accounting. Our judgment regarding the level of control over an equity method investment includes considering key factors such as our ownership interest, participation in policy-making and other significant decisions and material intercompany transactions. Amounts recognized for equity method investments are included in equity method investments in our consolidated balance sheet and adjusted for our shares of the net earnings and losses of the investee and cash distributions, which are separately presented in our consolidated statements of income and comprehensive income and our consolidated statements of cash flows. We evaluate our equity method investments for impairment whenever events or changes in circumstances indicate that the carrying amounts of such investments may be impaired. A loss is recorded in earnings in the current period if a decline in the value of an equity method investment is determined to be other than temporary.

Derivatives

Derivatives

We record all derivative financial instruments, including forward fuel contracts, at estimated fair value in accordance with the provisions of ASC 815, Derivatives and Hedging ("ASC 815"). Changes in the fair value of the derivative instruments are recognized in operations, unless we elect to apply the hedge accounting treatment permitted under the provisions of ASC 815 allowing such changes to be classified as other comprehensive income for cash flow hedges. We validate the fair value of all derivative financial instruments on a periodic basis, utilizing exchange pricing and/or price index developers, such as Platts or Argus. During the years ended December 31, 2017, 2016 and 2015, we did not elect to apply hedge accounting treatment to our derivative positions and, therefore, all changes in fair value are reflected in the statements of income and comprehensive income.

Our policy under the guidance of ASC 815-10-45, Derivatives and Hedging—Other Presentation Matters ("ASC 815-10-45"), is to net the fair value amounts recognized for multiple derivative instruments executed with the same counterparty and offset these values against any cash collateral associated with these derivative positions. See Note 17 for further discussion.

Fair Value of Financial Instruments

Fair Value of Financial Instruments

The fair values of financial instruments are estimated based upon current market conditions and quoted market prices for the same or similar instruments. Management estimates that the carrying value approximates fair value for all of our assets and liabilities that fall under the scope of ASC 825, Financial Instruments ("ASC 825").

We apply the provisions of ASC 820, Fair Value Measurements and Disclosure ("ASC 820"), in our presentation and disclosures regarding fair value, which pertain to certain financial assets and liabilities measured at fair value in the balance sheet on a recurring basis. ASC 820 defines fair value, establishes a framework for measuring fair value and expands disclosures about such measurements that are permitted or required under other accounting pronouncements. See Note 16 for further discussion.

We apply the provisions of ASC 825 as it pertains to the fair value option. This standard permits the election to carry financial instruments and certain other items similar to financial instruments at fair value on the balance sheet, with all changes in fair value reported in earnings. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. As of December 31, 2017 and 2016, we did not make the fair value election for any financial instruments not already carried at fair value in accordance with other standards.

Self Insurance Reserves

Self-Insurance Reserves

We have no employees. Rather, we are managed by the directors and officers of our general partner. However, Delek employees providing services to the Partnership are covered under Delek’s insurance programs. Delek has workers' compensation and liability insurance with varying retentions and deductibles with limits that management considers adequate.

Environmental Expenditures

Environmental Expenditures

We have historically accrued environmental and clean-up related costs of a non-capital nature when it is both probable that a liability has been incurred and the amount can be reasonably estimated. Environmental liabilities represent the current estimated costs to investigate and remediate contamination at our properties. This estimate is based on internal and third-party assessments of the extent of the contamination, the selected remediation technology and review of applicable environmental regulations, typically considering estimated activities and costs for the next 15 years, unless a specific longer range estimate is practicable. Accruals for estimated costs from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study and include, but are not limited to, costs to perform remedial actions and costs of machinery and equipment that are dedicated to the remedial actions and that does not have an alternative use. Such accruals are adjusted as further information develops or circumstances change. We discount environmental liabilities to their present value if payments are fixed and determinable. Expenditures for equipment necessary for environmental issues relating to ongoing operations are capitalized. Estimated recoveries of costs from other parties are recorded on an undiscounted basis as assets when their realization is deemed probable.

Asset Retirement Obligations

In order to determine fair value, management must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free rate and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation.

Asset Retirement Obligations

We recognize liabilities which represent the fair value of a legal obligation to perform asset retirement activities, including those that are conditional on a future event, when the amount can be reasonably estimated. These obligations are related to the required cleanout of our pipelines and terminal tanks and removal of certain above-grade portions of our pipelines situated on right-of-way property.

Revenue Recognition

Revenue Recognition

Revenues for products sold are recorded at the point of sale upon delivery of product, which is the point at which title to the product is transferred, and when payment has either been received or collection is reasonably assured. Service revenues are recognized as crude oil, intermediate and refined products are shipped through, delivered by or stored in our pipelines, trucks, terminals and storage facility assets, as applicable. We do not recognize product sales revenues for these services, as title on the product never passes to us. All service revenues are based on regulated tariff rates or contractual rates.

Cost of Goods Sold and Operating Expenses

Cost of Goods Sold and Operating Expenses

Cost of goods sold includes all costs of refined products, additives and related transportation. It also includes costs associated with the operation of our trucking assets. We do not recognize product cost of goods sold related to our shipping, delivering and storage services, as title to the product never passes to us. Operating expenses include the costs associated with the operation of owned terminals and other logistics assets, terminalling expense at third-party locations and pipeline maintenance costs.

Sales, Use and Excise Taxes

Sales, Use and Excise Taxes

Our policy is to exclude sales, use and excise taxes from revenue when we are an agent of the taxing authority, in accordance with ASC 605-45, Revenue Recognition—Principal Agent Considerations.

Deferred Financing Costs

Deferred Financing Costs

Deferred financing costs are included in other non-current assets in the accompanying consolidated balance sheets and represent expenses related to issuing and amending our revolving credit facility. Deferred financing costs associated with our 6.750% Senior Notes are included as a reduction to the associated debt balance in the accompanying consolidated balance sheets. These costs represent expenses related to issuing the senior notes. These amounts are amortized ratably over the remaining term of the respective financing and are included in interest expense in the accompanying consolidated statements of income and comprehensive income.

Operating Leases

Operating Leases

We lease certain equipment and have surface leases under various operating lease arrangements, most of which provide the option, after the initial lease term, to renew the leases. None of these lease arrangements include fixed rental rate increases.

Income Taxes

Income Taxes

We are not a taxable entity for federal income tax purposes or the income taxes of those states that follow the federal income tax treatment of partnerships. Instead, for purposes of these income taxes, each partner of the Partnership is required to take into account its share of income, gain, loss and deduction in computing its federal and state income tax liabilities, regardless of whether cash distributions are made to such partner by the Partnership. The taxable income reportable to each partner takes into account differences between the tax basis and fair market value of our assets, the acquisition price of such partner's units and the taxable income allocation requirements under the First Amended and Restated Agreement of Limited Partnership (the "Partnership Agreement").

We are subject to income taxes in certain states that do not follow the federal tax treatment of Partnerships. These taxes are accounted for under the provisions of ASC 740, Income Taxes (ASC 740). This statement generally requires DKL to record deferred income taxes for the differences between the book and tax bases of its assets and liabilities, which are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. Deferred income tax expense or benefit represents the net change during the year in our deferred income tax assets and liabilities, exclusive of the amounts held in other comprehensive income.

U.S. GAAP requires management to evaluate uncertain tax positions taken by the Partnership. The financial statement effects of a tax position are recognized when the position is more likely than not, based on the technical merits, to be sustained upon examination by the Internal Revenue Service. Management has analyzed the tax positions taken by the Partnership, and has concluded that there are no uncertain positions taken or expected to be taken. The Partnership is subject to routine audits by taxing jurisdictions

Equity based Compensation

Equity Based Compensation

Our general partner provides equity-based compensation to officers, directors and employees of our general partner or its affiliates, and certain consultants, affiliates of our general partner or other individuals who perform services for us, which includes unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The fair value of our phantom units is determined based on the closing market price of our common units on the grant date. The estimated fair value of our phantom units is amortized over the vesting period using the straight line method. Awards vest over one- to five-year service periods, unless such awards are amended in accordance with the LTIP. It is our practice to issue new units when phantom units vest.

Net income per Limited Partner Unit

Net Income per Limited Partner Unit

We use the two-class method when calculating the net income per unit applicable to limited partners because we have more than one participating class of securities. Our participating securities consist of common units, subordinated units, general partner units and incentive distribution rights ("IDRs"). The two-class method is based on the weighted-average number of common units outstanding during the period. Basic net income per unit applicable to limited partners (including subordinated unitholders) is computed by dividing limited partners’ interest in net income, after deducting our general partner’s 2% interest and IDRs, by the weighted-average number of outstanding common and subordinated units. Our net income is allocated to our general partner and limited partners in accordance with their respective partnership percentages after giving effect to priority income allocations for IDRs to our general partner, which is the holder of the IDRs pursuant to our Partnership Agreement. The weighted-average number of common units reflects the conversion of the subordinated units to common units on February 25, 2016. See Notes 5 and 12 for further discussion.

Diluted net income per unit applicable to common limited partners includes the effects of potentially dilutive units on our common units. At present, the only potentially dilutive units outstanding consist of unvested phantom units. Basic and diluted net income per unit applicable to subordinated limited partners are the same because there are no potentially dilutive subordinated units outstanding.

Comprehensive Income

Comprehensive Income

Comprehensive income for the years ended December 31, 2017, 2016 and 2015 was equivalent to net income.

New Accounting Pronouncements

New Accounting Pronouncements

In August 2017, the Financial Accounting Standards Board (the "FASB") issued guidance to refine and expand hedge accounting for both financial and commodity risks. Its provisions create more transparency around how economic results are presented, both on the face of the financial statements and in the footnotes and align the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. It also makes certain targeted improvements to simplify the application of hedge accounting guidance. This guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, and can be early adopted for any interim or annual financial statements that have not yet been issued. We expect to adopt this guidance on or before the effective date and are currently evaluating the impact that adopting this new guidance will have on our business, financial condition and results of operations.

In May 2017, the FASB issued guidance that clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. The modification accounting guidance applies if the value, vesting conditions or classification of the award changes. This guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, and can be early adopted for any interim or annual financial statements that have not yet been issued. We expect to adopt this guidance on or before the effective date and are currently evaluating the impact that adopting this new guidance will have on our business, financial condition and results of operations.

In January 2017, the FASB issued guidance that eliminates Step 2 of the goodwill impairment test, which required a comparison of the implied fair value of goodwill of a reporting unit with the carrying amount of that goodwill for that reporting unit. It also eliminates the requirements for any reporting unit with a zero or negative carrying amount to perform a qualitative assessment and, if it fails that qualitative assessment, to perform Step 2 of the goodwill impairment test. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. This guidance is effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We expect to adopt this guidance on or before the effective date and we do not anticipate that the adoption will have a material impact on our business, financial condition or results of operations.

In January 2017, the FASB issued guidance clarifying the definition of a business in order to assist entities with evaluating when a set of transferred assets and activities is considered a business. In general, we expect that the revised definition will result in fewer acquisitions being accounted for as business combinations than under the current guidance. This guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years and should be applied prospectively. Early adoption is permitted under certain circumstances. We early adopted this guidance as of July 1, 2017 and the adoption did not have a material impact on our business, financial condition or results of operations.

In March 2016, the FASB issued guidance that simplifies several aspects of the accounting for share-based payment award transactions, including the accounting for excess tax benefits and deficiencies, classification of awards as either equity or liabilities and classification of excess tax benefits on the statement of cash flows.  This guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years and can be early adopted for any interim or annual financial statements that have not yet been issued.  We prospectively adopted this guidance on January 1, 2017 and the adoption did not have a material impact on our business, financial condition or results of operations.

In February 2016, the FASB issued guidance that requires the recognition of a lease liability and a right-of-use asset, initially measured at the present value of the lease payments, in the statement of financial condition for all leases previously accounted for as operating leases. This guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. We expect to adopt this guidance on or before the effective date and are currently evaluating the impact adopting this new guidance will have on our business, financial condition and results of operations. 

In July 2015, the FASB issued guidance requiring entities to measure FIFO or average cost inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.  This guidance does not change the measurement of inventory measured using LIFO or the retail inventory method.  This guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years.   We adopted this guidance on January 1, 2017 and the adoption did not have a material impact on our business, financial condition or results of operations. 

In May 2014, the FASB issued guidance regarding “Revenue from Contracts with Customers,” to clarify the principles for recognizing revenue. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires improved interim and annual disclosures that enable the users of financial statements to better understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. The new guidance is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period, and can be adopted retrospectively. We expect to adopt the new standard in the first quarter of 2018 using the modified retrospective transition method. Based on the analysis performed to date, we do not expect the adoption of the standard to have a material impact on the timing or pattern of revenue recognition.

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Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Property, Plant and Equipment

Depreciation is computed using the straight-line method over management’s estimated useful lives of the related assets, except for automotive equipment, which is depreciated using a declining-balance method. The estimated useful lives are as follows:

	Years
Buildings and building improvements	15-40
Pipelines, tanks and terminals	15-40
Asset retirement obligation assets	15-50
Other equipment	3-15

Property, plant and equipment, at cost, consist of the following (in thousands):

	December 31,
	2017			2016
Land and land improvements	$	4,440		$	4,435
Building and building improvements	2,804			2,236
Pipelines, tanks and terminals	314,251			305,302
Asset retirement obligation assets	2,073			2,073
Other equipment	14,650			12,925
Construction in process	28,961			15,436
	367,179			342,407
Less: accumulated depreciation	(112,111		)	(91,378		)
	$	255,068		$	251,029

Property, plant and equipment, accumulated depreciation and depreciation expense by reporting segment as of and for the years ended December 31, 2017 and 2016 are as follows (in thousands):

	As of and For the Year Ended December 31, 2017
	Pipelines and Transportation			Wholesale Marketing and Terminalling			Consolidated
Property, plant and equipment	$	300,134		$	67,045		$	367,179
Less: accumulated depreciation	(84,435		)	(27,676		)	(112,111		)
Property, plant and equipment, net	$	215,699		$	39,369		$	255,068
Depreciation expense	$	17,268		$	3,583		$	20,851

	As of and For the Year Ended December 31, 2016
	Pipelines and Transportation			Wholesale Marketing and Terminalling			Consolidated
Property, plant and equipment	$	279,155		$	63,252		$	342,407
Less: Accumulated depreciation	(67,032		)	(24,346		)	(91,378		)
Property, plant and equipment, net	$	212,123		$	38,906		$	251,029
Depreciation expense	$	16,133		$	3,617		$	19,750

Schedule of Change in Asset Retirement Obligation

The reconciliation of the beginning and ending carrying amounts of asset retirement obligations as of December 31, 2017 and 2016 is as follows (in thousands):

	December 31,
	2017		2016
Beginning balance	$	3,772	$	3,506
Accretion expense	292		266
Ending balance	$	4,064	$	3,772

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Acquisitions (Tables)

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

The following table summarizes the allocation of the relative fair value assigned to the asset groups for the Big Spring Pipeline (in thousands):

Property, plant and equipment	$	6,443
Intangible assets (1)	2,560
Total	$	9,003

⁽¹⁾ Intangible assets acquired represent rights-of-way assets with indefinite useful lives. Rights-of-way assets are not subject to amortization.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

Commercial Agreements

Asset/Operation	Initiation Date	Initial/Maximum Term (years) (1)	Service	Minimum Throughput Commitment (bpd)	Fee (/bbl)
Lion Pipeline System and SALA Gathering System:
Crude Oil Pipelines (non-gathered)	November 2012	5 / 15	Crude oil and refined products transportation	46,000 (2)	$ 0 .95 (3)
Refined Products Pipelines	November 2012	5 / 15		40,000	$	0.11
SALA Gathering System	November 2012	5 / 15	Crude oil gathering	14,000	$ 2.55 (3)
East Texas Crude Logistics System:
Crude Oil Pipelines	November 2012	5 / 15	Crude oil transportation and storage	35,000	$ 0.45 (4)
Storage	November 2012	5 / 15		N/A	$ 278,923/month
East Texas Marketing	November 2012	10 (5)	Marketing products for Tyler Refinery	50,000	$ 0.777 (5)
Big Sandy Terminal: (6)
Refined Products Transportation	November 2012	5 / 15	Refined products transportation, dedicated terminalling services and storage for the Tyler Refinery	5,000	$	0.56
Terminalling	November 2012	5 / 15		5,000	$	0.56
Storage	November 2012	5 / 15		N/A	$ 55,735/month
Tyler Throughput and Tankage:
Refined Products Throughput	July 2013	8 / 16	Dedicated Terminalling and storage	50,000	$	0.36
Storage	July 2013	8 / 16		N/A	$ 832,530/month
Memphis Pipeline	October 2013	5	Refined Products Transportation	10,959	$	1.35
El Dorado Throughput and Tankage:
Refined Products Throughput	February 2014	8 / 16	Dedicated terminalling and storage	11,000	$	0.51
Storage	February 2014	8 / 16		N/A	$1,319,135/month
El Dorado Assets Throughput:
Light Crude Throughput	March 2015	9/15	Dedicated Offloading Services	N/A (7)	$ 1.11
Heavy Crude Throughput	March 2015	9/15	Dedicated Offloading Services	N/A (7)	$ 2.28

⁽¹⁾ Maximum term gives effect to the extension of the commercial agreement pursuant to the terms thereof.

⁽²⁾ Excludes volumes gathered on the SALA Gathering System.

⁽³⁾ Volumes gathered on the SALA Gathering System will not be subject to an additional fee for transportation on our Lion Pipeline System to the El Dorado Refinery.

⁽⁴⁾ For any volumes in excess of 50,000 bpd, the throughput fee will be $0.670/bbl.

⁽⁵⁾ For any volumes in excess of 50,000 bpd, the throughput fee will be $0.738/bbl. Following the primary term, the marketing agreement automatically renews for successive one-year terms, unless either party provides notice of non-renewal 10 months prior to the expiration of the then-current term. The initial primary term for the marketing agreement has been extended through 2026.

⁽⁶⁾ On July 19, 2013, we acquired the Hopewell Pipeline in order to effectively connect it with the Big Sandy Pipeline and thereby return the Big Sandy Terminal to operation. In connection with the acquisition, on July 25, 2013, we and Delek entered into the Amended and Restated Services Agreement (Big Sandy Terminal and Pipeline), which amended and restated the terminalling services agreement for the Big Sandy Terminal originally entered into in November 2012.

⁽⁷⁾  The throughput agreement provides for a minimum throughput fee of $1.5 million per quarter for throughput of a combination of light and heavy crude.

Schedule of Related Party Transactions

A summary of revenue and expense transactions with Delek and its affiliates, including expenses directly charged and allocated to our Predecessors, are as follows (in thousands):

	Year Ended December 31,
	2017		2016		2015
Revenues	$	156,280	$	149,564	$	152,564
Cost of Goods Sold	$	54,982	$	32,514	$	105,461
Operating and maintenance expenses (1)	$	29,483	$	27,668	$	31,636
General and administrative expenses (2)	$	7,492	$	6,254	$	6,356

⁽¹⁾  Operating and maintenance expenses include costs allocated to our Predecessors for operating support provided by Delek, including certain labor related costs, property and liability insurance costs and certain other operating expenses. Costs allocated to our Predecessors by Delek were $0.2 million for the year ended December 31, 2015.

⁽²⁾  No general and administrative expenses were allocated to our Predecessors by Delek for the year ended December 31, 2015

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Net Income Per Unit (Tables)

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Net Income Per Unit

The calculation of net income per unit is as follows (dollars in thousands, except per unit amounts):

	Year Ended December 31,
	2017			2016			2015
Net income attributable to partners	$	69,409		$	62,804		$	66,848
Less: General partner's distribution (including IDRs) (1)	18,797			12,437			5,013
Less: Limited partners' distribution	69,057			58,158			27,439
Less: Subordinated partner's distribution	—			4,424			26,878
(Distributions) earnings excess	$	(18,445	)	$	(12,215	)	$	7,518
General partner's earnings:
Distributions (including IDRs) (1)	$	18,797		$	12,437		$	5,013
Allocation of (distributions) earnings excess	(368		)	(244		)	150
Total general partner's earnings	$	18,429		$	12,193		$	5,163
Limited partners' earnings on common units:
Distributions	$	69,057		$	58,158		$	27,439
Allocation of (distributions) earnings excess	(18,077		)	(11,489		)	3,721
Total limited partners' earnings on common units	$	50,980		$	46,669		$	31,160
Limited partners' earnings on subordinated units:
Distributions	$	—		$	4,424		$	26,878
Allocation of (distributions) earnings excess	—			(482		)	3,647
Total limited partner's earnings on subordinated units	$	—		$	3,942		$	30,525
Weighted average limited partner units outstanding (2):
Common units - (basic)	24,348,063			22,490,264			12,237,154
Common units - (diluted)	24,376,972			22,558,717			12,356,914
Subordinated units - Delek (basic and diluted) (3)	—			1,803,167			11,999,258
Net income per limited partner unit (2):
Common - (basic)	$	2.09		$	2.08		$	2.55
Common - (diluted) (4)	$	2.09		$	2.07		$	2.52
Subordinated - (basic and diluted)	$	—		$	2.19		$	2.54

⁽¹⁾  General partner distributions (including IDRs) consist of the 2% general partner interest and IDRs, which represent the right of the general partner to receive increasing percentages of quarterly distributions of available cash from operating surplus in excess of $0.43125 per unit per quarter. See Note 12 for further discussion related to IDRs.

⁽²⁾  We base our calculation of net income per unit on the weighted-average number of common and subordinated limited partner units outstanding during the period. The weighted-average number of common and subordinated units reflects the conversion of the subordinated units to common units on February 25, 2016.

⁽³⁾  On February 25, 2016, all of the Partnership's 11,999,258 outstanding subordinated units converted into common units and began participating pro rata with the other common units in distributions of available cash. Distributions and the Partnership's net income were allocated to the subordinated units through February 24, 2016.

⁽⁴⁾   There were no outstanding common unit equivalents excluded from the diluted earnings per unit calculation during the year ended December 31, 2017. Outstanding common unit equivalents totaling 4,240 and 6,200 were excluded from the diluted earnings per unit calculation for the years ended December 31, 2016 and 2015, respectively, as these common unit equivalents did not have a dilutive effect under the treasury stock method.

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Depreciation is computed using the straight-line method over management’s estimated useful lives of the related assets, except for automotive equipment, which is depreciated using a declining-balance method. The estimated useful lives are as follows:

	Years
Buildings and building improvements	15-40
Pipelines, tanks and terminals	15-40
Asset retirement obligation assets	15-50
Other equipment	3-15

Property, plant and equipment, at cost, consist of the following (in thousands):

	December 31,
	2017			2016
Land and land improvements	$	4,440		$	4,435
Building and building improvements	2,804			2,236
Pipelines, tanks and terminals	314,251			305,302
Asset retirement obligation assets	2,073			2,073
Other equipment	14,650			12,925
Construction in process	28,961			15,436
	367,179			342,407
Less: accumulated depreciation	(112,111		)	(91,378		)
	$	255,068		$	251,029

Property, plant and equipment, accumulated depreciation and depreciation expense by reporting segment as of and for the years ended December 31, 2017 and 2016 are as follows (in thousands):

	As of and For the Year Ended December 31, 2017
	Pipelines and Transportation			Wholesale Marketing and Terminalling			Consolidated
Property, plant and equipment	$	300,134		$	67,045		$	367,179
Less: accumulated depreciation	(84,435		)	(27,676		)	(112,111		)
Property, plant and equipment, net	$	215,699		$	39,369		$	255,068
Depreciation expense	$	17,268		$	3,583		$	20,851

	As of and For the Year Ended December 31, 2016
	Pipelines and Transportation			Wholesale Marketing and Terminalling			Consolidated
Property, plant and equipment	$	279,155		$	63,252		$	342,407
Less: Accumulated depreciation	(67,032		)	(24,346		)	(91,378		)
Property, plant and equipment, net	$	212,123		$	38,906		$	251,029
Depreciation expense	$	16,133		$	3,617		$	19,750

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Other Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2017

Other Intangible Assets Disclosure [Abstract]

Schedule of Intangible Assets

Our identifiable intangible assets are as follows (in thousands):

	Useful			Accumulated
As of December 31, 2017	Life	Gross		Amortization			Net
Intangible assets subject to amortization:
Supply contract	11.5	$	12,227	$	(12,138	)	$	89
Intangible assets not subject to amortization:
Rights-of-way assets	Indefinite	15,828					15,828
Total		$	28,055	$	(12,138	)	$	15,917

	Useful			Accumulated
As of December 31, 2016	Life	Gross		Amortization			Net
Intangible assets subject to amortization:
Supply contract	11.5	$	12,227	$	(11,075	)	$	1,152
Intangible assets not subject to amortization:
Rights-of-way assets	Indefinite	13,268					13,268
Total		$	25,495	$	(11,075	)	$	14,420

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Long-Term Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Schedule of Maturities of Long-term Debt

Principal maturities of the Partnership's existing third party debt instruments for the next five years and thereafter are as follows as of December 31, 2017 (in thousands):

	2018		2019		2020		2021		2022		Thereafter		Total
Second Amended and Restated Credit Agreement	$	—	$	179,900	$	—	$	—	$	—	$	—	$	179,900
2025 Notes	$	—	$	—	$	—	$	—	$	—	$	250,000	$	250,000

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Equity (Tables)

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Schedule of Capital Units

The table below summarizes the changes in the number of units outstanding from December 31, 2014 through December 31, 2017 (in units).

	Common - Public		Common - Delek	Subordinated		General Partner	Total
Balance at December 31, 2014	9,417,189		2,799,258	11,999,258		494,197	24,709,902
GP units issued to maintain 2% interest	—		—	—		1,248	1,248
Unit-based compensation awards (1)	61,084		—	—		—	61,084
Balance at December 31, 2015	9,478,273		2,799,258	11,999,258		495,445	24,772,234
GP units issued to maintain 2% interest	—		—	—		1,057	1,057
Unit-based compensation awards (1)	51,818		—	—		—	51,818
Delek unit repurchases from public	(266,676	)	266,676	—		—	—
Subordinated unit conversion	—		11,999,258	(11,999,258	)	—	—
Balance at December 31, 2016	9,263,415		15,065,192	—		496,502	24,825,109
GP units issued to maintain 2% interest	—		—	—		1,102	1,102
Unit-based compensation awards	54,026		—	—		—	54,026
Delek unit repurchases from public	(228,854	)	228,854	—		—	—
Balance at December 31, 2017	9,088,587		15,294,046	—		497,604	24,880,237

⁽¹⁾ Unit-based compensation awards are presented net of 14,053, 17,276 and 21,144 units withheld for taxes as of December 31, 2017, 2016 and 2015, respectively.

Schedule of Calculation of Net Income Applicable to Partners

The following table presents the allocation of the general partner's interest in net income (in thousands, except percentage of ownership interest):

	Year Ended December 31,
	2017			2016			2015
Net income attributable to partners	$	69,409		$	62,804		$	66,848
Less: General partner's IDRs	(17,389		)	(11,160		)	(3,904		)
Net income available to partners	$	52,020		$	51,644		$	62,944
General partner's ownership interest	2.0		%	2.0		%	2.0		%
General partner's allocated interest in net income	1,040			1,033			1,259
General partner's IDRs	17,389			11,160			3,904
Total general partner's interest in net income	$	18,429		$	12,193		$	5,163

Schedule of Incentive Distributions Made to Managing Members or General Partners by Distribution

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and our unitholders in any available cash from operating surplus that we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that (i) our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest and (ii) our general partner has not transferred its IDRs.

		Target Quarterly Distribution per Unit		Marginal Percentage Interest in Distributions
		Target Amount		Unitholders		General Partner
Minimum Quarterly Distribution		$	0.37500	98.0	%	2.0	%
First Target Distribution	above	$	0.37500	98.0	%	2.0	%
	up to	$	0.43125
Second Target Distribution	above	$	0.43125	85.0	%	15.0	%
	up to	$	0.46875
Third Target Distribution	above	$	0.46875	75.0	%	25.0	%
	up to	$	0.56250
Thereafter	thereafter	$	0.56250	50.0	%	50.0	%

Schedule of Distributions Made to Members or Limited Partners, by Distribution

The table below summarizes the quarterly distributions related to our quarterly financial results:

Quarter Ended	Total Quarterly Distribution Per Limited Partner Unit		Total Quarterly Distribution Per Limited Partner Unit, Annualized		Total Cash Distribution, including general partner interest and IDRs (in thousands)		Date of Distribution	Unitholders Record Date
December 31, 2015	$	0.590	$	2.36	$	16,124	February 12, 2016	February 5, 2016
March 31, 2016	$	0.610	$	2.44	$	17,095	May 13, 2016	May 5, 2016
June 30, 2016	$	0.630	$	2.52	$	18,085	August 12, 2016	August 5, 2016
September 30, 2016	$	0.655	$	2.62	$	19,302	November 14, 2016	November 7, 2016
December 31, 2016	$	0.680	$	2.72	$	20,537	February 14, 2017	February 3, 2017
March 31, 2017	$	0.690	$	2.76	$	21,024	May 12, 2017	May 5, 2017
June 30, 2017	$	0.705	$	2.82	$	21,783	August 11, 2017	August 4, 2017
September 30, 2017	$	0.715	$	2.86	$	22,270	November 14, 2017	November 7, 2017
December 31, 2017	$	0.725	$	2.90	$	22,777	February 12, 2018	February 2, 2018

The allocation of total quarterly cash distributions made to general and limited partners for the years ended December 31, 2017, 2016 and 2015 is set forth in the table below. Distributions earned with respect to a given period are declared subsequent to quarter end. Therefore, the table below presents total cash distributions applicable to the period in which the distributions are earned (in thousands, except per unit amounts):

	Year Ended December 31,
	2017		2016		2015
General partner's distributions:
General partner's distributions	$	1,408	$	1,277	$	1,109
General partner's IDRs	17,389		11,160		3,904
Total general partner's distributions	18,797		12,437		5,013
Limited partners' distributions:
Common	69,057		58,158		27,439
Subordinated	—		4,424		26,878
Total limited partners' distributions	69,057		62,582		54,317
Total cash distributions	$	87,854	$	75,019	$	59,330
Cash distributions per limited partner unit	$	2.835	$	2.575	$	2.240

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Equity Based Compensation (Tables)

12 Months Ended

Dec. 31, 2017

Share-based Compensation [Abstract]

Schedule of Share-based Compensation, Phantom Units Award Activity

A summary of our unit award activity for the years ended December 31, 2017, 2016 and 2015, is set forth below:

		Number of Phantom Units		Weighted-Average Grant Price
Non-vested	December 31, 2014	215,464		$	23.48
Granted		11,836		$	39.73
Vested		(82,228	)	$	23.55
Non-vested	December 31, 2015	145,072		$	24.76
Granted		12,475		$	26.05
Vested		(69,094	)	$	24.66
Forfeited		(14,500	)	$	22.65
Non-vested	December 31, 2016	73,953		$	25.49
Granted		10,090		$	32.20
Vested		(68,079	)	$	24.60
Non-vested	December 31, 2017	15,964		$	33.54

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Equity Method Investments (Tables)

12 Months Ended

Dec. 31, 2017

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

Combined summarized financial information for our equity method investees is shown below (in thousands):

	Year Ended		Year Ended
	December 31, 2017		December 31, 2016
Current assets	$	12,671	$	7,760
Non-current assets	$	244,329	$	237,516
Current liabilities	$	1,798	$	4,512

	Year Ended		Year Ended			Year Ended
	December 31, 2017		December 31, 2016			December 31, 2015
Revenues	$	28,805	$	2,217		$	—
Gross profit	$	28,805	$	2,217		$	—
Net Income/loss	$	10,714	$	(3,641	)	$	(1,967	)

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Segment Data (Tables)

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

The following is a summary of business segment operating performance as measured by contribution margin for the period indicated (in thousands):

	Year Ended December 31,
	2017			2016			2015
Pipelines and Transportation
Net sales:
Affiliate	109,298			$	103,749		102,551
Third party	12,431			18,423			28,828
Total pipelines and transportation	121,729			122,172			131,379
Operating costs and expenses:
Cost of goods sold	18,210			19,425			19,607
Operating expenses	33,240			29,235			33,751
Segment contribution margin	$	70,279		$	73,512		$	78,021
Capital spending (excluding business combinations)	$	14,262		$	8,478		$	16,030
Wholesale Marketing and Terminalling
Net sales:
Affiliate	46,982			45,815			50,013
Third party	369,364			280,072			408,277
Total wholesale marketing and terminalling	416,346			325,887			458,290
Operating costs and expenses:
Cost of goods sold	354,680			282,733			416,697
Operating expenses	10,034			7,963			11,172
Segment contribution margin	$	51,632		$	35,191		$	30,421
Capital spending (excluding business combinations)	$	4,141		$	3,289		$	6,397
Consolidated
Net sales:
Affiliate	$	156,280		$	149,564		$	152,564
Third party	381,795			298,495			437,105
Total Consolidated	538,075			448,059			589,669
Operating costs and expenses:
Cost of goods sold	372,890			302,158			436,304
Operating expenses	43,274			37,198			44,923
Contribution margin	121,911			108,703			108,442
General and administrative expenses	11,840			10,256			11,384
Depreciation and amortization	21,914			20,813			19,692
(Gain) loss on asset disposals	(20		)	(16		)	104
Operating income	$	88,177		$	77,650		$	77,262
Capital spending (excluding business combinations)	$	18,403		$	11,767		$	22,427

The following table summarizes the total assets for each segment as of December 31, 2017 and 2016 (in thousands).

	Year Ended December 31,
	2017		2016
Pipelines and transportation	$	349,351	$	337,349
Wholesale marketing and terminalling	94,179		78,198
Total Assets	$	443,530	$	415,547

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value, Assets Measured on Recurring Basis

The fair value hierarchy for our financial assets and liabilities accounted for at fair value on a recurring basis at December 31, 2017 and 2016 was as follows: (in thousands):

	As of December 31, 2017
	Level 1		Level 2			Level 3		Total
Liabilities
OTC commodity swaps	—		(1,087		)	—		(1,087		)
Net liabilities	$	—	$	(1,087	)	$	—	$	(1,087	)

	As of December 31, 2016
	Level 1		Level 2			Level 3		Total
Assets
OTC commodity swaps	$	—	$	9		$	—	$	9
Total assets	—		9			—		9
Liabilities
OTC commodity swaps	—		(82		)	—		(82		)
Net assets	$	—	$	(73	)	$	—	$	(73	)

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

The following table presents the fair value of our derivative instruments, as of December 31, 2017 and 2016. The fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under our master netting arrangements, including any cash deficit or collateral on deposit with our counterparties. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements. As a result, the asset and liability amounts below may differ from the amounts presented in our accompanying consolidated balance sheets. During the years ended December 31, 2017 and 2016, we did not elect hedge accounting treatment for these derivative positions. As a result, all changes in fair value are marked to market in the accompanying consolidated statements of income and comprehensive income. See Note 16 for further information regarding the fair value of derivative instruments.

(in thousands)		December 31, 2017					December 31, 2016
Derivative Type	Balance Sheet Location	Assets		Liabilities			Assets		Liabilities
Derivatives:
OTC commodity swaps (1)	Other current assets	$	—	$	(1,087	)	$	9	$	(82	)
Total gross value of derivatives		—		(1,087		)	9		(82		)
Less: Counterparty netting and cash collateral (2)		—		(290		)	9		621
Total net fair value of derivatives		$	—	$	(797	)	$	—	$	(703	)

⁽¹⁾  As of December 31, 2017 and 2016, we had open derivative contracts representing 370,000 barrels and 93,000 barrels, respectively, of refined petroleum products.

⁽²⁾  As of December 31, 2017 and 2016, we had cash collateral of $0.3 million and a cash deficit of $0.6 million, respectively, netted with the net derivative position of our counterparty.

Derivative Instruments, Gain (Loss)

Recognized gains (losses) associated with our derivatives for the years ended December 31, 2017 and 2016 were as follows (in thousands):

		Year Ended December 31,
Derivative Type	Income Statement Location	2017			2016			2015
Interest rate derivatives	Interest expense	$	—		$	—		$	(24	)
OTC commodity swaps	Cost of goods sold	(1,550		)	(2,122		)	441
	Total	$	(1,550	)	$	(2,122	)	$	417

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation

The difference between the actual income tax expense and the tax expense computed by applying the statutory federal income tax rate to income before income taxes is attributable to the following (in thousands):

	Year Ended December 31,
	2017			2016			2015
State income taxes	(222		)	121			171
Other items	—			(40		)	(366		)
Income tax expense (benefit)	$	(222	)	$	81		$	(195	)

Schedule of Components of Income Tax Expense (Benefit)

Income tax expense (benefit) is as follows (in thousands):

	Year Ended December 31,
	2017			2016			2015
Current	$	(111	)	$	254		$	(209	)
Deferred	(111		)	(173		)	14
Total	$	(222	)	$	81		$	(195	)

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Minimum Rental Payments for Operating Leases

The following is an estimate of our future minimum lease payments for operating leases having remaining noncancelable terms in excess of one year as of December 31, 2017 (in thousands):

2018	$	2,482
2019	546
2020	483
2021	293
2022	173
Thereafter	8
Total future minimum rentals	$	3,985

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Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Selected Quarterly Financial Information [Abstract]

Schedule of Quarterly Financial Data

Quarterly financial information for the years ended December 31, 2017 and 2016 is summarized below. The quarterly financial information summarized below has been prepared by management and is unaudited (in thousands, except per unit data).

	For the Three Month Periods Ended
	March 31, 2017		June 30, 2017		September 30, 2017		December 31, 2017
Net sales	$	129,473	$	126,769	$	130,626	$	151,207
Operating income	$	18,472	$	23,371	$	22,636	$	23,698
Net income	$	14,595	$	18,977	$	16,923	$	18,914
Limited partners' interest in net income	$	10,486	$	14,425	$	12,178	$	13,891
Net income per limited partner unit:
Common (basic)	$	0.43	$	0.59	$	0.50	$	0.57
Common (diluted)	$	0.43	$	0.59	$	0.50	$	0.57

	For the Three Month Periods Ended
	March 31, 2016		June 30, 2016		September 30, 2016		December 31, 2016
Net sales	$	104,056	$	111,853	$	107,470	$	124,680
Operating income	$	18,974	$	22,512	$	17,001	$	19,163
Net income	$	15,448	$	18,893	$	13,151	$	15,312
Limited partners' interest in net income	$	13,195	$	16,102	$	9,892	$	11,422
Net income per limited partner unit:
Common (basic)	$	0.54	$	0.66	$	0.41	$	0.47
Common (diluted)	$	0.54	$	0.66	$	0.41	$	0.47
Subordinated - Delek (basic and diluted)	$	0.54	$	—	$	—	$	—

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General (Details) bpd in Thousands, bbl in Thousands	Mar. 31, 2015 bbl / pure bbl
El Dorado Assets | Light Crude Oil
Business Acquisition [Line Items]
Total throughput capacity (bpd)	25
El Dorado Assets | Heavy Crude Oil
Business Acquisition [Line Items]
Total throughput capacity (bpd)	12
Tyler Assets
Business Acquisition [Line Items]
Aggregate shell capacity (barrels)	350

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Accounting Policies Accounts Receivable (Details)	12 Months Ended
	Dec. 31, 2017 USD ($) customer	Dec. 31, 2016 USD ($)
Concentration Risk [Line Items]
Allowance for doubtful accounts | $	$ 0	$ 0
Accounts Receivable | Customer Concentration Risk
Concentration Risk [Line Items]
Number of customers | customer	1
Concentration risk, percentage	22.00%	36.60%

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Accounting Policies Inventory (Details) - Supplier Concentration Risk - Inventory purchased - Wholesale Marketing and Terminalling - vendor	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Concentration Risk [Line Items]
Number of vendors	1	2	1
Concentration risk, percentage	65.80%	72.00%	62.60%
Delek
Concentration Risk [Line Items]
Concentration risk, percentage	11.60%		24.90%

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Accounting Policies Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2017
Minimum | Building and building improvements
Estimated useful life (years)	15 years
Minimum | Pipelines, tanks and terminals
Estimated useful life (years)	15 years
Minimum | Asset retirement obligation assets
Estimated useful life (years)	15 years
Minimum | Other equipment
Estimated useful life (years)	3 years
Maximum | Building and building improvements
Estimated useful life (years)	40 years
Maximum | Pipelines, tanks and terminals
Estimated useful life (years)	40 years
Maximum | Asset retirement obligation assets
Estimated useful life (years)	50 years
Maximum | Other equipment
Estimated useful life (years)	15 years

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Accounting Policies Intangible Assets (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Supply contracts
Acquired Finite-Lived Intangible Assets [Line Items]
Estimated useful life (years)	11 years 6 months	11 years 6 months

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Accounting Policies Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 3,772	$ 3,506
Accretion expense	292	266	$ 251
Ending balance	$ 4,064	$ 3,772	$ 3,506

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Accounting Policies Deferred Financing Costs (Details)	Dec. 31, 2017	May 23, 2017
Senior Notes | 2025 Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	6.75%	6.75%

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Accounting Policies Net income per limited partner unit (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
General partner's ownership interest	2.00%	2.00%	2.00%

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Acquisitions Acquisitions from Delek (Details) $ in Millions	Mar. 31, 2015 USD ($)
El Dorado Assets
Business Acquisition [Line Items]
Cash payments for acquisitions	$ 42.5
Historical carrying value	7.6
Tyler Assets
Business Acquisition [Line Items]
Cash payments for acquisitions	19.4
Historical carrying value	$ 11.6

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Acquisitions from Third Parties (Details) $ in Thousands	Sep. 15, 2017 USD ($)
Big Spring Pipeline
Business Acquisition [Line Items]
Total purchase price	$ 9,003

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Acquisitions Purchase Price Allocation (Details) - Big Spring Pipeline $ in Thousands	Sep. 15, 2017 USD ($)
Business Acquisition [Line Items]
Property, plant and equipment	$ 6,443
Intangible Assets	2,560	[1]
Total purchase price	$ 9,003

[1] Intangible assets acquired represent rights-of-way assets with indefinite useful lives. Rights-of-way assets are not subject to amortization.

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Related Party Transactions Commercial Agreements (Details) - Delek		1 Months Ended
		Mar. 31, 2015 USD ($) $ / bbl	Feb. 28, 2014 USD ($) bbl / pure $ / bbl	Oct. 31, 2013 bbl / pure $ / bbl	Jul. 31, 2013 USD ($) bbl / pure $ / bbl	Nov. 30, 2012 USD ($) bbl / pure $ / bbl
Lion Pipeline System and SALA Gathering System | Crude Oil Pipeline
Related Party Transaction [Line Items]
Minimum throughput commitment (bpd)	[1]					46,000
Throughput commitment tariff rate (dollars per barrel)	[2]					0.95
Lion Pipeline System and SALA Gathering System | Crude Oil Pipeline | Minimum
Related Party Transaction [Line Items]
Term Of agreement (years)						5 years
Lion Pipeline System and SALA Gathering System | Crude Oil Pipeline | Maximum
Related Party Transaction [Line Items]
Term Of agreement (years)	[3]					15 years
Lion Pipeline System and SALA Gathering System | Refined Product Pipeline
Related Party Transaction [Line Items]
Minimum throughput commitment (bpd)						40,000
Throughput commitment tariff rate (dollars per barrel)						0.11
Lion Pipeline System and SALA Gathering System | Refined Product Pipeline | Minimum
Related Party Transaction [Line Items]
Term Of agreement (years)						5 years
Lion Pipeline System and SALA Gathering System | Refined Product Pipeline | Maximum
Related Party Transaction [Line Items]
Term Of agreement (years)	[3]					15 years
Lion Pipeline System and SALA Gathering System | SALA Gathering System
Related Party Transaction [Line Items]
Minimum throughput commitment (bpd)						14,000
Throughput commitment tariff rate (dollars per barrel)	[2]					2.55
Lion Pipeline System and SALA Gathering System | SALA Gathering System | Minimum
Related Party Transaction [Line Items]
Term Of agreement (years)						5 years
Lion Pipeline System and SALA Gathering System | SALA Gathering System | Maximum
Related Party Transaction [Line Items]
Term Of agreement (years)	[3]					15 years
East Texas Crude Logistics System
Related Party Transaction [Line Items]
Throughput volume subject to additional fee (bpd)						50,000
Throughput commitment rate, additional for excess barrels (dollars per barrel)						0.670
East Texas Crude Logistics System | Crude Oil Pipeline
Related Party Transaction [Line Items]
Minimum throughput commitment (bpd)						35,000
Throughput commitment tariff rate (dollars per barrel)	[4]					0.45
East Texas Crude Logistics System | Crude Oil Pipeline | Minimum
Related Party Transaction [Line Items]
Term Of agreement (years)						5 years
East Texas Crude Logistics System | Crude Oil Pipeline | Maximum
Related Party Transaction [Line Items]
Term Of agreement (years)	[3]					15 years
East Texas Crude Logistics System | Storage
Related Party Transaction [Line Items]
Minimum monthly storage fee revenue, amount | $						$ 278,923
East Texas Crude Logistics System | Storage | Minimum
Related Party Transaction [Line Items]
Term Of agreement (years)						5 years
East Texas Crude Logistics System | Storage | Maximum
Related Party Transaction [Line Items]
Term Of agreement (years)	[3]					15 years
East Texas Marketing
Related Party Transaction [Line Items]
Term Of agreement (years)	[5]					10 years
Minimum throughput commitment (bpd)						50,000
Throughput commitment tariff rate (dollars per barrel)	[5]					0.7770
Throughput volume subject to additional fee (bpd)						50,000
Throughput commitment rate, additional for excess barrels (dollars per barrel)						0.738
Big Sandy Terminal | Refined Product Pipeline
Related Party Transaction [Line Items]
Minimum throughput commitment (bpd)	[6]					5,000
Throughput commitment tariff rate (dollars per barrel)	[6]					0.56
Big Sandy Terminal | Refined Product Pipeline | Minimum
Related Party Transaction [Line Items]
Term Of agreement (years)	[6]					5 years
Big Sandy Terminal | Refined Product Pipeline | Maximum
Related Party Transaction [Line Items]
Term Of agreement (years)	[3],[6]					15 years
Big Sandy Terminal | Storage
Related Party Transaction [Line Items]
Minimum monthly storage fee revenue, amount | $	[6]					$ 55,735
Big Sandy Terminal | Storage | Minimum
Related Party Transaction [Line Items]
Term Of agreement (years)	[6]					5 years
Big Sandy Terminal | Storage | Maximum
Related Party Transaction [Line Items]
Term Of agreement (years)	[3],[6]					15 years
Big Sandy Terminal | Big Sandy Terminal
Related Party Transaction [Line Items]
Minimum throughput commitment (bpd)	[6]					5,000
Throughput commitment tariff rate (dollars per barrel)	[6]					0.56
Big Sandy Terminal | Big Sandy Terminal | Minimum
Related Party Transaction [Line Items]
Term Of agreement (years)	[6]					5 years
Big Sandy Terminal | Big Sandy Terminal | Maximum
Related Party Transaction [Line Items]
Term Of agreement (years)	[3],[6]					15 years
Tyler Terminal Throughput and Tankage
Related Party Transaction [Line Items]
Minimum throughput commitment (bpd)					50,000
Throughput commitment tariff rate (dollars per barrel)					0.36
Tyler Terminal Throughput and Tankage | Minimum
Related Party Transaction [Line Items]
Term Of agreement (years)					8 years
Tyler Terminal Throughput and Tankage | Maximum
Related Party Transaction [Line Items]
Term Of agreement (years)	[3]				16 years
Tyler Terminal Throughput and Tankage | Storage
Related Party Transaction [Line Items]
Minimum monthly storage fee revenue, amount | $					$ 832,530
Tyler Terminal Throughput and Tankage | Storage | Minimum
Related Party Transaction [Line Items]
Term Of agreement (years)					8 years
Tyler Terminal Throughput and Tankage | Storage | Maximum
Related Party Transaction [Line Items]
Term Of agreement (years)	[3]				16 years
Memphis Pipeline
Related Party Transaction [Line Items]
Term Of agreement (years)	[5]			5 years
Minimum throughput commitment (bpd)				10,959
Throughput commitment tariff rate (dollars per barrel)	[5]			1.35
El Dorado Throughput and Tankage | Refined Product Pipeline
Related Party Transaction [Line Items]
Minimum throughput commitment (bpd)			11,000
Throughput commitment tariff rate (dollars per barrel)			0.51
El Dorado Throughput and Tankage | Refined Product Pipeline | Minimum
Related Party Transaction [Line Items]
Term Of agreement (years)			8 years
El Dorado Throughput and Tankage | Refined Product Pipeline | Maximum
Related Party Transaction [Line Items]
Term Of agreement (years)	[3]		16 years
El Dorado Throughput and Tankage | Storage
Related Party Transaction [Line Items]
Minimum monthly storage fee revenue, amount | $			$ 1,319,135
El Dorado Throughput and Tankage | Storage | Minimum
Related Party Transaction [Line Items]
Term Of agreement (years)			8 years
El Dorado Throughput and Tankage | Storage | Maximum
Related Party Transaction [Line Items]
Term Of agreement (years)	[3]		16 years
El Dorado Assets
Related Party Transaction [Line Items]
Minimum throughput fee | $		$ 1,500,000
El Dorado Assets | Light Crude Oil
Related Party Transaction [Line Items]
Throughput commitment tariff rate (dollars per barrel)	[7]	1.11
El Dorado Assets | Light Crude Oil | Minimum
Related Party Transaction [Line Items]
Term Of agreement (years)		9 years
El Dorado Assets | Light Crude Oil | Maximum
Related Party Transaction [Line Items]
Term Of agreement (years)	[3]	15 years
El Dorado Assets | Heavy Crude Oil
Related Party Transaction [Line Items]
Throughput commitment tariff rate (dollars per barrel)	[7]	2.28
El Dorado Assets | Heavy Crude Oil | Minimum
Related Party Transaction [Line Items]
Term Of agreement (years)		9 years
El Dorado Assets | Heavy Crude Oil | Maximum
Related Party Transaction [Line Items]
Term Of agreement (years)	[3]	15 years

[1] Excludes volumes gathered on the SALA Gathering System.

[2] Volumes gathered on the SALA Gathering System will not be subject to an additional fee for transportation on our Lion Pipeline System to the El Dorado Refinery.

[3] Maximum term gives effect to the extension of the commercial agreement pursuant to the terms thereof.

[4] For any volumes in excess of 50,000 bpd, the throughput fee will be $0.670/bbl.

[5] Following the primary term, the marketing agreement automatically renews for successive one-year terms, unless either party provides notice of non-renewal 10 months prior to the expiration of the then-current term.

[6] On July 19, 2013, we acquired the Hopewell Pipeline in order to effectively connect it with the Big Sandy Pipeline and thereby return the Big Sandy Terminal to operation. In connection with the acquisition, on July 25, 2013, we and Delek entered into the Amended and Restated Services Agreement (Big Sandy Terminal and Pipeline), which amended and restated the terminalling services agreement for the Big Sandy Terminal originally entered into in November 2012.

[7] The throughput agreement provides for a minimum throughput fee of $1.5 million per quarter for throughput of a combination of light and heavy crude.

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Related Party Transactions Omnibus Agreement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Reimbursement of capital expenditures by Delek	$ 4,262	$ 1,880	$ 5,220
Omnibus Agreement | Operating Expense | Delek US | Delek
Related Party Transaction [Line Items]
Recovery of direct costs	$ 300	$ 1,200

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Related Party Transactions Other Agreements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Expense | Partnership Agreement | General Partner
Related Party Transaction [Line Items]
Payment for management fee	$ 18.8	$ 15.7	$ 22.8

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Related Party Transactions Summary of Transactions (Details) - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Revenue	[1]	$ 156,280,000	$ 149,564,000	$ 152,564,000
Delek
Related Party Transaction [Line Items]
Revenue		156,280,000	149,564,000	152,564,000
General and administrative expenses	[2]	7,492,000	6,254,000	6,356,000
Logistics Assets Predecessor | Delek
Related Party Transaction [Line Items]
Expenses				200,000
General and administrative expenses				0
Cost of goods sold | Delek
Related Party Transaction [Line Items]
Expenses		54,982,000	32,514,000	105,461,000
Operating Expense | Delek
Related Party Transaction [Line Items]
Expenses	[3]	$ 29,483,000	$ 27,668,000	$ 31,636,000

[1] See Note 4 for a description of our material affiliate revenue transactions.

[2] No general and administrative expenses were allocated to our Predecessors by Delek for the year ended December 31, 2015.

[3] Operating and maintenance expenses include costs allocated to our Predecessors for operating support provided by Delek, including certain labor related costs, property and liability insurance costs and certain other operating expenses. Costs allocated to our Predecessors by Delek were $0.2 million for the year ended December 31, 2015.

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Related Party Transactions Quarterly Cash Distributions Paid (Details) - USD ($) $ in Thousands											12 Months Ended
	Feb. 12, 2018	Jan. 23, 2018	Nov. 14, 2017	Aug. 11, 2017	May 12, 2017	Jan. 24, 2017	Nov. 14, 2016	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Cash distributions paid			$ 22,270	$ 21,783	$ 21,024	$ 20,537	$ 19,302	$ 18,085	$ 17,095	$ 16,124
Subsequent Event
Related Party Transaction [Line Items]
Cash distributions paid	$ 22,777
Delek
Related Party Transaction [Line Items]
Cash distributions paid											$ 60,100	$ 47,000	$ 35,900
Delek | Subsequent Event
Related Party Transaction [Line Items]
Cash distributions declared		$ 16,200

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Net Income Per Unit Narrative (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Mar. 31, 2016
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
General partner's ownership interest	2.00%	2.00%	2.00%
Subordinated- Delek
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Limited Partners' capital account, units outstanding	0	0		11,999,258

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Net Income Per Unit Calculation of Net Income Per Unit (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Net income per unit [Line Items]
Net income attributable to partners										$ 69,409		$ 62,804		$ 66,848
(Distributions) earnings excess										$ (18,445)		$ (12,215)		$ 7,518
Footnote [Abstract]
General partner's ownership interest										2.00%		2.00%		2.00%
Maximum | First target distribution
Footnote [Abstract]
Distribution payment targets										$ 0.43125
General Partner
Net income per unit [Line Items]
Total earnings										$ 18,429		$ 12,193		$ 5,163
Limited Partner, Common Units
Net income per unit [Line Items]
Total earnings										50,980		46,669		31,160
Limited Partner, Subordinated Units
Net income per unit [Line Items]
Total earnings										$ 0		$ 3,942		$ 30,525
Common Units
Weighted average limited partner units outstanding:
Common units - (basic)	[1]									24,348,063		22,490,264		12,237,154
Common units - (diluted)	[1]									24,376,972		22,558,717		12,356,914
Net income per limited partner unit:
Common units - (basic)		$ 0.57	$ 0.50	$ 0.59	$ 0.43	$ 0.47	$ 0.41	$ 0.66	$ 0.54	$ 2.09	[1]	$ 2.08	[1]	$ 2.55	[1]
Common units - (diluted)		$ 0.57	$ 0.50	$ 0.59	$ 0.43	0.47	0.41	0.66	0.54	$ 2.09	[1]	$ 2.07	[1]	$ 2.52	[1]
Footnote [Abstract]
Common units excluded from computation of earnings per share										0		4,240		6,200
Subordinated- Delek
Weighted average limited partner units outstanding:
Subordinated units - Delek (basic and diluted)	[1]									0		1,803,167		11,999,258
Net income per limited partner unit:
Subordinated units - Delek (basic and diluted)						$ 0.00	$ 0.00	$ 0.00	$ 0.54	$ 0.00	[1]	$ 2.19	[1]	$ 2.54	[1]
Footnote [Abstract]
Limited Partners' capital account, units outstanding		0				0			11,999,258	0		0
General Partner
Net income per unit [Line Items]
Net income attributable to partners										$ 18,429		$ 12,193		$ 5,163
General partner's distribution	[2]									18,797		12,437		5,013
(Distributions) earnings excess										(368)		(244)		150
Limited Partner
Net income per unit [Line Items]
Limited partners' distribution										69,057		62,582		54,317
Limited Partner | Common Units
Net income per unit [Line Items]
Limited partners' distribution										69,057		58,158		27,439
(Distributions) earnings excess										$ (18,077)		$ (11,489)		$ 3,721
Weighted average limited partner units outstanding:
Common units - (basic)	[3]									24,348,063		22,490,264		12,237,154
Common units - (diluted)	[3]									24,376,972		22,558,717		12,356,914
Net income per limited partner unit:
Common units - (basic)	[3]									$ 2.09		$ 2.08		$ 2.55
Common units - (diluted)	[3],[4]									$ 2.09		$ 2.07		$ 2.52
Limited Partner | Subordinated Units
Net income per unit [Line Items]
Limited partners' distribution										$ 0		$ 4,424		$ 26,878
(Distributions) earnings excess										$ 0		$ (482)		$ 3,647
Weighted average limited partner units outstanding:
Subordinated units - Delek (basic and diluted)	[3],[5]									0		1,803,167		11,999,258
Net income per limited partner unit:
Subordinated units - Delek (basic and diluted)	[3]									$ 0.00		$ 2.19		$ 2.54
Limited Partner | Subordinated- Delek
Net income per unit [Line Items]
Net income attributable to partners												$ 3,942		$ 30,525

[1] We base our calculation of net income per unit on the weighted-average number of common and subordinated limited partner units outstanding during the period. The weighted-average number of common and subordinated units reflect the conversion of the subordinated units to common units on February 25, 2016. See Notes 5 and 12 for further discussion.

[2] General partner distributions (including IDRs) consist of the 2% general partner interest and IDRs, which represent the right of the general partner to receive increasing percentages of quarterly distributions of available cash from operating surplus in excess of $0.43125 per unit per quarter. See Note 12 for further discussion related to IDRs.

[3] We base our calculation of net income per unit on the weighted-average number of common and subordinated limited partner units outstanding during the period. The weighted-average number of common and subordinated units reflects the conversion of the subordinated units to common units on February 25, 2016.

[4] There were no outstanding common unit equivalents excluded from the diluted earnings per unit calculation during the year ended December 31, 2017. Outstanding common unit equivalents totaling 4,240 and 6,200 were excluded from the diluted earnings per unit calculation for the years ended December 31, 2016 and 2015, respectively, as these common unit equivalents did not have a dilutive effect under the treasury stock method.

[5] On February 25, 2016, all of the Partnership's 11,999,258 outstanding subordinated units converted into common units and began participating pro rata with the other common units in distributions of available cash. Distributions and the Partnership's net income were allocated to the subordinated units through February 24, 2016.

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Major Customer Narrative (Details) - Sales Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Delek
Concentration Risk [Line Items]
Concentration risk, percentage	28.90%	32.80%	25.90%
Sunoco
Concentration Risk [Line Items]
Concentration risk, percentage	9.00%	10.50%	16.20%

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Inventory Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Inventory [Line Items]
Inventory	$ 20,855,000	$ 8,875,000
Cost of goods sold
Inventory [Line Items]
Inventory Write-down	$ 300,000	$ 0	$ 300,000

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Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 367,179	$ 342,407
Less: accumulated depreciation	(112,111)	(91,378)
Property, plant and equipment, net	255,068	251,029
Depreciation expense	20,851	19,750
Pipelines and Transportation
Property, Plant and Equipment [Line Items]
Property, plant and equipment	300,134	279,155
Less: accumulated depreciation	(84,435)	(67,032)
Property, plant and equipment, net	215,699	212,123
Depreciation expense	17,268	16,133
Wholesale Marketing and Terminalling
Property, Plant and Equipment [Line Items]
Property, plant and equipment	67,045	63,252
Less: accumulated depreciation	(27,676)	(24,346)
Property, plant and equipment, net	39,369	38,906
Depreciation expense	3,583	3,617
Land and land improvements
Property, Plant and Equipment [Line Items]
Property, plant and equipment	4,440	4,435
Building and building improvements
Property, Plant and Equipment [Line Items]
Property, plant and equipment	2,804	2,236
Pipelines, tanks and terminals
Property, Plant and Equipment [Line Items]
Property, plant and equipment	314,251	305,302
Asset retirement obligation assets
Property, Plant and Equipment [Line Items]
Property, plant and equipment	2,073	2,073
Other equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	14,650	12,925
Construction in process
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 28,961	$ 15,436

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Goodwill Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Goodwill [Line Items]
Goodwill, impairment loss	$ 0	$ 0	$ 0
Goodwill	12,203,000	12,203,000
Wholesale Marketing and Terminalling
Goodwill [Line Items]
Goodwill	7,500,000	7,500,000	7,500,000
Pipelines and Transportation
Goodwill [Line Items]
Goodwill	$ 4,700,000	$ 4,700,000	4,700,000
Goodwill, acquired during period			$ 500,000

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Other Intangible Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Intangible Assets [Line Items]
Accumulated amortization	$ (12,138)	$ (11,075)
Intangible assets, gross	28,055	25,495
Intangible assets, net	15,917	14,420
Rights-of-Way
Other Intangible Assets [Line Items]
Rights-of-way assets	$ 15,828	$ 13,268
Supply contracts
Other Intangible Assets [Line Items]
Estimated useful life (years)	11 years 6 months	11 years 6 months
Intangible assets, gross	$ 12,227	$ 12,227
Accumulated amortization	(12,138)	(11,075)
Intangible assets, net	89	1,152
Amortization expense	1,100	$ 1,100	$ 1,100
Estimated future amortization expense	$ 100

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Long-Term Obligations Second Amended and Restated Credit Agreement (Details) - Revolving Credit Facility - Fifth Third Bank - Line of Credit - USD ($)		12 Months Ended
	Dec. 30, 2014	Dec. 31, 2017	Jul. 09, 2013
Debt Instrument [Line Items]
Weighted average interest rate		4.30%
Second Amended and Restated Credit Agreement
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 700,000,000.00		$ 400,000,000.0
Maximum borrowing capacity under accordion feature	$ 800,000,000.0
Unused capacity, commitment fee percentage		0.50%
Holdings Note outstanding amount		$ 102,000,000
Line of credit facility, amount outstanding		179,900,000
Letters of credit		9,000,000
Amounts drawn under letters of credit		0
Available borrowing capacity		$ 511,100,000
United States of America, Dollars | Prime Rate
Debt Instrument [Line Items]
Description of variable rate basis	U.S. dollar prime rate
United States of America, Dollars | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Description of variable rate basis	London Interbank Offered Rate
Canada, Dollars | Canadian prime rate
Debt Instrument [Line Items]
Description of variable rate basis	Canadian dollar prime rate
Canada, Dollars | Canadian Dealer Offered Rate (CDOR)
Debt Instrument [Line Items]
Description of variable rate basis	Canadian Dealer Offered Rate

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Long-Term Obligations Senior Notes Narrative (Details) - Senior Notes - 2025 Notes - USD ($)	May 23, 2017	Dec. 31, 2017
Debt Instrument [Line Items]
Debt instrument, face amount	$ 250,000,000.0
Debt instrument, interest rate, stated percentage	6.75%	6.75%
Debt instrument, redemption price, percentage of principal amount redeemed	35.00%
Line of credit facility, amount outstanding		$ 250,000,000
Deferred financing costs		(5,500,000)
Debt discount		$ (1,700,000)
Prior to May 15, 2020
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage of principal amount redeemed	106.75%
Twelve-Month Period Beginning on May 15, 2020
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage of principal amount redeemed	105.063%
Twelve-Month Period Beginning on May 15, 2021
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage of principal amount redeemed	103.375%
Twelve-Month Period Beginning on May 15, 2022
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage of principal amount redeemed	101.688%
Twelve-Month Period Beginning on May 15, 2023
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage of principal amount redeemed	100.00%

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Long-Term Obligations Maturities of Long-term debt (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Second Amended and Restated Credit Agreement | Revolving Credit Facility | Fifth Third Bank | Line of Credit
Debt Instrument [Line Items]
2018	$ 0
2019	179,900
2020	0
2021	0
2022	0
Thereafter	0
Total	179,900
2025 Notes | Senior Notes
Debt Instrument [Line Items]
2018	0
2019	0
2020	0
2021	0
2022	0
Thereafter	250,000
Total	$ 250,000

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Equity (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Mar. 31, 2016
Limited Partners' Capital Account [Line Items]
Delek's Limited Parter Interest	61.50%
General partner's ownership interest	2.00%	2.00%	2.00%
General Partner's units	497,604	496,502
Common - Public
Limited Partners' Capital Account [Line Items]
Limited Partners' capital account, units outstanding	9,088,587	9,263,415
Common - Delek
Limited Partners' Capital Account [Line Items]
Limited Partners' capital account, units outstanding	15,294,046	15,065,192
Subordinated- Delek
Limited Partners' Capital Account [Line Items]
Limited Partners' capital account, units outstanding	0	0		11,999,258
Delek US
Limited Partners' Capital Account [Line Items]
Delek's ownership interest in General Partner	94.60%
Other Affiliates
Limited Partners' Capital Account [Line Items]
Delek's ownership interest in General Partner	5.40%

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Equity Units Rollforward (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance	24,825,109	24,772,234		24,709,902
GP units issued to maintain 2% interest	1,102	1,057		1,248
Unit-based compensation awards	54,026	51,818	[1]	61,084	[1]
Delek unit repurchases from public	0	0
Subordinated unit conversion		0
Balance	24,880,237	24,825,109		24,772,234
Units withheld for taxes	14,053	17,276		21,144
General Partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance	496,502	495,445		494,197
GP units issued to maintain 2% interest	1,102	1,057		1,248
Unit-based compensation awards	0	0	[1]	0	[1]
Delek unit repurchases from public	0	0
Subordinated unit conversion		0
Balance	497,604	496,502		495,445
Common - Public | Limited Partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance	9,263,415	9,478,273		9,417,189
GP units issued to maintain 2% interest	0	0		0
Unit-based compensation awards	54,026	51,818	[1]	61,084	[1]
Delek unit repurchases from public	(228,854)	(266,676)
Subordinated unit conversion		0
Balance	9,088,587	9,263,415		9,478,273
Common - Delek | Limited Partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance	15,065,192	2,799,258		2,799,258
GP units issued to maintain 2% interest	0	0		0
Unit-based compensation awards	0	0	[1]	0	[1]
Delek unit repurchases from public	228,854	266,676
Subordinated unit conversion		11,999,258
Balance	15,294,046	15,065,192		2,799,258
Subordinated | Limited Partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance	0	11,999,258		11,999,258
GP units issued to maintain 2% interest	0	0		0
Unit-based compensation awards	0	0	[1]	0	[1]
Delek unit repurchases from public	0	0
Subordinated unit conversion		(11,999,258)
Balance	0	0		11,999,258

[1] Unit-based compensation awards are presented net of 14,053, 17,276 and 21,144 units withheld for taxes as of December 31, 2017, 2016 and 2015, respectively.

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Equity Net income applicable to partners (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity [Abstract]
Net income attributable to partners	$ 69,409	$ 62,804	$ 66,848
Less: General partner's IDRs	(17,389)	(11,160)	(3,904)
Net income available to partners	$ 52,020	$ 51,644	$ 62,944
General partner's ownership interest	2.00%	2.00%	2.00%
General partner's allocated interest in net income	$ 1,040	$ 1,033	$ 1,259
General partner's IDRs	17,389	11,160	3,904
Total general partner's interest in net income	$ 18,429	$ 12,193	$ 5,163

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Equity Percentage Allocations of Available Cash from Operating Surplus (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Incentive Distribution Made to Member or Limited Partner [Line Items]
General partner's ownership interest	2.00%	2.00%	2.00%
Minimum Quarterly Distribution
Incentive Distribution Made to Member or Limited Partner [Line Items]
Distribution payment targets	$ 0.37500
Minimum Quarterly Distribution | Limited Partner
Incentive Distribution Made to Member or Limited Partner [Line Items]
Marginal percentage interest in distributions	98.00%
Minimum Quarterly Distribution | General Partner
Incentive Distribution Made to Member or Limited Partner [Line Items]
Marginal percentage interest in distributions	2.00%
First Target Distribution | Limited Partner
Incentive Distribution Made to Member or Limited Partner [Line Items]
Marginal percentage interest in distributions	98.00%
First Target Distribution | General Partner
Incentive Distribution Made to Member or Limited Partner [Line Items]
Marginal percentage interest in distributions	2.00%
First Target Distribution | Minimum
Incentive Distribution Made to Member or Limited Partner [Line Items]
Distribution payment targets	$ 0.37500
First Target Distribution | Maximum
Incentive Distribution Made to Member or Limited Partner [Line Items]
Distribution payment targets	$ 0.43125
Second Target Distribution | Limited Partner
Incentive Distribution Made to Member or Limited Partner [Line Items]
Marginal percentage interest in distributions	85.00%
Second Target Distribution | General Partner
Incentive Distribution Made to Member or Limited Partner [Line Items]
Marginal percentage interest in distributions	15.00%
Second Target Distribution | Minimum
Incentive Distribution Made to Member or Limited Partner [Line Items]
Distribution payment targets	$ 0.43125
Second Target Distribution | Maximum
Incentive Distribution Made to Member or Limited Partner [Line Items]
Distribution payment targets	$ 0.46875
Third Target Distribution | Limited Partner
Incentive Distribution Made to Member or Limited Partner [Line Items]
Marginal percentage interest in distributions	75.00%
Third Target Distribution | General Partner
Incentive Distribution Made to Member or Limited Partner [Line Items]
Marginal percentage interest in distributions	25.00%
Third Target Distribution | Minimum
Incentive Distribution Made to Member or Limited Partner [Line Items]
Distribution payment targets	$ 0.46875
Third Target Distribution | Maximum
Incentive Distribution Made to Member or Limited Partner [Line Items]
Distribution payment targets	0.56250
Thereafter
Incentive Distribution Made to Member or Limited Partner [Line Items]
Distribution payment targets	$ 0.56250
Thereafter | Limited Partner
Incentive Distribution Made to Member or Limited Partner [Line Items]
Marginal percentage interest in distributions	50.00%
Thereafter | General Partner
Incentive Distribution Made to Member or Limited Partner [Line Items]
Marginal percentage interest in distributions	50.00%

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Equity Cash distributions (Details) - USD ($)
$ / shares in Units, $ in Thousands

12 Months Ended

Feb. 12, 2018

Nov. 14, 2017

Aug. 11, 2017

May 12, 2017

Jan. 24, 2017

Nov. 14, 2016

Aug. 12, 2016

May 13, 2016

Feb. 12, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Distribution Made to Limited Partner [Line Items]

Quarterly cash distribution (dollars per unit)

$ 0.715

$ 0.705

$ 0.69

$ 0.68

$ 0.655

$ 0.63

$ 0.61

$ 0.59

Total Quarterly Distribution Per Limited Partner Unit, Annualized

$ 2.86

$ 2.82

$ 2.76

$ 2.72

$ 2.62

$ 2.52

$ 2.44

$ 2.36

Total Cash Distribution, including general partner interest and IDRs (in thousands)

$ 22,270

$ 21,783

$ 21,024

$ 20,537

$ 19,302

$ 18,085

$ 17,095

$ 16,124

General partner's IDRs

$ 17,389

$ 11,160

$ 3,904

Total cash distributions

$ 87,854

$ 75,019

$ 59,330

Cash distributions per limited partner unit

$ 2.835

$ 2.575

$ 2.2400

Derivative Instruments and Hedging Activities Disclosure

Derivative Instruments

From time to time, we enter into forward fuel contracts to limit the exposure to price fluctuations for physical purchases of finished products in the normal course of business. We use derivatives to reduce the impact of market price volatility on our results of operations. Typically, we enter into forward fuel contracts with major financial institutions in which we fix the purchase price of finished grade fuel for a predetermined number of units with fulfillment terms of less than 90 days.

From time to time, we may also enter into interest rate hedging agreements to limit floating interest rate exposure under the Second Amended and Restated Credit Agreement. Our initial credit facility required us to maintain interest rate hedging arrangements on at least 50% of the amount funded on November 7, 2012 under the credit facility, which was required to be in place for at least a three-year period beginning no later than March 7, 2013. Accordingly, effective February 25, 2013, we entered into an interest rate hedge in the form of a LIBOR interest rate cap for a term of three years for a total notional amount of $45.0 million, thereby meeting the requirements in effect at that time. The interest rate hedge remained in place in accordance with its term through its maturity date in February 2016.

The following table presents the fair value of our derivative instruments, as of December 31, 2017 and 2016. The fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under our master netting arrangements, including any cash deficit or collateral on deposit with our counterparties. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements. As a result, the asset and liability amounts below may differ from the amounts presented in our accompanying consolidated balance sheets. During the years ended December 31, 2017 and 2016, we did not elect hedge accounting treatment for these derivative positions. As a result, all changes in fair value are marked to market in the accompanying consolidated statements of income and comprehensive income. See Note 16 for further information regarding the fair value of derivative instruments.

(in thousands)		December 31, 2017					December 31, 2016
Derivative Type	Balance Sheet Location	Assets		Liabilities			Assets		Liabilities
Derivatives:
OTC commodity swaps (1)	Other current assets	$	—	$	(1,087	)	$	9	$	(82	)
Total gross value of derivatives		—		(1,087		)	9		(82		)
Less: Counterparty netting and cash collateral (2)		—		(290		)	9		621
Total net fair value of derivatives		$	—	$	(797	)	$	—	$	(703	)

⁽¹⁾  As of December 31, 2017 and 2016, we had open derivative contracts representing 370,000 barrels and 93,000 barrels, respectively, of refined petroleum products.

⁽²⁾  As of December 31, 2017 and 2016, we had cash collateral of $0.3 million and a cash deficit of $0.6 million, respectively, netted with the net derivative position of our counterparty.

Recognized gains (losses) associated with our derivatives for the years ended December 31, 2017 and 2016 were as follows (in thousands):

		Year Ended December 31,
Derivative Type	Income Statement Location	2017			2016			2015
Interest rate derivatives	Interest expense	$	—		$	—		$	(24	)
OTC commodity swaps	Cost of goods sold	(1,550		)	(2,122		)	441
	Total	$	(1,550	)	$	(2,122	)	$	417

General Partner

Distribution Made to Limited Partner [Line Items]

General partner's distributions

$ 1,408

$ 1,277

$ 1,109

General partner's IDRs

17,389

11,160

3,904

Total general partner's distributions

18,797

12,437

5,013

Limited Partner

Distribution Made to Limited Partner [Line Items]

Limited partners' distribution

69,057

62,582

54,317

Limited Partner | Common Units

Distribution Made to Limited Partner [Line Items]

Limited partners' distribution

69,057

58,158

27,439

Limited Partner | Subordinated

Distribution Made to Limited Partner [Line Items]

Limited partners' distribution

$ 0

$ 4,424

$ 26,878

Subsequent Event

Distribution Made to Limited Partner [Line Items]

Total Quarterly Distribution Per Limited Partner Unit, Annualized

$ 2.90

Total Cash Distribution, including general partner interest and IDRs (in thousands)

$ 22,777

Cash distributions per limited partner unit

$ 0.725

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Equity Based Compensation Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Number of units authorized	612,207
Total fair value of vested units	$ 1.7	$ 1.7	$ 1.9
Unrecognized compensation costs	$ 0.4
Unrecognized compensation costs, weighted-average period for recognition	8 months
Minimum
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Awards requisite service period (years)	1 year
Maximum
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Awards requisite service period (years)	5 years
General and administrative expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Unit-based compensation expense	$ 0.7	$ 0.6	$ 0.4

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Equity Based Compensation Unit Award Activity Summary (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Unit Award Activity [Roll Forward]
Non-vested (units)	73,953	145,072	215,464
Granted (units)	10,090	12,475	11,836
Vested (units)	(68,079)	(69,094)	(82,228)
Forfeited (units)		(14,500)
Non-vested (units)	15,964	73,953	145,072
Unit award activity, Weighted Average Grant Date Fair Value [Roll Forward]
Non-vested, weighted-average grant price, beginning of year (usd per unit)	$ 25.49	$ 24.76	$ 23.48
Granted, weighted-average grant price (usd per unit)	32.20	26.05	39.73
Vested, weighted average grant price (usd per unit)	24.60	24.66	23.55
Forfeited, weighted average grant price (usd per unit)		22.65
Non-vested, weighted-average grant price, end of year (usd per unit)	$ 33.54	$ 25.49	$ 24.76

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Equity Method Investments Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 106,465	$ 101,080
CP LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage	50.00%
Rangeland Rio
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage	33.00%

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Equity Method Investments Summarized Financial Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Current assets	$ 12,671	$ 7,760
Non-current assets	244,329	237,516
Current liabilities	1,798	4,512
Revenues	28,805	2,217	$ 0
Gross profit	28,805	2,217	0
Net Income/loss	$ 10,714	$ (3,641)	$ (1,967)

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Segment Data Narrative (Details)	12 Months Ended
	Dec. 31, 2017 segment
Segment Reporting [Abstract]
Number of reportable segments	2

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Segment Data (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Affiliate	[1]									$ 156,280	$ 149,564	$ 152,564
Third party										381,795	298,495	437,105
Total pipelines and transportation		$ 151,207	$ 130,626	$ 126,769	$ 129,473	$ 124,680	$ 107,470	$ 111,853	$ 104,056	538,075	448,059	589,669
Operating costs and expenses:
Cost of goods sold										372,890	302,158	436,304
Operating expenses										43,274	37,198	44,923
Segment contribution margin										121,911	108,703	108,442
General and administrative expenses										11,840	10,256	11,384
Depreciation and amortization										21,914	20,813	19,692
(Gain) loss on asset disposals										(20)	(16)	104
Operating income		23,698	$ 22,636	$ 23,371	$ 18,472	19,163	$ 17,001	$ 22,512	$ 18,974	88,177	77,650	77,262
Capital spending (excluding business combinations)										18,403	11,767	22,427
Total assets		443,530				415,547				443,530	415,547
Pipelines and Transportation
Segment Reporting Information [Line Items]
Affiliate										109,298	103,749	102,551
Third party										12,431	18,423	28,828
Total pipelines and transportation										121,729	122,172	131,379
Operating costs and expenses:
Cost of goods sold										18,210	19,425	19,607
Operating expenses										33,240	29,235	33,751
Segment contribution margin										70,279	73,512	78,021
Capital spending (excluding business combinations)										14,262	8,478	16,030
Total assets		349,351				337,349				349,351	337,349
Wholesale Marketing and Terminalling
Segment Reporting Information [Line Items]
Affiliate										46,982	45,815	50,013
Third party										369,364	280,072	408,277
Total pipelines and transportation										416,346	325,887	458,290
Operating costs and expenses:
Cost of goods sold										354,680	282,733	416,697
Operating expenses										10,034	7,963	11,172
Segment contribution margin										51,632	35,191	30,421
Capital spending (excluding business combinations)										4,141	3,289	$ 6,397
Total assets		$ 94,179				$ 78,198				$ 94,179	$ 78,198

[1] See Note 4 for a description of our material affiliate revenue transactions.

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Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash collateral (deficit)	$ 290	$ (630)
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		9
Net assets (liabilities)	(1,087)	(73)
Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		0
Net assets (liabilities)	0	0
Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		9
Net assets (liabilities)	(1,087)	(73)
Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		0
Net assets (liabilities)	0	0
Fair Value, Measurements, Recurring | OTC commodity swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		9
Derivative Liability	(1,087)	(82)
Fair Value, Measurements, Recurring | OTC commodity swaps | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liability	0	0
Fair Value, Measurements, Recurring | OTC commodity swaps | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		9
Derivative Liability	(1,087)	(82)
Fair Value, Measurements, Recurring | OTC commodity swaps | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liability	$ 0	$ 0

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Derivative Instruments Narrative (Details) $ in Millions	Feb. 25, 2013 USD ($)
Interest Rate Contract
Derivative [Line Items]
Derivative, notional amount	$ 45.0

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Derivative Instruments (Details) bbl in Thousands, $ in Thousands		Dec. 31, 2017 USD ($) bbl	Dec. 31, 2016 USD ($) bbl
Derivative Instruments, Gain (Loss) [Line Items]
Less: Counterparty netting and cash collateral, Liabilities		$ (290)	$ 630
Derivatives not designated as hedging instrument
Derivative Instruments, Gain (Loss) [Line Items]
Assets		0	9
Less: Counterparty netting and cash collateral, Assets	[1]	0	9
Total net fair value of derivative, Assets		0	0
Liabilities		(1,087)	(82)
Less: Counterparty netting and cash collateral, Liabilities	[1]	(290)	621
Total net fair value of derivative, Liabilities		$ (797)	$ (703)
Open derivative contracts (barrels) | bbl		370	93
Other current assets | Derivatives not designated as hedging instrument | OTC commodity swaps
Derivative Instruments, Gain (Loss) [Line Items]
Assets	[2]	$ 0	$ 9
Liabilities	[2]	$ (1,087)	$ (82)

[1] As of December 31, 2017 and 2016, we had cash collateral of $0.3 million and a cash deficit of $0.6 million, respectively, netted with the net derivative position of our counterparty.

[2] As of December 31, 2017 and 2016, we had open derivative contracts representing 370,000 barrels and 93,000 barrels, respectively, of refined petroleum products.

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Derivative Instruments Income Statement Location (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, gain (loss) on derivative, net	$ (1,550)	$ (2,122)	$ 417
Interest Rate Contract | Interest expense | Derivatives not designated as hedging instrument
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, gain (loss) on derivative, net	0	0	(24)
OTC commodity swaps | Cost of goods sold | Derivatives not designated as hedging instrument
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, gain (loss) on derivative, net	$ (1,550)	$ (2,122)	$ 441

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Income Taxes Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Uncertain tax positions	$ 0	$ 0
Uncertain tax positions, income tax penalties and interest expense	0	0	$ 0
Other non-current assets
Deferred tax assets	400,000	300,000
Due to Related Parties
Taxes payable	$ 300,000	$ 100,000

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Income Taxes Reconciliation of Actual Income Tax Expense to Statutory (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
State income taxes	$ (222)	$ 121	$ 171
Other items	0	(40)	(366)
Total	$ (222)	$ 81	$ (195)

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Income Taxes Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Current	$ (111)	$ 254	$ (209)
Deferred	(111)	(173)	14
Total	$ (222)	$ 81	$ (195)

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Commitments and Contingencies Crude Oil Releases (Details) $ in Millions	Dec. 31, 2017 USD ($)	Jan. 31, 2016 bbl	Apr. 28, 2015 bbl	Mar. 31, 2013 bbl
Modisette Release
Loss Contingencies [Line Items]
Barrels of crude oil released		30
Paline Release
Loss Contingencies [Line Items]
Barrels of crude oil released		350
Fouke Junction Crude Oil Release
Loss Contingencies [Line Items]
Barrels of crude oil released			130
Magnolia Station Spill
Loss Contingencies [Line Items]
Barrels of crude oil released				5,900
Accrual for environmental loss contingencies | $	$ 1.0

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Commitments and Contingencies Letters of Credit (Details)	Dec. 31, 2017 USD ($)
Fifth Third Bank | Revolving Credit Facility | Letter of Credit
Debt Instrument [Line Items]
Line of credit facility, amount outstanding	$ 0

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Commitments and Contingencies Operating Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Operating leases, rent expense	$ 5,600	$ 5,700	$ 5,300
2018	2,482
2019	546
2020	483
2021	293
2022	173
Thereafter	8
Total future minimum rentals	$ 3,985

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Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Selected Quarterly Financial Information [Abstract]
Net sales	$ 151,207	$ 130,626	$ 126,769	$ 129,473	$ 124,680	$ 107,470	$ 111,853	$ 104,056	$ 538,075		$ 448,059		$ 589,669
Operating income	23,698	22,636	23,371	18,472	19,163	17,001	22,512	18,974	88,177		77,650		77,262
Net income	18,914	16,923	18,977	14,595	15,312	13,151	18,893	15,448	69,409		62,804		66,211
Limited partners' interest in net income	$ 13,891	$ 12,178	$ 14,425	$ 10,486	$ 11,422	$ 9,892	$ 16,102	$ 13,195	$ 50,980		$ 50,611		$ 61,685
Common Units
Common (basic)	$ 0.57	$ 0.50	$ 0.59	$ 0.43	$ 0.47	$ 0.41	$ 0.66	$ 0.54	$ 2.09	[1]	$ 2.08	[1]	$ 2.55	[1]
Common units - (diluted)	$ 0.57	$ 0.50	$ 0.59	$ 0.43	0.47	0.41	0.66	0.54	2.09	[1]	2.07	[1]	2.52	[1]
Subordinated- Delek
Subordinated units - Delek (basic and diluted)					$ 0.00	$ 0.00	$ 0.00	$ 0.54	$ 0.00	[1]	$ 2.19	[1]	$ 2.54	[1]

[1] We base our calculation of net income per unit on the weighted-average number of common and subordinated limited partner units outstanding during the period. The weighted-average number of common and subordinated units reflect the conversion of the subordinated units to common units on February 25, 2016. See Notes 5 and 12 for further discussion.

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Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Thousands		1 Months Ended	12 Months Ended
	Feb. 12, 2018	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 20, 2018
Subsequent Event [Line Items]
Quarterly cash distribution declared (dollars per unit)			$ 2.835	$ 2.575	$ 2.2400
Asset acquisitions			$ 9,003	$ 0	$ 400
Subsequent Event
Subsequent Event [Line Items]
Quarterly cash distribution declared (dollars per unit)	$ 0.725
Forecast
Subsequent Event [Line Items]
Asset acquisitions		$ 315,000
DKGP Energy Terminals, LLC | Subsequent Event
Subsequent Event [Line Items]
Equity method investment, ownership percentage						50.00%