Delek Logistics Partners (DKL) 10-K 1 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

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	1,552,797
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	2,017
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

Consolidated Balance Sheets

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)

Consolidated Balance Sheets (Pa

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

Consolidated Statements of Inco

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	$ 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.

Consolidated Statements of Part

Consolidated Statements of Partners' Equity (Deficit) - USD ($) $ in Thousands		Total		Equity of Predecessors	Limited PartnerCommon - Public	Limited PartnerCommon - Delek	Limited PartnerSubordinated- 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.

Consolidated Statements of Par6

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

Consolidated Statements of Cash

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

General General

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.

Accounting Policies Accounting

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.

Acquisitions Acquisitions

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.

Related Party Transactions

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.

Net Income Per Unit Net Income

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.

Major Customer Major Customer

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.

Inventory Inventory

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 .

Property, Plant and Equipment P

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

Goodwill Goodwill

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.

Other Intangible Assets Other I

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.

Long-Term Obligations Long-Term

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 payme nt with all existing and future senior indebtedness of the Issuers, and senior in right of payment to any future 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, th e 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

Equity Equity

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

Equity Based Compensation

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

Equity Method Investments Equit

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 )

Segment Data

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

Fair Value Measurements

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.

Derivative Instruments

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

Income Taxes

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.

Commitments and Contingencies

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

Selected Quarterly Financial Da

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 $ — $ — $ —

Subsequent Events

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.

General (Policies)

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.

Accounting Policies (Policies)

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.

Accounting Policies (Tables)

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

Acquisitions (Tables)

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.

Related Party Transactions (Tab

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

Net Income Per Unit (Tables)

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.

Property, Plant and Equipment (

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

Other Intangible Assets (Tables

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

Long-Term Obligations (Tables)

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

Equity (Tables)

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

Equity Based Compensation (Tabl

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

Equity Method Investments (Tabl

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 )

Segment Data (Tables)

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

Fair Value Measurements (Tables

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 )

Derivative Instruments (Tables)

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

Income Taxes (Tables)

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 )

Commitments and Contingencies (

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

Selected Quarterly Financial 46

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 $ — $ — $ —

General (Details)

General (Details) bpd in Thousands, bbl in Thousands	Mar. 31, 2015bbl / purebbl
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

Accounting Policies Accounts Re

Accounting Policies Accounts Receivable (Details)	12 Months Ended
	Dec. 31, 2017USD ($)customer	Dec. 31, 2016USD ($)
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%

Accounting Policies Inventory (

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%

Accounting Policies Property, P

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

Accounting Policies Intangible

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

Accounting Policies Asset Retir

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

Accounting Policies Deferred Fi

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%

Accounting Policies Net income

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%

Acquisitions Acquisitions from

Acquisitions Acquisitions from Delek (Details) $ in Millions	Mar. 31, 2015USD ($)
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

Acquisitions from Third Parties

Acquisitions from Third Parties (Details) $ in Thousands	Sep. 15, 2017USD ($)
Big Spring Pipeline
Business Acquisition [Line Items]
Total purchase price	$ 9,003

Acquisitions Purchase Price All

Acquisitions Purchase Price Allocation (Details) - Big Spring Pipeline $ in Thousands	Sep. 15, 2017USD ($)
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.

Related Party Transactions Comm

Related Party Transactions Commercial Agreements (Details) - Delek		1 Months Ended
		Mar. 31, 2015USD ($)$ / bbl	Feb. 28, 2014USD ($)bbl / pure$ / bbl	Oct. 31, 2013bbl / pure$ / bbl	Jul. 31, 2013USD ($)bbl / pure$ / bbl	Nov. 30, 2012USD ($)bbl / pure$ / 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.

Related Party Transactions Omni

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

Related Party Transactions Othe

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

Related Party Transactions Summ

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.

Related Party Transactions Quar

Related Party Transactions Quarterly Cash Distributions Paid (Details) - USD ($) $ in Thousands

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

Net Income Per Unit Narrative (

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

Net Income Per Unit Calculation

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	$ 0	$ 0	$ 0.54	$ 0	[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		$ 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.

Major Customer Narrative (Detai

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%

Inventory Narrative (Details)

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

Property, Plant and Equipment67

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

Goodwill Narrative (Details)

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

Other Intangible Assets (Detail

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

Long-Term Obligations Second Am

Long-Term Obligations Second Amended and Restated Credit Agreement (Details) - Revolving Credit Facility - Fifth Third Bank - Line of Credit - USD ($)	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		$ 400,000,000
Maximum borrowing capacity under accordion feature	$ 800,000,000
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

Long-Term Obligations Senior No

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
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%

Long-Term Obligations Maturitie

Long-Term Obligations Maturities of Long-term debt (Details) $ in Thousands	Dec. 31, 2017USD ($)
Second Amended and Restated Credit Agreement | Revolving Credit Facility | Fifth Third Bank | Line of Credit
Debt Instrument [Line Items]
2,018	$ 0
2,019	179,900
2,020	0
2,021	0
2,022	0
Thereafter	0
Total	179,900
2025 Notes | Senior Notes
Debt Instrument [Line Items]
2,018	0
2,019	0
2,020	0
2,021	0
2,022	0
Thereafter	250,000
Total	$ 250,000

Equity (Details)

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%

Equity Units Rollforward (Detai

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.

Equity Net income applicable to

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

Equity Percentage Allocations o

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%

Equity Cash distributions (Deta

Equity Cash distributions (Details) - USD ($) $ / shares in Units, $ in Thousands	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

Equity Based Compensation Narra

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

Equity Based Compensation Unit

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

Equity Method Investments Narra

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%

Equity Method Investments Summa

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)

Segment Data Narrative (Details

Segment Data Narrative (Details)	12 Months Ended
	Dec. 31, 2017segment
Segment Reporting [Abstract]
Number of reportable segments	2

Segment Data (Details)

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.

Fair Value Measurements (Detail

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

Derivative Instruments Narrativ

Derivative Instruments Narrative (Details) $ in Millions	Feb. 25, 2013USD ($)
Interest Rate Contract
Derivative [Line Items]
Derivative, notional amount	$ 45

Derivative Instruments (Details

Derivative Instruments (Details) bbl in Thousands, $ in Thousands		Dec. 31, 2017USD ($)bbl	Dec. 31, 2016USD ($)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.

Derivative Instruments Income S

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

Income Taxes Narrative (Details

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

Income Taxes Reconciliation of

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)

Income Taxes Components of Inco

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)

Commitments and Contingencies C

Commitments and Contingencies Crude Oil Releases (Details) $ in Millions	Dec. 31, 2017USD ($)	Jan. 31, 2016bbl	Apr. 28, 2015bbl	Mar. 31, 2013bbl
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

Commitments and Contingencies L

Commitments and Contingencies Letters of Credit (Details)	Dec. 31, 2017USD ($)
Fifth Third Bank | Revolving Credit Facility | Letter of Credit
Debt Instrument [Line Items]
Line of credit facility, amount outstanding	$ 0

Commitments and Contingencies O

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
2,018	2,482
2,019	546
2,020	483
2,021	293
2,022	173
Thereafter	8
Total future minimum rentals	$ 3,985

Selected Quarterly Financial 94

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	$ 0	$ 0	$ 0.54	$ 0	[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.

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Thousands	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%